Drilling
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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.
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Adjustable Kick Off (AKO) sub or Bent Sub is a small segment of drill string which is tilted at an angle rather than being straight. It is run above the bit and below the power section in the drill string and is used for drilling directional well or for kicking off from a vertical well. Running AKO sub in the string makes it possible to steer the well as needed through sliding. Tilt of the sub depends on tool size, hole size and DLS (Dog Leg Severity) requirement.
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Annular Velocity (AV) is the velocity of drilling fluid in the annulus. It is an important element for achieving effective hole cleaning. Flow rate and annular cross-sectional area are used for calculating average annular velocity. The average annular velocity is a theoretical calculation considering a gauge hole. If there are some over-gauge areas in the well due to hole instability or caving, the risk of cuttings getting lodged in those enlarged sections should be carefully evaluated.
Cutting accumulation is severe in high-angle wells as the cuttings tend to accumulate on the low side of the well. The combined effect of mud rheology, annular velocity, and pipe rotation helps clean the hole by removing drilled and suspended solids from the well.
In general, a minimum average annular velocity of 150 ft/min is recommended for achieving effective cutting cleaning in a high-angle well. However, higher annular velocity also increases Equivalent Circulation Density (ECD). ECD higher than a certain value could cause losses. Hence annular velocity is optimized based on well configuration, well profile, and limits of open formations.
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Annulus is the space between two tubular. In drilling, unless specified, it is considered as the space between drilling string and open hole or casing. Common abbreviations used in drilling industry are TCA (Tubing Casing Annulus) and CCA (Casing to Casing Annulus).
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Anti-Collision is a term used for analysis or report that evaluates the collision risk between two or more wells. In an area where many directional and vertical wells have been drilled, there is always a risk of drilling and penetrating into an existing well bore. Carrying out an anti-collision analysis is an essential part of directional well planning in a development drilling.
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Azimuth defines the direction of the well. It is measured in a horizontal plane and is expressed as angle from a reference plane, usually 'True North'. Horizontal plane is divided into four quadrants of 90o each with reference plane as zero. If the azimuth at a survey point is 225o, it means that the well at that point is in the 3rd quadrant and is heading in South West direction in reference to 'True North'.
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Background gas expresses the average gas reading that is observed while drilling. It is also sometimes call "Drill Gas". It is an indication that formation being drilled contains gas but doesn't necessarily an indication of higher formation pressure. The gas enters the wellbore only when new formation is drilled. It will seep in from already drilled part of the well only if the formation has enough permeability and pressure differential. Background gas doesn't indicate an underbalance condition but may lead to it if total volume of gas in the system lightens the hydrostatic column enough.
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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.
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Bent Sub or AKO(Adjustable Kick Off) sub is a small segment of drill string which is tilted at an angle rather than being straight. It is run above the bit and below the power section. Running a bent sub in the string makes it possible to steer the well as needed through sliding. Tilt of the sub depends on tool size, hole size and DLS requirement.
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Most drill bits have a pin connection on top whereas drill collars have a pin connection at bottom. Bit sub is a BOX x BOX sub with connections matching with pin connections on bit and drill collar. It is installed right above bit if near bit stabilizer is not planned to be run above bit. Bit subs are also bored out to take a float valve.
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Bottom Hole Assembly, commonly known as BHA refers to a set of tools between the drill bit and drill pipe. One of the main objectives of BHA is to have enough weight to transfer to the bit for enhancing the bit's ability to cut hard rocks. A conventional BHA for drilling vertical wells is designed as a tapered string with a larger diameter and heavier drill collars above the bit. A well-designed BHA produces a smooth hole, minimizes vibration, maintains the intended profile of the well and improves bit performance.
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A casing is a steel pipe that is run in the well after drilling the hole to a certain depth. The casing is run to prevent the collapse of the drilling hole. In most cases, the casing is cemented to provide effective isolation to avoid communication between the zones behind the casing and the new formations to be drilled below the casing pipe in the next hole section. Various different sizes of casing pipes are used in the industry. The grades and connections also vary depending on the application, design loads, and availability.
