Schlumberger drilling cd's

Schlumberger drilling cd's

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With highly interactive show with visual and vocal effects illustrating drilling &other topics related to oil production.

the cd's are explained in 6 languages:

:: Arabic

:: English

:: French

:: Spanish

:: Indonesian

:: Portuguese

contents


cd1 : An introduction to drilling rigs and main components of drill string

part1

part2

Cd2:BOP Equipments

part1
part2

Cd3:Drilling Fluids and Mud Test

part1
part2

Cd4:Mud circulation and treating Equipments

part1
part2

Cd5:Hoisting Equipments

part1
part2
part3

Cd6:Rotating Equipments & Mast and Substructure

part1
part2

Cd7:Pipe Handling

part1
part2

Cd8:Casing and Cementing

part1

Cd9:Well logging, Mud logging and Drill stem test

part1

Cd10:Power System and instrument

part1
part2

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Damage during drilling

1-Tubing Damage
2-Matrix Damage
3-Deposition within Porous Formation
Reason for Scale Control: Tubing Damage
•Tubing ID Restriction
1-Constrained production
2-Often layered with scale, wax, asphaltene, etc.
•Completion components blocked with scale
1-Gas Lift Mandrels
2-SSSV
3-Nipples, ..etc
•Corrosion under scale deposition
1-Bacterial / H2S
2-Pitting
3-Loss of steel integrity
Reason for Scale Control: Matrix Damage
1-Hydrocarbon flow through water-saturated matrix
2-Scale deposition restricts flow
3-Scale reduces matrix permeability
4-Complete scaling of pore throat not likely; however,
5-Small quantity of scale =large loss in permeability
6-Large loss in permeability =significant reduction in productivity
Organic Deposit
A type of damage in which heavy hydrocarbons precipitate when temperature or pressure is reduced.
1-These deposits are commonly located in the tubing,gravel pack and perforations, or inside the formation . The injection of cold treating fluids promotes the formation of organic deposits.
2-Organic deposits such as paraffins or asphaltenes are resolubilized using aromatic organic solvents such as toluene or xylene.
3-Small amounts of alcohol help to further dissolve asphaltenes.
Organic deposits are heavy hydrocarbons (paraffins or asphaltenes) that precipitate as the pressure or temperature is reduced.
They are typically located in the tubing, perforations or formation.
1. Paraffins: (dissolved in oil)
Paraffins are the simplest of hydrocarbons. They are composed of only carbon and hydrogen atoms, and the carbons occur as an unbranded chain.
2. Asphaltenes: (undissolved, but suspended as a colloid in oil)
Asphaltenes are organic materials consisting of condensed aromatic and naphthenic ring compounds with molecular weights of several hundred to several thousand. In “solution,” they usually exist as a colloidal suspension,
3. Tar:
-Tar is simply an asphaltene or other heavy-oil deposit. It cannot be removed by acid or mutual solvents. Removal requires dispersion in an aromatic solvent, and energy is typically necessary to achieve removal.
4. Resins :
-(Peptizing agent, dissolved in oil, help suspend asphaltene in oil)
5. Wax:
-A combined deposit of paraffins, asphaltenes, resins, mixed with clays, sand, and debris (dissolved in oil)

Scale Inhibitor

A chemical treatment used to control or prevent scale deposition in the production conduit or completion system.
Scale-inhibit or chemicals may be continuously injected through a down hole injection point in the completion, or periodic squeeze treatments may be undertaken to place the inhibitor in the reservoir matrix for subsequent commingling with produced fluids.Some scale-inhibitor systems integrate scale inhibitors and fracture treatments into one step, which guarantees that the entire well is treated with scale inhibitor. In this type of treatment, a high-efficiency scale inhibitor is pumped into the matrix surrounding the fracture face during leak off.
It adsorbs to the matrix during pumping until the fracture begins to produce water. As water passes through the inhibitor-adsorbed zone, it dissolves sufficient inhibitor to prevent scale deposition. The inhibitor is better placed than in a convention a scale-inhibitor squeeze, which reduces the re-treatment cost and improves production.

