Protect Formation Productivity

•Protecting the formations productivity is a big concern. After all the well was drilled to produce hydrocarbons, not as a science project.
•Formation damage can happen as a result of solids plugging up the porosity or permeability or through chemical or mechanical interactions with the formation •The type of the completion will determine the level of protect required –For example an open hole completion will require much more protection than a cement and perforation completion
•Consideration should be given to the type of fluid chosen to protect the formation
•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.
•Offset well information can help to predict formation damage
•Return permeability tests run with different fluids on cores will help to determine the best non-damaging fluids

Facilitate the Retrieval of Information from the Wellbore

•Accurate information retrieval is essential to the success of the drilling operation, particularly during exploration drilling
•The chemical and physical properties of the mud affect evaluation –During drilling mud loggers retrieve samples for evaluation
–After drill electric logs must be run in the hole to further evaluate the wells economics
–Logging may be performed while drilling using LWD (Logging While Drilling) tools
–Drill stem test may need to be completed
–Core may have to be cut
•All these techniques and tools may be affected by the mud properties both chemical and physical
–If the cuttings are dispersed mud loggers will have difficulty evaluating cuttings
–Additives (such as lubricants and asphalts) may mask oil shows –Certain electric logs require conductivity through the drilling fluid –Washouts will affect DST packer seats –Poor hole cleaning will make coring difficult

Suspend Cuttings When Circulation is Interrupted

•Drilling muds must suspend drill cuttings, weight materials and additives under a wide range of conditions, yet allow the cuttings to be removed by the solids-control equipment.

•Drill cuttings that settle during static conditions can cause bridges and fill, which in turn can cause stuck pipe or lost circulation.

•Weight material which settles is referred to as sag and causes a wide variation in the density of the well fluid.
•Sag occurs most often under dynamic conditions in high-angle wells, where the fluid is being circulated at low annular velocities
•High viscosity shear thinning fluids (thixotropic) and required to suspend cuttings during connections and other interruptions in circulation.
•Thixotropic fluids have properties that thin when stress is applied (such as circulation of the fluid) and thicken up or gel when static
•Most drilling fluids are thixotropic, polymers added to the fluid increase the low end rheology of the fluid and help to suspend cuttings and barite

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Provide Borehole Stability

•Borehole instability is most often identified by a sloughing formation, which causes tight hole conditions, bridges and fill on trips.

•This means the well must be reamed and cleaned and in extreme cases re-drilled •Borehole stability is greatest when the hole maintains its original size and cylindrical shape. •Once the hole is eroded or enlarged in any way, it becomes weaker and more difficult to stabilize •Hole enlargement leads many problems–low annular velocity–poor hole cleaning–increased solids loading–fill–increased treating costs–poor formation evaluation–higher cementing costs and inadequate cement bonding •Hole enlargement through sand and sandstone formations –mechanical actions: –erosion most often being caused by hydraulic forces and excessive bit nozzle velocities –Need to reduce impact force and nozzle velocity –Weaker sands require a slight overbalenceand good quality filter cake containing bentonite •Hole enlargement through shale –Water based muds can penetrate shale making it swell and soften over time and slough in –Higher mud weights and chemical/polymer inhibitors can reduce or eliminate slough •Highly fractured shales are very unstable –Usually require mechanical methods to clean, they require higher mud weights to control or oil based muds •Extremely water sensitive shales require an oil based or synthetic based fluid to drill successfully –These fluids provide better shale inhibition than water based fluids –Clays and shales do not hydrate or swell in the presence of oil –Osmotic forces created by the emulsified brine phase prevent adsorption of water by the shales

Cool and Lubricate the Bit and Drillstring

Considerable friction and heat by rotational and hydraulic forces of the bit and drillstring
•Circulation of the fluid cools the drillstring and bit distributing it throughout the wellbore.
•The drilling fluid also helps to cool down the bottom hole temperature.
•Drilling fluid also lubrictesthe BHA further reducing frictional heat.
When required lubricaingadditives are put into the fluid to further mitigate the problem •Without the cooling and lubricating action of the drilling fluid many sensitvemotors and components could not function or would fail under the heat. •Indications of poor lubrication are increased torque and drag, abnormal wear and heat checking of the drillstring compenents

