Mud Related Drilling Problems Packing Off-Under gauge Hole

Packing Off

•Drilling-fluid systems with poor suspension characteristics exhibit strong packing-off tendencies
•Factors that can lead to caving of the formation include:
–Pressure imbalance
–Shale hydration
–Bottom hole assembly striking the wall
Massive particle caving sticks the drill bit.•The Solution is to increase the suspension characteristics of the mud

Mud Related Drilling Problems
Unde gauge Hole

•Under gauge hole is a condition where the borehole is smaller than the bit diameter used to drill the section.
•Under gauge hole can result from any of the following causes:
–Plastic flowing formations
–Wall-cake buildup in a permeable formation
–Swelling shales
•A plastic flowing formation is a formation that is plastic (easily deformable when stressed) and can flow into the borehole.
–When these types of formations are penetrated by the bit, the hole is at gauge.
–However, when the hydrostatic pressure exerted by the column of drilling fluid is less than the hydrostatic pressure of the formation, under balance results, the formation flows, and hole diameter decreases.
•Undergauge hole is a common problem when drilling a thick salt section with an oil mud.
–The salt can flow into the borehole and make the section undergauge.
–When plastic salt formations exist, they are usually below 5,000 feet.
–Spotting fresh water is the best way to free the pipe from a plastic salt formation.
•Wall-cake buildup occurs when the drilling fluid has poor filtration control across a permeable zone.
•Excessive wall-cake buildup can also be caused by:
–High percentage of low-gravity solids
–High differential pressures (excessive mud weights)

Mud Related Drilling Problems Differential Sticking –Reduce Hydrostatic-Key Seating

Reduce Hydrostatic

•Reducing the hydrostatic pressure and therefore the differential pressure with the use of nitrogen has been tried as another alternative.
–Considerations regarding wellbore stability and potential well control problems must be evaluated prior to implementing this method.
–The well is displaced partially or completely with nitrogen
–The method will normally have some hole sloughing issues related with it

Key Seating

•Keyseating is a situation frequently encountered in deviated or crooked holes when the drillpipe wears into the wall. The normal drilling rotation of the drillstring cuts into the formation wall in deviated areas where the drillpipe tension creates pressure against the sides of the hole.
•Keyseating is diagnosed when the drillpipe can be reciprocated within the range of tool joint distances or until collar reaches the keyseat, while pipe rotation and circulation remain normal
–May not be able to rotate when the tool joint is jammed into the keyseat
he friction generated by drillpipe rotation against the bore wall cuts a narrow channel, or keyseat, into the formation.
•A preventive measure is to carefully control upper hole deviation and dogleg severity throughout the well path.
–This action will eliminate the force that leads to keyseat creation.
–Once a keyseat is formed, the best solution is to ream out the small-diameter portions of the hole with reaming tools.
–This action will solve the immediate stuck-pipe problem, but the keyseat can be formed again unless preventive steps are taken.

Attach a reamer to the drill assembly to widen the keyseat.

Mud Related Drilling Problems Differential Sticking

•Differential pressure sticking of the drill pipe can be defined as the force that holds the pipe against the wall of the borehole due to the differential pressure between the hydrostatic pressure of the mud column and the formation pressure. •The pressure differential acts in the direction of the lower pressure in the formation. •This pressure pushes the pipe toward the permeable formation. •As the pressure differential gets larger, the force exerted on the pipe gets larger. •Differential stuck pipe occurs most often at a point next to the drill collars. •This is due to the drill collars being larger; hence more surface area is in contact with the side of the wellbore. •The following are major factors in differential pressure sticking: –The pipe becomes stuck opposite a permeable formation. –The sticking occurs after an interruption of pipe movement. –The pipe comes in contact with a soft, mushy or non-resilient type wall cake. •If the pipe is differentially stuck, as opposed to other types of sticking, the following will occur: –Circulation, if interrupted, will be restored and maintained after sticking is noticed. –The pipe cannot be raised or lowered. –No large amounts of cuttings are circulated out The force required to move differentially stuck pipe could exceed the strength of the drill pipe. •Several preventative steps can be taken to minimize the chances of becoming stuck: –The mud density should be maintained as low as practical, taking into consideration wellbore stability and potential well control problems. –Keep the pipe moving or rotating. •Avoid undue shutdowns and/or slow connections. •Use spiral drill collars to reduce the contact area against the well bore. –Maintain a low fluid loss and pay particular attention to the filter cake; i.e.: it should be thin, tough and resilient. •In areas where differential sticking is prevalent, the high temperature / high pressure fluid loss should be maintained below 20 ml. •Adding 2-8% lubricant to the mud system gives preferential oil wetting to the drill string, thereby allowing better lubricity and minimizing the possibility of stuck pipe. •When the drill string become stuck, it is imperative to act quickly as the sticking coefficient increases with time. •To avoid costly and time consuming wash over operations, a couple of methods are generally used to free the pipe.

