Slip
Manual slips secure the drill string within the rotary table during drilling operations. Slips are constructed with three or more hinged steel wedges, which form a nearly circular shape when placed around the drill pipe. Replaceable inserts are embedded into the inner side of the steel wedges. The outer surface of the slips is tapered to match the inner taper of the insert bowl of the rotary table. As the drill pipe is lowered into the slips, the inserts grip the pipe, causing the slips to descend and securely lock everything together. Resting the drill string securely in slips allows disconnecting of the upper part of the drill string while the lower portion remains suspended. After attaching another component to the lower portion, lifting the string releases the slip for lowering the drill string for further operations.
Kill Rate Pressure
‘Kill rate pressure’ (KRP) is the pressure required to overcome the friction in the circulating system at a given pup rate. Since the fluid properties and other well parameters can affect kill rate pressures, it is important that kill rates and kill rate pressures are taken regularly.
Kill Rate
The fluid circulation rate used while killing a well is called ‘Kill-rate'. Kill rate, also known as 'Slow Pump Rate' (SPR) or 'Slow Circulating Rate' (SCR) is a predetermined fluid circulating rate, expressed in fluid volume per unit time, planned to be used to circulate under kick conditions. The kill rate is usually some selected fraction of the normal circulating rate used while drilling.
Kill-Weight Fluid
Kill weight fluid, also called kill weight mud, is a drilling fluid with a density that generates sufficient hydrostatic pressure at the influx point within a wellbore. This fluid is a critical component of well control operations, for equalizing formation pressure and effectively stopping the flow of formation fluid into the wellbore.
The sequence of pumping the kill-weight mud into the well varies depending on the killing method employed. Kill weight is calculated based on stabilized shut-in drill pipe pressure (SIDP) recorded after encountering a kick.
Secondary Well Control
When primary well control measures cannot maintain control of the well during either drilling, completion, or production operations, the process used for bringing the well under control is called secondary well control. Secondary well control comprises specific procedures and equipment. Blow-out prevention (BOP) equipment and particular methods such as the driller method, wait and weight, lubricate and bleed, and bull heading are used as part of the secondary well control process to regain control of the well.
Primary Well Control
The conventional way of drilling is to maintain an overbalance where the pressure (force per unit area) in the wellbore while drilling is maintained above the formation pressure. The difference between the hydrostatic pressure of drilling fluid in the well and the fluid pressure in the formation is called 'Overbalance'. This hydrostatic pressure prevents reservoir fluid from flowing into the wellbore during drilling operations and is called the 'Primary Well Control' mechanism. A kick, also known as a wellbore influx, can occur when primary well control fails.
Fracture Closure Stress
Fracture Closure Stress (FCS) is based on the concept that the wellbore is held together due to the built-in stresses within the wellbore. The overburden pressure and pore pressure laterally translate into creating these stresses. FCS describes the mechanism of how the fracture in a wellbore initiates and propagates. Whenever the pressure inside the wellbore exceeds the stress holding the wellbore closed which is the ‘Fracture Closure Stress’, the fracture will initiate and propagate.
Ballooning
Ballooning, or 'Well Breathing' is a term given to the loss/gain situation. Ballooning occurs when the 'Fracture Closure Stress' is greater than the mud weight but less than the Equivalent Circulation Density (ECD). In this situation, the well stands full in the static condition. However, fracture extends and takes mud when circulation is established since ECD exceeds the fracture closure stress. When the pumps are stopped and ECD removed, the fracture closes, forcing some or all the mud back into the wellbore.
Pore Throats
Pore throats are openings between grains of formation rocks through which the formation fluid or fine particles may travel.
Blocking Material
Blocking materials are solids in the mud system that block the pore throat openings of permeable rock. Blocking material stops the flow of mud solids into the formation. However, the filtrate loss continues through the reduced gaps. Drilled solids, barite, and Calcium Carbonate are common blocking materials in the mud system.
Lost Circulation Material (LCM)
The seepage loss or vugular loss of drilling fluid occurs due to high permeability formation, cavernous zones, or coarse beds of gravel. These losses seize once the solid particles in the mud system block the pore throats. In shallow unconsolidated sands or gravel beds, increasing the viscosity of mud also helps to stop or restrict the losses. If the loss rate is not controlled through these means, coarse, fibrous material is used, which is called 'Lost Circulation Materials' or LCM. Lost circulation treatment is most effective when LCM is mixed in batches of approximately 100 bbls. These LCM pills with a high concentration of coarse material are pumped into the well and placed opposite to the thief zones to stop or reduce the rate of drilling fluid loss.
