PI

QUIZ QSTN-AND-ANS
PIPELINE Only one answer is correct. Identify the correct answer:

1. For Short distance offshore hydrocarbon transportation, recommend mode of transportation is: Pipelines, Rail, Road tanker, Ship/Barge 2. For Long distance onshore hydrocarbon transportation, the most economic recommend mode: Pipelines, Rail, Road tanker, Ship/Barge 3. Right-of-way may use: Multiple lines, single line, none 4. In the construction of the long-run cost function, the principal fixed cost components are as follows: Those that change with pipe diameter; Scheduled maintenance cost Break down maintenance cost 5. Economic diameter is Directly proportional to specific gravity of fluid, inversely proportional to specific gravity of fluid does not have any effect. 6. Economic diameter is Directly proportional to Viscosity of fluid, inversely proportional to viscosity of fluid, Does not have any effect. 7. Presence of water vapors in gas, the Heat value of unit mass: Increases, decreases, no effect 8. The facilities piping code is governed by: ANSI-[(B31.3), (B31.4) , (B31.8)], 9. The liquid pipelines are governed by: ANSI-[(B31.3), (B31.4) , (B31.8)], 10. The Gas pipelines are governed by: ANSI-[(B31.3), (B31.4), (B31.8)], 11. Risers are constructed for Process/unmanned well platform fluid flow, Subsea completed manifold, onshore process plants
12. Hydraulic Shock/ surge and Water hammering in Pipes Increases, Decreases, Does not have effect (on the design pressure). 13. Compressibility factor is required for evaluation of power requirement for transportation of Liquid, Gas, solids 14. Presence of water vapor in Ethane compared with pure Ethane, will (Increase, decrease, no effect) on compression power requirement 15. Ductility in the pipeline material physical property is an indication of Brittleness, plasticity, yield strength 16. A check valve shall have a closure member(s) (as ball or a flapper) permit fluid to flow In one direction only, in both directions, in none of the direction 17. The most common industry standard for steel linepipe is API-5L. API-5A, API-5CT 18. Pressure Recorder Alarm is set at Maximum Allowable Operating Pressure, less than Maximum Allowable Operating Pressure, Equal to Maximum Allowable Operating Pressure. 19. For liquids, viscosity

20.

21. 22.

23.

Decreases with increasing temperature, Increases with increase in temperature, no effect on change due to change in temperature Vapor pressure is The pressure exerted by the vapor in liquid phase in a confined container at a given temperature, The pressure exerted by the vapor phase of a liquid in a confined container at a given temperature, None of the above Vapor pressure Decreases with temperature, Increases with temperature, No effect due to change of system temperature After a weld is made, Does not matter later or earlier , It is examined to ensure integrity of the weld before laying into the trench; It is examined to ensure integrity of the weld before laying into the trench, Pipelines are coated primarily to protect them Against erosion, against corrosion, against expansion due to temperature variations.

24. J lay barge used for laying pipeline in Shallow water, Deep sea water, in both conditions, none of the conditions

25. The pipeline is to be put into operation Before commissioning of pipeline, After Pigging of pipeline, after certification that all relevant codes have been followed, 26. Utility pigs have very few moving parts and they are primarily used for Filling of water for hydro testing, Acquiring internal geometry like pitting, cracks etc in pipeline, Product separation and cleaning, 27. Formation of wax in crude in pipeline results in: Decrease in pressure drop, No effect, Increase in pressure drop, 28. The presence of H2S in gas normally Decreases the hydrate formation temperature, at constant pressure, Increases the hydrate formation temperature, at constant pressure, No effect of presence of H2S in hydrate formation temperature 29. In order to avoid hydrate formation in gas, the initial temperature of gas to be Higher than the hydrate formation temperature, lower than the hydrate formation, No effect gas temperature on Hydrate formation. 30. The main cause of scale deposition is The super saturation of the scale forming substances in associated water, Increase in system temperature, Removal of impurities from the system.