Mud Related Drilling Problems
Differential Sticking -Spotting Fluid

•Spotting crude oil or diesel oil with a surfactant around the drill collars has gained wide acceptance. –There are many surfactants available are arecommonly called spotting fluids. –If a surfactant is not available on location, a straight diesel oil pill should be spotted across the collars as quick as possible. –If differential sticking is suspected in an area, always keep a supply of a differential sticking surfactant on location in the event it may be required. •Generally enough pill is mixed up to cover the entire length of the drill collars, plus an excess of 1.5 m3(10 bbls) to be left on top of the collars, and another 3.0 m3(20 bbls) to be left inside the drill collars. •Normally 20-25 litresof surfactant is recommended per cubic metreof diesel oil (1-2 gal/bbl). •The pill should be spotted leaving 3 m3(20 bbls) inside the drill string. –The pipe should then be worked by pulling up to a predetermined over pull weight, applying torque and releasing the weight at regular intervals. –The pill across the collars has a tendency to migrate up the hole; therefore approximately 0.1 m3(1/2 -1 bbl) of excess fluid in the pipe should be pumped every half hour. •An average waiting period is generally 10-12 hours. –If the pipe does not come free in a reasonable period of time (maximum of 2 pills), mechanical methods may be required to free the pipe. –If the spotting pill has to be weighted due to an abnormally pressure zone, or to increase the pill density to that of the mud weight to minimize migration, the spotting procedure would be the same although some of the products may be different.

Mud Related Drilling Problems Stuck Pipe

•The drill string can be stuck for many reasons including poor hole cleaning due to inadequate mud carrying capacity, sloughing shale, key seating and/or differential pressure sticking.
•Bridges can be caused by poor cleaning or by sloughing of the walls into the wellbore.
–The key to a muds lifting capacity is indicated by the appearance of formation solids coming over the shale shaker.
–An unusually large amount of shale indicates that the hole is washing out.
–Rounded edges on large cuttings show that these pieces have been tumbling in the hole for a long time and are not being lifted out effectively.
–Long splinters or fissured shale may indicate that the shale is "popping" into the wellbore, indicative of overpressuredshale.
–At times large amounts of material can remain in the hole without any surface indication that a hole cleaning problem exists.
•Large pieces of rock, which are not removed from the hole often, become lodged between stabilizers or reamers and the hole.
–If this occurs while drilling, the torque required to rotate the drill string will increase rapidly.
–If pieces of rock become lodged while making a connection or during a trip, the additional pull of the hook will appear as a drag.
–A sudden increase in pump pressure can sometimes be observed, as bridges form and restrict mud flow up the annulus
•Prevention of stuck pipe is often the best remedy


•Methods of preventing stuck pipe due to sloughing shale or inadequate hole cleaning may include the following:
–Increase the viscosity and particularly the Yield Point of the mud.
•There is no exact yield value that can be specified, as every situation is unique, but generally an upper Yield Point of ±30 lb/100ft2should clean most cuttings or cavingsfrom the wellbore.
•Again watch the shale shaker closely to determine the characteristics of cuttings.
–If possible annular hydraulics should be improved, to provide faster cuttings transport.
•Pump liners may have to be changed or larger bit nozzles utilized so that more fluid may be circulated without excessive pump pressure buildup.
•Critical velocities should be calculated to avoid turbulent flow that could increase shale problems by tearing up or eroding the hole.
–Use viscous pills to sweep the hole when drilling. This is a common and effective practice when drilling
–Increasing the mud density may be beneficial in some cases to balance the pore pressure of the shale, and to help hold formations in place to stabilize the wellbore.
–Reducing the water loss may help to minimize the hydration of shales and wetting along bedding planes with could disperse and slough into the wellbore.
–The drill string itself should be evaluated to minimize flexure of the string against the sides of the wellbore, which might tend to physically knock shale from the walls of the borehole.
–Keep the hole full at all times.
•Avoid excessive surge or swab pressures by tripping slowly, especially if a float is utilized in the string.
–Use invert mud or inhibitive water base mud.

Oil Muds –Acid Gas

•Hydrogen sulfide (H2S) is a poisonous and dangerous acidic gas encountered in many formations and produced fluids. –It can quickly deaden senses and can be fatal even at low concentrations. –Personal protection and the appropriate safety measures should be taken any time hydrogen sulfide is suspected. •Oil and synthetic muds provide good protection from hydrogen sulfide corrosion and hydrogen embrittlement. –The continuous oil or synthetic phase of the mud is non-conductive and does not provide an electrolyte for the corrosion process. –If the mud has adequate wetting agents, the drill pipe will be preferentially oil-or synthetic-wet. –If the emulsion becomes unstable, and the mud water-wets the drillstring and casing, the corrosion protection provided by oil and synthetic muds will be lost. •Use personal safety protection and the utmost caution if hydrogen sulfide is encountered. –When hydrogen sulfide is expected or encountered, the oil mud alkalinity (POM) should be maintained at >5.0 cm3of 0.1 N H2SO4at the flow line with additions of lime. –Addition of Zinc oxide is also recommended •When hydrogen sulfide is encountered, the mud may require large additions of lime, emulsifier and wetting agents to stabilize its properties. –The mud should be watched for indications of water-wetting. •When Hydrogen Sulfide is encountered –Mud may turn black –The excess lime will drop rapidly –The mud should be tested for H2S with the Garret Gas Train and treated with scavenger and lime as required