Inhibitor Types

There are a number of scale inhibitor types:
1.Inorganic phosphates.
2.Organo phosphorous compounds.
3.Polyvinyl sulphonate co-polymers.
4.Organic polymers.
5.Blends of phosphonates and polymers.

Scale inhibitors prevent undesirable buildup on your equipment. Appropriate treatment by NCP Scale Inhibitors will extend the life of industrial equipment and provide optimal process conditions.Fields where NCP Scale Inhibitors can be used are:Oil and Gas field
1-Water injection
2-Refineries
3-Water desalination
4-Power plants
5-Industrial waters

Mineral Scale

Mineral scales (subsequently referred to as scales) are inorganic solids precipitated from water and subsequently deposited. Scales are a common form of formation damage and blockages or restrictions to perforations, screens, liner or tubing.
Like most production chemistry problems, they pose a safety issue through loss of operability of check valves, safety valves or, in severe cases, tree valves. To predict the scaling potential of reservoir aquifer water, a representative water sample is required.
This requires that an appraisal or exploration well deliberately produces water, and that any contaminants such as completion or drilling fluids are also analyzed so that interference is backed out.
The water chemistry of hydrocarbon bearing reservoirs is highly variable, ranging from very low ion strength to high salinity brines containing a wide range of various ions.
Prevention and mitigation:
1.Mitigate or prevent scale in formation by using formation water instead of seawater,
2.Scale Inhibitor
Scales:
Hard inorganic crystals (~ 3 –4 mhos)
1-Slightly less than steel (5 mhos)
2-Diamond, 9 mhos
3-Variable crystal size
4-Microns to centimeters
5-Produced form aqueous solutions
6-Soluble in specially formulated solutions

Scale Types

The equilibrium that existed for so long is then upset on a geologically diminutive timescale during the production phase of the field development.
Production creates pressure and temperature reduction or introduces new fluids (muds, completion fluids or water injection).
The main types of scales are:
1-Carbonates–mainly calcium carbonate, but also iron carbonate
2-Sulphates–barium, strontium and calcium
3-Sulphide–less frequently encountered scales, but include lead, zinc and iron
4-Salts–mainly sodium chloride;
Most Common Types of Scales
1-Calcite (CaCO3)
–Formed due to the presence of calcium ions and bicarbonate ions in the produced water
–Pressure changes may cause precipitation

2-Barite (BaSO4)
–Generally formed when there is co-production of formation water (Ba2+) and injection water (SO4-)

Hydrogen Sulfide Gas Problems

Hydrogen sulfide is a colour less, flammable, poisonous gas that smells like rotten eggs.
Hydrogen Sulfide gas is very dangerous and in high concentrations is lethal and in low concentration gives a rotten eggs mell.
Hydrogen sulfide(or hydrogen sulphide) is the chemical compound with theformulaH2S. This colorless, toxic, flammable gas is partially responsible for the foul odor of rotten eggs and flatulence. It often results from the bacterial break down of sulfur-containing organic matter in the absence of oxygen, such as in swamp sand sewers (anaerobic digestion). It also occurs in volcanic gases,natural gas and some well waters. The body produces small amounts of H2S and uses it as a signaling molecule.

Safety

Hydrogen sulfide is a highly toxic and flammable gas. Being heavier than air, it tends to accumulate at the bottom of poorly ventilated spaces. Although very pungent at first, it quickly deadens the sense of smell, so potential victims may be unaware of its presence until it is too late. For safe handling procedures, a hydrogen sulfide material safety data sheet (MSDS)should be consulted.