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Connection Gas is the term used for gas observed on bottoms up after making a pipe connection. It indicates amount of gas that enters the well bore during connection. Pipe connection causes loss annular pressure losses effect as the pumps are turned off. The bottom hole pressure in this static condition is equivalent to only the hydrostatic pressure of mud column. Gas feeds into the well due to loss of hydrostatic pressure caused by loss of annular friction pressure. Connection gas is an indication that formation pressure is more than hydrostatic pressure of column of mud in hole in static condition. Increasing trend of connection gas would indicate the need of increasing mud weight to balance the formation pressure.
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Corrosion Caps are also known as Temporary Abandonment Caps or TA Caps. They are used for suspending an offshore well at the seabed. Once an offshore well is drilled and needs to be temporarily suspended for moving the rig off location, leaving the casing or wellhead open at the seabed could allow botanical growth or corrosion of exposed threads. This could make it difficult to reconnect to the well for any future operations. Hence a Corrosion Cap is installed to protect the threads and seal areas.
Corrosion caps are installed and retrieved with a running tool. Corrosion caps can also offer pressure containment if a check valve is installed in the stem of the cap. Normally after disconnecting casing strings at MLS, the corrosion cap is installed for the topmost threads. However, caps can be installed for each casing string for isolating the string and its annular space if required.
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As the drilling bit is rotated and the weight is applied, it grinds the rock into small pieces called cuttings. Mud pumped through the drill string brings the cuttings to surface where they are removed from drilling mud using solid control equipment.
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Directional Drilling is the process of drilling a deviated well to reach Bottom Hole Location (BHL) that is different from Surface location. Directional drilling is carried out for several reasons. It could be either for accessing specific BHL where the surface location is obstructed or inaccessible or for reaching several BHLs from one surface location or for enhancing reservoir production from a well. Directional Drilling is a specialized service. It needs many special tools and skills for designing & achieving the intended direction of a well.
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Directional Surveys are carried out in a well to measure angle and direction of a well at a certain depth. Surveys are essential part of directional drilling to establish actual well path and compare it with the planned trajectory.
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Dog Leg Severity commonly referred to as DLS is a measure of change in direction of a wellbore. It is described in degrees per 100 feet or per 30 meters. The difference between the directional measurements between two survey points is used for computing the DLS value. In simple terms, the difference in inclination of two survey points is used, but in reality, the directional measurements include inclination (inc) and azimuth (Az) of the well.
The actual computation of DLS is based on the 'Radius of Curvature' method. The formula used for computing DLS is: Dogleg severity (DLS) = {cos-1 [(cos Inc1 x cos Inc2) + (sin Inc1 x sin Inc2) x cos (Az2 – Az1)]} x (100 ÷ MD).
Higher DLS values result in higher torque and drag in drilling & tripping operations. It also risks creating key seats, which increase string wear and the possibility of fatigue failure. Severe key seating can also cause sting stuck-ups.
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A drill bit is a rock-cutting tool used for drilling a hole in the ground. A drill bit could either have fixed cutting blades or rollers. They use different types of cutters made of steel, tungsten carbide, polycrystalline diamond compact (PDC) material, or diamonds for cutting rocks. The design and type of cutting teeth are selected based on the type of rocks to be drilled. Drill bits are broadly classified as roller cone or fixed cutter bits. They are further classified based on the material used for cutting teeth, bearing type, suitability for cutting different compressive strength rocks, etc.
A drill bit is connected to the drill string and is run in the well. The drill string is rotated at the surface, which turns the bit at the bottom of the hole to cut the rock into small pieces called drilled cuttings. Downhole drive mechanisms like Positive Displacement Motors (PDM) or Turbines are also used for generating bit rotation and torque downhole.
