Well Logging and Drilling

WELL LOGGING AND DRILLING Purpose of Logging 1) Lack of Core (older wells) 2) Driller's logs - poor and subjective 3) Core/geol. logs - limited to well bore 4) See behind casing 5) Qualitative measurement in-situ 6) Correlation (SP, natural gamma) - objective record "Geophysical", "wireline", "E-logs" generally refer to the same thing - they are a part of the process of well production - mud logs, DST's and production tests may also be run with geophysical logs.

Fluid Circulation System Water/air for shallow holes Drilling mud - water base with colloidal and silt particles. Additives: (1) bentonite - viscosity control (2) barite - density control (3) salt - retards clay swelling & evaporite dissolution Mud Serves Many Purposes a) Lubrication (drill bit and string) b) Cuttings removal c) Maintain borehole pressure (prevents blowouts, fluid escape, breakouts) d) Entrained hydrocarbons in cuttings (mud logging) e) Permeable formation identification

3 Basic Types i. electrical (resistivity, conductivity, SP) ii. nuclear (density, porosity, natural radioactivity) iii. sonic (acoustic-porosity, fractures, correlation Drilling Artifacts That Affect Well Logs with seismic section)  Rugosity - hole diameter varies with depth Others  Sloughing - swelling of clay into hole Caliper, magnetic, gravity  Keyseats - wider hole where it intersects joints Fluid column logs --> temperature, flowmeter, fluid conductivity Well Completion Water Wells: flushing, screen installation, gravel pack, Properties sought grout or bentonite backfill, development, pump installation.  porosity Oil Wells: hydrofracturing or acid injection, casing, bottom  composition (rock and fluid) plug, perforation, pump installation (logs may be run  degree of saturation several times during these phases).  permeability Logging Procedure  metal content Logging truck contains:  heat flux a. measure wheel (has magnetic markers on cable)  rock quality b. cable or wireline (armored and insulated)  in-situ stress c. logging tool (hangs from end of cable) Logging tool consists of: Important Dates a. bridle (may contain electrodes) 1927-1931: Doll, Schlumberger brothers - France, 1st b. cable head (with weak pt.) resistivity, SP c. cartridge (power supply, amps, microprocessors) 1935 - Dipmeter d. sensors or sonde Late 1940's - Gamma-ray, neutron - oil field sondes are often 20 ft or longer 1950's - Focused resistivity tools, induction tools - for hydrological or geotechnical they are a few feet 1960's - Digital recording, full waveform sonic (3D - slimline sonde less than 2 inches in diameter velocity) e. spring or centering device 1970's - Borehole televiewer, VSP, Slimline sondes, f. a gamma ray sensor may be added between the head integrated circuitry and cartridge 1980's - Borehole radar, EM propagation, cross-hole Depth Monitoring tomography, deep logs Common oil well reference point: top of the K.B (Kelly Bushing) Costs (1986) Basic suite - $5-10 per foot plus mobilization charge Water well depths may be referenced to top of casing or Municipal water well - $8000 for 700 ft. running SP, ground level. gamma, neutron, induction, sonic, and density Methods of measuring depths - count rotations of the measure wheel - recording Drilling Methods odometer 1) Cable tool - check with magnetic marks on cable armor 2) Rotary Page 1 of 46

- corrections for cable stretching every 100 ft. - gamma-ray marker beds and casing collars may be used (calibrate depth with known formations) Common errors in depth 1. sticking of tool or cable (see tension log) 2. sloppiness - operator inattendance 3. error in tool length 4. memorizer error Typical Logging Procedure - Usually log from the bottom of the hole to the top to keep cable tension more even (exceptions are temperature and fluid conductivity logs where you want minimal fluid disturbance) and to check the total depth of the hole to see if depth error exists before logging Header - needs to be filled out before logs are completed (in the field!) Calibration of logs Basic principles - calibrate before and after logs are run - calibrate over the entire range of measured values - should be presented with log or on separate log

5) Units - industry standards 6) Receive basic measurements in digital format for your own replotting. (e.g. #cps instead of neutron porosity) Definitions Wellbore environment: Figure 1 in A and G Mud cake - deposited by invading fluid Mud filtrate - fluid that invades formation Flushed zone - no formation water left, completely invaded (some hydrocarbons may be left though) Transition zone - mud filtrate and formation fluid Uninvaded - virgin formation fluid General symbols to be used Porosity: phi = pore volume / total volume (interconnected pores = effective P) Degree of saturation: Sw = volume pore water / total pore volume Sh = volume hydrocarbons / total pore volume Hydraulic Conductivity - K = water volume / unit area in unit time Kclay ~ 10-8 cm/s Ksand ~ 10-4 cm/s Permeability: ka (intrinsic or absolute), the ease of transmission for any fluid Relative permeability-- permeability when 2 pore fluids are present K = ka(rho)g / mu where rho = density, mu = dynamic viscosity measured in Darcy's (D) = 1 cm3 fluid / 1 cm2 * 1 s oil/gas reservoirs - mD

Calibration for various types of log techniques (a) electrical logs - standard resistor (b) nuclear logs - blocks placed around detectors in field, to mimic laboratory response, aluminum or paraffin jigs (c) sonic logs - downhole is best, using a known formation (d) caliper - use steel rings of set diameter DRILLING FLUID - or by repeated runs over a standard hole In geotechnical engineering, drilling fluid is a fluid used to aid the drilling of boreholes into the earth. Often used while drilling oil and natural gas wells and on exploration drilling Log Presentation - may be linear, linear-log, or log scale rigs, drilling fluids are also used for much simpler - if linear resistivity, usually have at least 2 scales for boreholes, such as water wells. Liquid drilling fluid is often overshoot and conductivity called drilling mud. The three main categories of drilling Track 1 will contain one of the following: fluids are water-based muds (which can be dispersed and caliper, SP, natural gamma, fluid conductivity/resistivity, non-dispersed), non-aqueous muds, usually called oil-based cable tension mud, and gaseous drilling fluid, in which a wide range of Tracks 2 & 3 will each have one of the following: gases can be used. density (increasing right), porosity (increasing left), The main functions of drilling fluids include providing resistivity (increasing right), conductivity (increasing left), hydrostatic pressure to prevent formation fluids from travel time (increasing left), compensation corrections, entering into the well bore, keeping the drill bit cool and tension clean during drilling, carrying out drill cuttings, and suspending the drill cuttings while drilling is paused and Quality control on logs 1) Be there when the log is run. when the drilling assembly is brought in and out of the hole. 2) Check for headers, scales, remarks, scale changes The drilling fluid used for a particular job is selected to 3) Supervise calibration - have some idea of what to avoid formation damage and to limit corrosion. expect from the log 4) Use a service company with a good reputation and whose operators are also interpreters. Do not accept "black-box" technology. Page 2 of 46

Types of drilling fluid Function 2.1 Remove cuttings from well 2.2 Suspend and release cuttings 2.3 Control formation pressures 2.4 Seal permeable formations 2.5 Maintain wellbore stability 2.6 Minimizing formation damage 2.7 Cool, lubricate, and support the bit and drilling assembly 2.8 Transmit hydraulic energy to tools and bit 2.9 Ensure adequate formation evaluation 2.10 Control corrosion (in acceptable level) 2.11 Facilitate cementing and completion 2.12 Minimize impact on environment  3 Composition of drilling mud  4 Mud engineer  5 Compliance engineer  6 See also  7 References  8 Further reading The main functions of drilling fluids include; Providing hydrostatic pressure, To prevent formation fluids from entering into the well bore, Keeping the drill bit cool and clean during drilling, Carrying out drill cuttings and suspending the drill cuttings while drilling is paused and the drilling assembly is brought in and out of the hole. The drilling fluid used for a particular job is selected to avoid formation damage and to limit corrosion. Types of drilling fluid Many types of drilling fluids are used on a day-to-day basis. Some wells require that different types be used at different parts in the hole, or that some types be used in combination with others. The various types of fluid generally fall into a few broad categories:[1]  Air: Compressed air is pumped either down the bore hole's annular space or down the drill string itself.  Air/water: The same as above, with water added to increase viscosity, flush the hole, provide more cooling, and/or to control dust.  Air/polymer: A specially formulated chemical, most often referred to as a type of polymer, is added to the water & air mixture to create specific conditions. A foaming agent is a good example of a polymer.  Water: Water by itself is sometimes used.  Water-based mud (WBM): A most basic waterbased mud system begins with water, then clays and other chemicals are incorporated into the water to create a homogenous blend resembling something between chocolate milk and a malt

(depending on viscosity). The clay (called "shale" in its rock form) is usually a combination of native clays that are suspended in the fluid while drilling, or specific types of clay that are processed and sold as additives for the WBM system. The most common of these is bentonite, frequently referred to in the oilfield as "gel". Gel likely makes reference to the fact that while the fluid is being pumped, it can be very thin and free-flowing (like chocolate milk), though when pumping is stopped, the static fluid builds a "gel" structure that resists flow. When an adequate pumping force is applied to "break the gel", flow resumes and the fluid returns to its previously free-flowing state. Many other chemicals (e.g. potassium formate) are added to a WBM system to achieve various effects, including: viscosity control, shale stability, enhance drilling rate of penetration, cooling and lubricating of equipment.  Oil-based mud (OBM): Oil-based mud can be a mud where the base fluid is a petroleum product such as diesel fuel. Oil-based muds are used for many reasons, some being increased lubricity, enhanced shale inhibition, and greater cleaning abilities with less viscosity. Oil-based muds also withstand greater heat without breaking down. The use of oil-based muds has special considerations. These include cost and environmental considerations.  Synthetic-based fluid (SBM): Synthetic-based fluid is a mud where the base fluid is a synthetic oil. This is most often used on offshore rigs because it has the properties of an oil-based mud, but the toxicity of the fluid fumes are much less than an oil-based fluid. This is important when men work with the fluid in an enclosed space such as an offshore drilling rig. On a drilling rig, mud is pumped from the mud pits through the drill string where it sprays out of nozzles on the drill bit, cleaning and cooling the drill bit in the process. The mud then carries the crushed or cut rock ("cuttings") up the annular space ("annulus") between the drill string and the sides of the hole being drilled, up through the surface casing, where it emerges back at the surface. Cuttings are then filtered out with either a [shale shaker], or the newer shale conveyor technology, and the mud returns to the mud pits. The mud pits let the drilled "fines" settle; the pits are also where the fluid is treated by adding chemicals and other substances. The returning mud can contain natural gases or other flammable materials which will collect in and around the shale shaker / conveyor area or in other work areas. Because of the risk of a fire or an explosion if they ignite, special monitoring sensors and explosion-proof certified Page 3 of 46

equipment is commonly installed, and workers are advised to take safety precautions. The mud is then pumped back down the hole and further re-circulated. After testing, the mud is treated periodically in the mud pits to ensure properties which optimize and improve drilling efficiency, borehole stability, and other requirements listed below. Drilling fluids depends on geological factors such as rocks that are going to be drilled and anticipated down hole temperatures and pressures, where the level of inhibition is one of the key parameters. The selection of fluid type can be influence by technical requirements, cost, availability and environmental concerns. FUNCTIONS The main functions of a drilling mud can be summarized as follows: 1. Remove cuttings from well Drilling fluid carries the rock excavated by the drill bit up to the surface. Its ability to do so depends on cutting size, shape, and density, and speed of fluid traveling up the well (annular velocity). These considerations are analogous to the ability of a stream to carry sediment; large sand grains in a slow-moving stream settle to the stream bed, while small sand grains in a fast-moving stream are carried along with the water. The mud viscosity is another important property, as cuttings will settle to the bottom of the well if the viscosity is too low. Other properties include:  Most drilling muds are thixotropic (that is, they become a gel under static conditions). This characteristic keeps the cuttings suspended when the mud is not moving during, for example, maintenance.  Fluids that have shear thinning and elevated viscosities are efficient for hole cleaning.  Higher annular velocity improves cutting transport. Transport ratio (transport velocity / lowest annular velocity) should be at least 50%.  High density fluids may clean hole adequately even with lower annular velocities (by increasing the buoyancy force acting on cuttings). But may have a negative impact if mud weight is in excess of that needed to balance the pressure of surrounding rock (formation pressure), so mud weight is not usually increased for hole cleaning purposes.  Higher rotary drill-string speeds introduce a circular component to annular flow path. This helical flow around the drill-string causes drill cuttings near the wall, where poor hole cleaning conditions occur, to move into higher transport regions of the annulus. Increased

rotation are the best methods in high angle and horizontal beds. 2. Suspend and release cuttings  Must suspend drill cuttings, weight materials and additives under a wide range of conditions.  Drill cuttings that settle can causes bridges and fill, which can cause stuck-pipe and lost circulation.  Weight material that settles is referred to as sag, this causes a wide variation in the density of well fluid, this more frequently occurs in high angle and hot wells  High concentrations of drill solids are detrimental to: o Drilling efficiency (it causes increased mud weight and viscosity, which in turn increases maintenance costs and increased dilution) o Rate of Penetration (ROP) (increases horsepower required to circulate) o Mud properties that suspended must balanced with properties in cutting removal by solids control equipment  For effective solids controls, drill solids must be removed from mud on the 1st circulation from the well. If re-circulated, cuttings break into smaller pieces and are more difficult to remove.  Conduct a test to compare the sand content of mud at flow line and suction pit (to determine whether cuttings are being removed). 3. Control formation pressures  If formation pressure increases, mud density should also be increased, often with barite (or other weighting materials) to balance pressure and keep the wellbore stable. Unbalanced formation pressures will cause an unexpected influx of pressure in the wellbore possibly leading to a blowout from pressured formation fluids.  Hydrostatic pressure = density of drilling fluid * true vertical depth * acceleration of gravity. If hydrostatic pressure is greater than or equal to formation pressure, formation fluid will not flow into the wellbore.  Well control means no uncontrollable flow of formation fluids into the wellbore.  Hydrostatic pressure also controls the stresses caused by tectonic forces, these may make wellbores unstable even when formation fluid pressure is balanced.

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If formation pressure is subnormal, air, gas, mist, stiff foam, or low density mud (oil base) can be used.  In practice, mud density should be limited to the minimum necessary for well control and wellbore stability. If too great it may fracture the formation. The hydrostatic head produced by the mud in psi is = 0.052 x G xH Where G = density of mud in ppg H = depth of the hole in feet. This hydrostatic head will counter the formation pressure in order to avoid a blowout while drilling. For example, Lets say a well is being drilled in a saltwater basin (pressure gradient of 0.465 psi/ft), the pressure in the formation at 10,000 feet would be expected to be: 10,000 x 0.465 = 4,650 psi The weight of mud required to counter this pressure is calculated as follows. P = 0.052GH 4,650 = 0.052 x G x 10,000 G = 8.94 ppg 4. Seal permeable formations  When mud column pressure exceeds formation pressure, mud filtrate invades the formation, and a filter cake of mud is deposited on the wellbore wall.  Mud is designed to deposit thin, low permeability filter cake to limit the invasion.  Problems occur if a thick filter cake is formed; tight hole conditions, poor log quality, stuck pipe, lost circulation and formation damage.  In highly permeable formations with large pore throats, whole mud may invade the formation, depending on mud solids size; o Use bridging agents to block large opening, then mud solids can form seal. o For effectiveness, bridging agents must be over the half size of pore spaces / fractures. o Bridging agents (e.g. calcium carbonate, ground cellulose).  Depending on the mud system in use, a number of additives can improve the filter cake (e.g. bentonite, natural & synthetic polymer, asphalt and gilsonite).

5. Maintain wellbore stability  Chemical composition and mud properties must combine to provide a stable wellbore. Weight of the mud must be within the necessary range to balance the mechanical forces.  Wellbore instability = sloughing formations, which can cause tight hole conditions, bridges and fill on trips (same symptoms indicate hole cleaning problems).  Wellbore stability = hole maintains size and cylindrical shape.  If the hole is enlarged, it becomes weak and difficult to stabilize, resulting in problems such as low annular velocities, poor hole cleaning, solids loading and poor formation evaluation  In sand and sandstones formations, hole enlargement can be accomplished by mechanical actions (hydraulic forces & nozzles velocities). Formation damage is reduced by conservative hydraulics system. A good quality filter cake containing bentonite is known to limit bore hole enlargement.  In shales, mud weight is usually sufficient to balance formation stress, as these wells are usually stable. With water base mud, chemical differences can cause interactions between mud & shale that lead to softening of the native rock. Highly fractured, dry, brittle shales can be extremely unstable (leading to mechanical problems).  Various chemical inhibitors can control mud / shale interactions (calcium, potassium, salt, polymers, asphalt, glycols and oil – best for water sensitive formations)  Oil (and synthetic oil) based drilling fluids are used to drill most water sensitive Shales in areas with difficult drilling conditions.  To add inhibition, emulsified brine phase (calcium chloride) drilling fluids are used to reduce water activity and creates osmotic forces to prevent adsorption of water by Shales. 6. Minimizing formation damage  Skin damage or any reduction in natural formation porosity and permeability (washout) constitutes formation damage  Most common damage; o Mud or drill solids invade the formation matrix, reducing porosity and causing skin effect o Swelling of formation clays within the reservoir, reduced permeability

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Precipitation of solids due to mixing of mud filtrate and formations fluids resulting in the precipitation of insoluble salts o Mud filtrate and formation fluids form an emulsion, reducing reservoir porosity  Specially designed drill-in fluids or workover and completion fluids, minimize formation damage. Some of the most common mechanisms for formation damage are:  a) Mud or drill solids invading the formation matrix, plugging pores.  b) Swelling of formation clays within the reservoir, reducing permeability.  c) Precipitation of solids as a result of mud filtrate and formation fluids being incompatible.  d) Precipitation of solids from the mud filtrate with other fluids, such as brines or acids, during completion or stimulation procedures.  e) Mud filtrate and formation fluids forming an emulsion, restricting permeability.  The possibility of formation damage can be determined from offset well data and studies of formation cores for return permeability. Drilling fluids designed to minimize a particular problem, specially designed reservoir drill-in fluids or workover and completion fluids, all can be used to minimize formation damage. 7. Cool, lubricate, and support the bit and drilling assembly  Heat is generated from mechanical and hydraulic forces at the bit and when the drill string rotates and rubs against casing and wellbore.  Cool and transfer heat away from source and lower to temperature than bottom hole.  If not, the bit, drill string and mud motors would fail more rapidly.  Lubrication based on the coefficient of friction. Oil- and synthetic-based mud generally lubricates better than water-based mud (but the latter can be improved by the addition of lubricants).  Amount of lubrication provided by drilling fluid depends on type & quantity of drill solids and weight materials + chemical composition of system.  Poor lubrication causes high torque and drag, heat checking of the drill string, but these problems are also caused by key seating, poor hole cleaning and incorrect bottom hole assemblies design.  Drilling fluids also support portion of drillstring or casing through buoyancy. Suspend in

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drilling fluid, buoyed by force equal to weight (or density) of mud, so reducing hook load at derrick. Weight that derrick can support limited by mechanical capacity, increase depth so weight of drill-string and casing increase. When running long, heavy string or casing, buoyancy possible to run casing strings whose weight exceed a rig's hook load capacity.