Oil Muds –Oil/Water Ratio–Electrical Stability– Gas Solubility

Oil/Water Ratio

•The oil-or synthetic-to-water (O/W or S/W) ratio relates only to the liquid portion of the mud and is not affected by the solids content.
–The oil-or synthetic to-water ratio relates the oil and water fractions to the total liquid fraction.
–Generally, higher mud weights require higher ratios.
–Different conditions favor the use of different ratios, so there is no ratio that must be used for any set of conditions.
•The calculation of the oil-to-water ratio requires retort values as follows:
–Oil ratio (O) = (vol% oil)/(vol% oil + vol% water) x 100
–Water ratio (W) = 100 –oil ratio
•The O/W ratio remains constant when the mud is weighted up or solids are incorporated into the mud, even though the volume percent liquid is decreased significantly.
–A rapid decrease in the O/W or S/W ratio indicates an influx of saltwater from the formation, and a pit volume increase should have been observed.
•When using oil or synthetic muds, all water hoses on the pits should be disconnected or plugged to prevent accidental contamination with water
•The viscosity and HTHP filtrate will change with changes in the oil-or synthetic-to-water ratio.
–Changing the ratio is not used to alter either of these properties.

Electrical Stability

•The electrical stability is an indication of how well (or tightly) the water is emulsified in the oil or synthetic phase.
–Higher values indicate a stronger emulsion and more stable fluid.
–Oil and the synthetic fluids do not conduct electricity. In the electrical stability test, the voltage (electrical potential) is increased across electrodes on a fixed-width probe until the emulsified water droplets connect (i.e., coalesce) to form a continuous bridge or circuit.
•The stronger the emulsion, the higher the voltage required to break down the emulsion completing the electrical circuit to conduct electricity.
•The unit of measure for recording the electrical stability is volts.
•Factors that can influence the electrical stability are:
–Water content
–Water wet solids
–Emulsion strength
–Temperature
–Salt concentration
–Saturation
–Weight material
•Freshly mixed, invert-emulsion muds usually have low electrical stabilities when shipped from the liquid mud plant, even though they are adequately treated with emulsifiers.
–The emulsions of these systems will tighten as they are exposed to downhole temperatures and sheared through the bit.

Gas Solubility

•Oil and synthetic fluids are soluble to methane and other gases encountered while drilling.
•They have high gas solubility to natural gas, carbon dioxide and hydrogen sulfide, see pic.
•This can interfere with kick detection and well-control procedures.
–This soluble gas does not begin to come out of solution until the pressure is reduced as the mud is circulated up the annulus.
–The majority of the gas expansion occurs in the last 1,000-ft interval below the surface.
–For this reason, extra care should be taken to monitor pit levels with these systems and when handling the influx of wellbore fluids.
–It is important to be able to monitor and detect kicks to a level of about 5 bbl

Oil Muds – Osmotic Theory and Borehole Stability-Water Activity– Water Phase Salinity

Osmotic Theory and Borehole Stability

•Osmosis is the net movement of water across a selectively permeable membrane driven by a difference in solute concentrations on the two sides of the membrane •In reference to Invert emulsion oils muds the water phase is saturated with Calcium Chloride –While drilling occurs and new shales are exposed to the fluid, the water captured in the shale will move with osmosis into the fluid effectively drying out the shale –Using this theory, the shale in the borehole cannot hydrate therefore it becomes more stable

Water Activity

•Water activity (AW) is a measure of the chemical potential for water to be transferred between mud and shales. –Activity is measured using the vapor pressure (relative humidity) of shale or mud. –Activity can also be estimated based on the chemical composition of the brine (salinity). –Pure water has an AWof 1.0. –Calcium chloride brines used in most non-aqueous emulsion muds have an AWbetween 0.8 (22% wt) and 0.55 (34% wt). –Lower values for activity are more inhibitive.

Water Phase Salinity

•Calcium chloride is added to increase the emulsified water phase salinity to provide inhibition of shales and reactive solids. •The range for calcium chloride content is usually 25 to 35% by weight. •The CaCl2content should be determined by titration and can be calculated by: •% CaCl2 (wt) =(Ag x 1.565)/((Ag x 1.565) + %H2O) x 100 •Where: –Ag = cm3 0.282 N silver nitrate per cm3of mud –% H2O = Volume % water from retort •The concentration can be adjusted by adding powdered calcium chloride over several circulations. –Powdered CaCl2is preferred over flake CaCl2, because the larger flake particles do not readily dissolve in oil and synthetic muds. –Flaked salts must first be dissolved in water before being added to a non-aqueous system. –The powdered form is generally available as 94 to 97% active material.