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Drill Collars are heavy wall rigid pipes that are used as part of bottom hole assembly above drill bit. Drill Collars are stiff tubulars and are added in the drilling assembly so that more weight on bit can be applied on bit for drilling without the risk of buckling the drill string. Drill collars can be either plain or spiral. Spiral drill collars have spiral groove machined on its outer surface. This reduces the contact area of the drill collar with hole, reducing chances of differential sticking.
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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
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"Error Ratio" also known as "Separation Factor" is used for assessing the collision risk of two wellbores. It is calculated as a ratio of Center to Center distance and sum of semi-major axis of error ellipse of the two wellbores. Error Ratio of 1 indicates that the error ellipses of the two well bores touch each other. Error Ratio of less than 1 means that error ellipses overlap and Error Ratio of more than 1 means that the ellipses don't overlap.
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The extended leak-off test (XLOT) is a technique used to measure the stress in oil and gas wells and is used to obtain horizontal stress data for predicting wellbore stability. Surface pressure is applied to the fluid column to determine the pressure at which fracture will propagate into the exposed formation.
XLOT test procedures are similar to routine leak-off tests but with multiple leak-off cycles, longer data collection time, and better data acquisition and analysis.
Stress Caging - An effective wellbore strengthening approach
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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.
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A Float Sub is a sub with a float valve installed in its bore. The flapper in the float valve allows circulation but isolates the drill string from the well bore pressure. The float sub has pin and box connections matching with the Bottom Hole Assembly and it is usually placed above the bit or above the mud motor. The decision to run a float sub in the drilling string depends on the company policy.
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The Formation Integrity Test (FIT) is essentially a test of formation strength to a predetermined value. FIT is carried out by gradually increasing the bottom hole pressure after drilling out the casing shoe and a few feet of formation. The intent of FIT is not to pressurize the wellbore until the formation fractures but to test the strength of the formation to a pre-established limit. Since it is carried out below the casing shoe, it also tests if any cement channeling can compromise the well's integrity.
Since the maximum mud weight is limited by the fracture gradient, FIT is useful to know what maximum mud weight can be used for drilling. FIT is also used as a basis for casing depths and well control options in case of influx.
Stress Caging - An effective wellbore-strengthening approach
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Gas observed at surface is reported as Units. Unit doesn't represent any absolute volume of gas. 50 units = 1%
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Geodesy is the study of the shape of the earth. It explains the concepts of latitude, longitude, ellipsoid and geodetic datum.
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Maps used in directional drilling are flat, but the earth is an oblated spheroid which is close to an ellipsoid. A point on earth is defined by latitude and longitude whereas, on a flat map, a point is defined by easting and northing. Geodetic system is a means of converting co-ordinates on earth to map co-ordinates by using map projections.
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Maps are used for various surveys. Since maps are flat surface, the latitude and longitude of spherical earth are converted using mathematical formula called 'Map Projection'. This results in a grid of horizontal and vertical lines on the map. The north on this grid of map is called 'Grid North'. At central meridian, Grid North equals True North.
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As the name suggests, Heavy Weight Drill Pipe (HWDP) is a tubular with drill pipe dimensions but has a heavier wall. It is used as the intermediate member of the drill string between drill collars and drill pipes. HWDP usually has longer tool joint than drill pipe. Its weight is less than the drill collar but more than drill pipe. Having HWDP in the drill string has multiple advantages. It reduces the required number of drill collars in the string while maintaining drill string's ability to apply required weight on bit for drilling. It has less wall contact than drill collar which reduces torque and the chances of differential sticking. HWDP provides smooth weight transition from drill collars to drill pipes and can be run through the hole angle much easily due to less rigidity.
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Inclination is the angle of deflection of bit from vertical while drilling operations. Inclination is measured in vertical plane. There are various methods of measuring wellbore inclination. The simplest one is through an inclinometer.