8. Transmit hydraulic energy to tools and bit  Hydraulic energy provides power to mud motor for bit rotation and for MWD (measurement while drilling) and LWD (logging while drilling) tools. Hydraulic programs base on bit nozzles sizing for available mud pump horsepower to optimize jet impact at bottom well.  Limited to: o Pump horsepower o Pressure loss inside drillstring o Maximum allowable surface pressure o Optimum flow rate o Drill string pressure loses higher in fluids higher densities, plastic viscosities and solids.  Low solids, shear thinning drilling fluids such as polymer fluids, more efficient in transmit hydraulic energy.  Depth can be extended by controlling mud properties.  Transfer information from MWD & LWD to surface by pressure pulse. 9. Ensure adequate formation evaluation  Chemical and physical mud properties and wellbore conditions after drilling affect formation evaluation.  Mud loggers examine cuttings for mineral composition, visual sign of hydrocarbons and recorded mud logs of lithology, ROP, gas detection or geological parameters.  Wireline logging measure – electrical, sonic, nuclear and magnetic resonance.  Potential productive zone are isolated and performed formation testing and drill stem testing.  Mud helps not to disperse of cuttings and also improve cutting transport for mud loggers determine the depth of the cuttings originated.  Oil-based mud, lubricants, asphalts will mask hydrocarbon indications.  So mud for drilling core selected base on type of evaluation to be performed (many coring Page 6 of 46

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operations specify a blend mud with minimum Composition of drilling mud of additives). Water-based drilling mud most commonly consists of bentonite clay (gel) with additives such as barium sulfate (barite), calcium carbonate (chalk) or hematite. Various Control corrosion (in acceptable level) Drill-string and casing in continuous contact with thickeners are used to influence the viscosity of the fluid, drilling fluid may cause a form of corrosion. e.g. xanthan gum, guar gum, glycol, Dissolved gases (oxygen, carbon dioxide, hydrogen carboxymethylcellulose, polyanionic cellulose (PAC), or sulfide) cause serious corrosion problems; starch. In turn, deflocculants are used to reduce viscosity of o Cause rapid, catastrophic failure clay-based muds; anionic polyelectrolytes (e.g. acrylates, o May be deadly to humans after a short polyphosphates, lignosulfonates (Lig) or tannic acid period of time derivates such as Quebracho) are frequently used. Red mud  Low pH (acidic) aggravates corrosion, so use was the name for a Quebracho-based mixture, named after corrosion coupons to monitor corrosion type, the color of the red tannic acid salts; it was commonly used rates and to tell correct chemical inhibitor is in 1940s to 1950s, then was made obsolete when used in correct amount. lignosulfonates became available. Other components are  Mud aeration, foaming and other O2 trapped added to provide various specific functional characteristics conditions cause corrosion damage in short as listed above. Some other common additives include period time. lubricants , shale inhibitors, fluid loss additives (to control  When drilling in high H2S, elevated the pH loss of drilling fluids into permeable formations). A fluids + sulfide scavenging chemical (zinc). weighting agent such as barite is added to increase the overall density of the drilling fluid so that sufficient bottom hole pressure can be maintained thereby preventing an Facilitate cementing and completion  Cementing is critical to effective zone and well unwanted (and often dangerous) influx of formation fluids. completion.  During casing run, mud must remain fluid and Drilling Fluid Additives minimize pressure surges so fracture induced Drilling muds typically have several additives. (Air and lost circulation does not occur. foam fluids typically do not contain many additives because  Mud should have thin, slick filter cake, the additives are either liquid or solid, and will not mix with wellbore with no cuttings, cavings or bridges. air and foam drilling fluids.) The following is a list of the  To cement and completion operation properly, more significant additives: mud displace by flushes and cement. For  Weighting materials, primarily barite (barium effectiveness; sulfate), may be used to increase the density of the o Hole near gauges mud in order to equilibrate the pressure between the o Mud low viscosity wellbore and formation when drilling through o Mud non progressive gel strength particularly pressurized zones. Hematite (Fe2O3) sometimes is used as a weighting agent in oil-based muds (Souders, 1998). Minimize impact on environment Mud is, in varying degrees, toxic. It is also difficult  Corrosion inhibitors such as iron oxide, aluminum and expensive to dispose of it in an bisulfate, zinc carbonate, and zinc chromate protect environmentally friendly manner. A Vanity Fair pipes and other metallic components from acidic article described the conditions at Lago Agrio, a compounds encountered in the formation. large oil field in Ecuador where drillers were  Dispersants, including iron lignosulfonates, break effectively unregulated. Texaco, the drilling up solid clusters into small particles so they can be company, left the used mud (and associated carried by the fluid. cuttings and crude oil) in unlined open-air pits,  Flocculants, primarily acrylic polymers, cause allowing it to contaminate both surface and suspended particles to group together so they can underground waters. Storing mud properly is very be removed from the fluid at the surface. expensive. After a decade of drilling, Texaco  Surfactants, like fatty acids and soaps, defoam and considered transferring the mud waste at Lago emulsify the mud. Agrio to concrete-lined pits, but estimated that it  Biocides, typically organic amines, chlorophenols, would cost over 4 billion dollars (US). or formaldehydes, kill bacteria and help reduce the souring of drilling mud.

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Fluid loss reducers include starch and organic polymers and 3. Air and foam limit the loss of drilling mud to under-pressurized or high- There are drilling conditions under which a liquid drilling permeability formations. fluid is not most desirable circulating medium. Air or foam is used in drilling some wells when these special conditions exist. Drilling fluid can solve problems Many drilling problems are due to conditions or situations that occur after drilling begins and for which the drilling Mud Properties fluid was not designed. 1. Mud density or mud weight Some of these problems can be solved by adding materials Mud weight is measured by means of a mud balance. The to the drilling fluid to adjust its properties. weight of water is 8.33 ppg. The mud weight can be Other cases, it may be necessary to replace the drilling fluid increased by adding barite (barium sulphate). Barite has a being used with another fluid system. specific gravity of between 4.2 – 4.3. The most common changes is the mud weight or density. Weighting material is added when high-pressure formations Other materials can be used to increase mud weight such as are expected. ilmenite (S.G of 4.58) Some of the problems are:

2. Mud viscosity Mud viscosity is difficult to measure but in the field the Marsh funnel and the Fann V-G meter is commonly used. The Marsh Funnel is filled with mud, the operator then notes the time, removes his finger from the discharge and measures the time for one quart (946 cm3) to flow out. Marsh funnels are manufactured to precise dimensional standards and may be calibrated with water which has a 0.5 sec.funnel viscosity of 26

1. Lost circulation Lost circulation can occur in several types of formations, including high permeable formations, fractured formations and cavernous zones. Lost circulation materials can be added to the mud to bridge or deposit a mat where the drilling fluid being lost to the formation. These materials include cane and wood fibres, cellophane flakes and even padi husks were used in oil drilling in Sumatra. 3. Gel strength The gel strength of a mud is a measure of the shearing 2. Stuck pipe stress necessary to initiate a finite rate of shear. Stuck pipe can occur after drilling has been halted for a rig With proper gel strength can help suspend solids in the hole breakdown, while running a directional survey or when and allow them to settle out on the surface, excessive gel conducting other nondrilling operation. strength can cause a number drilling problems. The drill pipe may stick to the wall of the hole due to the formation of filter cake or a layer of wet mud solids on the 4. Filtration wall of the hole in the formation. The filtration, water loss or wall building test is conducted with a filter press. 3. Heaving or sloughing hole The rate at which filtrate will invade permeable zone and This occurs when shales enter the well bore after the section the thickness of the filter cake that will be deposited on the has been penetrated by the bit. To solve this problem, wall of the hole as filtration takes place are important keys drilling is suspended the hole is conditioned (by letting the to trouble-free drilling mud in circulation for a period of time) Drilling Fluid treating and monitoring equipment In addition to the main mud pumps, several items of mud Types of drilling fluids treating equipment are found on most rigs. Much of this 1. Water-base mud equipment is aimed at solids removal, including shale This fluid is the mud in which water is the continuous shakers, desanders, desilters and centrifuges. phase. This is the most common drilling mud used in oil drilling. Shale shakers remove larger particles from the mud stream 2. Oil-based mud as it returns from the bottom of the hole. Shakers are This drilling mud is made up of oil as the continuous phase. equipped with screens of various sizes, depending on the Diesel oil is widely used to provide the oil phase. This type type of solids to be removed. of mud is commonly used in swelling shale formation. With water-based mud the shale will absorb the water and it Finer particles in the mud stream are removed with swells that may cause stuck pipe. desanders, desilters and centrifuges. Each of these items of Page 8 of 46

solids-control equipment is applicable only over a certain range of particle sizes. In addition to removing solids, mud handling equipment may also include a mud degasser to remove entrained gas from the mud stream. Degassing the drilling fluid is sometimes necessary when small volumes of gas flow into the well bore during drilling.

In drilling a blow out preventer (BOP) stack is always attached at the top of the conductor pipe. In case of a gas kick (a sign that may lead to a blow out) the BOP stack can close the annular space between the drilling pipe and the conductor pipe or casing or shut the whole hole (with a blind ram of the BOP).

4. Lost Circulation Additional equipment include mixers to agitate mud in the Lost circulation means the loss of substantial amount of tanks, smaller pumps to various duties and equipment for drilling mud to an encountered formation. adding chemicals and solid materials to the mud system. Lost circulation materials are commonly circulated in the mud system both as a cure and a continuous preventive. These materials are the fibrous materials such as the hay, Drilling hazards The following are some of the most common hazards in sawdust or padi husk and lamellated (flat and platy) drilling and can be overcome by proper control of the mud materials such as mica, cellophane. properties. Summary of drilling fluid functions 1. Salt section hole enlargement  Suspend cuttings (drilled solids), remove them Salt section can be eroded by the drilling fluid and causes from the bottom of the hole and the well bore, and hole enlargement. These enlargement will require larger release them at the surface mud volume to fill the system and in case of casing the  Control formation pressure and maintain well-bore hole, larger cement volume is required. stability To avoid these problems a salt saturated mud system is  Seal permeable formations prepared prior to drilling the salt bed.  Cool, lubricate, and support the drilling assembly  Transmit hydraulic energy to tools and bit 2. Heaving shale problems  Minimize reservoir damage Areas with shale sections containing bentonite or other  Permit adequate formation evaluation hydratable clays will continually absorb water, swell and  Control corrosion slough into the hole.  Facilitate cementing and completion Such beds are referred to as heaving shales and constitute a  Minimize impact on the environment severe drilling hazard when encountered.  Inhibit gas hydrate formation Pipe sticking, excessive solid buildup in the mud and hole  Maintain wellbore stability bridging are typical problems.  Transmit hydraulic energy to tools and bit  Ensure adequate formation evaluation Various treatments of the mud are sometimes successful,  Control corrosion (in acceptable level) such as  Facilitate cementing and completion • Changing mud system to high calcium content by adding  Minimize impact on environment lime, gypsum etc which reduces the tendency of the mud to hydrate water sensitive clays. • Increasing circulation rate for more rapid removal of WELL COMPLETION Once the design well depth is reached, the formation must particles. be tested and evaluated to determine whether the well will • Increasing mud density for greater wall support be completed for production, or plugged and abandoned. • Decreasing water loss mud To complete the well production, casing is installed and • Changing to oil emulsion mud cemented and the drilling rig is dismantled and moved to • Changing to oil-based mud. the next site. A service rig is brought in to perforate the production 3. Blowouts Blowout is the most spectacular, expensive and highly casing and run production tubing. If no further preproduction servicing is needed, the christmas tree is feared hazard of drilling. This occurs when encountered formation pressure exceed installed and production begins. the mud column pressure which allows the formation fluids Well completion activities include: to blow out of the hole.  Conducting Drill Stem Test Mud density or the mud weight is the principal factor in  Setting Production Casing controlling this hazard.  Installing Production Tubing Page 9 of 46

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Starting Production Flow Setting Production Casing Beam Pumping Units Production casing is the final casing in a well. It can be set After production starts, the well may need further servicing. from the bottom to the top. Sometimes a production liner is installed. If it's decided that the well will not be completed, then it This casing is set the same as other casings, then cemented will be plugged and abandoned. in place. See Casing Operations and Cementing for more information on specific hazards and solutions. Conducting drill stem test To determine the potential of a producing formation, the operator may order a drill stem te st (DST). The DST crew Installing Production Tubing makes up the test tool on the bottom of the drill stem, then A well is usually produced through tubing inserted down lowers it to the bottom of the hole. Weight is applied to the the production casing. Oil and gas is produced more tool to expand a hard rubber sealer called a packer. Opening effectively through this smaller-diameter tubing than the tool ports allows the formation pressure to be tested. through the large-diameter production casing. This process enables workers to determine whether the well can be produced. Joints of tubing are joined together with couplings to make up a tubing string. Tubing is run into the well much the same as casing, but tubing is smaller in diameter and is Potential Hazards:  Being pinched or struck by the drill stem test tools removable. during floor operations.  Swabbing the hole on the way out with the test tool The steps for this activity are: could cause a kick to occur, which could result in a  Tubing elevators are used to lift tubing from the blowout leading to injuries and deaths. rack to the rig floor.  Being exposed to unexpected release of H2S or  The joint is stabbed into the string, which is other gases or liquids. suspended in the well, with air slips.  A packer seat failure or fluid loss to an upper  Power tongs are used to make-up tubing. formation could cause a kick that might result in a  This process is repeated until tubing installation is blowout causing injuries and deaths. complete.  Other hazards are similar to those encountered  The tubing hanger is installed at the wellhead. during trippingout/in. New technology allows tubing to be manufactured in a continuous coil, without joints. Coiled tubing is inserted Possible Solutions:  Wear appropriate PPE. into the well down the production casing without the need  Instruct workers in handling and using the special for tongs, slips, or elevators, which takes considerably less tools required during drill stem testing. time to run.  Keep a method for filling the hole in place at all times. Before any test starts, the rig management Potential Hazards: must ensure that the blow-out prevention system  Getting pinched fingers and hands from tongs and includes a kill system that is capable of pumping slips. fluid into the well below the annular preventer and  Being struck by swinging tubing and tubing at least on-set of pipe rams. elevators.  Run a pump-out-sub or downhole circulating  Getting caught between the joint and tongs or device in the test string to to enable the system to stump. be reversed.  Being struck by the tubing hanger wrench if it Ensure all workers on the location understand the dangers should slip. before starting any drill stem test. They should be fully  Getting fingers and hands pinched and caught informed of and trained in appropriate safety procedures, between tubing hanger and tubing head. including the use of safety equipment and breathing apparatus. If in an H2S area, post a sign indicating the test Possible Solutions: in full view for the general public to see. Post reliable  Keep all fingers and hands away from pinch points. people to stop them from coming to the location. Define a  Instruct workers to be on alert when on the rig floor minimum of two muster points with all vehicles parked in and pipe racking area. an appointed area.  Avoid placing hands on the end of the tubing stump. Page 10 of 46

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Use the correct tools for each task. Inspect the tools before use. Use coiled tubing. Starting Production flow Production flow is started by washing in the well and setting the packer. Washing in means to pump in water or brine to flush out the drilling fluid. Usually this is enough to start the well flowing. If not, then the well may need to be unloaded. This means to swab the well to remove some of the brine. If this does not work the flow might be started by pumping high-pressure gas into the well before setting the packer. If the well does not flow on its own, well stimulation or artificial lift may need to be considered. Potential Hazards:  A blowout may be possible whenever well pressures are changed. Possible Solutions: Monitoring of well pressures and working blow out preventers (BOP's) are the best way to prevent blowouts. Beam Pumping Units If the well doesn't produce adequately, a beam pumping unit may be installed. There are four basic types of beam pumping units. Three involve a walking beam, which seesaws to provide the up and down reciprocating motion to power the pump. The fourth reciprocates by winding a cable on and off a rotating drum. The job of all four types is to change the circular motion of an engine to the reciprocating motion of the pump.

Servicing is done by specialized crews and includes:  Transporting Rig and Rigging Up o Transporting Rig o Rigging Up Service Rig o Set Up Work Area  General Servicing o Removing the Horsehead o Removing the Wellhead o Pulling and Running Rods o Pulling and Running Tubing  Special Services o Wireline Operations o Well Logging o Perforating o Cementing o Stimulation o Swabbing o Hot Oiling o Snubbing o Coil Tubing  Workover o Sand Cleanout o Repairing Liners and Casing o Well Recompletions  Sidetracking Plug-Back TRANSPORTATION After the drilling rig is removed, the well site is cleaned and re-leveled for the service rig. A workover rig is driven or transported to the site and positioned at the well.

Potential Hazards:  Working in unstable or slippery conditions on the lease road/drill site.  Striking fixed objects such as power line poles.  Contacting electrical service lines.  Being involved in vehicular accidents. Potential Hazard:  Being pinched, struck, or crushed by falling or  Getting caught between the rig and the wellhead. swinging parts during assembly.  Being struck by a moving rig. Possible Solutions:  Ensure that the work crew understands the Possible Solutions: assembly procedures and hazards involved in the  Inspect the route in advance for adequate vehicle tasks. access and satisfactory surface conditions. Wear appropriate PPE.  Ensure adequate driver training.  Ensure proper vehicle maintenance.  Establish and follow a specific procedure for positioning the rig. SERVICING Servicing operations assumes that the well has been  Use a ground guide while backing the rig. completed and initial production has begun.  Keep all personnel clear of the moving rig. All servicing activity requires specialized equipment. The equipment is transported in and rigged up. The pump units are brought in disassembled on trucks and off-loaded onsite. The many parts of the pump unit include large heavy metal pieces that need to be assembled.

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Rigging up service rig Before rigging up, guyline anchors are set into the ground and pull tested. The service rig is then spotted over the well.

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Use proper hand and foot placement. See general safety and health. Control the position of the counterweight by maintaining tension on the guywire to keep the weight away from the mast.

The truck- or trailer-mounted rig is stabilized and leveled by manual or hydraulic jacks. All guy lines are uncoiled and laid out to remove kinks or knots. Set up work area The work area is prepared by setting up all relevant The mast is readied for raising, then raised and guyed into equipment for the job, including the derrick emergency place. The derrick emergency escape device is rigged up escape device. and the work platform is readied for service operations. Potential Hazards: Potential Hazards:  Being electrocuted by overhead power lines.  Being struck by or caught between equipment.  Slips, trips, and falls as a result of unstable or  Receiving strains and sprains. slippery conditions.  Getting hand, finger, and foot injuries.  Being caught between the mast and mast cradle or  Slips, trips, and falls. being struck by or caught in guy lines and cables  Failing to properly install derrick emergency escape when mast is being raised. device when personnel may be expected to work in  Being struck by a toppling mast if the carrier shifts. the derrick.  Being sprayed with oil if the hydraulic cylinder or  Getting burned or exposed to respiratory hazards hoses fail as mast is being raised. due to ignition of flammable liquids, vapors, and  Twisting and falling of the mast if a guy line or gases. anchor breaks or fails. Possible Solutions:  Receiving strains and sprains.  Install guardrails as required. [29 CFR 1910.23];  Getting hand, finger, and foot injuries during rig Association of Energy Services Companies up. (AESC), Recommended Safe Procedures and  Getting the climbing assist counterweight tangled Guidelines for Oil and Gas Well Servicing. in the mast.  Inspect equipment integrity such as slings, tongs, and hand tools. [29 CFR 1910.184] Possible Solutions:  Identify all electrical hazards and maintain  Train crew to select and use the proper tools for the adequate clearances. [29 CFR 1910.303 Table S3] job.  Take appropriate precautions to mitigate slip, trip,  Instruct workers to stand clear of suspended loads. and fall hazards.  Use a tag line to guide equipment into position.  Stay clear of the unit while the mast is being raised,  Inspect hoses and connections before and after lowered, or telescoped. attaching to the tongs.  Uncoil and visually inspect all cables before  Connect hoses after the tongs have been positioned. starting to raise the mast. Stand to the side of lines  Properly install derrick emergency escape device in and cables as the mast is being raised. accordance with manufacturer's recommendations.  Inspect the well pad and set additional foundation  Proper equipment type and placement. See Well materials as appropriate. Site Ignition Sources.  Inspect all high-pressure hoses and fittings.  Ensure that the unit operator assesses the wind General servicing speed and direction to determine if the mast can be Wells often need maintenance or service on surface or raised safely. down-hole equipment. Working on an existing well to  Allow no personnel on the unit, other than the restore or increase oil and gas production is an important operator working at the controls, when raising or part of today's petroleum industry. A well that is not lowering the mast. All others stand clear. producing to its full potential may require service or  Inspect all anchors before rigging up the mast. workover. Anchors should meet American Petroleum Institute (API) specifications for loads and guying patterns. Maintenance activities associated with the well when using [2004 Publications, Programs, and Services. a workover/service rig are: American Petroleum Institute (API), (2004)]  Removing the Horsehead (Pumping unit only)  Use proper lifting techniques.  Removing the Wellhead  Pulling and Running Rods

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Pulling and Running Tubing

Removing the horsehead (Pumping unit only) Typically, the horsehead of a pumping unit must be removed to gain access to the wellhead equipment. Potential Hazards:  Having the unit start up while working on equipment.  Being struck by counterweights on the pumping unit.

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Check wellhead pressure and bleed pressure off before removal. Use the correct tools for each task. Inspect the tools before each use. Wear proper PPE including safety glasses. Keep fingers and hands away from pinch points. Cover open cellars. Wear fall protection as appropriate. Implement a confined space entry program.

Pulling and running Rods To service, repair, or replace the rods or pump, the sucker rod string must be pulled out of the hole. Pulling rods refers to the process of removing rods from the well. Running rods refers to the process of replacing rods in the well.

Possible Solutions:  Use lockout/tagout, to include mechanically securing the flywheel. Potential Hazards:  Being struck by dropped horsehead or caught Potential Hazards: between horsehead and walking beam.  Falling from heights.  Getting fingers and hands pinched and caught Possible Solutions: between tools and/or equipment.  Wear appropriate fall protection including a full  Being struck by falling tools or equipment. body harness. For Fall Protection guidance, consult:  Falling from an elevation. o [29 CFR 1910.23(c)(1)], Fall protection when working from platforms Possible Solutions:  Inspect all slings before use. o [29 CFR 1910.66 Appendix C], Fall  Use tag lines to position the horsehead when protection guidelines removing or lowering and to keep personnel clear o [29 CFR 1910 Subpart D], Walkingof suspended load. working surfaces  Use the correct tools for each task.  Inspect the tools before each use.  Never disconnect personal fall arrest systems while  Keep fingers and hands away from pinch points. working in the derrick.  Secure tools from falling and keep the area below Potential Hazards: clear of personnel.  Getting fingers or hands pinched in or between rod  Use proper PPE and fall protection as required. wrenches, rod elevators, power tongs, rod hook, rod transfer, and rod fingers. Removing well head To begin the process, the wellhead must be removed from Possible Solutions: the casing flange.  Ensure that workers are instructed in proper hand and finger placement when making and breaking rod connections or setting rods on the rod fingers. Potential Hazards:  Being struck by released pressure or flying  Ensure that workers are instructed in proper particles. latching procedures while pulling and running rods.  Being struck by the wrench or hammer while Potential Hazards: removing bolts and fittings.  Being struck by dropped objects.  Getting caught between wellhead, hydraulic Possible Solutions: wrenches, and wellhead fittings.  Wear the proper personal protective equipment  Getting fingers and hands pinched and caught such as: between flanges or valves. o Hard hat  Slips, trips, and falls. o Work gloves  Entering into well cellars. o Safety-toed footwear  Use extra caution while people are working overhead. Possible Solutions:  Stand clear of valves and fittings when removing  Avoid carrying tools while climbing the derrick fitting or bleeding off pressure. ladder. Raise tools with a line to any worker above the derrick floor. Page 13 of 46

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Ensure that all tools and equipment being used are secured with the proper safety lines. Pulling and running tubing Among the reasons for pulling tubing includes replacing a packer, locating a tubing leak, or plugged tubing. Raising or Lowering Traveling Block and Elevator

personnel to review responsibilities and to coordinate the operations to be performed.