Oil Muds

•The origin of non-aqueous drilling fluids can be traced to the 1920s when crude oil was used as a drilling fluid.
•The advantages of oil as a drilling and completion fluid were obvious even then:
–Clays do not hydrate and swell.
–Wellbore stability is improved.
–Production is improved from sandstones containing clays.
–Problems are reduced when drilling evaporites(salts, anhydrite, etc).
–Wellbore enlargement is reduced.
–Mud properties are more stable.
–Contamination resistance is increased.
•Oils also have certain characteristics that are undesirable.
–They are flammable and may contain compounds that cause the failure of rubber goods such as hoses, O-rings, gaskets and Blowout Preventer (BOP) elements.
–Oils lack gel structure and are difficult to viscosifyso they can be weighted.
–Many oils contain toxic or hazardous compounds that cause Health, Safety and Environmental (HSE) concerns.
–They have high gas solubility for many of the gases encountered when drilling wells (natural gas, carbon dioxide and hydrogen sulfide).
–This can interfere with kick detection and well-control procedures.
–Oils may not degrade readily under certain conditions.
–Oils also float on water and can migrate a significant distance from their source
•Today, an invert emulsion mud is a fluid with diesel oil, mineral oil or synthetic fluid as the continuous phase and water or brine as an emulsified phase.
–The emulsified water or brine is dispersed within the oil
–This is the internal phase.
–Calcium chloride salt is used to increase the emulsified water phase salinity to a level where it does not influence (soften or swell) water-sensitive formations and cuttings.
•Invert emulsion muds should be used when conditions justify their application.
•Environmental acceptability, disposal, initial makeup cost, daily maintenance cost, anticipated hole problems, formation evaluation and formation damage issues should all be considered.

Oil Muds -Applications–Emulsion Fundamentals–Additives

Applications

•Troublesome shales. •Salt, anhydrite, carnalliteand potash zones. •Deep, hot wells. •Drilling and coring sensitive productive zones. •Extended-reach drilling projects. •Difficult directional wells. •Slim-hole drilling. •Corrosion control. •Hydrogen sulfide (H2S) and carbon dioxide (CO2) bearing formations. •Perforating and completion fluids. •Casing pack or packer fluids. •Workover fluids. •Spotting fluids to free stuck pipe.

Emulsion Fundamentals

•Invert emulsion drilling fluids are mixtures of two immiscible liquids: oil (or synthetic) and water. –They may contain 50% or more water. –This water is broken up into small droplets and uniformly dispersed in the external nonaqueous phase. –These droplets are kept suspended in the oil (or synthetic) and prevented from coalescing by surfactants that act between the two phases. •To adequately emulsify the water in oil, there must be sufficient chemical emulsifier to form a film around each water droplet. –The emulsion will be unstable if there is not sufficient emulsifier. –As the water content increases, the required concentration of emulsifier increases. •From the standpoint of stability, the smaller the droplet, the more stable the emulsion since large droplets will coalesce more easily than smaller droplets •Uniform droplet size also makes the emulsion more stable –Shear is required to reduce the droplet size, the fluid through the bit, mud guns and shearing devices will aid in reducing droplet size •The importance of sufficient shear and small droplet size and their relationship to mud stability cannot be overemphasized. –Small, uniform water droplets generate viscosity and gel strengths that help support weight material and aid in the reduction of fluid loss by becoming trapped in the filter cake. •Increasing water content (internal phase) of an invert emulsion: –Increases the size of water droplets. –Increases the chances of water droplets coalescing. –Increases the emulsion plastic viscosity. –Increases the amount of emulsifier required to form a stable emulsion. –Decreases the emulsion stability. •The incorporation of solids into a water-in-oil or synthetic emulsion can have either a positive or negative effect on mud properties, depending upon the manner in which they are wetted. –As long as the solids are maintained in an oil-wet condition and do not coalesce or deplete the required surfactant concentration, they will form a stable emulsion. •Non-aqueous drilling fluids are formulated using additives based on a broad group of chemicals called surface-active agents or surfactants. –These chemicals include emulsifiers, soaps and wetting agents. –They act by reducing the interfacial tension between two liquids or between a liquid and a solid. –Surfactants have a hydrophilic (water-loving) polar head and an organophilic (oil-loving or lipophilic) non-polar tail, •Non-aqueous systems contain wetting agents that coat surfaces and solids to alter the contact angle (wettability) of the solid-liquid interfaces, –These materials allow preferentially wetting of solids by the oil or synthetic. –If a fluid is over treated with wetting agents so that solids are totally wetted, the solids may tend to settle or sag. –Solids must be maintained in the preferentially oil-wet condition to maintain a stable fluid. •The preferential oil-wet condition can be disrupted by contamination with water, increased solids loading and insufficient treatments of wetting agents. –When water-wet solids occur: –Solids tend to adhere to shaker screens. –The appearance of the mud becomes “grainy,”losing its glossy sheen. –The Electrical Stability (ES) will decrease. –The rheology will increase. –Barite settling will be observed in mud cup, heat cup and pits. –The High-Temperature, High-Pressure (HTHP) fluid loss will increase and may contain free water.