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An inflow test, also called a negative pressure test, is aimed at testing the barriers placed in the well for ensuring well integrity. The barriers in a well are installed to avoid fluid flowing past the barrier from the formation into the well or vice versa. To ensure well integrity, it is important to test whether the barrier fulfills this requirement.
An Inflow test is essentially the inverse of a positive pressure test performed in the well. In the inflow test, a differential pressure is created in the direction from formation to the well. It is achieved by reducing the hydrostatic pressure above a barrier to a level below the formation pressure. The test is designed to check if any formation fluid will leak past the barrier into the well.
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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 in the well and the fluid pressure in the formation being drilled is called 'Overbalance'. Overbalance is considered the primary barrier to well control and is maintained to disallow the flow of formation fluid into the wellbore. If for any reason, the overbalance is lost and the hydrostatic pressure drops below the formation pressure, the formation fluid can enter the well. This flow of fluid from the formation into the wellbore is called influx or kick
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Jar is used in the string for generating heavy blows and thus helping in releasing stuck pipes. Jars can be classified as Fishing Jar or Drilling Jar. They can also be classified based on operating mechanism as Mechanical or Hydraulic Jars. The mechanism inside jar allows to build up high energy level in the string by way of stretch of slack off weight and makes it release suddenly to create heavy blow.
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As part of the drilling process cuttings are generated, which need to be cleared as soon as possible from the bottom. The hydraulic energy is used to aid the drilling and also to circulate the drill cuttings out of the hole. However, if there isn't enough space for the cuttings to get past the drill bit, they may not escape quickly. If the cuttings are not cleared efficiently, they tend to clog the bit and stay at the bottom getting reground, adversely affecting the drilling efficiency. Hence the drill bits are designed with several flow paths, which serve as conduits for cuttings to get past the bit. These flutes are called junk slots.
The Junk Slot Area is measured in square inches and is the total cross-sectional area of these slots when viewing the bit face-on. Junk slots can vary in shape and size. While drilling a soft formation, the rate of penetration is high, which generates cuttings at a faster rate. Hence the bits for drilling softer formations need to be designed with larger junk slot areas to be able to clear the drilled cuttings faster. Junk slots also allow drilling fluid to flow freely and prevent surge and swab while tripping.
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Junk sub is a sub with box-down and pin-up tool joints. A skirt is fitted in the middle portion extending to the box end. This skirt acts as a basket to collect junk that is too heavy to be circulated out. Bleed holes are provided in the skirt for the mud to exit the skirt and return to the circulating system. Junk sub is run directly above the bit.
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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 in the well and the fluid pressure in the formation being drilled is called 'Overbalance'. Overbalance is considered the primary barrier to well control and is maintained to disallow the flow of formation fluid into the wellbore. If for any reason, the overbalance is lost and the hydrostatic pressure drops below the formation pressure, the formation fluid can enter the well. This flow of fluid from the formation into the wellbore is called kick or influx.
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If for any reason, the overbalance in a well is lost and the hydrostatic pressure in the well drops below the formation pressure, the formation fluid called influx can enter the well. Well Killing is the process of placing the heavier fluid back in the well by displacing out the influx for regaining primary control of the well.
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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. Item description
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A leak-off test (LOT) is a pressure integrity test that is carried out to determine the strength of the formation or fracture pressure. The leak-off test provides important information required for safely drilling the next hole section by establishing the maximum mud weight, kick tolerance, maximum allowable surface pressure for shutting in a well, etc.
LOT is carried out immediately below the casing shoe. A small portion of the new formation is drilled below the casing shoe, the well is shut in and pressure is increased gradually in small increments by slowly pumping fluid in the well. The surface pressure is closely monitored with every increase. At some point, the fluid will leak into the formation either due to the opening of a fracture or a permeable flow path in the formation. This provides information on the strength of the formation below the shoe.