Potential Hazard:  Being struck by wireline due to line failure. Possible Solutions:  Keep all non-essential workers out of the immediate work area. Potential Hazards:  Being struck by the elevators and traveling block as  Inspect wireline, rope sockets, and cable heads for they are raised or lowered. defects before use.  Getting fingers and hands pinched between  Operate the wireline at a safe speed. elevators and tongs or tubing collar.  Use an appropriate method to determine the end of line location. Possible Solutions:  Instruct workers to stand clear of tong and slip area when lowering the elevator and traveling block. Potential Hazards:  Use handles on elevators as they are descending  Being struck by wireline, lubricator, sheaves, or into place over the tubing. other equipment.  Getting caught in wireline. Latching or Unlatching Elevators onto the Tubing Possible Solutions:  Keep all non-essential workers out of the Potential Hazards:  Pinching hands or fingers in the elevators. immediate work area.  Being struck by elevators not securely latched.  Inspect all slings, chains, pins or other attachment devices before lifting or suspending tools or Possible Solutions:  Ensure that workers are instructed in proper equipment. latching procedure.  Inspect and maintain elevators. Potential Hazards:  Pinching hands and fingers.  Getting sprains, strains or suffering from Special services Special services are operations that use specialized overexertion. equipment and workers who perform support well drilling Possible Solution: and servicing operations.  Minimize manual handling of lubricators and other Coordination between all personnel is critical for site equipment. safety. Therefore, all special services operations should  Use proper hand placement and tag lines to avoid conduct a pre-job safety meeting to include all personnel on pinch points. the job site. Potential Hazards:  Wireline Operations  Falling from a height.  Well Logging  Receiving burns or being exposed to a respiratory  Perforating hazard due to a fire.  Cementing Possible Solutions:  Stimulation  Use proper fall protection.  Swabbing  Position the unit properly with respect to wind  Hot Oiling direction and distance from potential gas or vapor  Snubbing sources [RP 54, Recommended Practice for  Coil Tubing Occupational Safety for Oil and Gas Well Drilling and Servicing Operations, Wireline Service. American Petroleum Institute (API), (2007, Wireline Operation All wireline operations require special precautions. March)]. Wireline operations may include slick line and electric line operations. Operations completed through the use of Potential Hazard: wireline include logging, perforating, setting of downhole  Being exposed to an unexpected release of tools, fishing, bailing, and swabbing. pressure. Possible Solutions: Note: The special service supervisor should hold a pre-job  Install a pressure release valve in the lubricator sub. meeting with the special service crew and other involved Page 14 of 46

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Bleed pressure from lubricator sub before breaking connections.  Check for an unusually tight connection that may indicate that pressure has not been released. Potential Hazard:  Toppling mast or boom. Possible Solution:  Install foundation, outriggers, and guying according to the manufacturer's recommendations.

below illustrate possible solutions; for more detailed information see Additional Information below.

Possible Solutions:  Keep non-essential workers away from the rig floor and marked-off areas where radiation hazards may be present.  Wear appropriate personnel protective equipment (PPE).  Allow only authorized and qualified logging company personnel to handle the logging tools.  Report any damage to radioactive logging tools. Potential Hazard:  Getting injured due to an unexpected release of pressure.

Cementing Cementing and pumping operations may be performed by specialized pumping services or in conjunction with well servicing operations (such as, casing, squeezing, and zone isolations). The hazards involved will vary with mode of dry cement delivery and mixing as well as the primary designed function of the pumping equipment.

Note: The special service supervisor should hold a pre-job meeting with the special service crew and other involved personnel to review responsibilities and coordinate the operations to be performed.

Potential Hazards:  Surface detonation of explosives. Possible Solutions: Well logging Well logging is used to identify formation and other  Keep all non-essential personnel out of the downhole properties of the well bore. immediate work area.  Post warning signs and prohibit the use of radios, Logging tools can include radioactive, electric, mechanical, telephones, or navigational systems. and sonic tools, among others.  Shut down non-essential electrical systems during gun-arming operations. Note: See also Wireline Operations and Perforating for  Perform operations involving explosives under the descriptions of additional hazards. direct supervision of the special services supervisor.  Report any suspected remnants of explosives to the Potential Hazards:  Being exposed to radiation. special services supervisor.

Note: The special service supervisor should hold a pre-job meeting with the special service crew and other involved personnel to review responsibilities and coordinate the operations to be performed.

Rig Up - Spotting and assembly of equipment to perform cementing or pumping operations. Possible Solutions:  Check for the presence of trapped pressure before opening the tool housing. Potential Hazards:  Being struck by moving vehicles.  Being exposed to potential ignition and respiratory Perforating A specialized crew transports and operates the perforating hazards. equipment. Upon arrival to the site, the tools are assembled,  Overexerting, or getting sprains and strains. then lowered into the well by a wireline unit or conveyed  Being exposed to pinch points (for example, by tubing. Then, a specialized gun shoots small holes into hammer union wings and hammers, pump iron and the casing of the producing zone. racks).  Being hit by flying particles. The perforations allow the oil or gas to flow into the casing  Falling from heights. or liner. If pressure is sufficient, the oil or gas will rise to  Slips, trips, and falls. the surface.  Being struck by falling equipment. Detailed operational procedures and trained personnel are necessary for the safe handling of explosives. The solutions Page 15 of 46

Possible Solutions:  Preplan equipment locations and use a spotter(s) to position equipment out of fall lane of the derrick and upwind of vapor and gas sources.  Use mechanical lifting aids, proper lifting techniques, and team lifting where appropriate.  Use proper hand and body positioning.  Wear proper PPE including fall protection and respiratory protection where appropriate.  Conduct a pre-job inspection to identify, then eliminate or correct hazardous work surfaces.  Require all non-essential personnel to stand clear.  Secure all elevated lines. Pumping - Executing the job Potential Hazards:  Being struck by high pressure lines or unexpected release of pressure (due to, mismatched or excessively worn hammer unions, line failure).  Being exposed to chemical hazards (such as, silica, toxic liquids, and gases).  Being exposed to high noise levels.  Slips, trips, and falls.  Overexerting, or receiving sprains and strains while handling materials (such as sacks and buckets). Possible Solutions:  Direct all non-essential personnel to stand clear.  Require pump operator to stay by the controls.  Conduct adequate pressure tests on pump(s) and lines before pumping. [RP 54, Recommended Practice for Occupational Safety for Oil and Gas Well Drilling and Servicing Operations, Wireline Service. American Petroleum Institute (API), (2007, March)].  Hobble high-pressure lines properly.  Use proper equipment inspection techniques to include hammer unions (Note: This is a particular problem with 602 and 1502, as they will couple but will not hold beyond the lower pressure rating number). o High Pressure Lines and Hammer Unions. International Association of Drilling Contractors (IADC) Alert 98-01, (1998). o More On Mismatched Hammer Unions. International Association of Drilling Contractors (IADC) Alert 99-33, (1999). o Additional Serious Incidents With Mismatched Hammer Unions. International Association of Drilling Contractors (IADC) Alert 00-15, (2000).  Wear proper personal protective equipment (for example, respiratory, skin, and hearing) as appropriate for the hazards present.  Conduct a pre-job inspection to identify, then eliminate or correct hazardous work surfaces.

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Use mechanical lifting aids, proper lifting techniques, and team lifting where appropriate.

Rig Down - Disassembly and demobilization of equipment Potential Hazards:  Being struck by moving vehicles.  Being exposed to potential ignition and respiratory hazards.  Overexerting or receiving sprains and strains.  Being exposed to pinch points (such as, hammer union wings and hammers, pump iron and racks).  Being hit by flying particles.  Falling from heights.  Slips, trips, and falls.  Being struck by falling equipment. Possible Solutions:  Use a spotter(s) to direct equipment movement.  Use mechanical lifting aids, proper lifting techniques, and team lifting where appropriate.  Use proper hand and body positioning.  Wear proper PPE including fall protection and respiratory protection where appropriate.  Conduct a post-job inspection to identify, then eliminate or correct hazardous work surfaces.  Require all non-essential personnel to stand clear. Stimulation Well stimulation involves techniques to optimize well performance. This may include pumping of acids, energized fluids, and various other chemicals to improve formation flow characteristics. Note: The special service supervisor should hold a pre-job meeting with the special service crew and other involved personnel to review responsibilities and to coordinate the operations to be performed. Note: When pumping energized fluids (such as, carbon dioxide or liquid nitrogen) substantial increased hazards exist related to asphyxiation, temperature extremes, and unexpected pressure releases. Use special procedures to ensure the safety of personnel. Rig Up - Spotting and assembly of equipment to perform stimulation operations. Potential Hazards:  Being struck by moving vehicles.  Being exposed to potential ignition and respiratory hazards.  Overexerting or receiving sprains and strains.  Being exposed to pinch points (such as, hammer union wings and hammers, pump iron and racks). Page 16 of 46

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Being hit by flying particles. Falling from heights. Slips, trips, and falls. Being struck by falling equipment. Being injured due to potential ignition of flammable or combustible carrier or base fluids.

Possible Solutions:  Preplan equipment locations and use a spotter(s) to position equipment out of fall lane of the derrick and upwind of vents, vapor and gas sources.  Use mechanical lifting aids, proper lifting techniques, and team lifting where appropriate.  Use proper hand and body positioning.  Wear proper PPE including fall protection and respiratory protection where appropriate.  Conduct a pre-job inspection to identify, then eliminate or correct hazardous work surfaces.  Require all non-essential personnel to stand clear.  Secure all elevated lines.  Provide adequate bonding and grounding for blending, pumping and sand transfer equipment.  Use hose covers or shielding for transfer or suction lines containing flammable liquids.

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Use proper equipment inspection techniques to include hammer unions (Note: This is a particular problem with 602 and 1502, as they will couple but will not hold beyond the lower pressure rating number). o High Pressure Lines and Hammer Unions. International Association of Drilling Contractors (IADC) Alert 98-01, (1998). o More On Mismatched Hammer Unions. International Association of Drilling Contractors (IADC) Alert 99-33, (1999). o Additional Serious Incidents With Mismatched Hammer Unions. International Association of Drilling Contractors (IADC) Alert 00-15, (2000). Wear proper personal protective equipment (such as respiratory, skin, and hearing) as appropriate for the hazards present. Conduct a pre-job inspection to identify, then eliminate or correct hazardous work surfaces. Use mechanical lifting aids, proper lifting techniques, and team lifting where appropriate. Keep non-essential personnel away from markedoff areas where radiation hazards may be present. Allow only authorized and qualified company personnel to handle radioactive tracer materials or radioactive densiometers. Prevent contamination and exercise proper personal hygiene when working around radioactive materials.

Pumping - Executing the job Potential Hazards:  Being struck by high-pressure lines or unexpected  release of pressure (for example, mismatched or excessively worn hammer unions, line failure).  Being exposed to chemical hazards (such as, silica, toxics, asphyxiants). Rig Down - Disassembly and demobilization of  Being exposed to high noise levels. equipment  Slips, trips, and falls.  Overexerting or receiving sprains and strains while Potential Hazards: handling materials (such as sacks and buckets).  Being struck by moving vehicles.  Being exposed to temperature extremes.  Being exposed to potential ignition hazards,  Being exposed to radiation associated with including flammable or combustible liquids or radioactive tracer materials. gases.  Being exposed to potential skin and respiratory hazards. Possible Solutions:  Require all non-essential personnel to stand clear.  Overexerting or receiving sprains and strains.  Direct equipment operators to stay by their  Being exposed to pinch points (such as, hammer controls. union wings and hammers, pump iron and racks).  Conduct adequate pressure tests on pump(s) and  Being struck by particles or fluid. lines and ensure proper valve alignment before  Falling from heights. pumping. Install a check valve as close to the well  Slips, trips, and falls. head as possible [RP 54, Recommended Practice  Being struck by falling equipment. for Occupational Safety for Oil and Gas Well  Being injured due to the unexpected release of Drilling and Servicing Operations, Wireline trapped pressure. Service. American Petroleum Institute (API), (2007, March)]. Possible Solutions:  Hobble high pressure lines properly.  Use a spotter(s) to direct equipment movement.

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Use mechanical lifting aids, proper lifting  Remove all spillage of flammable liquids from techniques, and team lifting where appropriate. equipment, cellars, rig floor, and ground area  Use proper hand and body positioning. adjacent to the wellhead.  Wear proper personal protective equipment (such  Wear proper PPE, including respiratory protection, as fall protection, respiratory, skin, and hearing as required. protection) as appropriate for the hazards present. Potential Hazard:  Conduct a post-job inspection to identify, then  Being struck by a pressurized line. eliminate or correct hazardous work surfaces.  Being exposed to a high-pressure connection failure  Direct all non-essential personnel to stand clear. caused by mismatched or excessively worn hammer  Follow procedures to release trapped pressure unions. safely. Possible Solutions:  Avoid approaching, walking over or standing near pressurized lines. Swabbing Swabbing is the act of pulling fluid from the well bore  Securely anchor pressurized lines to prevent through the use of wire rope and cup assembly. Swabbing whipping or bouncing caused by pressure surges. equipment includes a swabbing assembly, lubricator with  Use proper equipment inspection techniques to an oil saver, and shut-off valve on the well, also called a include hammer unions (Note: This is a particular swabbing valve. problem with 602 and 1502 and others, as they will couple but will not hold beyond the lower pressure rating number). General precautions during all swabbing operations:  Conduct swabbing operations during daylight o High Pressure Lines and Hammer Unions. hours. International Association of Drilling  Keep all personnel clear of the derrick or within six Contractors (IADC) Alert 98-01, (1998).. feet (two meters) of the wellhead during swabbing o More on Mismatched Hammer Unions. operations. International Association of Drilling  Locate swab tanks at least 100 feet (30 meters) Contractors (IADC) Alert 99-33, (1999). from the well, where location allows. o Additional Serious Incidents With Mismatched Hammer Unions. International Potential Hazard:  Loss of well control. Association of Drilling Contractors (IADC) Alert 00-15, (2000). Possible Solutions:  Use appropriate equipment, rated for the expected pressures, to shut in the well. Potential Hazard:  Inspect lubricators, swages, and unions for defects  Being struck by pressurized fluids or the lubricator such as cuts, corrosion, and thread damage before when removing the lubricator from the well. use.  Getting strains and sprains from handling the  Adjust oil savers by remote control with a hydraulic lubricator. pump placed safely away from the wellhead.  Train all personnel in emergency evacuation Possible Solutions: procedures.  Close the shut-off valve and bleed the pressure from the lubricator before removing it. Potential Hazard:  Fire, explosive, or respiratory hazard from leakage  Use a lubricator that will allow removal of the swab or venting of oil or gas from tanks, lines or or other tools with the well shut in (valve closed). lubricator.  Use a dolly or other method to minimize manual handling of the equipment. Possible Solutions:  Place fire extinguishers in accessible positions. Potential Hazard:  Move sources of potential ignition (such as, open  Pinching fingers between swab assembly and fires for melting of babbitt) to designated areas at a lubricator when changing swab cups or mandrels. safe distance from the wellhead or flammable Possible Solutions: liquid storage areas such as the swab tank before  Use a winch line, where available, not the swab swabbing. line, to handle the lubricator.  Make provisions to contain spilled flammable  Use a lubricator that will allow removal of the swab liquids. or other tools with the well shut in (valve closed).  Monitor the oil saver for wear and potential leakage. Page 18 of 46

meeting with the special service crew and other involved Hot oiling A hot oil unit is designed to circulate heated fluid into personnel to review responsibilities and to coordinate the piping, tubing, casing, or tanks for a variety of reasons, operations to be performed. including the removal of paraffin and tar-based oils. Potential Hazards:  Falling from heights.  Being exposed to an unexpected release of pressure, and loss of well control. Potential Hazard:  Fire or explosion hazard from contact with  Being burned by a fire and explosion. flammable liquids, vapors, or gases.  Having limited ingress and egress.  Working in an unstable basket due to lack of guy Possible Solutions:  Locate hot oil trucks and tanks a safe distance (100 wires. feet is recommended) from the well and out of the  Being caught between the rig assist pull down and fall line of the derrick, if it is on site. Where crows nest. impractical, use additional safety measures.  Position hot oil units upwind or crosswind from Possible Solutions: potential sources of flammable liquids, vapors, or  Ensure proper fall protection. gasses. Wind direction indicator should be present  Inspect and maintain all pressure control equipment and visible to the operator. prior to operations.  Shut down hot oiling operation immediately if a  Provide adequate means of access to and exit from leak occurs. the basket.  Make fire extinguishers readily accessible to the  Provide emergency escape method [RP 54, hot oil operator. Recommended Practice for Occupational Safety for  Avoid parking over or placing lines containing Oil and Gas Well Drilling and Servicing flammable fluids under trucks or other vehicles. Operations, Wireline Service. American Petroleum  Install check valve in the pump line as close to the Institute (API), (2007, March)]. well head as possible.  Rig all equipment in accordance with equipment  Inspect all components of the hot oil unit before recommendations. each use.  Ensure proper body and hand placement.  Shut the burner down if the wind dies.  Shut the burner down and reposition equipment if Coil tubing the wind changes direction so as to create a hazard. Technology allows tubing to be manufactured in a continuous coil without joints. Coiled tubing is inserted into the well down the production casing without the need for Potential Hazard:  Being burned by hot oil or hot oil line or frostbite tongs, slips, or elevators. injuries from contact with propane or propane lines. Possible Solution: Potential Hazards:  Wear proper personnel protective equipment such  Pinching fingers and hands. as heavy padded, insulated, leather gloves  Being exposed to an unexpected release of pressure. Potential Hazards: Expert Review  Unexpected release of pressure  Getting struck by falling or shifting objects (such as suspended injector heads). Possible Solutions:  Do not connect heavy joints of pipe to the small  Falling from heights. nipples on the pumping T. Possible Solutions:  Secure all hot oil and discharge lines.  Keep all fingers and hands away from pinch points  Connect the hot oil line directly to the flow line if (such as tubing spool, rollers, injector head). pump pressure exceeds safe limits (500 psi).  Inspect the tools and equipment before use.  Remain clear of pressurized lines.  Rig up boom trucks in accordance with manufacturer's recommendations.  Use fall protection. Subbing Snubbing is the control of a tubing string while running it in or out of a well bore under pressure. Note: The special service supervisor should hold a pre-job Page 19 of 46

Work over Workover activities include one or more of a variety of remedial operations on a producing well to try to increase production.  Sand Cleanout  Repairing Liners and Casing  Well Recompletions o Sidetracking o Plug-Back

Potential Hazard:  The hazards associated with sidetracking are similar to Drilling. Plug back Plug-back places a cement plug at one or more locations in a well to shut off flow from below the plug. Plug-back is also used before abandoning a well or before sidetracking is done.