Additives

•Emulsifiers. –Emulsifiers are surfactants that reduce the surface tension between the water droplets and oil (or synthetic). –They stabilize the mixture by being partially soluble in water and partially soluble in oil –They are usually long-chain alcohols, fatty acids or polymers and can be anionic, cationic or non-ionic. •Soaps. –Some emulsifiers are soaps that are formed by the reaction of a fatty acid ester with an alkali (such as lime) where the hydrogen on the fatty acid is replaced by a metal, such as calcium from lime. –Soaps made with sodium are water-soluble and form oil-in-water emulsions. •Wetting agents. –A wetting agent is a surface-active agent that reduces the interfacial tension and contact angle between a liquid and a solid. –This causes the liquid to spread over the surface of the solid –Wetting agents have one end that is soluble in the continuous-phase liquid and the other that has a strong affinity for solid surfaces, •Viscosifiers. –Although emulsified water increases viscosity, viscosifiers and gelling agents are also required. –Untreated clays cannot be used as viscosifiers because they do not hydrate and yield in oil or synthetic fluid. –If the clays are first coated with an amine, so that they are organophilic, then they will yield and viscosifyin oil and synthetic fluids. •Viscosifiers cont. –Organophilic clay still needs a polar activator (water or alcohol) to produce the maximum yield. –Therefore, their yield decreases as the oil-or synthetic-to-water ratio increases. •Alternative non-clay viscosifiers are available to increase viscosity. –They include asphaltic materials, fatty acid gellants and polymers. •Developing viscosity is a particular problem when mixing new fluids in mud plants where low shear mixing and low temperatures do not allow amine-treated clays to yield. –Freshly prepared muds should not be treated with more organophilic clay than will be required when drilling. •Weight material. –Barite is the most common weight material used in oil and synthetic-base muds. –Calcium carbonate is also used, particularly in lower-density packer fluids, where it is easier to suspend than either barite or hematite. –Hematite may be used in high-density muds where its high specific gravity helps minimize the total solids content of the mud. –Alternative weight materials may require different wetting agents. •Filtration-control additives. –HTHP filtration control of invert emulsion muds is affected by the viscosity of the continuous fluid phase, the oil or synthetic-to-water ratio, the tightness of the emulsion, water-wetting of the solids, the solids content, and the amount of amine-treated clay in the system. –Gilsoniteor asphalt, amine-treated lignite (and polymers are the most common filtration-control additives.

Solids Control –Centrifuges

•As with hydroclones, decanting-type centrifuges increase the forces causing separation of the solids by increasing centrifugal force.
•The decanting centrifuge consists of a conical, horizontal steel bowl rotating at a high speed, with a screw-shaped conveyor inside.
–This conveyor rotates in the same direction as the outer bowl, but at a slightly slower speed.
–The high rotating speed forces the solids to the inside wall of the bowl and the conveyor pushes them to the end for discharge.
•Centrifuges are capable of making a sharp cut point.
–The ideal cut point is the particle size at which all larger particles are separated and all finer particles are retained.
–This is, however, not possible, so the actual stated percent of cutpoint(D number) should be included when comparing centrifuge performance characteristics.

Solids Control –Centrifuges Discharge




Solids Control –Centrifuges -Applications

•Weighted mud
–Dual centrifuges can be rigged up for barite recovery.
–The first centrifuge recovers barite and send it back to the mud system.
–The overflow is sent to the second machine to remove LGS and send clean mud back to the mud system
•Un-Weighted mud
–Centrifuges set up in a parallel configuration, both remove low gravity solids and send cleaned fluid back to the mud system
•De-watering
–Whole mud is treated to form dry solids for disposal and clear water for recycling.
–For this application, the solids content of the mud is brought to a very low level.
–Then, chemicals are added to encourage the particles to coagulate and flocculate.
–Once the fluid is properly treated, it can be processed through a centrifuge, with mostly dry solids and water being recovered
•Reduction of mud costs, without sacrificing control of essential mud properties, is the main purpose of, and justification for, using a decanting centrifuge.
•Although it helps control undesirable fine solids, the centrifuge’s principal function is to minimize dilution and maintain acceptable properties in the mud system

Solids Control –Centrifuges –Internal Parts

Solids Control –Hydrocyclones

Hydrocyclones are cone shaped designed to take out smaller particles–Desanders 74-45 microns–Desilters 35-15 microns–Micro Cones 7-9 microns