Stress Caging - An effective wellbore-strengthening approach
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Since 'Magnetic North' and 'True North' do not coincide and refer to two different points on earth, a correction factor needs to be applied for the readings of the tools that refer to Magnetic North. Magnetic Declination is this correction factor and is defined as the angle between Magnetic North and True North. Magnetic Declination changes with time and location.
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Earth has got North and South poles but its geographic and magnetic poles do not coincide. Compass and other magnetic survey tools point to earth's 'Magnetic Pole'. North pole on earth's magnetic axis is called Magnetic North.
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Mud Line Suspension (MLS) systems are installed at or near mudline (seabed) in offshore wells . MLS supports the weight of casing strings that are run in the well as per well configuration and makes it possible to use a surface BOP & wellhead stack while drilling an offshore well. It also facilitates safely suspending the well at the seabed, disconnecting and reconnecting on a later date for future operations.
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Multiple laterals are drilled from one main wellbore. Multi-lateral technology increases reservoir exposure and drainage. It helps in reducing the field development cost.
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As the name suggests, if a stabilizer is installed in the bottom hole assembly, just above the bit, it is called a ‘Near-bit stabilizer’. Since the drill bit has a pin connection, near near-bit stabilizer has box-to-box connections to connect between the drill bit's pin end and the drill collar's pin end. A near-bit stabilizer reduces the bit tilt and provides more stability while drilling, which helps reduce bit whirl.
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A negative pressure test, also called the inflow test is aimed at testing the barriers placed in the well for ensuring well integrity. The barriers in a well are installed to avoid fluid flowing past the barrier from the formation into the well or vice versa. To ensure well integrity, it is important to test whether the barrier fulfills this requirement.
A negative pressure test is essentially the inverse of a positive pressure test performed in the well. In the inflow test or negative pressure test procedure, a differential pressure is created in the direction from the formation to the well. It is achieved by reducing the hydrostatic pressure above a barrier to a level below the formation pressure. The test is designed to check if any formation fluid will leak past the barrier into the well.
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As the name suggests, "Non Magnetic Drill Collar" is a drill collar made of a non-magnetic material. If magnetic survey instruments are run in hole, they encounter magnetic interference from regular drill collars which causes error in measurements of earth's magnetic field. Hence "Non Magnetic Drill Collars" of sufficient length need to be run as part of Bottom Hole Assembly for accuracy of survey readings. Non Magnetic Drill Collars are made of austenitic stainless steel and are usually non-spiral.
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Overbalanced drilling is conventional way of drilling, where the pressure (force per unit area) in the wellbore while drilling is maintained above the formation pressure. Difference between the hydrostatic pressure in the well and the fluid pressure in the formation being drilled is called 'Overbalance'. Overbalance is considered the primary barrier for well control and is maintained to disallow flow of formation fluid into the wellbore. Different companies have different policies for maintaining minimum level of overbalance depending on type of well and expected reservoir fluid.
Excessive overbalance can significantly slow the drilling progress and limit removal of drilled cuttings below the bit. High overbalance coupled with poor mud properties across porous formation can also result in thick mud cake risking differential sticking of drill string. It also risks formation damage across reservoir rock.
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P&A is a commonly used abbreviation of Plug & Abandon. It is the process of permanently abandoning a well by setting a set of abandonment plugs. Usually, when a well is drilled to the intended target depth and after evaluation if it is determined that the well will not be completed for production in near future, the well is abandoned. A set of cement and/or mechanical plugs are placed in the well to ensure complete isolation as per regulatory requirements. Every company has its own guidelines and policies for well abandonment. The type and number of plugs depend on the type of well and expected reservoir pressure, fluid, etc.
A well can be temporarily suspended as well if it is planned to complete, produce or reenter in the future. Offshore, a Mud Line Suspension (MLS) system is installed to be able to tie back the well in the future once the platform is installed. A corrosion cap is also installed on the top of the well to protect tieback threads and to avoid any debris getting into the well. The Corrosion Cap can be removed and retrieved before tying back the well to the platform.