Altering the lubricity of the drilling fluid is far from an exact science
•Many different drilling fluids exist from oil-based to silicate water based. •Different methods and additives are available to reduce torque and drag from actual lubricating oils to graphite material to lubricating polymeric beads

Controlling Formation Pressures

•Controlling the pressure of the formations drilled is a very important function of the drilling fluid

•As the formation pressure increases, the density of the drilling fluid is increased to balance or slightly overbalance the well and keep it in control
•Pressure exerted by the drilling fluid while static is called hydrostatic pressure •Drilling fluids are typically weighted up with heavy material such as barite, calcium carbonate, hematite and in extreme situations galena
•The well is considered under control when no formation fluids or gasses are allowed into the well bore
–In some situations small amounts of background gas are allowed into the well bore the well bore may be considered in control if the flow is controllable •Hydrostatic pressure is also used to control unstable wellbores
–Formations may be tectonically stressed especially in deviated wells
–Drilling fluid density can be increased to balance the tectonic stress and help provide a stable wellbore
•Density of drilling fluid ranges from air (0 psi/ft) to 20 lb/gal (2400 kg/m3)

Release Cuttings at the Surface

•High concentrations of drill solids are detrimental to almost every aspect of the drilling operation, primarily drilling efficiency and ROP •Drill cuttings increase the mud weight and viscosity, which in turn increases maintenance costs and the need for dilution.

•Drill cuttings also increase the horsepower required to circulate, the thickness of the filter cake, the torque and drag, and the likelihood of differential sticking. •Drilling fluid properties that suspend cuttings must be balanced with those properties that aid in cuttings removal by solids-control equipment.
•Cuttings suspension requires high-viscosity, shear thinning thixotropic properties, while solids-removal equipment usually works more efficiently with fluids of lower viscosity
•Solids-control equipment is not as effective on non-shear-thinning drilling fluids, which have high solids content and a high plastic viscosity.
•For effective solids control, drill solids must be removed from the drilling fluid on the first circulation from the well.
•If cuttings are re-circulated, they break down into smaller particles that are more difficult to remove.
•One easy way to determine whether drill solids are being removed is to compare the sand content of the mud at the flow line and at the suction pit.

Transport Cuttings

Transport cuttings•The well is drilled and cuttings are produced the must be removed from the well
•The drilling fluid is circulated down through the pipe and bit nozzles entraining the cuttings and carrying them up the annulus to surface

•Cuttings removal is a function of cuttings size, shape and density; rotation of the drillstring; and mud properties such as viscosity, density and annular velocity
•Viscosity describes the rheological properties of the drilling fluid
–Cuttings settle faster in low viscosity fluids
–Higher viscosity fluids improve cuttings transport
–Most drilling fluids are thixotropic meaning that they gel under static conditions

•Velocity refers to the annular velocity of the fluid–Generally the higher the annular velocity the better cuttings removal
–If velocity is too high then turbulent flow may occur resulting in less efficient cuttings removal and possible wellbore erosion
–The net velocity is the difference in the slip velocity of the cuttings and the annular velocity
•Transport velocity=Annular velocity -slip velocity

Cuttings transport in high angle wells is more challenging than vertical ones
–Cuttings tend to accumulate at the low side of the hole creating cuttings beds
–The use of thixotropic fluids with high Low-Shear-Rate Viscosity run in Laminar flow can help clean out these cuttings beds
–High flow rate and thin fluid to try and achieve a turbulent flow can keep these wells clean
–Generally a mixture of high LSRV fluids and thin turbulent fluids are required to keep the hole clean

•High density fluid sweeps aid in hole cleaning
–The higher density fluid tends to get into the smaller cuttings beds and push them into the higher section of the hole to be cleaned off
•Pipe rotation
–This helps stir up the cuttings and lets the fluids take them away