•A centrifugal pump feeds a high-volume mud through a tangential opening into the large end of the funnel-shaped hydroclone.
•When the proper amount of head (pressure) is used, this results in a whirling of the fluid much like the motion of a water spout, tornado or cyclone, expelling wet, higher mass solids out the open bottom while returning the liquid through the top of the hydroclone.
•Thus, all hydroclones operate in a similar manner, whether they are used as desanders, desilters or clay ejectors.
•Head is related to pressure as follows: –Head (ft) = Pressure (psi)/[.052 x mud weight (lb/gal)] –Most hydrocyclones designed for about 75 ft of head at the inlet manifold
•Capacity is related to hydroclone size, so more smaller hydroclones are required for a given volume than larger ones.
•An example of hydroclone removal efficiency, showing the cut and D10-D50-D90values for typical 3-, 4-and 6-in. hydroclones, is depicted in the graph opposite.
•Desanders usually are 6-in. hydroclones or larger, with two 12-in. hydroclones being common. •Desilters use 4-to 6-in. hydroclones, with 12 or more 4-in. hydroclones being common.
•Clay ejectors or microclones use 2-in. hydroclones, with 20, 2-in. hydroclones being common. •The hydroclone discharge, or underflow, must be evaluated to ensure that the hydroclone is operating efficiently.
•The discharge should be in the form of a fine spray, with a slight suction felt at its center. •When drilling a large diameter hole at high ROP, the feed may become overloaded with solids and result in a rope-type discharge. –At times, this may have to be tolerated, since shutting the unit down would be worse.

Solids Control –Shale Shakers Screens

•A shale shaker is only as good as the mesh size and quality of its screen.
•A number of screen types are available today and performance varies.
•For example, a 100-mesh “square”screen removes 100% of the particles greater than 140 microns, while a high flow-rate, 100-mesh “layered”screen removes 95% of the particles greater than 208 microns.
–This layered-screen performance is equal roughly to only a 70-mesh “square”screen.
•Screen mesh:
–The number of openings per linear inch.
–For example, a 30 x 30-mesh “square”screen has 30 openings along a 1-in. line in both directions.
–A 70 x 30-mesh “oblong”(rectangular opening) screen will have 70 openings along a 1-in. line one way and 30 openings on a 1-in. line perpendicular.
•Depending on the manufacturer,wiresize and weave, this 70 x 30-mesh screen may be described as:
–An “oblong”or “rectangular”70-mesh screen,
–An “oblong 80”in an attempt to rate the effective rectangular opening in terms of a square equivalent or possibly
–A 100-mesh screen.
•Avoid using mesh designations when comparing screen types.
•In addition to mesh count, various wire sizes and weave patterns are used that affect the opening size and flow-rate for a particular mesh size.
•The 100-mesh square, layered, oblong and bolted screens each removes different particle sizes.


•Shaker screen values for U.S. standard sieve equivalents, square mesh market screen.

Solids Control –Types of Shale Shakers

•The circular-motion shaker,
–Older design
–Produces the lowest G-force
–Fast conveyance of cuttings
–Often used as scalping shakers
–Works well with sticky, clay-type solids
–Has a low capacity for drying cuttings, so wet cuttings are often discharged
•The elliptical-motion shaker,
–Modification of the circular motion type in which the center of gravity is raised above the deck and counter-weights are used to produce an egg-shaped motion that varies in both intensity and throw as solids move down the deck.
–Slow transport
–Dryer cuttings
•The linear-motion shaker
–Uses two circular-motion motors mounted on the same deck.
–The motors are set for opposite rotation to produce a downward G-force and an upward G-force when the rotations are complementary, but no G-force when the rotations are opposed.
–The G-force on most linear-motion shakers is variable from about 3 to 6.
•The linear-motion shaker cont
–Most versatile design
–produces fairly high G-force
–fast transport depending on the rotational speed, deck angle and vibrator position.

Solids Control –Solids Separation–Shale Shakers

Solids Separation

•Settling
–Settling pits are seldom used in modern drilling operations; however, they can be found from time to time.
–The rate of solids settling in settling pits or sand traps depends on
•Size, shape and specific gravity
•density of the drilling fluid
•viscosity of the drilling fluid
•type of fluid-flow regime
•residence time in the pit.
•Settling continued
–On a drilling rig with inferior shale shakers, a sand trap or settling pit will remove some of these large drill solids.
–Most modern shale shakers will remove sand-size and larger solids without the need for sand traps and/or settling pits.
•None of the solids-control equipment used in drilling will remove 100% of the solids generated.
•To compare the efficiency of solids-control equipment, a cut point particle-size rating is used.
–The cut point refers to the combination of a micron size and the percentage of that particle size removed.
•Cut point designations should include the percentage of the stated size removed.
–Cut points should always be denoted with the letter “D”with a subscript indicating the percentage removed.
–Without this percentage, no two cut point sizes can be compared.
–A D50cut point of 40 microns means that 50% of the 40-micron size particles have been removed and 50% have been retained in the mud system.