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Peak Gas is a term used to express the maximum gas observed during a drilling break.
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Pony Collar is a simply as shorter version of a drill collar. It can be either plain or spiral. Pony Collar is used in the string to adjust the spacing between the stabilization points or other tools as needed.
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The conventional process of drilling a well maintains the pressure (force per unit area) inside the wellbore higher than the formation pressure. The difference between the hydrostatic pressure in the well and the fluid pressure in the formation being drilled is called overbalance. Overbalance is considered the 'Primary Barrier' in a well.
The primary barrier keeps the well under control by ensuring that the specific gravity of the drilling fluid is more than the formation pressure and is aimed at disallowing the flow of formation fluid into the wellbore. Different companies have different policies for a minimum level of required overbalance as a primary barrier depending on the type of well and expected reservoir fluid.
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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.
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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.
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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.
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"Separation Factor" also known as "Error Ratio" is used for assessing the collision risk of two wellbores. It is calculated as a ratio of Center to Center distance and sum of semi-major axis of error ellipse of the two wellbores. Separation Factor of 1 indicates that the error ellipses of the two well bores touch each other. Separation Factor of less than 1 means that error ellipses overlap and Separation Factor of more than 1 means that the ellipses don't overlap.
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Service Loads in tubular design represent worst-case axial loading due to all selected burst and collapse service loads as a function of depth along with thermally induced axial strains.
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Short Drill Collar, also known as Pony Collar is a simply as shorter version of a drill collar. It can be either plain or spiral. Short Drill Collar is used in the string to adjust the spacing between the stabilization points or other tools as needed.
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The process of drilling a deviated section initiated from the already drilled part of the original wellbore is called Sidetracking a well. Sidetracking can be planned, intentional, or maybe accidental as well. A sidetrack can be initiated from either a cased hole or an open hole depending on the reasons for a sidetrack.
Sidetracking a well requires a specialized set of equipment, exhaustive planning, and directional drilling expertise. A well can be sidetracked either from the vertical, deviated, or horizontal part of the original wellbore depending on the reasons for sidetracking.
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Sliding is the process of drilling without rotating drill string. The bit still rotates as it is connected to motor. Sliding is carried out when attempts are being made to adjust the well trajectory. While drilling a directional well with motor, the bit is run on a bent sub and hence is at an inclination rather than being vertically down. The bit is oriented in the required direction and is rotated through motor without rotating the string. This makes it possible to drill ahead with bit pointing in specified direction.
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When drill pipe, casing, or tubing are run in or pulled out of the hole, they are set on slips at rotary bushing for connecting or disconnecting pipes. When the pipe is sitting on slips, in addition to tensile load due to the buoyed weight of the string, the pipe also experiences radial load or hoop stress exerted by slip segments. The damage to the pipe that can be caused due to this additional stress by slip segments is called ‘Slip Crushing Effect.’ Calculations and analyzing tools help in determining the maximum load that can be placed on the slips without damaging the tubular subjected to a tensile load. Slip crushing is affected by the pipe diameter, slip angle, slip length, and the coefficient of friction between the slip and the master bushing.
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Solid Expandable Tubulars are casing or liners, which are expanded downhole after running the pipe in the well. Metallurgically, the tubular expansion process is equivalent to cold-working steel tubular to increase the diameters to the required size downhole. The process is complicated and requires overcoming operational hurdles for the expansion of pipe in a downhole environment. However, the technology provides the distinct advantage of extending the well depth where well conditions limit the number of regular-size casings that can be used to reach planned well depth.
An expansion cone is used to permanently mechanically deform the pipe. The cone is moved through the tubular by hydraulic pressure across the cone itself and/or by a direct mechanical pull or push force.
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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.