There are two methods for placing a cement plug in a well: Sand cleanout Sand cleanout operations are performed to remove buildup  Plug-back using tubing. of sand in the wellbore. Hazards are  Plug-back using a dump bailer (see Wireline Operations). Potential Hazard:  Hazards are similar to those for well servicing. See Potential Hazard: Wireline Operations.  The hazards associated with plug-back are similar to Drilling and Cementing. Repairing liners and castings Liners and casing are essentially the same and repair Slip, trip and fall procedures are the same for both. Casing can be damaged There are many ways to protect from slips, trips, and falls. by corrosion, abrasion, pressure, or other forces that create Even so, they still happen and the following are means to holes or splits. A packer is run down the well to locate the either prevent slips, trips, and falls or to minimize the hole in the casing. Fluid is pumped into the casing above consequences if they should happen. the packer. A loss of pressure indicates a hole in the casing.  Wear personal protective equipment (such as hard The following are the principal methods for repairing hats, work gloves, safety shoes, and eye casing: protection).  Squeeze cementing.  Be aware of the slipping and falling hazards when  Patching a liner. working on the drilling floor, servicing rig floors or  Replacing casing. other platforms.  Adding a liner.  Keep all work areas clean and clear of oil, tools,  Opening collapsed casing. and debris.  Use non-skid surfaces where appropriate.  Provide guardrails and guards around work areas Potential Hazard:  Hazards are similar to those for installing casing. that are prone to slips, trips, and falls. See Casing Operations and Cementing.  Install, inspect, and secure stairs and handrails. [29 CFR 1926.1052]  Instruct workers on proper procedures for using and Side tracking Sidetracking is the workover term for drilling a directional installing ladders. hole to bypass an obstruction in the well that cannot be  Use only ladders in good repair that do not have removed or damage to the well, such as collapsed casing missing rungs. that cannot be repaired. Sidetracking is also done to deepen  Do not install stairs with missing or damaged steps. a well or to relocate the bottom of the well in a more Repair them before installing them. productive zone, which is horizontally removed from the  Keep walkways clean and free of debris and original well. tripping hazards. [29 CFR 1910.22]  Keep all cords and hoses orderly and clear of To sidetrack, a hole (called a window) is made in the casing walking spaces. above the obstruction. The well is then plugged with  Cover open cellars. cement below the window. Special drill tools, such as a  Conduct a pre-job inspection to identify, then whipstock, bent housing, or bent sub are used to drill off at eliminate or correct hazardous work surfaces. an angle from the main well. This new hole is completed in  Walking/Working Surfaces Standard requires [29 the same manner as any well after a liner is set CFR 1910.22(a)(1)]: Keep all places of employment clean and in an orderly condition. Page 20 of 46

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Keep aisles and passageways clear and in good removed. repair, with no obstruction across or in aisles that could create a hazard [29 CFR 1910.22(b)(1)]. Potential Hazards: Provide floor plugs for equipment so power cords  Being struck by rig equipment (such as casing need not run across pathways. jacks, power tongs, and casing elevators).  Use waterproof footgear to decrease slip/fall  Being exposed to other hazards similar to those hazards. encountered during regular drilling or workover operations. Strains and sprains General solutions for strains and sprains include:  Use proper lifting technique. Possible Solutions:  Hoist slowly to limit pipe momentum.  Solutions are similar to those found in Tripping  Seek assistance when moving awkward and heavy Out/In and Casing Operations. guards and covers.  Use proper stance and slip-lifting techniques. Slips Place cement plugs have three handles and should be lifted jointly by Cement plugs are placed in the borehole to prevent more than one person. migration of fluids between the different formations. This  Use lifting equipment and limit manual positioning also prevents the migration of gas or fluids to the surface. of elevators.  Practice proper hand placement and use of pullback Potential Hazards: (tail) ropes.  Being struck by pressured lines when pumping  Use mechanical lifting aids, proper lifting cement. techniques, and team lifting where appropriate. Possible Solutions:  Use proper hand and body positioning.  Instruct personnel to stand clear of pressurized  Ergonomics. OSHA Safety and Health Topics lines. Page. o Hand Injury Use of mud o Lifting Mud is a vital part of drilling operations. It provides o Repetitive motions hydrostatic pressure on the borehole wall to prevent uncontrolled production of reservoir fluids, lubricates and cools the drill bit, carries the drill cuttings up to the surface Weather conditions Weather conditions can create hazardous working and forms a "filter-cake" on the borehole wall to prevent conditions: therefore it is necessary to monitor weather drilling fluid invasion. To fulfill these tasks effectively, the conditions and forecasts to allow time to prepare for such mud contains carefully chosen additives to control its conditions as may occur. Lightning is especially hazardous chemical and rheological properties. and unpredictable. When lightning is present, crews must avoid situations where they could become part of potential Drilling mud is usually a shear-thinning non-Newtonian current paths. fluid of variable viscosity. When it is under more shear, such as in the pipe to the bit and through the bit nozzles, viscosity is lower which reduces pumping-power Plug and abandon well A well is abandoned when it reaches the end of its useful requirements. When returning to the surface through the life or is a dry hole. much roomier annulus it is under less shear stress and  The casing and other equipment is removed and becomes more viscous, and hence better able to carry the salvaged. rock cuttings. Bentonite is commonly used as an additive to  Cement plugs are placed in the borehole to prevent control and maintain viscosity, and also has the additional migration of fluids between the different benefit of forming a mud-cake (also known as a filter cake) formations. on the bore-hole wall, preventing fluid invasion.  The surface is reclaimed.  Removing Casing Barite is commonly used to "weight" the mud to maintain  Place Cement Plugs adequate hydrostatic pressure down-hole. This is critical in a drilling operation to avoid a kick and ultimately a blowout from uncontrolled production of formation fluids. The Removing casing The rig is used to remove the casing and plug the well. The "mud-pits" at the surface have their levels carefully wellhead is removed. After the casing is cut off, it is monitored, since an increase in the mud level indicates a Page 21 of 46

kick is taking place, and may require shutting in the well Oil Well Stimulation and circulating heavier weighted drilling mud to prevent Oil well stimulation plays a vital role in production further formation fluid or gas production. operations. With oil prices at all-time highs, it is imperative from an oil company's perspective and the consumer's Drilling fluid must be chemically compatible with the perspective that as much production as possible be safely formations being drilled. Salinity must be chosen so as not extracted from the reservior. to cause clay swelling or other problems. Mud can be "oil- Why? So, the oil company can realize the highest price per based" or "water-based". In many areas oil-based muds are barrel, and the consumer can get more oil circulating in being phased out, as they are less environmentally friendly, supply to balance demand. But then, we digress... although in some formations they are necessary because of It has been said by many wise petroleum investors chemical compatibility issues. Offshore rigs typically use (oxymoron?) that the industry's saving grace is that their synthetic oil based mud. assets are in the ground! Once found, they argue, it is difficult to lose. Clearly, these investors weren't reservoir engineers as will be explained below. Important Fluid Properties One of the most important mud properties is the mud Producing that oil isn't as simple as running the kitchen weight (density). If the mud weight exceeds the fracture faucet and watching the basin fill-up (see oil production pressure of the formation, the formation may fracture and discussion) . Natural production tendencies for wells are for large quantities of mud are lost to it, in a situation referred the oil production rates (and reservoir pressure) to be at its to as lost circulation. These cracks can also cause water to highest at initial production, and fall-off considerably as the seep into the well bore or into a hydrocarbon bearing zone, well is produced. Typically, one finds oil rates declining as which would likely impede the ability of the formation to water production increases, driving up operations costs produce oil (or require the separation of large quantities of while revenue shrinks. This scenario continues until the water). well fails and/or becomes uneconomic to operate or repair. The purpose of oil well stimulation, then, is to increase a Conversely, if the mud weight is too low it will have a well's productivity by restoring oil production to original hydrostatic pressure that is less than the formation pressure. rates less normal decline, or to boost production above This will cause pressurized fluid in the formation to flow normal predictions. into the wellbore and make its way to the surface. This is referred to as a formation "kick" and can lead to a So, what is oil well stimulation? potentially deadly blowout if the invading fluid reaches the Oil well stimulation is the general term describing a variety surface uncontrolled. of operations performed on a well to improve its productivity. Other important mud properties to be maintained are the YP Stimulation operations can be focused solely on the (Yield Point) which determines the carrying capacity of the wellbore or on the reservoir; it can be conducted on old mud to carry the drill cuttings to the surface. Mud should be wells and new wells alike; and it can be designed for capable of forming a thin "mud cake" which forms a lining remedial purposes or for enhanced production. Its main two of the borehole walls. types of operations are matrix acidization and hydraulic fracturing. Matrix acidization involves the placement of acid within the Drilling Fluids Companies Drilling fluids operations are often contracted to service wellbore at rates and pressures designed to attack an companies, a trend commonly observed in the oil industry impediment to production without fracturing or damaging for most of it operations. The largest three companies for the reservoir (typically, hydrofluoric acid is used for mud services are M-I SWACO (A Schlumberger sandstone/silica-based problems, and hydrochloric acid or Company), Baroid Drilling Fluids (Halliburton Oilfield acetic acid is used for limestone/carbonate-based Services), and Baker Hughes Drilling Fluids. There are, problems). Most matrix stimulation operations target up to however, many smaller companies providing drilling fluid a ten foot radius in the reservoir surrounding the wellbore. services as well. Hydraulic fracturing, which includes acid fracturing, involves the injection of a variety of fluids and other Labels: barite, bentonite, drilling fluid, drilling fluids materials into the well at rates that actually cause the engineer, drilling mud, mud engineer, mud engineer's duty, cracking or fracturing of the reservoir formation. The mud engineering, mud logging, mud system, use of mud variety of materials includes, amongst others: water, acid, special polymer gels, and sand. The fracturing of the reservoir rock and the subsequent filling of the fractured voids with sand ("proppant") or the creation of acid Page 22 of 46

channels allows for an enhanced conduit to the wellbore or introduced in surface flowlines on a regular basis to from distances in excess of a hundred feet. prevent scale precipitation and build-up. Operational techniques such as bringing on production or injection slowly after stimulation activities (to prevent So, why do wells need oil well stimulation? Hydraulic fracturing and acid fracturing in practically all damaging flow surges which could mobilize once immobile types of formations and oil gravities, when done correctly, fines within the pores, plug perforations, or cause sand have been shown to increase well productivity above that control problems downhole or at the surface), and routine projected in both new and old wells. From an economic maintenance and surveillance (like cleaning out process standpoint, oil produced today is more valuable than oil filter traps which can easily clog lines and cause the transfer produced in the future. Fracturing candidates may not of damaging suspended particles, or monitoring production necessarily "need" oil well stimulation, but the economics decline to identify potential deviances before the problem is may show that such a treatment would pay=off. exacerbated). To understand why remedial stimulation (matrix Importantly though, a sound understanding of formation acidization) is necessary, you have to consider the damage causes, and the inclusion of chemists/chemical conditions at work, deep down inside the reservoir... engineers on the production team will lead to increased well Before the well is ever drilled, the untapped hydrocarbons productivity and life. sit in the uppermost portions of the reservoir (atop any present water) inside the tiny pore spaces, and in equilibrium at pressures and temperatures considerably Oil Well Drilling different from surface conditions. So, How Are Oil Wells Drilled? Once penetrated by a well, the original equilibrium Oil well drilling has been the main means of producing oil condition (pressure, temperature, and chemistry) is ever since Colonel Drake drilled that first well in 1859, permanently changed with the introduction of water or oil- which signaled the start of the American petroleum based drilling fluids loaded with suspended clays, and the industry. circulation of cement slurries. The interaction of the Drilling techniques and equipment have changed introduced fluids with those originally present within the throughout the decades from cable tools to rotary-based reservoir, coupled with pressure and temperature changes ones, from straight holes to sidetrack and GPS-based can cause a variety of effects which, in turn, can plug the directional drilling, and from ―guess-timates‖ and ―feel‖ to numerous odd-shaped pores causing formation damage. computer-based accuracy. Some of the types of damage include: scale formation, clay The biggest improvement in oil well drilling, however, swelling, fines migration, and organic deposition. has been in the preparations prior to ever breaking Petroleum engineers refer to the level of formation damage ground. around the wellbore as skin effect. A numerical value is The drilling of a well, especially a ―wildcat‖ (see oil used to relate the level of formation damage. A positive exploration discussion), is a milestone event, involving skin factor reflects damage/impedance to normal well practically every sub-discipline of the oil business, and productivity, while a negative value reflects productivity signifies the start of direct field investigation. enhancement. For the oil exploration and production company, the drilling Formation damage, however, is not limited to initial of the well represents final exploration sunk costs prior to production operations. Remedial operations of all kinds the possibility of recovering those costs through well from well killing to well stimulation itself, can cause production revenues. For the petroleum geologist and the formation damage. Nor is fines and scale generation limited reservoir engineer, the drilling of the well represents the to the reservoir. They can also develop in the wellbore in final confirmation of the interpretation of numerous strands casing and tubulars, and be introduced from surface of indirect evidence of oil‘s presence. For the production flowlines and incompatible injection fluids. These fines and and facilities engineers, it represents the soon to be realized precipitates can plug pores and pipe throughout an entire oil asset requiring sub-surface and surface management and field. equipment to maximize production (see oil production In short, any operation throughout a well's life can cause discussion). And, for the drilling engineer, well, it is time to formation damage and impede productivity. earn their pay! So, how do you keep from damaging the formation Through experience and communications with while stimulating a well? geologists, reservoir engineers, production engineers, Oil field service companies offer chemical inhibitors useful and facilities engineers - the technical team - the drilling for the full spectrum of well operations that can be injected engineer develops a plan for reaching the targeted into the well ahead of acidization or other such stimulation formation at the bottomhole location identified, from activities to reduce fines generation and organic deposition, the surface location specified – at the cost authorized. Page 23 of 46

Before ever setting up on the drilling location, the drilling engineer has gained all of the necessary approvals to drill from company and regulatory authorities (click here for regulatory contact information). The appropriate hole dimensions, the wireline testing procedures, the well casing program, and the cement volumes are all known upfront (see well capacity tables). The drilling engineer has already scheduled an oil well drilling rig, alerted a wireline and cementing service company, and ordered necessary drilling fluids, tanks, pipe and safety equipment (including blowout prevention equipment; Click here to view oil field service company contacts ). Operations normally proceed on a 24 hours per day basis and depending on methods, depths, and rock types encountered, can last anywhere from a few days to several months. History has shown that rarely do operations proceed in a ―normal‖ fashion. Each well is its own story. It is quite normal to encounter hard rock zones, and experience sand control problems, as well as for minor equipment breakdowns to occur - right next to a well which didn't experience half of the problems! Drill bits wear out, wrong auxiliary equipment is delivered, and various other events happen that slow progress, raise corporate anxieties, and compromise schedules. Due to all of the problems, which can and do happen on site, oil companies have increasingly focused on safe operations. This is something everyone can control. Most oil well drilling operations are actually completed by drilling service companies, with oil company drilling engineers supervising. Oil companies are using their natural leverage by insisting on safe operations by contractors, which minimize employee ―accidents‖ and environmental impacts, and maximize accountability. Drilling service companies with poor safety records are not kept for long. Drilling Operations Operations proceed in accordance with terms of a permit issued by the regulatory agency with jurisdiction. Normally, a drilling location is graded, a conductor pipe is set to support subsequent casing strings, blowout control equipment is installed and tested for well safety, the drilling rig and auxiliary equipment is moved in and set up, and drilling operations are underway. Contemporary drilling operations consist of downhole tools (drill bits, reamers, shock absorbers, etc.), drill string components (drill collars, drillpipe, kelly, etc.), suspension equipment (rotary swivel, hook, blocks, and wire rope), supporting structures (derrick), rotary drive mechanism (rotary table, turbodrill, dynadrill), hoisting equipment (drawworks, auxiliary brakes, cathead, etc.), transmission systems (mechanical transmission, clutch, belts, and chains), prime movers (diesel, turbo-electric), hydraulic circulating system (slush pump, high pressure surface

equipment, drill string, shale shaker, desander, degasser, mud tanks/mixers), and rig floor and wellhead accessories/tools (cat lines, elevators, rotary slips, power slip, safety clamps, power tongs, rig instrumentation, blowout prevention equipment, etc.) (look at a picture of a drilling rig). Although each area is vitally important to safe and efficient drilling operations, the drill string including the downhole tools is the most important area; being at the point of impact, transmitting surface derived energy into bottomhole torque and hole digging. The drill string/subsurface assembly is composed primarily of a swivel, a kelly, drillpipe, a drill collar, and a bit. The swivel connects the rotating drill string to the drilling rig support system. It suspends the drill string, permits free rotation and serves as the means for drilling fluid circulation. Drilling fluid is circulated through the drill pipe and bit to cool the bit and assist in cuttings removal. The drilling fluid also serves to coat the open-hole to prevent cave-ins and prevent any reservoir fluids (oil, gas and water) encountered from rushing in. The swivel connects to the kelly, which is usually either a square or hexagonal-sided pipe of about 43 feet long, that transmits the torque from the rotary table on the rig floor to the drill string causing the bit to turn and make hole. Drill pipe sections are connected to the kelly one at a time allowing the bit to work deeper and deeper in the hole. The drill collar is a heavy-walled pipe which connects the drill bit to the drillpipe. Its weight puts pressure on the bit to keep it working at the bottom of the hole. The drill bit is the primary downhole tool, cutting up formation as it rotates. Diamond bits are used for hard formations. However, tri-coned steel-teethed bits are most commonly used today. Sometimes, geologists inspect the cuttings that are circulated to surface to identify and confirm the formation that is currently being drilled. At various and defined intervals, the well may be logged by wireline service companies. Why is this done? Well logging tells the industry experts the formations they are in, the fluids present within the formation (including oil!) and the quality of the cement job. Metal pipe called surface casing is inserted into the well once the drillpipe is removed, and is cemented to the earth by cementing service companies. Cement is pumped and circulated within the well to permanently affix the pipe to the earth. This provides support, and limits communication between the surface and the subsurface to just that space inside of the pipe. Subsequent drilling punctures the bottom of the recently placed cement sheath and continues down to the objective depth. To drill deeper, the rig crew performs the seemingly routine act of ceasing rotary table rotation and mud circulation, lifting the drill string, setting it on slips at the Page 24 of 46

rig floor, breaking the joint between the kelly and the topmost drillpipe with tongs, screwing on an additional length of drillpipe at the kelly, lifting the string again, removing the slips, lowering the string downhole, and reestablishing mud circulation and rotary table rotation. Intermediate casing might be run in hole and cemented, too, depending on well design criteria and formation characteristics. When the total depth is reached a final cement job is conducted to either plug the well back up because no significant hydrocarbon was found, or to secure the production casing string in place for future completion and production. The drilling contractor rigs down and moves off of the drilling location and heads on to the next assignment. Oil Exploration So, How Is Oil Found? It all begins with oil exploration... Petroleum geologists and engineers have established that oil, when trapped, collects into underground pools called reservoirs. It is from these reservoirs that oil is produced. So, all these geologists have to do is find the oil reservoirs and sit back and watch the oil production flow! Couldn‘t be easier right? Well, not exactly. It is said that the best place to find oil is in an oilfield. This is true, without question. But, what do you do when there is no defined oilfield, and there are no nearby wells? It sounds quite simplistic but, think about it, every major oilfield must have begun with the drilling of the field‘s first well. How did they know where to drill the well, and how did they convince their bosses that drilling that well was worth the expensive research and drilling costs? Doesn't sound so easy now, eh? If you're thinking there's some risk to all of this, well there definitely is tremendous risk! The industry calls these wells miles away from known production, wildcats. Depending on the results of their attempts at finding hydrocarbon, the wells are known as discovery wells or dry holes. If the discovery well shows hydrocarbon, other development wells are drilled to confirm the find. If nothing is found, well, the operator will simply abandon the well and move on to other prospects and plays. Through the utilization of a variety of high and low-tech tools and methodologies, today’s producing reservoirs were discovered. The presence of oil seeps and pits at surface is a strong indication that oil may be present underground. If a trapping mechanism exists below, one may have found a reservoir. The surface exposure (outcropping) of known source and reservoir rock suggests the right conditions for oil generation and storage may be present. If a trap of some

kind were detected, it is possible that a reservoir could be discovered. So, how do geologists detect reservoirs miles below the surface of the earth? The only direct way of confirming oil’s presence is to drill a well. But, drilling a well is an expensive proposition. Most wells cost in excess of $100,000 to drill, and many cost over $1,000,000. Given that the success of finding commercially producible-sized hydrocarbon reservoirs is approximately 1 in 10 chances, oil companies - out of sheer necessity - seek to minimize the cost of failed wildcats by exhausting all reasonable indirect methods of locating hydrocarbons first. Seismic surveys, using a variety of sonic wave producing guns and extra-sensitive listening devices, allow geophysicists to obtain profiles (cross-sections) of subsurface rock at great depths. If a trap of some sort can be deduced from the sub-surface reflections, there is a chance that oil or gas can be found. Gravitational and magnetic surveys are flown by aircraft over areas on land and sea to identify the geophysical properties which might suggest the presence of hydrocarbon bearing traps. Ultimately, though, it is only by drilling the well that the indirect observations will be confirmed. Drilling process summary These and other needs in the art are addressed in one embodiment by a method for drilling a borehole in an earthen formation. In an embodiment, the method comprises (a) providing a drilling system including a drillstring having a longitudinal axis, a bottom-hole assembly coupled to a lower end of the drillstring, and a drill bit coupled to a lower end of the bottom-hole assembly. In addition, the method comprises (b) rotating the drill bit at a rotational speed. Further, the method comprises (c) applying weight-on-bit to the drill bit and advancing the drill bit through the formation to form the borehole. Still further, the method comprises (d) pumping a drilling fluid down the drillstring to the drill bit. The drilling fluid has a flow rate down the drillstring. Moreover, the method comprises (e) oscillating the rotational speed of the drill bit during (c). The method also comprises (f) generating non- steady state conditions in the borehole during (e). These and other needs in the art are addressed in another embodiment by a method for maintaining non-steady state conditions in a borehole being drilled in an earthen formation. In an embodiment, the method comprises (a) providing a drilling system including a drillstring having a longitudinal axis, a bottom-hole assembly coupled to a lower end of the drillstring, and a drill bit coupled to a lower end of the bottom-hole assembly. In addition, the Page 25 of 46

method comprises (b) applying torque to the drill bit to rotate the drill bit. The drill bit has a rotational speed and a rotational acceleration. Further, the method comprises (c) applying weight-on-bit to the drill bit to advance the drill bit through the formation to form the borehole. The drill bit has an axial speed and an axial acceleration. Still further, the method comprises (d) pumping a drilling fluid down the drillstring to the drill bit. The drilling fluid has a flow rate down the drillstring and a pressure at an inlet of the drillstring. The rotational speed of the drill bit, the rotational acceleration of the drill bit, the axial speed of the drill bit, the axial acceleration of the drill bit, the flow rate of the drilling fluid down the drillstring, and the pressure of the drilling fluid at the inlet of the drillstring is each a drilling parameter. Moreover, the method comprises (e) controllably oscillating two or more of the following drilling parameters during (c): the rotational speed of the drill bit; the rotational acceleration of the drill bit; the axial speed of the drill bit; the axial acceleration of the drill bit; the flow rate of the drilling fluid down the drillstring; and the pressure of the drilling fluid at the inlet of the drillstring. These and other needs in the art are addressed in another embodiment by a computer- readable storage medium. In an embodiment, the computer-readable storage medium comprises software, when executed by a processor, causes the processor to (a) receive a predetermined maximum rotational speed for a drillstring, a predetermined minimum rotational speed for the drillstring, and a predetermined set point for the rotational speed of the drill bit. In addition, the software, when executed by the processor, causes the processor to (b) monitor the rotational speed of the drillstring. Further, the software, when executed by the processor, causes the processor to (c) control the rotational speed of the drillstring. Still further, the software, when executed by the processor, causes the processor to (d) oscillate the rotational speed of the drillstring about the predetermined set point for the rotational speed and between the predetermined maximum rotational speed and the predetermined minimum rotational speed. Thus, embodiments described herein comprise a combination of features and advantages intended to address various shortcomings associated with certain prior devices, systems, and methods. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description, and by referring to the accompanying drawings.

in working on these problems, but should not be considered the exclusive controlling factor. Solution to these problems often requires adjustments of mud composition, mud properties, and operational procedures such that all facets of the problem are relieved. Drilling problems and wellbore instability is interrelated. It is important to understand the possible connections, first to diagnose the problem and, second to take appropriate remedial actions.

