Mud Related Drilling Problems Foaming

•A small amount of foaming occurs in most drilling muds.
•Foaming occurs due to high interfacial surface tension phenomena or mechanical air entrapment.
•Most foaming occurs on the surface and normally does not adversely affect the mud.
•If the foam or air bubbles become dispersed throughout the mud, the pump may stroke in an erratic manner, which could cause serious mechanical damages
•Air leak in mud pump
•The discharges of the desilter/desanderor mud hopper can whip air into the mud.
•High chloride content in mud.
–Salt water muds have an inherent tendency to foam.
•Lignosulfonateshave a tendency to foam, especially in high concentrations.
Causes •Over treatment of mud detergents. •Air entrapped in drill pipe after tripping. •High pressure-low volume formations or swabbing when tripping may cause the mud to become gas cut. •Thick mud containing a large amount of drilled solids are particularly susceptible to foaming. •Bacteria fermentation of the mud.
Treatment
•The mud has to be thinned in order to permit effective removal and prevent a build-up of foam.
–Lower the viscosity, YP and in particular the Gel Strengths with dispersants (Desco) or Lignite as required to allow the foam to dissipate.
•Alcohol base defoamersor Aluminum Sterate(oil soluble only; mix with diesel oil) may be added directly into the suction tank.
•Avoid air leaks in pumps and suctions.
Prevent whipping air into mud.
–Submerge all surface guns, hopper and solids control equipment discharges.
•"Roll" the tanks with the submerged guns to allow the air or gas bubbles to escape into the atmosphere.
•If a wash gun is available, spray the surface of the mud with a fine spray of diesel or water.

Mud Related Drilling Problems Formation Damage-Corrosion

•Formation Damage:

–Damage to the productivity of a well resulting from invasion into the formation by mud particles or mud filtrates. –Asphalt from crude oil will also damage some formations. •Common mechanisms for formation damage are: –Mud or drill solids invading the formation matrix, plugging pores. –Swelling of formation clays within the reservoir, reducing permeability. –Precipitation of solids as a result of mud filtrate and formation fluids being incompatible. –Precipitation of solids from the mud filtrate with other fluids, such as brines or acids, during completion or stimulation procedures. –Mud filtrate and formation fluids forming an emulsion, restricting permeability. •Prevention –Formation damage can be minimized by using a Drill In fluid •Drill In Fluids should contain non-damaging polymers, bridging agent •Should have superior regain permeability •May have shale or clay inhibitors •Should be easy to clean up

Corrosion

•Corrosion is the destruction of metal through electrochemical action between metal and its environment. •Corrosion can be costly in terms of damage to pipe and well parts and can even result in the loss of an entire well. •About 75 to 85 percent of drillpipe loss can be attributed to corrosion. •Other areas affected by corrosion include pump parts, bits, and casing. •Factors affecting corrosion include: –Temperature. Generally, corrosion rates double with every 55°F (31°C) increase in temperature. –Velocity. The higher the mud velocity, the higher the rate of corrosion due to film erosion (oxide, oil, amine, etc.). –Solids. Abrasive solids remove protective films and cause increased corrosive attack. –Metallurgical factors. Mill scale and heat treatment of pipe can cause localized corrosion. –Corrosive agents. Corrosive agents such as oxygen, carbon dioxide, and hydrogen sulfide can increase corrosion and lead to pipe failure. •Types of Corrosion –Uniform corrosion •Even corrosion pattern over surfaces –Localized corrosion •like corrosion pattern over surfaces –Pitting •Highly localized corrosion that results in the deep penetration of surfaces •Corrosive agents found in drilling fluids include: –Oxygen –Hydrogen sulfide –Carbon dioxide –Bacteria –Dissolved salts –Mineral scale

Corrosion -Oxygen

•Oxygen causes a major portion of corrosion damage to drilling equipment. •Oxygen acts by removing protective films; this action causes accelerated corrosion and increased pitting under deposits. •The four primary sources of oxygen are: –Water additions –Actions of mixing and solids-control equipment –Aerated drilling fluids –The atmosphere •If oxygen corrosion is suspected treatment would include adding an oxygen scavengers –Many types of oxygen scavengers exist –Manufactures recommended treatment should be followed in this case

Corrosion -Hydrogen sulfide

•Hydrogen sulfide can enter the mud system from: –Formation fluids containing hydrogen sulfide –Bacterial action on sulfur-containing compounds in drilling mud –Thermal degradation of sulfur-containing drilling fluid additives –Chemical reactions with tool-joint thread lubricants containing sulfur •Hydrogen sulfide is soluble in water. •Dissolved hydrogen sulfide behaves as a weak acid and causes pitting. •Hydrogen ions at the cathodicareas may enter the steel instead of evolving from the surface as a gas. •This process can result in hydrogen blistering in low-strength steels or hydrogen embrittlement in high-strength steels. •Both the hydrogen and sulfide components of hydrogen sulfide can contribute to drillstring failures. •Hydrogen sulfide corrosion is mitigated by increasing the pH to above 9.5 and by using sulfide scavengers and film-forming inhibitors. –Sulfide scavengers include Zinc Carbonate, Zinc Oxide and other specialty chemical products –Most film forming inhibitors are amine inhibitors, many are available

Corrosion –Carbon Dioxide

•Carbon dioxide is found in natural gas in varying quantities. •When combined with water, carbon dioxide forms carbonic acid and decreases the water's pH, which increases the water's corrosivity. •While carbon dioxide is not as corrosive as oxygen, it can cause pitting. •Maintaining the correct pH is the primary treatment for carbon dioxide contamination. •Either lime or caustic soda can be used to maintain pH.