Toxicity of H2S

Hydrogen sulfide is considered a broad-spectrum poison, meaning that it can poison several different systems in the body, although the nervous system is most affected. The toxicity of H2S is comparable with that of hydrogen cyanide. It forms a complex bond with iron in the mitochondrialcy to chromeenzymes, thereby blocking oxygen from binding and stop ping cellular respiration. Since hydrogen sulfide occurs naturally in the environment and the gut, enzymes exist in the body capable of detoxifying it by oxidation to (harmless) sulfate.Hence, low levels of sulfide may be tolerated indefinitely.
At some threshold level, believed to average around 300–350 ppm, the oxidative enzymes become overwhelmed. Many personal safety gas detectors, such as those used by utility, sewage and petrochemical workers, are set to alarm at as low as 5 to 10 ppm and to go into high alarm at 15 ppm.
Exposure to lower concentrations can result in eye irritation, a sore throat and cough, nausea, shortness of breath, and fluid in the lungs. These symptoms usually go away in a few weeks. Long-term, low-level exposure may result in fatigue, loss of appetite,headaches, irritability, poor memory, and dizziness. Chronic exposures to low level H2S (around 2ppm) has been implicated in increased miscarriage and reproductive health issues amongst Russian and Finnish wood pulp workers, but the reports have not (as of circa 1995) been replicated.

Toxicity of H2S in Details

0.0047ppmis the recognition threshold, the concentration at which 50% of humans can detect the characteristic odor of hydrogen sulfide, normally described as resembling "a rotten egg".
Less than 10 ppm has an exposure limit of 8 hours per day.
10–20 ppm is the borderline concentration for eye irritation.
50–100 ppm leads to eye damage.
At 150–250 ppm the olfactory nerve is paralyzed after a few inhalations, and the sense of smell disappears, often together with awareness of danger,
320–530 ppm leads to pulmonary edema with the possibility of death.
530–1000 ppm causes strong stimulation of the central nervous system and rapid breathing, leading to loss of breathing;
800 ppm is the lethal concentration for 50% of humans for 5 minutes exposure(LC50).
Concentrations over 1000 ppm cause immediate collapse with loss of breathing, even after inhalation of a single breath.
Hydrogen sulfide was used by the British as a chemical agent during World War One. It was not considered to be an ideal war gas, but while other gases were in short supply it was used on two occasions in 1916.The gas, produced by mixing certain household ingredients, was used in a suicide wave in 2008, primarily in Japan.

Hydraulics –Surge and Swab Pressures

•Swabbing
–When the drillstring is picked up to make a connection or trip out of the well, the mud in the annulus must fall to replace the volume of pipe pulled from the well.
–The hydrostatic pressure is momentarily reduced while the mud is falling in the annulus.
•Surging
–When the drillstring or casing is lowered or run into the well, mud is displaced from the well.
–The frictional pressure losses from the flow of mud in the annulus as it is displaced by the pipe causes pressures in excess of the hydrostatic pressure of the column of mud in the wellbore.
•Swab and surge pressures are related to the mud’s rheological properties:
–The mud’s gel strengths
–The speed at which the pipe is pulled from, or run into, the well
–The annular dimensions
–The length of drillstring in the well
•The rheological properties affect swab and surge pressures in the same manner as they affect annular pressure losses.
•Increases in either the plastic viscosity or the yield point will increase the swab and surge pressures.
•Since the maximum (not average) swab and surge pressures must be less than the pressures needed to swab the well in or break the formation down, swab and surge pressures must be calculated for the maximum drill string velocity when tripping.
•This is generally calculated as one-and-one-half times the average drill string velocity.
VMaxDrillstring(ft/min per stand) =(1.5 x stand length (ft) x 60 sec)/(min seconds per stand)
•The annular velocity must be calculated for each annular space.
•These annular velocities should be substituted into the API equations for the annular pressure losses for each interval.
•The swab and surge pressures are then calculated in the same manner as the ECD.
AVSwab-Surge(ft/min) =(VMaxDrillstring(ft/min) x drillstring displacement (bbl/ft))/(annular capacity (bbl/ft))
•The object of calculating swab and surge pressures is to determine safe pulling and running speeds and minimized trip times.
•This is done by changing the maximum or minimum time per stand and recalculating the swab and surge pressures until times per stand are found where the swab and surge pressures plus the hydrostatic pressure is approximately equal to the formation pressure and fracture pressure.
•This time per stand is only relevant for the present length of drillstring in the well.
•As pipe is removed from the hole, the drillstring length decreases and the bottom hole assembly will be pulled into large diameter casing.
•This will make it possible to pull each stand faster without risk of swabbing in the well.
•When tripping in to the well, the length of drillstring will be increasing and the annular spaces will decrease as the BHA is run into smaller diameters.
•This will require that the running time per stand be increased to avoid fracturing the formation.
•The swab and surge pressures should be calculated at either 500-or 1,000-ft intervals.
•Slip Velocity
–Free settling occurs when a single particle falls through a fluid without interference from other particles or container walls
•For Slip velocity we use stokes law
VS=( gC x DS*2(rS-rL))/(46.3μ)
–VS= Slip or settling velocity (ft/sec)
–gC= Gravitational constant (ft/sec2)
–DS= Diameter of the solid (ft)
–rS= Density of solid (lb/ft3)
–rL= Density of liquid (lb/ft3)
–μ= Viscosity of liquid (cP)
•This equation is a mathematical expression of events commonly observed:
–The larger the difference between the density of the cutting and the density of the liquid the faster the solid will settle.
–The larger the particle is the faster it settles
–The lower the liquid’s viscosity (1/μ), the faster the settling rate.