1. Loss of circulation/ Mud losses Lost circulation occurs when a very porous and permeable formation is encountered in the subsurface. The drilling mud flows into the formation without building up a filter cake. During lost circulation, more mud is being pumped down the well than is flowing back up. These can be classified as total losses (lost circulation) or partial losses with some gains (wellbore breathing). In an intact formation, a hydraulic fracture is initiated by too high a mud weight. The high mud pressure causes tensile failure. Following fracture initiation, the fracture may propagate depending on the maximum borehole pressure and take in drilling fluid. When the borehole pressure is reduced the initiated fractures close and may give mud back (often associated with a build-up in annular pressure). Remedy To stop the loss of drilling fluids, the voids must be plugged so that a filter cake can be formed on the porous section. The plugging material must be of such consistency or contain particles of such sizes as to offer greater resistance of the drilling fluid into the voids than the resistance to movement upward through the annulus such as mica flakes, ground pecan hulls, sugar cane hulls, shredded cellophane, and even shredded paper money to solve lost-circulation problems. The old proverb, "prevention is better than cure," stands fast when it come to the problem of loss circulation. Prevention  Maintain proper mud weight  Minimize annular friction pressure  Maintain adequate hole cleaning  Set casing to protect weaker formations  If anticipated, treat mud with lost circulation materials If it happens  Pump lost circulation materials in the mud  Seal the zone with cement or other blockers  Set casing Drilling problems  Dry drill (clear water) Borehole problems related to drilling fluids and their No other problem in drilling is so dependent upon the remedies: A number of major drilling-problems are directly related to practices of the driller. Circulation losses can be avoided in zones known to be troublesome by simply adhering to the drilling fluid and drilling practices. Mud is a useful tool good drilling practice: Page 26 of 46

2. Stuck pipe Differential-pressure is the major cause of stuck pipe and the characteristics of differential-pressure sticking are;  Bit off bottom and pipe immovable,  Permeable formations exposed in the hole,  Circulating rate and pressure normal after drill string sticks. From what you have read of the mechanism of wall-sticking, certain practices in mud control obviously help avoid stuck pipe. These are  Minimum mud weight for least pressure differential and to assure low solids content for thin wall-cake,  Low filtration rate for slowest build-up of cake when circulation is stopped, and  Minimum friction between the wall-cake and the pipe. Least friction will be assured by keeping the mud free, and by adding a lubricating agent Remedy The prevention or solutions of these various causes of stuck pipe are different and require correct identification before taking remedial action. Unfortunately, it is not always easy to identify the specific cause of pipe sticking and an incorrect assumption may lead to treatment which is detrimental. For instance, differential pressure sticking may be assumed when inadequate hole cleaning is the actual problem. If lignite and lignosulfonate are added to decrease the fluid loss and relieve the differential sticking problem, they will thin the mud and make the hole cleaning worse. Consequently, we must be careful not to jump to an incorrect conclusion and take action that will magnify the problem. Probably the best method of identification is by a process of elimination of all other possible causes. In differential pressure sticking, oil is often added to a mud to prevent sticking. It not only reduces the fluid loss but also decreases the coefficient of friction of the cake. Emulsified oil droplets are deformable under pressure and apparently spread, under the force of the pipe, against the cake and lubricate the interface. Diesel oil, although a poor lubricating oil, works quite well. Special additives can be added to diesel oil to improve its performance. Oil must be well emulsified in order to function properly. In pipe sticking due to poor hole cleaning, we are interested in increasing the yield point at the temperatures that exist downhole. Addition of bentonite is a quite efficient method for increasing the yield point. This is especially true when it is allowed to flocculate. Thinners should not be used when attempting to increase the yield point. In light-weight muds, flocculation can be promoted by addition of lime or soda ash. This causes high yield points to be developed with low plastic viscosity and allows for both good hole cleaning and fast penetration rates.

In pipe sticking due to plastic flow of salt, When sticking due to salt flow occurs, fresh water should be spotted over the stuck interval. Some of the water should be left in the pipe so that the water over the stuck interval can be replaced periodically to maximize the dissolving rate. 3. Drill Bit Jamming: The drill pipe and bit may become jammed when the drilling fluid is not allowed to thoroughly clean the borehole prior to stopping to add another joint of drilling pipe or the fluid is too thin to lift gravel from the bottom of the borehole. Remedy Therefore, if the drill bit starts to catch when drilling, stop further drilling and allow the drilling fluid to circulate and remove accumulated cuttings from the borehole. Then continue to drill at a slower rate. If it continues to catch, thicken the drilling fluid. If the drill bit and pipe become jammed, stop drilling and circulate drilling fluid until it is freed. If circulation is blocked, try to winch the bit and pipe out of the borehole. Stop the engine and use a pipe wrench to reverse rotation (no more than 1 turn or the rod may unscrew!). Rapidly hit the drill pipe with a hammer to try and jolt the bit free. If these actions are not successful, use lengths of drill pipe without a bit attached or Wattera tubing to "jet out" the cuttings. Attach the pipe or tubing directly to the discharge hose from the mud pump. Thicken the drilling fluid to ensure that the cuttings holding the bit can be removed. Then place tension of the stuck pipe with the drill rig winch. Once fluid starts to circulate out of the borehole; slowly push the jetting pipe/tubing down the borehole beside the jammed drill pipe until the bit is reached. When fluid starts to circulate out of the stuck pipe and/or it loosens, pull the stuck drill pipe and resume circulation of the thickened drilling fluid back down the drill pipe and bit. Remove the jetting pipe. If water freely circulates out the borehole, slowly lower the drill pipe and bit and resume drilling. 4. Drilling Fluid Backflow: Sometimes drilling fluid comes up through the drill pipe when the swivel is disconnected. This is caused by falling soil particles pressurizing drilling fluids at the bottom of the hole. Immediate action is required because this occurs when either the borehole is caving-in or when drill cuttings have not been cleaned well enough from the borehole. Remedy If you notice backflow of drilling fluid, immediately reconnect the drill pipe and continue circulation to clean-out the cuttings. If caving is suspected, thicken the drill mud while continuing circulation.

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5. Damage of reservoir rocks Some reservoir rocks can be damaged by forcing drilling mud into them. This can be caused by using too heavy an overbalance while drilling. The drilling mud clogs the pores or causes chemical or physical changes in the rock. This decreases the rock's permeability near the well bore. Formation damage prevents or reduces production from the reservoir rock when the well is completed. 6. Blowout An unexpected pressure in the subsurface can cause a blowout. The overbalance is lost and the fluids flow out of the subsurface rocks into the well in what is called a kick. As the water, gas, or oil flows into the well, it mixes with the drilling mud, causing it to become even lighter and exert less pressure on the bottom of the well. The diluted drilling mud is called gas cut, salt-water cut, or oil cut. Remedy The blowout preventers are immediately thrown to close the hole and heavier drilling mud is pumped into the well through a choke manifold to circulate the kick out. 7. Hole cleaning Hole cleaning is one of the basic functions of any drilling fluid. Cuttings generated by the bit, plus any caving and/or sloughing must be carried to the surface by the mud. Failure to achieve effective hole cleaning can lead to serious problems, including stuck pipe, excessive torque and drag, annular pack-off, lost circulation, high mud costs and slow drilling rates. Cuttings transport is affected by several interrelated mud and drilling parameters. Removing cuttings from below the drill bit is still a crucial function of a drilling fluid. The circulatory fluid rising from the bottom of the well bore carries the cuttings toward the surface. Under the influence of gravity, these cuttings tend to fall through the ascending fluid. This is known as slip velocity. Remedy The slip velocity will depend upon the viscosity (thickness) and density of the fluid. The thicker the fluid, the lower the slip velocities. The more dense the fluid, the lower the slip velocity. For effective cuttings removal, the fluid velocity must be high enough to overcome the slip velocity of the cuttings. This means that fluid velocity can be lowered in a highly viscous (thick) or very dense fluid and cuttings still effectively removed from the well bore. In general, hole cleaning ability is enhanced by the following:  Increased fluid density  Increased annular velocity  Increased YP (yield point) or mud viscosity at annular shear rates.

8. Health effect associated with drilling fluids contact: The risk of adverse health effects from drilling fluids is determined by the hazardous components of the fluids, additives and by human exposure to those components. Skin irritation and contact dermatitis are the most common health effects observed from drilling fluids exposure in human beings, with headache, nausea, eye irritation, and coughing seen less frequently. The effects are caused by the physico-chemical properties of the drilling fluid as w ell as the inherent properties of drilling fluid additives, and are dependent on the route of exposure such as dermal, inhalation, oral and others. Remedy Always wear protective gears and for environmental protection, several nontoxic substitutes for diesel oil have been placed on the market. These materials consist of alcohols, vegetable oils, specially refined mineral oil with low toxicity, surfactants, and other water-soluble lubricants. In general, they are very expensive and must be used in quite low concentrations. As a result, their performance does not compare to that of diesel. 9. Washout or hole enlargement: Enlargement of borehole, commonly referred to as washout, is caused by hydraulic erosion, mechanical abrasion due to the drill string and inherent sloughing of shale formations, excessive cuttings return at surface, excessive hole fill after tripping, mud volumes in excess of calculated amount, oversize hole from LWD calipers, etc. Washouts can be explained primarily by two mechanisms, borehole collapse of a portion of the wellbore due to insufficient mud weight and/or hole erosion due to improper mud chemistry design. The associated problems include difficulty in cementing, potential hole deviation, an increase in hydraulic requirement for effective hole cleaning and difficulty in some logging-tool operations. Remedy Generally, proper mud design, lower hydraulics and elimination of severe drill string vibrations can minimize the problem. 10. Borehole Instability This is caused by mechanical in situ stresses, erosion due to drilling fluids, chemical interaction of fluids and formations. These lead to problems such as hole Closure, increase in torque and drag, pipe sticking, running and seating casing, hole enlargement, difficulty in cementing, increase chance of hole deviation, hydraulic problems in cleaning the hole, trouble logging the well, fracturing of the formation, lost circulation and kick potential, formation collapse, pipe sticking, loss of the hole and generally producing formation damage defined as ―the impairment of Page 28 of 46

the unseen by the inevitable, causing unknown reduction in the un-quantifiable.‖ Remedies  Lower mud weight  Water loss control 11. Altered, damaged or plastic zone. This corresponds to near-wellbore zone of shale altered as a result of hydration or swelling. Improperly designed waterbased muds can lead to shale hydration or swelling. Main problems associated with sticky hole are increased torque and drag and key seat, especially in high angle holes. INTRODUCTION TO DRILLING FLUIDS Over the past decade or so there has been need for improvements in drilling fluids. In modern day drilling the drilling fluids plays a critical part not only as the primary well control but as a source of transmitting information from the well bore to surface. It is often the fluid that will indicate any pending or changes developing down hole This section will attempt to introduce you to the primary uses of the drilling fluid and hopefully with the help of many of the Mud Engineer that visit the site give you a far better insight to the many function we have come to expect from the fluid and the companies that supply the many chemicals that go to make up the drilling fluids. It will also bring into to the picture mud cleaning equipment and the circulating system along with Hydraulics Just how much faction expected from the fluid can be seen from the list below.  Removes cuttings from the bottom of the hole and carries them to the surface  Holds cuttings and weight material in suspension when circulation is interrupted  Releases sand and cuttings at the surface  Walls the hole with an impermeable cake  Minimizes adverse effects upon the formation  Cools and lubricates the bit and drill string  Supports part of the weight of the drill stem and casing  Controls subsurface pressure  Transmits hydraulic horsepower  Maximizes down hole information obtained  Transmit electronic data from down hole tools.  Help preserver and protect the drill string and casing From the list we now start to see how important the drilling and workover fluid is for safe and successful drilling and completion operation. Each page on the menu will be dedicated to one subject to enable information to be added. Other pages will be made up to incorporate new information as and when I is gathered.

During the course of the past years a lot of effort has been put into, finding, sourcing and begging companies into getting together enough information to make this section interesting. We in the industry have a phobia when it means parting with anything that may be of value or help to others, however we as drilling people are not interested in the secret formulas that go into designing a particular chemical only in the results. Drillers that understand the function of any fluid are a bonus to an operation. Drillers of to-day have a far better education and understanding of what is going on around them. Consultant need to understand and must continue to keep ahead if they are to perform to the best of their ability. HYDRAULIC HORSEPOWER HYDRAULIC HORSEPOWER The drilling fluid is the medium which transmits available hydraulic horsepower to the system. This horsepower is needed to move the fluid through the surface system, down the drill string, through the bit, up the annulus (the space between the hole wall and the drill pipe), through the pits and back to the suction pump. Fluid flowing from the bit nozzles exerts a jetting action that keeps the face of the hole and the teeth edge of the bit clear of the cuttings. The horsepower required to move the mud through the remaining system should be minimized in order to maximize horsepower at the bit. The heavier a fluid becomes, the greater the horsepower that is required to move it through the system. This results in less horsepower at the bit and slower penetration rates. Hydraulic energy can be used to maximize the rate of penetration by improving cuttings removal at the bit. It also provides power for mud motors to rotate the bit. Hydraulic energy is measured in terms of hydraulic horsepower. Hydraulic horsepower is determined by multiplying pump pressure by the flow rate and dividing it by the constant 1714. Example Given a standpipe pressure of 3000 psi A pump rate of 750 gallons a minute. The constant being 1714 what is the hydraulic horsepower. hp. = (3000 psi * 750 gallons) / 1714 = 1312.71 hp. When pumping through a pipe pressure is lost due to friction. Drill string pressure losses are higher in fluids with higher densities, plastic viscosities and solids. The use of small diameter drill rods and mud motors all reduce the amount of pressure available for use at the bit. Page 29 of 46

Low-solids, shear thinning drilling fluids or those that have drag reducing characteristics, such as polymer fluids, are more efficient at transmitting hydraulic energy to drilling tools and the bit. In shallow bores, sufficient hydraulic horsepower usually is available to clean the bit efficiently. Because drill string pressure losses increase with length a point will be reached where there is insufficient pressure for optimum bit cleaning. This length can be extended by carefully controlling the fluid properties. As stated the hydraulic horsepower starts at the stand pipe and finishes at the flow line out let at "0" psi having been lost due to the circulating system Drilling Fluid Bottom Line Everyone want to make a profit this can only be achieve by optimizing equipment and the condition that prevail at the rig site. Running a rig at maximum rate will eventually cost the operator in downtime. A well prepared and maintained drilling fluid combined with optimizing other essence equipment with well trained people are the answer to a successful operation There are large advantages to to using a good system Reduce the amount of time it takes to complete a bore. The rate of penetration will be increased by improving the hole cleaning efficiency and the lubricity of the fluid. The rate of penetration is controlled, by the torque available at the bit, the thrust applied at the bit and the amount of hydraulic energy available at the bit. The fluid used will heavily influence each of these areas. Using fluid systems will improve each of these areas. The thrust applied at the bit is dependent on hole cleaning efficiencies. If cutting beds are eliminated more thrust will be available at the bit. Conservatively, a rate of penetration increase of 5-15% should be achievable with the use of a fluid system. The bore will be completed in a shorter amount of time thus allowing the rig to move onto another project. Good fluid systems will provide better directional steering control. Steering control is directly related to hole cleaning. Steering control is improved by eliminating cutting beds and being able to apply thrust to the bit. Sometimes it is very difficult to initiate and maintain a build rate. The problem usually is that the thrust applied by the rig will not reach the bit. Part of the thrust is used in overcoming the drag imposed by the cutting beds. When a direction change is required, the rotation is stopped. The head is then rotated to the proper angle and pushed forward without rotation. Ground force against the wedge forces the cutting head to change direction. Once the drill string is aligned with the intended path, the drilling procedure resumes. Many times multiple attempts have to be made in order to turn the direction of the bore.

This is due to the fact that you are not getting the force you think you are to the bit. The most important aspect of steering control is to produce a smooth bore path and not a serpentine path. The serpentine path will greatly increase the difficulty of pulling the product line into place Fewer problems that cause rig down time are encountered when using a a good system Problems such as stuck pipe, lost circulation and inadequate directional control can be reduced. Each one of these problems causes non-productive rig time and cost money. These problems are traceable to inadequate hole stability and hole cleaning. A properly formulated fluid system will enhance both of these critical functions. Water quality The system will reduce the operational stress experienced by the rig. A rig that is operating at or near its operational limits is detrimental. The ideal situation would be to accomplish the job using a minimum of available rig power. Running a rig at 75% 0f its efficiency will improve over all efficiency of an operation by as much as 40%. The Drilling contractor is in business to make money. The best way to increase the amount of money that is earned is to increase revenue and decrease costs. Another way is to charge more for your services. In competitive situations where the work is done on a bid basis this is not possible. So, is it possible to improve the efficiency of the drilling process and at the same time reduce costs? I know that it can be done but it will take some effort on the part of the drilling contractor. The effort will be to learn how fluid systems can improve the drilling operation and then teach crews how to use and implement them. MUD MIXING AND USAGE This section will delve into mud mixing and usage. The various aspects of mud mixing include water quality, products, mixing order and adequate mixing of the products. WATER QUALITY An ample supply of fresh water often simplifies the selection of the drilling fluid. Clarity alone, however, should not be accepted as evidence of purity of water, or even of its suitability for mud making. A few simple tests usually serve to define water quality. Water pH: Fresh water should have a pH of 7. Test the water with pH paper. If the pH is below 7, add soda ash to Page 30 of 46

raise the pH to between 8 and 9. All fluid products will perform better in this pH range.

foaming problem, especially in the case of drilling detergent.

Sulphide: Note odor. Sulphide contaminated water will have the characteristic smell of rotten eggs. Add caustic soda to raise pH to 10. If caustic soda is not available then change water source.

Caution: If you are using a PHPA polymer in the fluid make sure you rinse out the mixing tank before you mix another batch of fluid. PHPA polymer is an effective flocculent in dilute solution. If there is a residue of polymer left in the tank it will flocculate the bentonite that you try to mix. Rinsing out the tank is a good practice to implement and takes very little time.