Shale Shakers

•The most important solids-control devices are shale shakers, which are vibrating screen separators used to remove drill cuttings from the mud •As the first step in the mud-cleaning/solids-removal chain, they represent the first line of defense against solids accumulation. •Shale shakers differ from other solids-removal equipment in that they produce nearly a 100% cut (D100) at the screen opening size. •Many potential problems can be avoided by observing and adjusting the shale shakers to achieve maximum removal efficiency for the handling capacity. •Using screens of the finest mesh to remove as many drill solids as possible on the first circulation from the well is the most efficient method of solids control. –It prevents solids from being re-circulated and degraded in size until they cannot be removed. –As much as 90% of the generated solids can be removed by the shale shakers •Unless the shale shakers are operating properly, and have screens of the finest mesh possible, all other equipment is subject to overloading and inefficient operation

•The mud flow should be spread over as much of the screen surface as possible by using feed-control gates located between the possum belly (flow line-to shaker transitional reservoir and the screen surface.
–The mud should cover 75% of the screens (About 1 foot from the end of the screens)

Solids Control –Particle Size Classification

•It is important to understand how particle sizes in drilling mud are classified and the types of solids that fall into each category.
•Particles in drilling mud can range from very small clays, (less than 1/25,400th of an inch), to very large drill cuttings (larger than an inch).
•Due to the extremely small particles, sizes are expressed in micron units.
•A micron is one-millionth of a meter
–(1/1,000,000 or 1 x 10 -6m).
–1 in. equals 25,400 microns.

Solids Control –Particle Size Classification

•It is important to understand how particle sizes in drilling mud are classified and the types of solids that fall into each category. •Particles in drilling mud can range from very small clays, (less than 1/25,400th of an inch), to very large drill cuttings (larger than an inch). •Due to the extremely small particles, sizes are expressed in micron units. •A micron is one-millionth of a meter –(1/1,000,000 or 1 x 10 -6m). –1 in. equals 25,400 microns.


•In a drilling mud, viscosity increases proportionally with the surface area of solids. –The surface area of all solids must be wetted. –As the amount of liquid is reduced due to increased surface area, fluid viscosity increases and performance declines. –Colloidal solids produce most of the viscosity in drilling muds due to this surface area increase. –The volume of colloidal-size solids contained in drilling mud must be controlled for the sake of economy and efficiency. •The picture shows how the same volume of material takes up substantially more surface area

Solids Control

•The types and quantities of solids present in drilling mud systems determine the fluid’s density, viscosity, gel strengths, filter-cake quality and filtration control, and other chemical and mechanical properties. •Solids and their volumes also influence mud and well costs, including factors such as –Rate of Penetration (ROP), –hydraulics, –dilution rates, –Torque and drag, –surge and swab pressures, –Differential sticking, –lost circulation, –Hole stability, –balling of the bit and the bottom-hole assembly. •Since it is not possible to remove all drill solids either mechanically or by other means they must be considered a continual contaminant of a mud system. •Solids removal is one of the most important aspects of mud system control, since it has a direct bearing on drilling efficiency. •Money spent for solids control and for solving problems related to drill solids represents a significant portion of overall drilling cost

Deep water Drilling –High Rig Costs

•The practices of drilling and completing wells in deep water are high-cost operations.
•Optimization can be achieved through proper, coordinated planning and implementation of all of the related efforts on a deep water project to reduce cost and maximize productivity.
•A low-cost approach to fluids is not always the correct approach for deepwater projects.
–Any drilling fluid system or process that can help reduce the time required to reach the operator’s objectives should be considered, regardless of cost.
–The cost of a high-performance mud system can be offset easily by the savings in rig cost realized by reducing the number of days required to complete the project.

Deepwater Drilling –Large Mud Volumes-Low Flow Line Temperatures

Large Mud Volumes

•Wells drilled in deep water require long risers and large diameter casing strings. –The riser, large-diameter casing and large hole sizes call for large mud system volumes. –A 20-in. ID riser in 2,500 ft of water has a volume of 972 bbl. –It is not uncommon for a deepwater drilling operation to have a circulating system of 4,000 bbl or more. –These large systems require proportionately larger quantities of mud additives for maintenance and treating. •Logistics –Inventory management is critical –Delivery time –Sea conditions –Changing hole conditions •Considerations –Bulk bags (1 ton or more) –Floating liquid storage for brines –Bulk handling systems –Proper estimates

Low Flow Line Temperatures

•As explained earlier, water temperature decreases with depth.
•Long risers surrounded by cold sea water will result in much colder mud temperatures and higher vicositiesin the riser and at the flow line.
•The increased viscosity from temperature, particularly in oilbaseand synthetic muds, may limit the shale shaker screens which can be used without losing mud to relatively large mesh sizes.
•Often, there is a temptation to treat the mud system to reduce the viscosity at the flow line, but this should be avoided, since it will reduce hole cleaning in the riser.
•Circulating a third “boost”mud pump on the riser will limit the amount of cooling that occurs in it.
•A Fann Model 70 HTHP viscometer can be used to provide a more accurate profile of the effects of cold and hot temperatures and pressures on a particular mud.