Hydraulics –ECD-Bit Hydraulics

•Equivalent circulating density (ECD)

–The pressure on a formation while circulating is equal to the total annular circulating pressure losses from the point of interest to the bell nipple, plus the hydrostatic pressure of the mud.
–This force is expressed as the density of mud that would exert a hydrostatic pressure equivalent to this pressure.
Formula for ECD
ECD (lb/gal) = Pa(psi)/ 0.052 x TVD (ft)
•Excessive ECD may cause losses by exceeding fracture gradient on a well
.•It is important to optimize rheological properties to avoid excessive ECD.

Bit Hydraulics

•In addition to bit pressure loss, several other hydraulics calculations are used to optimize the drilling performance.
•These include hydraulic horsepower, impact force and jet velocity calculations.
•Hydraulic Horsepower (hhp)
–The recommended hydraulic horsepower (hhp) range for most rock bits is 2.5 to 5.0 Horsepower per Square Inch (HSI) of bit area.
–Low hydraulic horsepower at the bit can result in low penetration rates and poor bit performance.
•Hydraulic Horsepower (hhp)
–The bit hydraulic horsepower cannot exceed the total system hydraulic horsepower.
hhpb= QPBit/1,740
–Q = Flow rate (gpm)
–PBit= Bit pressure loss (psi)
•Hydraulic Horsepower (hhp)
–Hydraulic Horsepower per square inch
HSI = 1.27 x hhpb/Bit Size*2
–Bit Size = Bit diameter (in.)
–System Hydraulic HorsepowerhhpSystem= PTotalQ1,714
–PTotal= Total system pressure losses (psi)

Nozzle Velocity

–Although more than one nozzle size may be run in a bit, the nozzle velocity will be the same for all of the nozzles.
–Nozzle velocities of 250 to 450 ft/sec are recommended for most bits.
–Nozzle velocities in excess of 450 ft/sec may erode the cutting structure of the bit.
•Nozzle Velocity
Vn(ft/sec) = 417.2 x Q/(Dn1*2+ Dn2*2+ Dn3*2+ …)
–Q = Flow rate (gpm)
–Dn= Nozzle diameter (32nds in.)
–Q = Flow rate (gpm)
•Percent pressure drop at the bi
t–It is generally desired to have 50 to 65% of surface pressure used across the bit.
%PBit= PBit x 100/PTotal
•Hydraulic impact force (IF)
IF (lb) = Vn x Qr/1,930
–Vn= Nozzle velocity (ft/sec)
–Q = Flow rate (gpm)
–r = Density (lb/gal)
–Impact force per inch squaredIF (psi) = 1.27 x IF (lb)/Bit Size*2