Vugular Loss
If the pore throats of rock are very big, severe levels of losses are encountered where even complete circulation can be lost. If the pore throats are larger than 1/16” in diameter, the rock is termed a vugular rock. These vugular pore throats cannot be easily plugged and losses are harder to control. Since vugular losses are in significant volume, they are measured in ‘Barrels Per Minute (BPM)’ rather than ‘Barrels Per Hour (BPH)’. Vugular-sized pore throats are commonly found in carbonate, gravel, or any uncompacted formation.
Filtrate Loss
Drilling fluid consists of solids in a liquid phase. Filtrate loss is the loss of the liquid phase into the rock. Operationally, the industry does not differentiate between seepage and filtrate losses, and both are collectively referred to as seepage loss. Filtration control materials are added to the mud system, but filtrate loss cannot be stopped unless effective blockage of the pore throat is achieved.
Seepage Loss
It is a slow and steady loss of volume of drilling fluid. In general, it is termed seepage loss if the loss rate is less than 30 barrels per hour BPH. Seepage losses are caused in highly permeable rocks. Seepage losses can be stopped by blocking the pore throats of the rock with solids or adding ‘Lost Circulation Material (LCM)’ to the mud system. The flow of mud into the pore throat of the rock is stopped when they are sufficiently blocked by the solid particles in the mud.
Dull Bit Grading
Dull bit grading is the method of evaluating the condition of a drill bit used for drilling after it is pulled out of the hole. The method uses a system developed by the International Association of Drilling Contractors (IADC). The pulled-out bit is inspected to identify wear and damage to the cutting structure and other parts of the bit. A precise dull bit grading can help to identify the effects of operating parameters and drilling dysfunctions in drilling a particular formation type. It provides vital clues to improve bit design and optimize bit selection for different drilling scenarios
Stabilizer Blade Taper Angle
The gauge diameter of a stabilizer blade is more than the mandrel or the main body of the stabilizer. A taper is provided from the main stabilizer body to the blade pad. The taper angle is defined as the angle of the taper to the main body of the stabilizer. Having a taper provides a smooth transition from the body of a stabilizer to the blade of the stabilizer. Having a smooth transition is an important design consideration of a drilling stabilizer. An abrupt transition would result in a shoulder that will make the stabilizer hang up while tripping or drilling.
Wrap Angle
The wrap angle is an attribute of a spiral blade stabilizer. It is measured in degrees and is defined as the total contact that all the stabilizer blades make with the borehole wall. Based on the stabilizer design and drilling operations requirements, the wrap angle can vary from 180 to 600 degrees. Wrap angle does not apply to straight-blade stabilizers.
Spiral Blade Stabilizer
Spiral blade stabilizers have their blades at an angle rather than being coaxial with the body of the stabilizer. Spiral blades provide more stability to the drill string, which results in efficient drilling by reducing vibrations and allowing efficient transfer of weight to the bit. The configuration of the spiral blade stabilizers varies based on the number of blades, pad diameter, wrap angle, and blade taper angle.
Straight-Blade Stabilizer
Straight-blade stabilizers have straight vertical blades in the coaxial direction of the main stabilizer body or mandrel. The blades can either be integral to the stabilizer or on a replaceable sleeve. Straight blade stabilizers have less surface contact and wrap angle. They however provide fluid concentration with less probability of getting balled up while drilling sticky shale formations. Straight-blade stabilizers are mostly used in motor housing for sliding operations.
Adjustable gauge stabilizers (AGS)
Adjustable gauge stabilizers (AGS), also known as ‘Variable Gauge Stabilizers (VGS)’ are designed to change the gauge or pad diameter of the stabilizer after tripping the string in the hole. These stabilizers can have two or three different gauge settings. Stabilizers are run in the hole in the closed position and pads can be opened to alter the stabilizer gauge hydraulically through pump pressure. Adjustable gauge stabilizers can be used with the motor as well as rotary drilling assemblies and provide greater inclination control.