Corrosion –Bacteria

•Microorganisms can cause fermentation of organic mud additives, changing viscosity and lowering pH. •A sour odor and gas are other indicators that bacteria are present. •Degradation of mud additives can result in increased maintenance cost •Microbiocidesare used to control bacteria in drilling environments

Corrosion –Dissolved Salts

•Dissolved salts increase corrosion by decreasing the electrical resistance of drilling fluids and increasing the solubility of corrosion by-products. •Some of these byproducts can cause a scale or film to form on the surface of the metal. •Amine filming agents added to the metal will aid in reducing corrosion due to dissolved salts •Mineral scale deposits set up conditions for local corrosion-cell activity. •The continuous addition of a scale inhibitor can control the formation of scale deposits.

Mud Related Drilling ProblemsLost Circulation

Lost circulation or loss of returns describes the complete or partial loss of fluid to the formation as a result of excessive hydrostatic and annular pressure drop. •Lost circulation is characterized by a reduction in the rate of mud returns from the well compared to the rate at which it is pumped downhole (flow out <> •If the annulus of the well will not remain full even when circulation of the fluid has ceased, the hydrostatic pressure will reduce until the differential pressure between the mud column and the loss zone is zero. –This may induce formation fluids from other zones, previously controlled by the mud hydrostatic pressure, to flow into the wellbore resulting in a kick, blowout, or underground blowout. –It may also cause previously stable formations to collapse into the wellbore. •Permeable or fractured formations can result in partial or complete loss of circulation. •Formation fractures can be natural or caused by excessive drilling fluid pressure on a structurally weak formation. •Once a fracture has been induced, the fracture will widen and take more mud at a lower pressure. •To avoid inducing formation fractures: –Maintain the minimum equivalent-circulating density (ECD) and mud weight. –Avoid pressure surges.

Lost Circulation –Fractured

•Permeable or fractured formations can result in partial or complete loss of circulation. •Formation fractures can be natural or caused by excessive drilling fluid pressure on a structurally weak formation. •Once a fracture has been induced, the fracture will widen and take more mud at a lower pressure. •To avoid inducing formation fractures: –Maintain the minimum equivalent-circulating density (ECD) and mud weight. –Avoid pressure surges. •Indication: –Lost circulation of this type is indicated by a complete or partial loss of returns and a decrease in pit volume. •Treatment –If a induced fracture is suspected, the hole can be allowed to heal by pulling into the casing and waiting 6 to 12 hours. –After the waiting period, stage back to bottom and check for full returns. –If full returns have not been established, treat the losses as if they were cavernous/vugularlosses.

Lost Circulation –Permeable

•Permeable and porous formations include: –Loose, noncompactedgravel beds –Shell beds –Reef deposits –Depleted reservoirs •These types of formations cause seepage loss to complete loss of returns. •Indication –Seepage into permeable formations is indicated by partial to full loss of returns and a decrease in pit volume. •Treatment –Reduce mud weight as much as possible. –Treat the system with a combination of fine-to medium-grade lost-circulation products

Lost Circulation –Corrective Measures

•Conventional Lost Circulation pill –Consider using a combination of LCM material with varying sizes to provide for an optimum bridging agent with this type of pill. –Small amounts of Lime may be used to slightly flocculate the Bentonite, to increase the viscosity preventing the LCM material from settling out and plugging the bit. –It is cheaper to obtain the viscosity using small amounts of Lime. –The Lime addition will also provide a higher fluid loss than the Gel slurry thereby increasing the sealing rate. •The actual concentration of LCM in the pill may vary; the formulation listed below assumes no jet or very large nozzles in the bit. •Once the approximate point of loss is established, a 15 -30 m3(100-300 bbl) pill should be mixed •Fresh Water15-50 m3(94 –310 bbl) •Soda Ash0.50-0.75 kg/m3(0.15-0.25ppb) •Caustic Soda0.50-0.75 kg/m3(0.15-0.25ppb) •Bentonite70-75 kg/m3(25-26 ppb) •Sawdust15 kg/m3(5 ppb) •FibreSeal15 kg/m3(5 ppb) •WalnutShells/Mica 15 kg/m3(5 ppb) •Lime1.0-1.5 kg/m3(0.35 –0.5 ppb) •Once the pill has been mixed, spot just above the loss zone by pumping slowly; 160-320 litres/min. (1-2 bbl./min.) until the hole is full and circulation is regained. •If the hole remains full, close the hydriland squeeze the annulus with 300-500 kPa(50-75 psi) for 30 minutes. •If this procedure fails, repeat once. •A second failure may indicate that another technique may be in order. Effective control of lost circulation into a permeable zone may require a broad range of particles •Gunk Squeeze –When you are faced with a lost circulation problem and you are using an oil/synthetic mud, mix the gunk squeeze with water and Organofilic Clay instead of oil/synthetic and bentonite. •To mix a gunk squeeze, follow these steps: –Drain and clean the mixing tank thoroughly. •Prepare a gunk slurry –Pump the following in this order: •Spacer to cover approx. 500' of drillstring •Squeeze to cover approx. 2 times open hole volume •Spacer to cover approx. 500' of drillstring –The spacer fluid should have the same base fluid as the squeeze. –Displace the squeeze to the bit. –Close blowout preventers (BOPs). –Pump down the drillpipe and annulus in equal volumes until the squeeze and spacer are displaced from the drillpipe. –Maintain equal pressure on drillpipe and casing.

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.