Hydraulics –Pressure losses

•The circulating system of a drilling well is made up of a number of components or intervals, each with a specific pressure drop.
•The sum of these interval pressure drops is equal to the total system pressure loss or the measured standpipe pressure.
•The total pressure loss for this system can described mathematically as:
PTotal= PSurf Equip+ PDrillstring+ PBit+ PAnnulus
•Surface pressure losses include losses between the standpipe pressure gauge and the drill pipe.
–This includes the standpipe, kellyhose, swivel, and kellyor top drive.
–To calculate the pressure loss in the surface connections, use the API pipe formula for pressure loss in the drill pipe.
•Top Drive Surface connections
–There is no current standard case for top drive units.
–The surface connections of most of these units consist of an 86-ft standpipe and 86 ft of hose with either a 3.0-or 3.8-in. ID. In addition, there is an “S”pipe that is different on almost every rig.
•Drill String Pressure losses
–The pressure loss in the drillstring is equal to the sum of the pressure losses in all of the drillstring intervals, including drill pipe, drill collars, mud motors, MWD/LWD/PWD or any other downhole tools.
•Friction Factor
–Before calculating the pressure loss, the Fanning friction factor (fp) is calculated next with different equations being used for laminar and turbulent flow.
–This friction factor is an indication of the resistance to fluid flow at the pipe wall.
–The friction factor in these calculations assumes a similar roughness for all tubulars.
•Formulas for friction Factor–If the Reynolds number is less than or equal to 2,100:
fp= 16/NRep
–If the Reynolds number is greater than or equal to 2,100
fp=((log n + 3.93)/50)/NRep((1.75 –log n)/7)
•Pipe Interval Pressure loss
–Drillstring (including drill collars) intervals are determined by the ID of the pipe.
–The length of an interval is the length of pipe that has the same internal diameter.
–The following equation is used to calculate the pressure loss for each drillstring interval.
•Formula for Pipe Pressure loss
•Pp(psi) =( fp x Vp*2 x r x L)/(92,916 x D)
•Vp= Velocity (ft/min)
•D = ID pipe (in.)
•r = Density (lb/gal)
•L = Length (ft)
•Pressure loss for motors and tools
–If the drillstring contains a downhole motor; an MWD, LWD or PWD tool; a turbine or a thruster, their pressure losses must be included in the system pressure losses when calculating the system’s hydraulics.
–These pressure losses can significantly change the pressure available at the bit, as well as bypass flow around the bit.
–The pressure loss through MWD and LWD tools varies widely with mud weight, mud properties, flow rate, tool design, tool size and the data transmission rate.
–Some manufacturers publish pressure losses for their tools but these pressure losses can be conservative, because they are usually determined with water.
–The pressure loss across motors and turbines cannot be accurately determined by formula, but, again, this pressure loss data is available from the suppliers.
–Regular nozzle type bit
Pbit= 156rQ*2/(Dn1*2+ Dn2*2+ Dn3*2+ …)*2
–Diamond type coring bitPbit= rQ*2/10,858(TFA)*2
–r = Density (lb/gal)
–Q = Flow ratio (gpm)
•Pressure loss in the annulus
–The total annular pressure loss is the sum of all of the annular interval pressure losses.
–Annular intervals are divided by each change in hydraulic diameter.
–A change in drillstring outside diameter and/or a change in casing, liner or open hole inside diameter would result in a hydraulic diameter change.
–As with the drillstring pressure loss equations, the friction factor must first be determined before calculating the pressure loss for each annular section.
–The pressure loss for each interval must be calculated separately and added together for the total annular pressure loss.
This equation is used to calculate the individual interval pressure losses.
Pa(psi) =( fa xVa x 2r x Lm)/((92,916 x D2)-D1)
–Va= Velocity (ft/min)
–D2= ID hole or casing (in.)
–D1= OD Drill pipe or collars (in.)
–r = Density (lb/gal)
–Lm= Length (ft)
-fa as before


–TFA = Total Flow Area (in.2)