Hardness: Test with calcium indicator. Hard water will not produce lather with bar soap. In the absence of a calcium test use the bar soap test. Add soda ash until calcium test is negative and the pH is between 8 and 9. Soda ash precipitates out the calcium as insoluble calcium carbonate, making it harmless. Salt: Change water source if tasted. There is no chemical method to remove chlorides from water. Salt will drastically reduce the yield of bentonite and increase the water loss of the fluid. If you notice severe thickening or separation of bentonite or polymer in the mixing tank, then you probably have a water quality problem. This is not always the problem since other factors can cause separation but water quality should be the first thing that should be investigated. Mixing in the correct order It is essential that products be mixed in the correct order. Some products have an adverse effect on other products when they are mixed in an incorrect order. For example, if PHPA polymers are mixed before the bentonite then the bentonite will not yield properly. The following mixing guidelines should be adhered to when mixing products. If there is a water quality problem, treat the water before you add any products. Add the required amount of bentonite and mix for 5-10 minutes. This should be adequate if the mixing system has sufficient shear. I would recommend mixing longer if the mixing system shear is not adequate. The fluid should look smooth and not have any large lumps floating around. In general, the longer you mix any fluid products the better they will work. One sack products that have polymer additives will need to be mixed longer than high yield bentonite products. After the bentonite is hydrated, add any polymer additives that you might be using. Here again, the mixing time should be extended to allow the polymers to hydrate and shear. The last addition should be lubricants or drilling detergent. Only mix long enough to make sure the additives are homogeneous in the fluid. Over mixing may cause a

SUMMARY Recommending a drilling fluid system should be based on the ability of the fluid to achieve these critical functions and to minimize problems. Initially, anticipated problems helps in selecting a particular drilling fluid system but other considerations may exist that dictate use of a different system. The cost, availability of products and environmental factors are always important considerations. Drilling fluids almost always require tradeoffs in treating and maintaining the properties needed to accomplish the required functions. For example, a high mud viscosity might improve hole cleaning, yet it might lower hydraulic efficiency, increase solids retention and slow the penetration rate. A driller that understands fluids and knows how to change them will have a powerful drilling tool at his disposal. Bentonite slurries will continue as the fluid of choice for most contractors. The slurry will be effective for most short, shallow and small diameter bores. Bear in mind the shortcomings that are inherent in bentonite slurries and be prepared to use additives when needed. As the bores become larger and longer, the contractor should consider using a fluid system in place of the bentonite slurries. When the geological sequence also becomes challenging then fluid systems are demanded. There are some contractors that have mini rigs and boring small diameter, shallow holes using only water. How well does water meet the functional requirements. water will clear cuttings from the hole when in turbulent flow. However, water that is not in turbulent flow is a poor hole cleaning medium. The hole cleaning ability of water is entirely dependent on the pumping capacity of the rig. Water will lubricate and cool the bit. In fact water has a better coefficient of friction than bentonite fluids at high pressure. Water will not stabilize the hole. Water in turbulent flow will erode weak formations leading to hole enlargement. Large amounts of water can be lost to highly permeable Page 31 of 46

formations such as gravel. In clays that hydrate and swell, water is your worst enemy. Since water is a Newtonian fluid it does not have any yield point or thixotropic characteristics. This means that as soon as the pump is shut off all the cuttings will fall to the bottom of the hole. Any colloidal clay particles will stay in suspension but the majority of the cuttings will settle out on the low side of the hole. Water is fairly efficient at transmitting hydraulic energy to the bit. Efficiency is lost as the water becomes loaded with solids. Water is not a good choice for a drilling fluid. BENTONITE The vast majority of drilling contractors will utilize a bentonite slurry when doing an HDD bore. The bentonite that is used will normally be high yield or a comber nation mix that has additives such as polymer, soda ash, water loss control agents and thinners added to the bentonite. Bentonite slurries in general are good hole cleaners as long as a couple of rules are followed. Utilize an elevated viscosity from the start and use the highest possible annular velocity as it provides the impact force necessary for good cuttings transport. This is only applicable to the main hole since cutting transport is severely limited when reaming. During reaming suspension is the most critical function rather than cutting transport. however the reader should be aware that boycott settling will still occur in the 30-60 degree section of the hole and that cutting beds will form on the low side of the hole especially during extended periods of sliding. Bentonite slurries were thought to provide lubrication since they feel slippery. However, they are good lubricants only under low pressure conditions. They are not good lubricants when exposed to high pressure conditions. The coefficient of friction in the bentonite slurry is higher at 720 psi than water. However bentonite slurries are good hole stabilizers in permeable formations such as sand and gravel. The slurry will deposit a filter cake on the permeable formation allowing the hydrostatic pressure to push against it. The filter cake should be thin and tough. How well bentonite slurries do in stabilizing clay sections is dependent on the water loss. The lower the water loss the better it will stabilize the clay. Since clay is not permeable no filter cake will be deposited. Suspending cuttings when circulation is stopped is another critical function. Settling of cuttings in bentonite slurries are controlled by the size, shape and density of the cutting, as well as, the physical properties of the fluid. The bigger and heavier the cutting the faster it will settle. It is impossible to know the exact physical properties of the fluid without testing being done. A simple way to check

settling is to collect a sample of mud at the return pit in a container. Let the container set for 5-10 minutes and then carefully pour out the mud and see how many cuttings are on the bottom of the container. If there are more than you want then increase the viscosity of the fluid with bentonite and/or polymer. The suspension ability of bentonite slurries are much greater than water but not as great as some other fluid types. When it comes to transmitting hydraulic energy to the bit the bentonite slurries are not good. Bentonite slurries contain 4 - 6 % solids. The solids create friction as they rub against the pipe and each other. So the pumping friction loss is increased. That means that less pressure reaches the bit and less work is done. If you had to give an honest evaluation of bentonite slurries then the best rating would be average. Of the five critical functions they are deficient in at least two to three areas. This is the reason that most drilling fluid suppliers will recommend adding some supplemental products in certain drilling situations. The products most often recommend are a bio-polymer to increase the gel strengths and improve suspension of solids, PAC polymers to decrease the filtrate water loss, PHP A polymers to inhibit clay hydration and swelling and drilling detergent to water wet the tools and reduce torque. These products will improve hole conditions and reduce certain problems. However, drilling detergent although widely used is not an efficient torque reducer and has a serious drawback. If you refer back to the table that compare various lubricants you will see that the detergents did not provide much reduction in the coefficient of friction. Wall Cake A drilling fluid will deposit a filter cake on the wall of the well bore. This wall cake helps protect the formation by retarding the passage of mud filtrate into it. The higher the permeability of a formation, the greater its ability to accept and receive large volumes of mud filtrate. Therefore, the nature of this filter cake will have a direct effect on such problems as formation damage, sloughing and caving, tight hole and stuck pipe. The type of wall cake is determined by the quantity and quality of particles in the mud system. It would normally be regarded as the thinner the better. The bentonite particles should be kept in the dispersed or deflocculated state and not allowed to flocculate. Bentonite in the flocculated state will increase the water loss and have a thick, soft filter cake. It is important to control the filtrate loss of the mud so that the water will not destabilize the formation. Page 32 of 46

A drilling mud with a low filtrate water loss will form a thin, tough filter cake. Specially formulated, bentonite product can provides filtrate control and a thin, tough filter cake. Any contaminates that flocculate the bentonite should be treated out immediately. To minimize erosion, avoid any unnecessary reaming or circulating opposite unconsolidated formations. Bentonite, polymers and starch are use to control the water loss It is essential that products be mixed in the correct order. Some products have an adverse effect on other products when they are mixed in an incorrect order. For example, if PHPA polymers are mixed before the bentonite then the bentonite will not yield properly. The following mixing guidelines should be adhered to when mixing products. If there is a water quality problem, treat the water before you add any products. Add the required amount of bentonite and mix for 5-10 minutes. This should be adequate if the mixing system has sufficient shear. I would recommend mixing longer if the mixing system shear is not adequate. The fluid should look smooth and not have any large lumps floating around. In general, the longer you mix any fluid products the better they will work. After the bentonite is hydrated, add any polymer additives that you might be using. Here again, the mixing time should be extended to allow the polymers to hydrate and shear. The last addition should be lubricants or drilling detergent. Only mix long enough to make sure the additives are homogeneous in the fluid. Over mixing may cause a foaming problem, especially in the case of drilling detergent. Caution: If you are using a PHPA polymer in the fluid make sure you rinse out the mixing tank before you mix another batch of fluid. PHPA polymer is an effective flocculent in dilute solution. If there is a residue of polymer left in the tank it will flocculate the bentonite that you try to mix. Rinsing out the tank is a good practice to implement and takes very little time. Hole cleaning Hole cleaning is one of the basic functions of any drilling fluid. Cuttings generated by the bit, plus any caving and/or sloughing, must be carried to the surface by the mud. Failure to achieve effective hole cleaning can lead to serious problems, including stuck pipe, excessive torque and drag, annular pack-off, lost circulation, high mud costs and slow drilling rates. Cuttings transport is affected by several interrelated mud and drilling parameters. Removing cuttings from below the drill bit is still a crucial function of a drilling fluid. The circulatory fluid rising

from the bottom of the well bore carries the cuttings toward the surface. Under the influence of gravity, these cuttings tend to fall through the ascending fluid. This is known as slip velocity. The slip velocity will depend upon the viscosity (thickness) and density of the fluid. The thicker the fluid, the lower the slip velocities. The more dense the fluid, the lower the slip velocity. For effective cuttings removal, the fluid velocity must be high enough to overcome the slip velocity of the cuttings. This means that fluid velocity can be lowered in a highly viscous (thick) or very dense fluid and cuttings still effectively removed from the well bore. The density of a fluid is determined by other factors and is not usually considered a factor in hole cleaning; therefore we limit adjustment of hole cleaning properties to viscosity and velocity adjustments to the drilling fluid. The viscosity desired will depend upon the desired hydraulics and the size of the cuttings contained in the fluid. The velocity will depend on several factors -the pump (capacity, speed, efficiency), the drill pipe size and the size of the bore hole. The velocity of a fluid will determine its flow characteristics, or flow profile. There are five stages, or different profiles, for a drilling fluid: (1) no flow, (2) plug flow, (3) transition, (4) laminar, 5) turbulent. The ideal velocity is one that will achieve laminar (or streamline) flow because it provides the maximum cuttings removal without eroding the well bore. On the other hand, turbulent flow (resulting from too high a velocity or too low fluid viscosity) not only requires more horsepower but can cause excessive hole erosion and undesirable hole enlargement. The proper combination of velocity and viscosity is a must for the right hydraulics and efficient hole cleaning. Cuttings will have a tendency to collect at points of low fluid velocity in the well bore annulus. These areas are found in washouts and where the drill pipe rests against the wall of the well bore. To that end, it is a good practice to rotate and work (raise and lower ) the drill string while just circulating to clean the hole, as this will help keep the cuttings in the main flow of the fluid and not allow them to gather next to the wall or pipe. Hole angle, annular velocity and mud viscosity are considered to be the most important. Cuttings and particles that must be circulated from the well have three forces working on them: (1) a downward force due to gravity, Page 33 of 46

(2) an upward force due to buoyancy from the fluid and (3) a force parallel to the direction of the mud flow due to mud flowing around the particle. The hole-cleaning process must counteract gravitational forces acting on cuttings to minimize settling during both dynamic and static periods. Three basic settling mechanisms can apply: (1) free, (2) hindered and (3) Boycott settling. Free settling occurs when a single particle falls through a fluid without interference from other particles or container walls. The larger the difference between the density of the cutting and the density of the liquid, the faster the particle will settle. The larger the particle is the faster it settles and the lower the liquid‘s viscosity, the faster the settling rate. Hindered settling is more realistic settling mode for near-vertical and near-horizontal intervals. Hindered settling occurs when fluid displaced by falling particles creates upward forces on adjacent particles, thereby slowing down their settling rate. The net results is still an overall downward movement, but the settling rate is always less (hindered), thus the name. Boycott settling is an accelerated settling pattern that can occur in inclined well bores. Boycott settling is the consequence of rapid settling adjacent to the high and low sides of inclined well bores. This causes a pressure imbalance which drives the lighter, upper fluid upwards and any cutting beds on the low side downwards. At relatively low flow rates, mud flows mainly along the high side and accelerates or enhances the Boycott effect. High flow rates and pipe rotation can disrupt the pattern and improve hole cleaning. If not properly supported, cuttings can accumulate at the bottom of the hole or on the low side of inclined intervals. "Plugs" and stuck pipe can be caused by dragging bottom hole tools up through pre-existing beds. Cuttings accumulations can be difficult to erode or resuspend, so mud properties and drilling practices which minimize their formation should be emphasized. Cuttings transport efficiency is largely a function of annular velocity and the annular velocity profile. Increasing annular velocity will always improve hole cleaning, though it still must work with other hole parameters. In fully concentric annulus, flow is evenly distributed around the drill string. Thus there is an equal distribution of fluid energy for cuttings transport. However, the drill string tends to lay on the low side of the hole in inclined sections, shifting or

skewing the velocity profile, the results of which is not conducive to cuttings transport. Cuttings accumulate on the bottom of the hole adjacent to the drill pipe where the mud flow is minimal. In this situation, pipe rotation is critical to achieve effective hole cleaning. However, there are times when drilling a directional hole that pipe rotation will not be possible. All is not lost at this point since we can offset the detrimental effects of not rotating with different mud types and changing certain mud properties. Generally speaking, different drilling fluid types provide similar cuttings transport if their down hole properties are similar. Properties of particular interest to hole cleaning include mud weight, viscosity and gel strengths. Mud weight helps buoy cuttings and slow their settling rate but it is really not used to improve hole cleaning. Instead, mud weights should be adjusted based only on pore pressure, fracture gradient and well-bore stability requirements. Mud viscosities helps determine carrying capacity. Yield points historically has been used as the key parameter which was though to affect hole cleaning. More recently, evidence concludes that Fann 6 and 3 RPM values are better indicators of carrying capacity. These values are more representative of the Low Shear Rate Viscosity (LSRV) which affects hole cleaning in marginal situations. One common rule of thumb is to maintain the 3 RPM value so that it is greater than the hole size (expressed in inches) in high angle wells. Gel strengths provide suspension under both static and low shear rate conditions. The ideal situation is for the fluid to have high, fragile gels that develop quickly and are easily broken. Excessive high, progressive gels, on the other hand, should be avoided as they cause high transient pressures that cause a number of serious drilling problems. Listed below are practical hole-cleaning guidelines aimed at field use on directional bores. Use hole-cleaning techniques to minimize cuttings-bed formation and subsequent slumping which can occur in 3060 degree hole sections. Utilize elevated-viscosity fluids from the start because cuttings beds are easy to deposit but difficult to remove. Maintain LSRV between 1.0 and 1.2 times the hole diameter when in laminar flow. This requirement will be easier to accomplish if the fluid is treated with a super's or high vis. This product is a bio-polymer that elevates the LSRV in fluids. Treat mud to obtain elevated, flat gels for suspension during static and low flow rate periods. Consider using the mud system that will give you excellent LSRV values and superior suspension abilities. The system uses an untreated bentonite and a mixed metal hydroxide additive. Schedule periodic wiper trips and pipe rotation intervals for situations where sliding operations are extensive. Page 34 of 46

Rotate pipe at speeds above about 50 RPM if possible to prevent bed formations and to help remove pre-existing beds. Expect little help from viscous sweeps, unless they are accompanied by high flow rates and pipe rotation Primary Well Control Under normal conditions the drilling fluid in the wellbore is the primary Well Control be it drilling mud or workover brine. One of its prime reasons for being there is to hold back the formation pressure. This is done by it having a higher pressure gradient in the fluid then the formation. If the formation gradient is not known we can work off the gradient of salt water until such time as a test is preformed and more accurate information is forthcoming. The drilling/workover fluid is kept a little higher that that of the expected formation fluids but not so high that it will break down or damage the formations. It must also be remember the the fluid column exert a pressure against the complete open wellbore section, although this pressure varies with depth so does that of the formation. Should the formation at any given depth be unable to except the pressure being applied and the fluid level in the wellbore drop, formation that were being held in place could very well start to intrude into the wellbore. Such intrusions can be in varied forms. Splinters from the side of the hole can be blown off or lose "unconsolidated" formation start to full in. formation fluid may start to enter the wellbore. The differential in pressure is commonly referred to as a trip margin or safety margin. As the well gets deeper so the mud gradient will be raised. But not excessively unless one is expecting a much higher formation pressure (gradient). The closer you can keep the ratio between both drilling fluid and formation gradient the faster it will drill. The hydrostatic head of the fluid column can be worked out using the formula (True vertical depth * .052 * the weight of the drilling fluid in pounds per gallon): And as the name says this is with the fluid static. If the fluid is moving (being pumped) this then changes to what is known as the dynamic fluid head. The dynamic fluid head is grater than that of the hydrostatic head due to the friction of the fluid moving back up the wellbore and is cause by the the resistant to flow created by the walls of the outer wellbore and the pipe in the string . we call this The Annular Pressure Loss) (APL) This pressure create an added pressure to the fluid at the bottom of the hole. This same pressure loss is used as a safety factor when a well is being circulated out during a

kill and will remain in place as long as the fluid is being moved. A kick is killed by Constant Bottom Hole Pressure. this pressure is created by using constant pump stroke to maintain a constant drill pipe pressure. this pressure is known as the final circulating and is maintained and controlled by the use of a choke and the APL until the New Kill fluid has replaced all the old drilling fluid from the wellbore A kick would be described as an influx from the formation that enters the well bore where the primary well control fluid has a lower pressure gradient than that of the formation. The longer it is allowed to come in the harder, it is to control. Not all flows are kicking. Sometimes a well will take fluid and give it back there are many reasons for this. Too higher circulating pressure with a high annular pressure lose could force fluid into the pores and hold it there until such pressures are release. " the circulation stopped" such a flow will not show while circulating. Imbalance fluid, expansion of fluid or pipe. bottoms up after a round trip can often confuse people. Such flows are short lived, however all should be investigated. The key to primary well control is keeping the fluid weight correct. Gas cut fluid coming from long gas sands will very often cut the fluid weight back. Gas in cutting will do the same. However, if treated before re-circulating will have no effect, as all the gas will be take out. If to server one should stop drilling and circulate on the choke as fluid being belched out over the bell nipple could reduce the hydrostatic head to the point that the well will kick. Such sand should be "controlled drilled" Oil will cut the mud weight. If the fluid is hot, it may be hard to detect. Water will lower the mud weight if drilling with fresh water mud, salt water starts to contaminate it, both the viscosity, and chlorides will rise. It is therefore important that a consent check on the weight of the fluid be made both in and out of the hole. The mud watcher or shaker man play a very big part in well control Beside keeping a check on the mud weight they should keep an eye on the shape and size of the cutting. As often when the primary well control starts to brake down other indication come over the shaker. Shape and size of cutting could be the first indication of a problem. Long splinter type slivers will often indicate the mud weight being too low. The splinters will often come from the wall of the hole Blown of by the formation pressure. A pump pressure drops could be another indication of mud problems but can also indicate the start of other problems. Pump pressure could also indicate a kick, as often it will drop if the bit penetrate a gas sand A rise in the mud temperature another indicator. Why? Heat is often caused by friction. What would cause friction Page 35 of 46

in a hole. Tight hole. Tight hole could be the swelling of the walls this would indict the hydrostatic head of the fluid column was not holding back the wall. So you see that stuff you keep dumping every time you open the wrong valve is not only expensive. but it also important and like the blood in your veins it plays an awful big part in the drilling and safety of the well. Transmit information Never before has the fluid had so much depending on it. Gone are many of the wire line tools. Incoming are the remote control valves, logging tools, MWD. The list is endless. What possibly started out with a bunch of cows munching around in a pool of water has now become a science. As new chemicals come to the market daily, You and I will need to understand there basic functions. Knowing your tools is knowing your job. Drilling fluid is a tool and as said many times. The drilling people that understand drilling fluid will, have a much better understanding of there work When a drilling fluid is controlled and properly maintained, it not only insures proper formation protection, optimum penetration rates, greater well production and lower equipment wear, but can also, within given parameters maximize down hole information. A well bore is drilled to: (1) gather information on formations, such information is then stored as locale information and is used in many other areas not all are involve with the oil industry. Locale area information then becomes part of the regional data bank and it is such information that has allowed scientist to start to pin point much of the worlds past. (2) find and recover usable fluids. A properly controlled drilling fluid is necessary not only to recover adequate rock cuttings for their analysis and study, but also to safely control subsurface pressures, optimize penetration rates for controlling drilling costs, minimize formation damage and therefore maximize well productivity.

References 1. Max R. Annis and Martin V. Smith. Drilling Fluid Technology. Revised Edition August 1996. Exxon Company, USA. 2. Baker Hughes. Drilling Fluids Reference Manual, Revision 2006. 3. Drilling Fluids and Health Risk Management, IPIECA. OGP.