DOWNSTREAM

1. Bottom product of atmospheric pressure crude oil distillation column is termed as A. reduced crude B. heavy ends

C. asphalt D. residuum 2. Which of the following tests is not done for transformer oil ? A. Flash point and acid value. B. Aniline point.

C. Dielectric strength. D. Copper strip corrosion test. 3. Which is the most undesirable component in kerosene? A. Aromatics , C. n-paraffins B. i-paraffins D.Naphthenes

4. Pick out the wrong statement about the smoking tendency of various hydrocarbon constituents of kerosene. A. Smoking tendency of hydrocarbons increases in the order: paraffins → iso paraffins → naphthenes → aromatics. B. Smoking tendency of paraffins increase with decrease in its molecular weight.

C. Smoking tendency of naphthenes decreases with its increasing molecular weight & also on addition of double bond. D. Smoking tendency of aromatics decreases with increase in its molecular weight. 5. Solvent used in duo-sol extraction for lube oil up gradation is a mixture of A. Propane & phenol-cresol mixture. B. Methyl ethyl ketone & glycol.

C. Phenol & furfural. D. propane & liquid sulpher dioxide. 6. Which of the following fractions of a crude oil will have the maximum gravity API (i.e. °API) ? A. Diesel B. Gasoline

C. Atmospheric gas oil D. Vacuum gas oil 7. For gasoline, the flash point (<50°C) is determined by the A. Abel apparatus. B. Pensky-Marten's apparatus.

C. Saybolt chromometer. D. None of these. 8. Flash point of atmospheric distillation residue is determined by __________ apparatus. A. Pensky-Martens (closed cup type). B. Abel.

C. Cleveland (open cup type) D. none of these. 9. Maximum sulpher percentage in low sulpher heavy stock (LSHS) furnace oil is about A.0.1 C.2.5 10.Pour point and freezing point is equal for A. petrol B. diesel B. 1 D.3.5

C. water D. crude petroleum 11.__________ is not an important refinery process for upgrading the quality of lubricating oil. A. Deoiling B. Solvent refining

C. Clay treatment D. Hydro treatment 12.Pick out the undesirable property for a solvent meant for dewaxing of lube oil. A. Complete miscibility with oil. B. High solubility of wax in the solvent.

C. Both (a) and (b).

D. Neither (a) nor (b). 13.Which of the following is used as a catalyst in fluidized bed catalytic cracking ? A. Silica-magnesia B. Silica-alumina

C. Bentonite clays D. All (a), (b) and (c) 14.Casing head gasoline is the liquid A. Butane. B. Propane.

C. Natural gas. D. Gasoline separated from wet natural gas by compression. 15.Visbreaking process is used mainly for making A. high cetane diesel B. high octane gasoline

C. fuel oil D. smoke free kerosene 16.Crude oil is pumped by a __________ pump. A.gear C.screw 17.Solvent used in the deasphalting process is A.furfurol C.propane 18.A good lubricant should have high A. viscosity index B. volatility B. phenol D.hexane B. centrifugal D.reciprocating

C. pour point none of these

19.Complete removal of __________ from gasoline is done by Unisol process using caustic soda and methyl alcohol. A.waxes C.asphalt 20.In petroleum refining, the process used for conversion of hydrocarbons to aromatics is A. catalytic cracking B. catalytic reforming B. mercaptans D.diolefins

C. hydro treating D. alkylation 21.Octane number of gasoline is a measure of its A. Knocking tendency. B. Ignition delay.