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Squeeze packer is used for carrying out squeeze jobs below packer. It is commonly used for remedial cement squeeze jobs. Packer can be set either mechanically or hydraulically. It supports the squeeze pressure and avoids back flow.
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Stabbing guide is a handling tools used while running in drill pipe, casing or tubing. It help align male-to-female connection of two separate pipes. Stabbing guides have two sections, a thru-bore (top section) and a counterbore (bottom section). Both thru-bore and counterbore are made of a strong, durable, yet somewhat elastic material. The top section guides the pin end to align with the box end of the other pipe . The bottom end of the stabbing guide helps the pin end slide over and sit in the box end of the pipe.
Making up misaligned ends could cross thread connections leaving a leak path. Cross treaded connection could have thread damage requiring replacement of pipe, which will result in additional time and cost. Using the right stabbing guide prevents thread damage and minimizes potential connection failure. A good stabbing guide will help in ensuring precisely aligned, securely connected pipe sections.
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Stabilizers are thick-walled hollow cylindrical components with stabilizing blades on their circumference. They are the components of the bottom hole assembly and are used to provide stability to the drill string. Stabilizers help avoid unintentional sidetracks, minimize vibrations, and enable weight and torque transfer to the bit efficiently by ensuring that the drill string rotates at or near the center of the borehole. Stabilizers have box and pin ends with API connections to be able to easily install at the desired position in the drilling assembly.
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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.
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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.
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Stress Caging is the technique of strengthening the wellbore so that the hole can be drilled without inducing downhole losses. Stress caging not only helps avoid downhole complications by avoiding loss of circulation but could also reduce the number of casing strings required for drilling the well to the planned target depth.
The technique achieves the objective of formation strengthening by treating weak formations with drilling fluids containing engineered particulate lost circulation materials. The process of stress caging aims to increase hoop stresses in near wellbore regions and seal shallow fractures at the wellbore formation interface continuously while drilling.
Stress Caging - An effective wellbore-strengthening approach
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While running in the drill string or casing in the well, the downward motion of the string forces the drilling fluid out of the flowline. This upward flow, causes frictional force with the wellbore wall and pipe that acts downwards. At the same time, the fluids immediately adjacent to the string are dragged downwards. This creates a piston effect and adds additional pressure to the hydrostatic pressure. This additional pressure is called 'Surge Pressure'. Excessive surge pressures can increase the Bottom hole pressure to high levels and induce losses.
e-Learning Resources on Surge and Swab Pressures while drilling
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If a drill string, casing, or logging tool is pulled out of the hole too fast, the string creates a piston effect pulling some mud out of the hole with it. This tends to reduce hydrostatic pressure in the well. The fluid in the annulus travels downwards to fill the void. This downward movement of fluid creates friction with the wellbore wall that acts upwards. The resultant pressure reduction created by this situation is called 'Swab Pressure'. If the swabbing reduces the pressure too much aSurge and Swab in Drillingnd the net hydrostatic pressure falls below the formation pressure, it may invite a kick (wellbore influx) into the wellbore. This may require carrying out well control procedures to secure the well.
e-Learning resources on Surge & Swab Pressures while drilling
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Tool Face is the Angle between high side of bend and North or high side of hole respectively. It is called "Magnetic Tool Face" if measured against "Magnetic North" and is called "Gravity Tool Face" if referred to the high side of the hole.
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Trip gas is the term used to define the gas observed on bottoms up after making a trip. It represents the amount of gas that feeds into the well during the trip while the well is in static condition. Gas feeds into the well due to loss of hydrostatic pressure caused by loss of annular friction pressure or swabbing effect during the trip.
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True North refers to geographical north pole of earth.
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Underbalanced drilling, or UBD, is the process of drilling a well by maintaining a hydrostatic head in the wellbore intentionally lower than the fluid pressure in the formation. The difference between the fluid pressure in the formation and the hydrostatic pressure in the well is called 'Underbalance'. The hydrostatic head can either be naturally under balance or by injecting natural gas, nitrogen, or air. If there is enough porosity and permeability in the rock, the formation fluid flows into the wellbore and up to the surface while drilling.