4. Australian Drilling Industry Training Committee Ltd (1992) Australian Drilling Manual 3rd edition", Macquarie Centre: Australian Drilling Industry Training Committee Ltd, ISBN 0-949279-20X. 5. Driscoll, F. (1986) Groundwater and Wells, St. Paul: Johnson Division GLOSSARY Abandon v: to temporarily or permanently cease production from a well or to cease further drilling operations. Bleed v: to drain off liquid or gas, generally slowly, through a valve called a bleeder. To bleed down, or bleed off, means to release pressure slowly from a well or from pressurized equipment. Blowout n: an uncontrolled flow of gas, oil, or other well fluids from the well. Blowout preventer (BOP) n: one or more valves installed at the wellhead to prevent the escape of pressure either in the annular space between the casing and the drill pipe or in open hole (for example, hole with no drill pipe) during drilling or completion operations. Blowout preventer control panel n: controls, opens and closes the blowout preventers. See blowout preventer. Blowout preventer control unit n: a device that stores hydraulic fluid under pressure in special containers and provides a method to open and close the blowout preventers. Blowout preventer stack (BOP stack) n: the assembly of well control equipment including preventers, spools, valves, and nipples connected to the top of the wellhead. Brake n: The braking device on the drawworks or airhoist to stop a load being lifted. It is a device for arresting the motion of a mechanism, usually by means of friction, as in the drawworks and airhoist brakes. Brake band n: a part of the brake mechanism consisting of a flexible steel band lined with a material that grips a drum when tightened. On drawworks, the brake band acts on the drum to control the lowering of the traveling block and its load. Cable n: 1. a rope of wire, hemp, or other strong fibers. 2. braided wire used to conduct electricity, often called power cable. Caliper log n: a record showing variations in wellbore diameter by depth, indicating undue enlargement due to caving in, washout, or other causes. The caliper log also reveals corrosion, scaling, or pitting inside tubular goods. Casing n: 1. steel pipe placed in an oil or gas well to prevent the wall of the hole from caving in, to prevent movement of fluids from one formation to another and to aid in well control. Cased hole n: a wellbore in which casing has been run. Casing centralizer n: a device secured around the casing at regular intervals to center it in the hole. Page 36 of 46

Casing cutter n: a heavy cylindrical body, fitted with a set of knives, used to cut and free a section of casing in a well. Casing coupling (collar) n: a tubular section of pipe that is threaded inside and used to connect two joints of casing. Casing crew n: the employees of a company that specializes in preparing and running casing into a well. Casing gun n: a perforating gun run into the casing string. Casing hanger n: a circular device with a frictional gripping arrangement of slips and packing rings used to suspend casing from a casing head in a well. Casinghead n: a heavy, flanged steel fitting connected to the first string of casing. It provides a housing for slips and packing assemblies, allows suspension of intermediate and production strings of casing, and supplies the means for the annulus to be sealed off. Also called a casing spool. Casing point n: the depth in a well at which casing is set, generally the depth at which the casing shoe rests. Casing pressure n: the pressure in a well that exists between the casing and the tubing or the casing and the drill pipe. CASING spider n: see spider. Casing slip n: see spider. Casing string n: the entire length of all the joints of casing run in a well. Casing shoe n: see guide shoe. Casing tongs n pl: large wrench used for turning when making up or breaking out casing. See tongs. Casing-tubing annulus n: in a wellbore, the space between the inside of the casing and the outside of the tubing. Cementing n: The application of a liquid slurry of cement and water to various points inside or outside the casing. Cementing materials n pl: a slurry of cement and water and sometimes one or more additives that affect either the density of the mixture or its setting time. The cement used may be high early strength, common (standard), or slow setting. Additives include accelerators (such as calcium chloride), retarders (such as gypsum), weighting materials (such as barium sulfate), lightweight additives (such as bentonite), or a variety of lost circulation materials. Cement plug n: 1. a portion of cement placed at some point in the wellbore to seal it. 2. a wiper plug. See cementing. Cementing pump n: a high-pressure pump used to force cement down the casing and into the annular space between the casing and the wall of the borehole. Cementing time n: the total elapsed time needed to complete a cementing operation. cement retainer n: a tool set temporarily in the casing or well to prevent the passage of cement, thereby forcing it to follow another designated path. It is used in squeeze cementing and other remedial cementing jobs. Centralizer n: see casing centralizer Christmas tree n: the control valves, pressure gauges, and chokes assembled at the top of a well to control flow of oil and/or gas after the well has been drilled and completed. It

is used when reservoir pressure is sufficient to cause reservoir fluids to rise to the surface. Complete a well v: to finish work on a well and bring it to productive status. See well completion. Core n: a cylindrical sample taken from a formation for geological analysis. Core analysis n: laboratory analysis of a core sample that may determine porosity, permeability, lithology, fluid content, angle of dip, geological age, and probable productivity of the formation. Core barrel n: a tubular device, usually from 10 to 60 feet (3 to 18 meters) long, run in place of a bit and used to cut a core sample. Core sample n: 1. a small portion of a formation obtained by using a core barrel and core bit in an existing wellbore. See core bit. 2. a spot sample of the contents of an oil or oil product storage tank usually obtained with a thief, or core sampler, at a given height in the tank. Coring n: the process of cutting a vertical, cylindrical sample of the formations encountered as a well is drilled. Coring bit n: a bit that does not drill out the center portion of the hole, but allows this center portion (the core) to pass through the round opening in the center of the bit and into the core barrel. Density log n: a special radioactivity log for open -hole surveying that responds to variations in the specific gravity of formations. It is a contact log (i.e., the logging tool is held against the wall of the hole). It emits neutrons and then measures the secondary gamma radiation that is scattered back to the detector in the instrument. The density log is an excellent porosity-measure device, especially for shaley sands. Some trade names are Formation Density Log, Gamma-Gamma Density Log, and Densilog. Derrick n: a large load-bearing structure, usually of bolted construction. In drilling, the standard derrick has four legs standing at the corners of the substructure and reaching to the crown block. The substructure is an assembly of heavy beams used to elevate the derrick and provide space to install blowout preventers, casingheads, and so forth. Derrick floor n: also called the rig floor. Derrickhand n: the crew member who handles the upper end of the drill string as it is being hoisted out of or lowered into the hole. On a drilling rig, he or she may be responsible for the circulating machinery and the conditioning of the drilling or workover fluid. Dipmeter log n: see dipmeter survey. Dipmeter survey n: an oilwell-surveying method that determines the direction and angle of formation dip in relation to the borehole. It records data that permit computation of both the amount and direction of formation dip relative to the axis of the hole and thus provides information about the geologic structure of the formation. Also called dipmeter log or dip log. Page 37 of 46

Directional drilling n: 1. intentional deviation of a wellbore from the vertical. Although wellbores are normally drilled vertically, it is sometimes necessary or advantageous to drill at an angle from the vertical. Controlled directional drilling makes it possible to reach subsurface areas laterally remote from the point where the bit enters the earth. Directional hole n: a wellbore intentionally drilled at an angle from the vertical. See directional drilling. Displacement fluid n: in well cementing, the fluid, usually drilling mud or salt water, that is pumped into the well after the cement is pumped into it to force the cement out of the casing and into the annulus. Drawworks n: the hoisting mechanism on a drilling rig. It is essentially a large winch that spools off or takes in the drilling line and thus lowers or raises the drill stem and bit. Drawworks brake n: the mechanical brake on the drawworks that can slow or prevent the drawworks drum from moving. Drawworks drum n: the spool-shaped cylinder in the drawworks around which drilling line is wound or spooled. Drill v: to bore a hole in the earth, usually to find and remove subsurface formation fluids such as oil and gas. Drill bit n: the cutting or boring element used in drilling oil and gas wells. Most bits used in rotary drilling are rollercone bits. The bit consists of the cutting elements and the circulating element. The circulating element permits the passage of drilling fluid and utilizes the hydraulic force of the fluid stream to improve drilling rates. Drill collars n: a heavy, thick -walled tube, usually steel, used between the drill pipe and the bit in the drill stem, used to stiffen the drilling assembly an put weight on the bit so that the bit can drill. Drill collar sub n: a sub made up between the drill string and the drill collars that is used to ensure that the drill pipe and the collar can be joined properly. Driller n: the employee normally in charge of a specific (tour) drilling or workover crew. The driller‘s main duty is operation of the drilling and hoisting equipment, but this person may also be responsible for downhole condition of the well, operation of downhole tools, and pipe measurements. Driller’s position n: the area immediately surrounding the driller‘s console. Drill floor n: also called rig floor or derrick floor. See rig floor. Drill in v: to penetrate the productive formation after the casing is set and cemented on top of the pay zone. Drilling contract n: an agreement made between a drilling company and an operating company to drill a well. It generally sets forth the obligation of each party, compensation, identification, method of drilling, depth to be drilled, and so on.

Drilling crew n: a driller, a derrickhand, and two or more helpers who operate a drilling or workover rig for one tour each day. Drilling engine n: an internal-combustion engine used to power a drilling rig. These engines are used on a rotary rig and are usually fueled by diesel fuel, although liquefied petroleum gas, natural gas, and, very rarely, gasoline can also be used. Drilling engineer n: an engineer who specializes in the technical aspects of drilling. Drilling fluid n: circulating fluid, one function of which is to lift cuttings out of the wellbore and to the surface. It also serves to cool the bit and to counteract downhole formation pressure. Drilling hook n: the large hook mounted on the bottom of the traveling block and from which the swivel is suspended. Drilling mud n: a specially compounded liquid circulated through the wellbore during rotary drilling operations. See drilling fluid, mud. Drill pipe n: the heavy seamless tubing used to rotate the bit and circulate the drilling fluid. Joints of pipe are generally approximately 30 feet long are coupled together by means of tool joints. Drill stem n: all members in the assembly used for rotary drilling from the swivel to the bit, including the kelly, the drill pipe and tool joints, the drill collars, the stabilizers, and various specialty items. Compare drill string. Drill stem test (DST) n: a method of formation testing. The basic drill stem test tool consists of a packer or packers, valves or ports that may be opened and closed from the surface, and two or more pressure-recording devices. The tool is lowered on the drill string to the zone to be tested. The packer or packers are set to isolate the zone from the drilling fluid column. Driller's console n: the control panel, where the driller controls drilling operations. Drilling line n: a wire rope hoisting line, reeved on sheaves of the crown block and traveling block (in effect a block and tackle), the primary purpose of which is to hoist or lower drill pipe or casing from or into a well. Drilling out n: the operation during the drilling procedure when the cement is drilled out of the casing. Drill string n: the column, or string, of drill pipe with attached tool joints that transmits fluid and rotational power from the kelly to the drill collars and the bit. Often, the term is loosely applied to include both drill pipe and drill collars. Dry hole n: any well that does not produce oil or gas in commercial quantities. A dry hole may flow water, gas, or even oil, but not in amounts large enough to justify production. Fish n: an object that is left in the wellbore during drilling or workover operations and that must be recovered before work can proceed. It can be anything from a piece of scrap metal to a part of the drill stem. Page 38 of 46

Fishing n: the procedure of recovering lost or stuck equipment in the wellbore. Fishing magnet n: a powerful magnet designed to recover metallic objects lost in a well. Fishing tool n: a tool designed to recover equipment lost in a well. Fishing-tool operator n: the person (usually a service company employee) in charge of directing fishing operations. Flowing well n: a well that produces oil or gas by its own reservoir pressure rather than by use of artificial means (such as pumps). Flow line n: the surface pipe through which oil or gas travels from a well to processing equipment or to storage. Flow rate n: the speed, or velocity, of fluid or gas flow through a pipe or vessel. Fluid injection n: injection of gases or liquids into a reservoir to force oil toward and into producing wells. Fluid loss n: the unwanted migration of the liquid part of the drilling mud or cement slurry into a formation, often minimized or prevented by the blending of additives with the mud or cement. Formation fluid n: fluid (such as gas, oil, or water) that exists in a subsurface formation. Formation gas n: gas initially produced from an underground reservoir. Formation pressure n: the force exerted by fluids or gas in a formation, recorded in the hole at the level of the formation with the well shut in. Also called reservoir pressure or shut-in bottomhole pressure. Formation testing n: the gathering of pressure data and fluid samples from a formation to determine its production potential before choosing a completion method. Formation water n: 1. the water originally in place in a formation. 2. any water that resides in the pore spaces of a formation. Gamma ray log n: a type of radioactivity well log that records natural radioactivity around the wellbore. Shales generally produce higher levels of gamma radiation and can be detected and studied with the gamma ray tool. See radioactivity well logging. Geologist n: a scientist who gathers and interprets data pertaining to the formations of the earth‘s crust. Hoist n: 1. an arrangement of pulleys and wire rope used for lifting heavy objects; a winch or similar device. 2. the drawworks. v: to raise or lift. Hoisting components n pl: drawworks, drilling line, and traveling and crown blocks. Auxiliary hoisting components include catheads, catshaft, and air hoist. Hoisting drum n: the large, flanged spool in the drawworks on which the hoisting cable is wound. See drawworks. hoisting line n: a wire rope used in hoisting operations.

Hook n: a large, hook-shaped device from which the elevator bails or the swivel is suspended. It turns on bearings in its supporting housing. Hoisting system n: The system on the rig that performs all the lifting on the rig, primarily the lifting and lowering of drill pipe out of and into the hole. It is composed of drilling line, traveling block, crown block, and drawworks. See also hoisting components. Induction log n: an electric well log in which the conductivity of the formation rather than the resistivity is measured. Because oil-bearing formations are less conductive of electricity than water-bearing formations, an induction survey, when compared with resistivity readings, can aid in determination of oil and water zones. Injection gas n: 1. a high-pressure gas injected into a formation to maintain or restore reservoir pressure. 2. gas injected in gas-lift operations. Injection log n: a survey used to determine the injection profile, that is, to assign specific volumes or percentages to each of the formations taking fluid in an injection well. The injection log is also used to check for casing or packer leaks, proper cement jobs, and fluid migration between zones. Injection water n: water that is introduced into a reservoir to help drive hydrocarbons to a producing well. Injection well n: a well through which fluids are injected into an underground stratum to increase reservoir pressure and to displace oil. Also called input well. Injector head n: a control head for injecting coiled tubing into a well that seals off the tubing and makes a pressure tight connection. Kelly n: the heavy square or hexagonal steel member suspended from the swivel through the rotary table and connected to the topmost joint of drill pipe to turn the drill stem as the rotary table turns. Kelly bushing n: a device fitted to the rotary table through which the kelly passes and the means by which the torque of the rotary table is transmitted to the kelly and to the drill stem. Also called the drive bushing. Kelly bypass n: a system of valves and piping that allows drilling fluid to be circulated without the use of the kelly. Kelly cock n: a valve installed at one or both ends of the kelly. When a high-pressure backflow occurs inside the drill stem, the valve is closed to keep pressure off the swivel and rotary hose. Kelly drive bushing n: see kelly bushing. Kelly driver n: a device that fits inside the head and inside of which the kelly fits. The kelly driver rotates with the kelly. Kelly saver sub n: a heavy and relatively short length of pipe that fits in the drill stem between the kelly and the drill pipe. The threads of the drill pipe mate with those of the sub, minimizing wear on the kelly. Page 39 of 46

Kelly spinner n: a pneumatically operated device mounted on top of the kelly that, when actuated, causes the kelly to turn or spin. Keyseat n: 1. an undergauge channel or groove cut in the side of the borehole and parallel to the axis of the hole. A keyseat results from the rotation of pipe on a sharp bend in the hole. 2. a groove cut parallel to the axis in a shaft or a pulley bore. Kick n: an entry of water, gas, oil, or other formation fluid into the wellbore during drilling. It occurs because the pressure exerted by the column of drilling fluid is not great enough to overcome the pressure exerted by the fluids in the formation drilled. If prompt action is not taken to control the kick, or kill the well, a blowout may occur. Kick fluids n pl: oil, gas, water, or any combination that enters the borehole from a permeable formation. Kick off v: 1. to bring a well into production; used most often when gas is injected into a gas lift well to start production. 2. in workover operations, to swab a well to restore it to production. 3. to deviate a wellbore from the vertical, as in directional drilling. Kickoff point (KOP) n: the depth in a vertical hole at which a deviated or slant hole is started; used in directional drilling. Kill v: 1. in drilling, to control a kick by taking suitable preventive measures (for example, to shut in the well with the blowout preventers, circulate the kick out, and increase the weight of the drilling mud). 2. in production, to stop a well from producing oil and gas so that reconditioning of the well can proceed. Log n: a systematic recording of data, such as a driller‘s log, mud log, electrical well log, or radioactivity log. Many different logs are run in wells to discern various characteristics of downhole formation. v: to record data. Log a well v: to run any of the various logs used to ascertain downhole information about a well. Logging devices n pl: any of several electrical, acoustical, mechanical, or radioactivity devices that are used to measure and record certain characteristics or events that occur in a well that has been or is being drilled. Manifold n: 1. an accessory system of piping to a main piping system (or another conductor) that serves to divide a flow into several parts, to combine several flows into one, or to reroute a flow to any one of several possible destinations. Mast n: a portable derrick that is capable of being raised as a unit, as distinguished from a standard derrick, which cannot be raised to a working position as a unit. For transporting by land, the mast can be divided into two or more sections to avoid excessive length extending from truck beds on the highway. Master bushing n: a device that fits into the rotary table to accommodate the slips and drive the kelly bushing so that

the rotating motion of the rotary table can be transmitted to the kelly. Master valve n: 1. a large valve located on the Christmas tree and used to control the flow of oil and gas from a well. Also called master gate. Mud n: the liquid circulated through the wellbore during rotary drilling and workover operations. Mud acid n: a mixture of hydrochloric and/or hydrofluoric acids and surfactants used to remove wall cake from the wellbore. Mud cake n: the sheath of mud solids that forms on the wall of the hole when liquid from mud filters into the formation. Also called filter cake or wall cake. Mud centrifuge n: a device that uses centrifugal force to separate small solid components from liquid drilling fluid. Mud cleaner n: a cone-shaped device, a hydrocyclone, designed to remove very fine solid particles from the drilling mud. Mud engineer n: an employee of a drilling fluid supply company whose duty it is to test and maintain the drilling mud properties that are specified by the operator. Mud-gas separator n: a device that removes gas from the mud coming out of a well when a kick is being circulated out. Mud hopper n: see hopper. Mud hose n: also called kelly hose or rotary hose. See rotary hose. Mud line n: a mud return line. Mud logging n: the recording of information derived from examination and analysis of formation cuttings made by the bit and of mud circulated out of the hole. A portion of the mud is diverted through a gas -detecting device. Cuttings brought up by the mud are examined under ultraviolet light to detect the presence of oil or gas. Mud logging is often carried out in a portable laboratory set up at the well site. Mud motor n: see downhole motor. Mud pit n: originally, an open pit dug in the ground to hold drilling fluid or waste materials discarded after the treatment of drilling mud. For some drilling operations, mud pits are used for suction to the mud pumps, settling of mud sediments, and storage of reserve mud. Steel tanks are much more commonly used for these purposes now, but they are still usually referred to as pits. Mud pump n: a large, high-pressure reciprocating pump used to circulate the mud on a drilling rig. A typical mud pump is a two or three-cylinder piston pump whose replaceable pistons travel in replaceable liners and are driven by a crankshaft actuated by an engine or a motor. Mud return line n: a trough or pipe that is placed between the surface connections at the wellbore and the shale shaker. Mud tank n: one of a series of open tanks, usually made of steel plate, through which the drilling mud is cycled to remove sand and fine sediments. Page 40 of 46

Mud weight n: a measure of the density of a drilling fluid expressed as pounds per gallon, pounds per cubic foot, or kilograms per cubic metre. Mud weight is directly related to the amount of pressure the column of drilling mud exerts at the bottom of the hole. Multiple completion n: an arrangement for producing a well in which one wellbore penetrates two or more petroleum-bearing formations. In one type, multiple tubing strings are suspended side by side in the production casing string, each a different length and each packed to prevent the commingling of different reservoir fluids. Each reservoir is then produced through its own tubing string. Alternatively, a small diameter production casing string may be provided for each reservoir, as in multiple miniaturized or multiple tubingless completions. See dual completion. Natural gas n: a highly compressible, highly expansible mixture of hydrocarbons with a low specific gravity and occurring naturally in a gaseous form. Neutron log n: a radioactivity well log used to determine formation porosity. The logging tool bombards the formation with neutrons. When the neutrons strike hydrogen atoms in water or oil, gamma rays are released. Since water or oil exists only in pore spaces, a measurement of the gamma rays indicates formation porosity. See radioactivity well logging. Oil n: a simple or complex liquid mixture of hydrocarbons that can be refined to yield gasoline, kerosene, diesel fuel, and various other products. Oil-base mud n: a drilling or workover fluid in which oil is the continuous phase and which contains from less than 2 percent and up to 5 percent water. This water is spread out, or dispersed, in the oil as small droplets. See oil mud. Oil-emulsion mud n: a water-base mud in which water is the continuous phase and oil is the dispersed phase. Oilfield n: the surface area overlying an oil reservoir or reservoirs. The term usually includes not only the surface area, but also the reservoir, the wells, and the production equipment. Oil mud n: a drilling mud, such as, oil-base mud and invert-emulsion mud, in which oil is the continuous phase. It is useful in drilling certain formations that may be difficult or costly to drill with waterbase mud.Compare oilemulsion mud. Oil sand n: 1. a sandstone that yields oil. 2. (by extension) any reservoir that yields oil, whether or not it is sandstone. Oil saver n: a gland arrangement that mechanically or hydraulically seals by pressure. It is used to prevent leakage and waste of gas, oil, or water around a wireline (as when swabbing a well). Oil spotting n: pumping oil, or a mixture of oil and chemicals, to a specific depth in the well to lubricate stuck drill collars.