C. Ignition temperature. D. Smoke point. 22.Pick out the additive property of lube oil out of following. A. °API gravity B. Specific gravity

C. Viscosity D. Flashpoint 23.Catalyst used in catalytic reforming is A. platinum on alumina B. nickel

C. iron D. aluminum chloride 24.Tanks used for the storage of petroleum products (which are inflammable) should be painted with__________ paint. A.black C.red 25.Cetane number of diesel used in trucks may be about A.5 C.35 B. 14 D.85 B. white D.yellow

26.__________ Determination is not a very significant and important test for gasoline. A. Gum & sulpher content B. Viscosity

C. Octane number D. Reid vapor pressure 27.Which of the following has the lowest viscosity (at a given temperature) of all? A. Naphtha B. Kerosene

C. Diesel D. Lube oil 28.Paraffin base crude oil as compared to asphalt base crude gives A. Higher yield of straight run gasoline. B. Higher octane number gasoline.

C. Lower viscosity index lube oil. D. poorer yield of lube oil 29.In the atmospheric pressure crude distillation, the content of __________ from lighter fraction to heavier ones. A. sulpher increases B. sulpher decreases

C. nitrogen decreases D. none of these 30.__________ converts n-paraffins to i-paraffins. A. Alkylation B. Polymerization

C. Isomerisation D. none of these 31.The color of gasoline is an indication of its A. Octane number. B. Lead susceptibility.

C. Gum forming tendency & thoroughness of refining.

D. None of these.

32.Flash point of an oil gives an idea of the A.Nature of boiling point diagram of the system. B. Amount of low boiling fraction present. C.Explosion hazards. D. All , (a), (b) and (c). 33.Which of the following constituents present in petroleum is responsible for ash formation? A.Nitrogen compounds B. Organ metallic compounds C.Sulphur compounds D.Oxygen compounds 34.Choose the correct statement regarding thermal cracking. A.A moderate change in operating temperature does not change the depth of cracking. B. Increased residence time results in the decreased severity of cracking. C.At low pressure, the yields of lighter hydrocarbons are more. D.Greater depth of cracking gives lower octane number gasoline 35.A typical yield of diesel in straight run distillation of crude oil may be about __________ percent. A.8 C.28 36.Which is almost absent in crude petroleum? A.Olefins C.Naphthenes B. Mercaptan D.Cyclo paraffins B. 18 D.35

37.Which one is used to determine the color of petroleum products ? A.Color comparator B. Saybolt chromometer C.Cleveland apparatus None of these

38.Pick out the wrong statement. A.Higher specific gravity of petroleum products means higher C/H ratio. B. Aromatics have lower specific gravity than corresponding paraffins. C.Hydrocarbons of low specific gravity (e.g, paraffins) possess the maximum thermal energy per unit volume. D.Hydrocarbons of high specific gravity (eg, aromatics) possess the maximum thermal energy per unit weight. 39.Olefins are A.Saturated hydrocarbons. B. Unsaturated cyclic compounds (hydrocarbons). C.Present in substantially good quantity in crude petroleum. D.none of these. 40.Which of the following is desirable in diesel and kerosene but is undersirable in gasoline ? A.Aromatics B. Mercaptan C.Paraffins D.Naphthenic acid 41.Phenols are added in gasoline to A.Improve the octane number. B. Act as an antioxidant. C.Reduce its viscosity. D.increase its pour point 42.Which of the following has the highest gum forming tendency in gasoline? A.Paraffins C.Aromatics 43.Higher viscosity of lubricating oil usually signifies A.lower Reid vapor pressure. B. higher acid number. C.higher flash point and fire point. D.lower flash point and fire point. 44.Aniline point test of an oil qualitatively indicates the __________ content of an oil. B. Diolefins D.Naphthenes

A.paraffin C.aromatic

B. olefin D. naphthenes

45.Bottom product of atmospheric pressure crude oil distillation column is termed as A. reduced crude B. heavy ends C. asphalt D. residuum 46. Which of the following is used as a solvent in deasphalting of petroleum products? A. Furfural B. Propane C. Methyl ethyl ketone D. Liquid sulpher dioxide 47. Fuel oil is subjected to Visbreaking to reduce its A. pour point, B. viscosity C. pressure drop on pumping D. all (a), (b) and (c) 48. Deoiling is the process of removal of oil from wax. It is done by the __________ process. A. solvent extraction B. sweating C. resettling D. all (a), (b) & (c) 49. Smoke point of kerosene expresses its A. Burning characteristics. , B. Luminosity characteristics. , C. Aromatic content directly. D. Lamp wick wetting characteristics. 50. Which of the following has the highest octane number? A. Aromatics B. i-paraffins C. Naphthenes D. Olefins E. n-paraffins