Underbalanced conditions do not allow filter cake build-up and also avoid formation damage due to the invasion of drilling mud and solids into the formation. Drilling rates in Underbalanced Drilling are typically high. In UBD, the influx of formation fluids must be controlled to avoid well-control problems. With the well flowing, the Blow Out Preventor (BOP) system is kept closed while drilling by using a rotating head to ensure maintain control of the well.
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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.
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Wellbore refers to the hole drilled in the ground either on land or offshore to explore or produce oil, gas, or water. A wellbore is drilled using a drill bit through several formation layers and rock types. Drilling fluid is used and is designed to provide the required hydrostatic pressure for ensuring wellbore stability, avoiding the influx of formation fluid, removing drilled cuttings, and cooling downhole. Based on types of formations, pore pressure, and fracture pressure estimations, wellbores are cased with steel casing and cement at predetermined intervals. Part of a wellbore can be left uncased also depending on the design, rock type, and objectives of the well.
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Well abandonment refers to the process of permanently suspending operations in a well. It is the process of permanently abandoning a well by setting a set of abandonment plugs. Usually, when a well is drilled to the intended target depth and after evaluation if it is determined that the well will not be completed for production in near future, the well is abandoned. A set of cement and/or mechanical plugs are placed in the well to ensure complete isolation as per regulatory requirements. Every company has its own guidelines and policies for well abandonment. The type and number of plugs depend on the type of well and expected reservoir pressure, fluid, etc.
A well can be temporarily suspended as well if it is planned to complete, produce or reenter in the future. Offshore, a Mud Line Suspension (MLS) system is installed to be able to tie back the well in the future once the platform is installed. A corrosion cap is also installed on the top of the well to protect tieback threads and to avoid any debris getting into the well. The Corrosion Cap can be removed and retrieved before tying back the well to the platform.
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'Well Commissioner' is Schlumberger's liner top test tool. After cementing the liner, multiple trips are required for cleaning out cement inside the liner, scrapping, and then running a retrievable packer assembly for carrying out a negative pressure test to ensure the integrity of the liner top. Well Commissioner is designed to save rig time by making it possible to clean out to cased hole TD and perform a negative pressure test at liner top in a single trip.
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'Well Dominator’ is Schlumberger's test tool for carrying out positive pressure test on liner top. After cementing the liner, the conventional sequence of operations requires multiple trips for cleaning out cement inside the liner, scrapping, and carrying out a positive and negative pressure test to ensure the integrity of the liner top. Well Dominator is run in the string in a combination of another Schlumberger tool Well Commissioner to complete all operations in a single run thus saving rig time.
It is a ball drop tool that remains hydraulically inactive while cleaning-out the casing. Dropping a ball activates pads of Well Dominator for carrying out a positive pressure test of liner top. Once the pressure test is successfully completed, dropping another ball deactivates it. A negative pressure test can be performed by Well Commissioner, which is part of the same string.
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Wellbore Tortuosity is a ratio of actual distance between two point in a wellbore and the straight line distance between the same two points. Inclination and azimuth measurements define the profile of the well whereas tortuosity is a measure of crookedness and indicates the well quality. High wellbore tortuosity not only affect the drilling process, drilling efficiency and casing running but also impact effectiveness of completions and production equipment in achieving reservoir return rates.
Dog leg severity (DLS) with measurements every 95 ft provide some insight into wellbore tortuosity but is insufficient to fully define it. Information acquired through tortuosity log help define wellbore shape and 3D visualization, facilitating in making critical decisions on well development and placement for artificial lift and other equipment in areas of low tortuosity. Collecting data at 1-ft intervals through tortuosity logs reveals areas of high side forces and high friction that won't be visible with standard MWD measurements carried out at every connection.
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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.