Oil string n: the final string of casing set in a well after the productive capacity of the formation has been determined to be sufficient. Also called the long string or production casing. Oilwell n: a well from which oil is obtained. Oil zone n: a formation or horizon of a well from which oil may be produced. The oil zone is usually immediately under the gas zone and on top of the water zone if all three fluids are present and segregated. Packer n: a piece of downhole equipment that consists of a sealing device, a holding or setting device, and an inside passage for fluids. Packer fluid n: a liquid, usually salt water or oil, but sometimes mud, used in a well when a packer is between the tubing and the casing. Packer fluid must be heavy enough to shut off the pressure of the formation being produced, and should not stiffen or settle out of suspension over long periods of time, and must be non -corrosive. Packer squeeze method n: a squeeze cementing method in which a packer is set to form a seal between the working string (the pipe down which cement is pumped) and the casing. Another packer or a cement plug is set below the point to be squeeze -cemented. By setting packers, the squeeze point is isolated from the rest of the well. Packing n: 1. a material used in a cylinder on rotating shafts of an engine or pump in the stuffing box of a valve, or between flange joints to maintain a leak proof seal. 2. the specially fabricated filling in packed fractionation columns and absorbers. Packing assembly n: the arrangement of the downhole tools used in running and setting a packer. Packing elements n pl: the set of dense rubber, washershaped pieces encircling a packer, which are designed to expand against casing or formation face to seal off the annulus. Pack-off n: a device with an elastomer packing element that depends on pressure below the packing to effect a seal in the annulus. Used primarily to run or pull pipe under low or moderate pressures. Also called a stripper. Pack off v: to place a packer in the wellbore and activate it so that it forms a seal between the tubing and the casing. Perforate v: to pierce the casing wall and cement of a wellbore to provide holes through which formation fluids may enter or to provide holes in the casing so that materials may be introduced into the annulus between the casing and the wall of the borehole. Perforating is accomplished by lowering into the well a perforating gun, or perforator. Perforated completion n: 1. a well completion method in which the producing zone or zones are cased through, cemented, and perforated to allow fluid flow into the wellbore. 2. a well completed by this method. Perforated liner n: a liner that has had holes shot in it by a perforating gun. Page 41 of 46

Perforated pipe n: sections of pipe (such as casing, liner, and tail pipe) in which holes or slots have been cut before it is set. Perforating gun n: a device fitted with shaped charges or bullets that is lowered to the desired depth in a well and fired to create penetrating holes in casing, cement, and formation. Perforation n: a hole made in the casing, cement, and formation through which formation fluids enter a wellbore. Usually several perforations are made at a time. Perforation depth control log (PDC log) n: a special type of nuclear log that measures the depth of each casing collar. Knowing the depth of the collars makes it easy to determine the exact depth of the formation to be perforated by correlating casing-collar depth with formation depth. Radioactivity log n: a record of the natural or induced radioactive characteristics of subsurface formations. Also called nuclear log. See radioactivity well logging. Radioactivity well logging n: the recording of the natural or induced radioactive characteristics of subsurface formations. A radioactivity log, also known as a radiation log or a nuclear log, normally consists of two recorded curves: a gamma ray curve and a neutron curve. Both help to determine the types of rocks in the formation and the types of fluids contained in the rocks. Ram n: the closing and sealing component on a blowout preventer. One of three types—blind, pipe, or shear—may be installed in several preventers mounted in a stack on top of the wellbore. Blind rams, when closed, form a seal on a hole that has no drill pipe in it; pipe rams, when closed, seal around the pipe; shear rams cut through drill pipe and then form a seal. Ram blowout preventer n: a blowout preventer that uses rams to seal off pressure on a hole that is with or without pipe. It is also called a ram preventer. Ram-type preventers have interchangeable ram blocks to accommodate different O.D. drill pipe, casing, or tubing. Range of load n: in sucker rod pumping, the difference between the polished rod peak load on the upstroke and the minimum load on the downstroke. Rate of penetration (ROP) n: a measure of the speed at which the bit drills into formations, usually expressed in feet (meters) per hour or minutes per foot (meter). Reservoir n: a subsurface, porous, permeable or naturally fractured rock body in which oil or gas are stored. Most reservoir rocks are limestones, dolomites, sandstones, or a combination of these. The four basic types of hydrocarbon reservoirs are oil, volatile oil, dry gas, and gas condensate. An oil reservoir generally contains three fluids—gas, oil, and water—with oil the dominant product. In the typical oil reservoir, these fluids become vertically segregated because of their different densities. Gas, the lightest, occupies the

upper part of the reservoir rocks; water, the lower part; and oil, the intermediate section. In addition to its occurrence as a cap or in solution, gas may accumulate independently of the oil; if so, the reservoir is called a gas reservoir. Associated with the gas, in most instances, are salt water and some oil. Volatile oil reservoirs are exceptional in that during early production they are mostly productive of light oil plus gas, but, as depletion occurs, production can become almost totally completely gas. Volatile oils are usually good candidates for pressure maintenance, which can result in increased reserves. In the typical dry gas reservoir natural gas exists only as a gas and production is only gas plus fresh water that condenses from the flow stream reservoir. In a gas condensate reservoir, the hydrocarbons may exist as a gas, but, when brought to the surface, some of the heavier hydrocarbons condense and become a liquid. Resistivity log n: a record of the resistivity of a formation. Usually obtained when an electric log is run. See resistivity well logging. Resistivity well logging n: the recording of the resistance of formation water to natural or induced electrical current. The mineral content of subsurface water allows it to conduct electricity. Rock, oil, and gas are poor conductors. Resistivity measurements can be correlated to formation lithology, porosity, permeability, and saturation and are very useful in formation evaluation. Rig n: the derrick or mast, drawworks, and attendant surface equipment of a drilling or workover unit. Rig down v: to dismantle a drilling rig and auxiliary equipment following the completion of drilling operations. Also called tear down. Rig floor n: the area immediately around the rotary table And extending to each corner of the derrick or mast—that is, the area immediately above the substructure on which the rotary table, and so forth rest. Rig up v: to prepare the drilling rig for making hole, for example, to install tools and machinery before drilling is started. Rod blowout preventer n: a ram device used to close the annular space around the polished rod or sucker rod in a pumping well. Rod hanger n: a device used to hang sucker rods on the mast or in the derrick. Rotary table n: The principal component of a rotary, or rotary machine, used to turn the drill stem and support the drilling assembly. It has a beveled gear arrangement to create the rotational motion and an opening into which bushings are fitted to drive and support the drilling assembly. Spontaneous potential (SP) n: one of the natural electrical characteristics exhibited by a formation as measured by a Page 42 of 46

logging tool lowered into the wellbore. Also called selfpotential or SP. Spontaneous potential (SP) curve n: a measurement of the electrical currents that occur in the wellbore when fluids of different salinities are in contact. The SP curve is usually recorded in holes drilled with freshwater -base drilling fluids. It is one of the curves on an electric well log. Also called selfpotential curve. Spontaneous potential (SP) log n: a record of a spontaneous potential curve. Spool n: the drawworks drum. Also a casing head or drilling spool. v: to wind around a drum. Spot v: to pump a designated quantity of a substance (such as acid or cement) into a specific interval in the well. For example, 10 barrels (1,590 litres) of diesel oil may be spotted around an area in the hole in which drill collars are stuck against the wall of the hole in an effort to free the collars. Spud v: 1. to begin drilling a well; such as, to spud in. 2. to force a wireline tool or tubing down the hole by using a reciprocating motion. Spud in v: to begin drilling; to start the hole. Spud mud n: the fluid used when drilling starts at the surface, often a thick bentonite-lime slurry. split master bushing n: a master bushing that is made in two pieces. Squeeze n: 1. a cementing operation in which cement is pumped behind the casing under high pressure to recement channeled areas or to block off an uncemented zone. Squeeze cementing n: the forcing of cement slurry by pressure to specified points in a well to cause seals at the points of squeeze. It is a secondary cementing method that is used to isolate a producing formation, seal off water, repair casing leaks, and so forth. Compare plug-back cementing. Sonic log n: a type of acoustic log that records the travel time of sounds through objects, cement, or formation rocks. Often used to determine whether voids exist in the cement behind the casing in a wellbore. Swivel n: a rotary tool that is hung from the rotary hook and traveling block to suspend and permit free rotation of the drill stem. It also provides a connection for the rotary hose and a passageway for the flow of drilling fluid into the drill stem. Temperature log n: a survey run in cased holes to locate the top of the cement in the annulus. Since cement generates a considerable amount of heat when setting, a temperature increase will be found at the level where cement is found behind the casing. Tracer log n: a survey that uses a radioactive tracer such as a gas, liquid, or solid having a high gamma ray emission. When the material is injected into any portion of the wellbore, the point of placement or movement can be recorded by a gamma ray instrument. The tracer log is used

to determine channeling or the travel of squeezed cement behind a section of perforated casing. Well n: the hole made by the drilling bit, which can be open, cased, or both. Also called borehole, hole, or wellbore. Wellbore n: a borehole; the hole drilled by the bit. A wellbore may have casing in it or it may be open (uncased); or part of it may be cased, and part of it may be open. Also called a borehole or hole. Wellbore soak n: an acidizing treatment in which the acid is placed in the wellbore and allowed to react by merely soaking. It is a relatively slow process, because very little of the acid actually comes in contact with the formation. Also called wellbore cleanup. Compare acid fracture. Well completion n: 1. the activities and methods of preparing a well for the production of oil and gas or for other purposes, such as injection; the method by which one or more flow paths for hydrocarbons are established between the reservoir and the surface. 2. the system of tubulars, packers, and other tools installed beneath the wellhead in the production casing; that is, the tool assembly that provides the hydrocarbon flow path or paths. Well control n: the methods used to control a kick and prevent a well from blowing out. Such techniques include, but are not limited to, keeping the borehole completely filled with drilling mud of the proper weight or density during operations, exercising reasonable care when tripping pipe out of the hole to prevent swabbing, and keeping careful track of the amount of mud put into the hole to replace the volume of pipe removed from the hole during a trip. Well fluid n: the fluid, usually a combination of gas, oil, water, and suspended sediment, that comes out of a reservoir. Also called well stream. Wellhead n: the equipment installed at the surface of the wellbore. A wellhead includes such equipment as the casinghead and tubing head. adj: pertaining to the wellhead. Well logging n: the recording of information about subsurface geologic formations, including records kept by the driller and records of mud and cutting analyses, core analysis, drill stem tests, and electric, acoustic, and radioactivity procedures. Well servicing n: the maintenance work performed on an oil or gas well to improve or maintain the production from a formation already producing. It usually involves repairs to the pump, rods, gas-lift valves, tubing, packers, and so forth. Well-servicing rig n: a portable rig, truck-mounted, trailermounted, or a carrier rig, consisting of a hoist and engine with a self-erecting mast. See carrier rig. Compare workover rig. Well site n: see location.

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Well stimulation n: any of several operations used to increase the production of a well, such as acidizing or fracturing. See acidize. Wickers n pl: broken or frayed strands of the steel wire that makes up the outer wrapping of wire rope. Wildcat n: 1. a well drilled in an area where no oil or gas production exists. Window n: 1. a slotted opening or a full section removed in the pipe lining (casing) of a well, usually made to permit sidetracking. Wireline n: a slender, rodlike or threadlike piece of metal usually small in diameter, that is used for lowering special tools (such as logging sondes, perforating guns, and so forth) into the well. Also called slick line. Wireline formation tester n: a formation fluid sampling device, actually run on conductor line rather than wireline, that also logs flow and shut-in pressure in rock near the borehole. A spring mechanism holds a pad firmly against the sidewall while a piston creates a vacuum in a test chamber. Formation fluids enter the test chamber through a valve in the pad. A recorder logs the rate at which the test chamber is filled. Fluids may also be drawn to fill a sampling chamber. Wireline formation tests may be done any number of times during one trip in the hole, so they are very useful in formation testing. Wireline log n: any log that is run on wireline. Wireline logging n: see well logging. Wireline operations n pl: the lowering of mechanical tools, such as valves and fishing tools, into the well for various purposes. Electric wireline operations, such as electric well logging and perforating, involve the use of conductor line. Wireline survey n: a general term used to refer to any type of log being run in a well. Wireline tools n pl: special tools or equipment made to be lowered into and retrieved from the well on a wireline, for example, packers, swabs, gas-lift valves, measuring devices. Wire rope n: a cable composed of steel wires twisted around a central core of fiber or steel wire to create a rope of great strength and considerable flexibility. Workover n: the performance of one or more of a variety of remedial operations on a producing well to try to increase production. Examples of workover jobs are deepening, plugging back, pulling and resetting liners, and squeeze cementing. See recompletion. Workover fluid n: a special drilling mud used to keep a well under control while it is being worked over. A workover fluid is compounded carefully so that it will not cause formation damage. Workover rig n: a portable rig used for working over a well. Work string n: 1. in drilling, the string of drill pipe or tubing suspended in a well to which is attached a

special tool or device that is used to carry out a certain task, such as squeeze cementing or fishing. 2. In pipeline construction, the string of washpipe that replaces the pilot string in a directionally drilled river crossing. The work string remains in place under the river until the actual pipeline is made up and is ready to be pulled back across the river. Squeeze cementing A cementing repair technique involving injecting cementing under pressure to fill channels in the primary cementing treatment. Cementing 1. the application of a liquid slurry of cement and water to various points inside or outside the casing. 2. to prepare and pump cement into place in a wellbore. cementing operations may be undertaken to seal the annulus after a casing string has been run, to seal a lost circulation zone, to set a [...] Cement squeeze A remedial cementing operation designed to force cement into leak paths in wellbore tubulars. the required squeeze pressure is achieved by carefully controlling pump pressure. squeeze cementing operations may be performed to repair poor primary cement jobs, isolate perforations or repair damaged casing or liner. Secondary cementing Any cementing operation after the primary cementing operation. secondary cementing includes a plug-back job, in which a plug of cement is positioned at a specific point in the well and allowed to set. wells are plugged to shut off bottom water or to reduce the depth of the well for other reasons. Primary cementing The cementing operation that takes place immediately after the casing has been run into the hole. it provides a protective sheath around the casing, segregates the producing formation, and prevents the undesirable migration of fluids. Plug-back cementing A secondary-cementing operation in which a plug of cement is positioned at a specific point in the well and allowed to set. Circulation squeeze A variation of squeeze cementing for wells with two producing zones in which (1) the upper fluid sand is perforated; (2) tubing is run with a packer, and the packer is set between the two perforated intervals; (3) water is circulated between the two zones to remove as much mud as possible from the channel; [...] Cementing head An accessory attached to the top of the casing to facilitate cementing of the casing. it has passages for cement slurry and retain chambers for cementing wiper plugs. Page 44 of 46

Channel (cement) A flow area in the cement from inefficient cementing displacement of the drilling mud. Cement plug A portion of cement placed at some point in the wellbore to seal it. see cementing. Scratcher A device that is fastened to the outside of casing to remove mud cake from the wall of a hole to condition the hole for cementing. by rotating or moving the casing string up and down as it is being run into the hole, the scratcher, formed of stiff wire, removes the cake so that [...] Casing pack A means of cementing casing in a well so that the casing may, if necessary, be retrieved with minimum difficulty. a special mud, usually an oil mud, is placed in the well ahead of the cement after the casing has been set. non-solidifying mud is used so that it does not bind or stick to [...] Unconsolidated formation Formations with insufficient cementing agents between the grains to stop movement of individual grains when fluid flows through the formation. usually less than 2 to 10 psi compressive strength. Bradenhead squeeze A process used to repair a hole in the casing by pumping cement down tubing or drill pipe. first, the casinghead, or bradenhead, is closed to prevent fluids from moving up the casing. then the rig‘s pumps are started. pump pressure moves the cement out of the tubing or pipe and, since the top of [...] Wiper plug A rubber-bodied, plastic- or aluminum-cored device used to separate cement and drilling fluid as they are being pumped down the inside of the casing during cementing operations. a wiper plug also removes drilling mud that adheres to the inside of the casing. Phases of Well Construction Well drilling and completion involves a number of distinct project functions. Companies may differ as to who is primarily responsible for each function, and where one function ends and another begins, but one good breakdown would be as follows:  Well Planning  Well Design  Drilling Operations  Formation Evaluation and Testing  Well Completion Note: For simplicity‘s sake, this discussion and its accompanying Case Study examine the drilling and completion process as it relates to a single well. In reality, most projects—particularly those relating to field development—are based on drilling multiple wells, and project budgets, drilling contracts, regulatory requirements and so forth are developed in this "multi-well" context.

The Job The mud engineer (or drilling fluids engineer) may be a university, college, or technical institute graduate, or may have no tertiary education at all, having gained experience working on rigs which could be over 10 years. On land, this experience would come from being a derrick hand, and offshore, the experience would come from being a pump man. Prior to working on his own, he has been on a special training course, known as "mud school", and often spends time working with a senior mud engineer to gain experience. Prior to drilling a well, a "mud program" will be worked out according to the expected geology, in which products to be used, concentrations of those products, and fluid specifications at different depths are all predetermined. As the hole is drilled and gets deeper, more mud is required, and the mud engineer is responsible for making sure that the new mud to be added is made up to the required specifications. The chemical composition of the mud will be designed so as to stabilize the hole. It is sometimes necessary to completely change the mud to drill through a particular subsurface layer. As drilling proceeds, the mud engineer will get information from the mud logger (mud logging technician) about progress through the geological zones, and will make regular physical and chemical checks on the drilling mud. In particular the Marsh funnel viscosity and the density are frequently checked. As drilling proceeds, the mud tends to accumulate small particles of the rocks which are being drilled through, and its properties change. It is the job of the mud engineer to specify additives to correct these changes, or to partially or wholly replace the mud when necessary. He or she must also keep an eye on the equipment which is used to pump the mud and to remove particles, and be prepared if the geologists' predictions are not entirely correct, or if other problems arise. It is sometimes necessary to stabilize the wall of a borehole at a particular depth by pumping cement down through the mud system, and the mud engineer is sometimes in charge of this process. The mud engineer is well supported by the mud supply company with computer aids and manuals dealing with all known problems and their solution, but it is his or her responsibility to get it right in a situation where mistakes can be very costly indeed. A mud engineer's job may involve long shifts of over 12 hours a day. Typical offshore and foreign work schedules are four weeks working and four weeks off. Page 45 of 46

Mud engineer’s duty The mud engineer‘s duties are to stay on the rig site (usually) and constantly monitor and readjust the properties and weight of the drilling fluid or ―mud‖. The mud or drilling fluid is what lubricates the drill bit, keeps it cool, flushes cuttings from the hole being drilled and holds back underground pressure from dangerous zones that contain natural gas. If the mud weight is not heavy enough or is ―underbalanced‖ a blowout can occur, burning down the rig and casing an out of control wild well and loss of life. If the mud or drilling fluid is too heavy it can flush out into the formation causing a ―lost circulation‖ situation which can ruin the well being drilled. The mud engineer adds weight to the drilling fluid or mud by means of adding the mineral barite. Barite is a heavy mineral that mixes with oil and water based muds. The weight of the drilling fluid is measured in PPG or pounds per gallon. Ten pound mud would weight ten pounds to the gallon.

disposed of in offshore waters due to low toxicity to marine organisms. New regulations restrict the amount of synthetic oil that can be discharged. These new regulations created a significant burden in the form of tests needed to determine the "ROC" or retention on cuttings, sampling to determine the percentage of crude oil in the drilling mud, and extensive documentation. It should be noted that no type of oil/synthetic based mud (or drilled cuttings contaminated with OBM/SBM) may be dumped in the North Sea. Contaminated mud must either be shipped back to shore in skips or processed on the rigs. A new monthly toxicity test is also now performed to determine sediment toxicity, using the amphipod Leptocheirus plumulosus. Various concentrations of the drilling mud are added to the environment of captive L. plumulosus to determine its effect on the animals. The test is controversial for two reasons: 1. These animals are not native to many of the areas regulated by them, including the Gulf of Mexico 2. The test has a very large standard deviation and samples that fail badly may pass easily upon retesting

The mud enginner uses a set of scales to constantly weight the mud and make sure that it is heavy enough for the pressures that are expected at a certain depth. An influx of gas or water, mixing with the drilling mud can cause it to suddenly get light, causing an under-balanced situation so the process of monitoring the weight of the mud is constant during the drilling of the well. Mud engineer’s salary The position of mud engineer carries a salary of around $72,500 and involves setting up a ‗mud program‘ according to the geology of the project. Mud engineer’s qualification The Mud Engineer is likely to have a degree in chemistry or some secondary chemistry qualification and an excellent understanding of the drilling procedures. The Mud Engineer should be good at math and science. Before taking up the position, a special training course needs to be completed. Compliance engineer The compliance engineer is the most common name for a relatively new position in the oil field, emerging around 2002 due to new environmental regulations on synthetic mud in the United States. Previously, synthetic mud was regulated the same as water-based mud and could be Page 46 of 46