(MISCELLANEOUS PRODUCTION)
1. Define productivity index and give its unit? The productivity index is the rate of production per unit draw down. It has unit of barrel per day or cubic feet per day. 2. What is IPR? IPR means inflow performance relation and it is relation between the flowing bottom hole pressure and the rate of production. 3. Describe the stages of flow in multiphase system when it flows up to the surface? The stages are as follows: 1. Liquid flow 2. Bubble flow 3. Plug flow 4. Annular flow 5. Mist flow 4. What are chokes and state its two types? The cokes are the devices that are used at the surface used to control the flow and control the amount of sand production with the help of a constriction. There are two types of chokes positive fixed chokes and adjustable chokes. 5. What are two valves used in SRP The two valves used in SRP are standing valve and travelling valve. 6. What is gas locking? Gas locking is the phenomena that occur when the barrel is completely filled with the gas in SRP. There is no room for compression and more oil cannot be pulled inside because the gas cannot be compressed enough to overcome the hydrostatic head acting on the travelling valve.this causes both the valves to be closed and the pump is gas locked. 7. Give two types of gas lift systems There are two types of gas lift systems: 1. CONTINOUS GAS LIFT SYSTEM  Continuous gas supply  Used when reservoir pressure is not so low.  Ensures continuous supply 2. INTERMITTENT GAS SUPPLY  Gas supply in some intervals  Intermittent supply  Used when reservoir pressure is very less

8. Give three types of installations of gas lift system? There are three installation methods in gas lift system: 1. Open continuous lift 2. Semi closed continuous lift 3. Closed intermittent lift 9. Define sick well. The sick well is a well where in the production has been reduced because of the skin formation and which requires production enhancement. 10. What is well stimulation The well stimulation is the technique used to improve the well productivity or injectivity by providing well bore or reservoir treatment. 11. What are different sand control techniques? The sand control can be done through techniques like: 1. Mechanical methods  Slotted screen (liner)  Wire wrapped screen  Pre packed screen  Gravel pack technique 2. Expandable sand screens 12. What are the steps in sick well analysis? The three steps involved in sick well analysis include: 1. Planning  It involves identifying the wells requiring treatment  It involves finding out of appropriate method for well stimulation 2. Execution  It involve carrying out of stimulation 3. Monitoring  It involves monitoring of the production data to know how successful was stimulation. 13. Describe principle of hydraulic jet pumping. It involves the hydraulic pump set at the bottom of well bore which pumps the power fluids inserted in well bore back to the surface along with the reservoir fluids and they are separated at the surface.

NATURAL GAS ENGINEERING
1. Give a classification of reservoir based on types on PVT properties for natural gas. a. 1. Retrograde Gas Condensate 2. near critical gas condensate 3. Wet gas 4. Dry gas 2. State few Equation of State used in Natural gas reservoir calculation. a. 1. Vander Wall's equation 2. Peng robinson equation 3. Redlich kwong equation 3. List different types of separators used in oil and gas industry. a. 1. Horizontal Separators 2. Vertical Separators 3. Spherical Separators 4. What are the various principles on which the separators work? a. 1. Gravity settling 2. Centrifuge 3. Impingement 5. What is the design considerations needed for designing separators? a. 1. The length to diameter ratio, L/D ration for horizontal or vertical separator must be kept between 3 to 8. 2. For a vertical separator the vapor -liquid interface phase must be at least 2 ft from the bottom and 4 ft from the top of the vessel, which implies that the min. height for a vertical separator must be 6 ft. 3. For a horizontal separator vapor - liquid interface must be 10 inch from the bottom and 16 inch from the top of the vessel, which implies a min. separator diameter of 26 inches.