Deep water Drilling – Low Fracture Gradients

•In deepwater drilling, challenges exist that are related to formation pore pressures and fracture gradients being very close at shallow depths. •For deepwater applications, the fracture gradient and equivalent pore pressure decrease as water depth increases. •At extreme water depths (±10,000 ft), this low fracture gradient (due to the lack of overburden) and low equivalent pore pressure make drilling impractical, even with unweightedmud, due to annular pressure losses increasing the Equivalent Circulating Density (ECD). •The typical deepwater well uses frequent shallow casing strings to seal off low fracture-gradient formations. •The low fracture gradients also present lost circulation problems from both surge and swab pressures. •This is especially true with synthetic, mineral oil and diesel systems, which are compressible and tend to reduce the allowable fracture gradients •Surge, swab and ECD pressures are a significant concern for all deepwater drilling operations, particularly while running and cementing casing. •Understanding the effects of temperature and pressure on hydraulics and drilling fluid rheology is very important in deepwater •Low water temperatures and the resulting low riser temperatures can result in elevated fluid rheology and high surge and swab pressures.

Deep water Drilling –Borehole Stability

•The geology of deepwater drilling is different from that on land and in shallow water.
–The formations, for example, are relatively young and very reactive.
–The clays and silts have not been altered by extreme heat or pressure and are not significantly dewatered.
•Sands are often unconsolidated and have not been compacted.
•Shallow clay formations, referred to as gumbo, are very soft and sticky.
•Cuttings from these formations can cause hole packoff, plugged flow lines, balling of bit and bottom-hole assembly, and reduced Rate of Penetrations (ROPs).
•Young clays contain high volumes of water and can be extremely sticky and problematic regardless of the degree of inhibition.
•Swelling and dispersion of the reactive shale must be addressed when drilling in deep water.
–Synthetic, diesel, mineral, PHPA, enhanced chloride and lignosulfonatesystems all have been used in deepwater applications.
–Synthetic and oil-base muds provide excellent inhibition, virtually eliminate problems with gumbo
•Water-base systems will require additives to increase performance and to minimize trouble with soft, sticky gumbo and for hydrate inhibition.
–Amines
–Glycols
–PHPA
–Silicate
–KCL

Deep water Drilling –Mud Systems-Gas Hydrates-

Mud Systems

•Many different mud systems can and have been used in deep water applications. –They range from systems as simple as seawater-base lignosulfonatemuds to environmentally approved high-performance synthetic muds.

Gas Hydrates

•Gas hydrates are an “ice-like”mixture of gas and water. At atmospheric pressure, freshwater freezes at 32°F (0°C).
–At high pressures, gas hydrates will form at moderate temperatures —even as high as room temperature.
–Gas hydrates occur naturally in arctic permafrost and deepwater seabed deposits, usually at depths greater than 800 ft.
•One cubic foot of gas hydrates can contain 170 ft3 of natural gas.
–Naturally occurring gas hydrates can pose a well-control problem when drilled, but gas hydrate formation in the drilling fluid is a more significant well-control problem in deep water situations.
•Gas hydrates can form in low-salinity drilling muds under pressure/temperature conditions as mild as 480 psi and 45°F (7.2°C), conditions which are common when controlling kicks in deep water.
•During well-control situations, hydrates can plug risers, BOP lines and choke-and-kill lines, interfering with effective well control.
•Reported cases of gas hydrates are few, the risk of losing the ability to operate BOP equipment adequately is always present.
–For this reason, all deepwater mud systems must be formulated to suppress the formation of gas hydrates.
•Increasing the salinity of water-base muds is the common method used to suppress hydrates.
–The standard deepwater water-base mud system uses 20% by weight salt to inhibit gas hydrates.
–Increasing the salinity of a water-base mud system will reduce the temperature at which gas hydrates can form at a given pressure.
–The amount of salt required depends on both hydrostatic and shut-in pressures and the seafloor temperature
–At higher pressures and colder temperatures, a combination of salt and either glycerol or water-soluble glycol is recommended for greater inhibition.
•Diesel oil, mineral oil and synthetic systems all provide excellent hydrate suppression.
–This inhibition is a result of the limited amount of water contained in them and the fact that the water phase generally has a high concentration (>25% wt) of calcium chloride.
–Dissolved gasses can reduce suppresion

Deep water Drilling

•Deep water exploration and production have significant potential in many offshore locations around the world. •Deep water drilling, in general, has a greater degree of difficulty than conventional drilling and presents many operational challenges. •Deep water Drilling –Greater than 1500ft of water –use of either dynamically positioned or chain-anchored floating rigs of either the semi submersible or drill ship design, using sub sea well heads and long riser systems –The wells are drilled in younger formations that have narrower fracture-radientto-pore-pressure profiles, requiring more casing strings and exhibiting high operating costs. •A list of fluid design issues and considerations includes: –Gas hydrates. –Geology/reactive formations. –Pore pressure and low fracture gradients. –Riser volumes/large-casing well designs/logistics. –Lost circulation. –Low flow line temperatures. –Hole cleaning. –Well control. –High daily rig costs.