6. How are the various stages of separation are decided? A. The various stages of separation are decided with the help of formula(image is also attached for reference): r = (p1/ps) ^ (1/n)

Where, r = pressure ratio n = no. of stages - 1 p1 = pressure at 1st separator Ps = pressure at stock tank condition

7. List few production forecasting tools used in in oil and gas industries. a. 1. Volumetric method 2. Decline curve analysis 3. Reservoir simulation and modeling 4. Material balance 8. What are Gas hydrates? a. A gas hydrate is a crystalline solid; its building blocks consist of a gas molecule surrounded by a cage of water molecules. It is similar to ice, except that the crystal structure is stabilized by the guest gas molecule within the cage of water molecules. 9. What are various steps in Gas processing System? a. 1. The reservoir module that deals with the flow of gas through subsurface strata. 2. Flow module for the flow of fluids from the reservoir to the wellhead at the surface. 3. Gas Gathering system module. This module calculates the flow of gas through the pipeline network at the surface that is used to collect gas from several wells for separation and processing 4. Separation module for separation of liquid and gas streams, 5. Metering devices for measuring amount of gas and oil from separators. 6. Gas conditioning module for removal of contaminants from the gas. 7. NGL (natural gas liquids) recovery module. 8. Gas compression and liquefaction. 9. Flow module for gas transport to consumers. 10. What is isentropic compression? a. The compression process is adiabatic reversible or isentropic (constant entropy) if the the gas behaves as an ideal gas, no heat is added to or removed from the gas during compression, and the process is frictionless. the pressure- volume behavior of a gas under isentropic compression or expansion is given by(image -2 of formula is attached with this mail): P1/P2 = (V2/V1) ^k = c Where k = Cp/Cv

11. What is work done in a cyclic process? a. zero 12. What are different types of flow meters used for measuring gas flow? a. 1. Orifice meters 2. venturi meter 3. Flow Nozzles 4. Displacement meters 5. Turbine Meters 6. Rotameter 7. ultrasonic meters

13. What are the main attributes of flow measurements? a. 1. accuracy 2. rangeability 3. repeatability 4. linearity 14. What are different types of Gas gathering Systems? a. 1. Well center Gathering System 2. Trunk line Gathering System 15. What are the various ways of preventing hydrate formation in pipelines? a. b. c. d. 1. gas Dehydration, Use of hydrate inhibitors. Use of heaters along the line or near the meters Other methods such as - elimination of leaks, enlarging meter piping and valves and replacing needle valves with gate valves or globe valves.

16. What do you understand by Slugging phenomenon with respect to pipeline transportation? a. Slugging refers to accumulation of liquids in gas flow lines. In low-pressure lines, the liquid accumulates at low spots in the line, restricting gas pressure untill enough pressure is built up for overcoming the block. In high pressure lines, liquid is swept through the line upto the orifice meter. 17. What is the work done in isochoric process? a. The work done in any process is given by integration of PdV from initial to filnal stage. So in case of isochoric process volume change is zero. Hence dV is equal to zero, hence the work done in isochoric process is zero. 18. An ideal gas system undergoes an adiabatic process in which it expands and does 20 J of work on its environment. What is the change in the system’s internal energy? 1. –20 J 2.–5J 3.0J 4. 20 J a. Heat transfer to the system = work done by the system + change in internal energy of the system

For adiabatic process, heat transfer to the system = 0 Therefore change in internal energy = - work done = -20 J 19. What is entropy change in adiabatic process? a. Adiabatic process means no heat transfer process, but the entropy not necessarily to be zero. IT will be zero if the process adiabatic reversible. Tds = dh - vdp, ds = dh/T - (v/T)dp, dh = cpdT and v/T = R/p ds = (cp/T)dT - (R/p)dp So, Δs = cp ln(T2/T1) - R ln(P2/P1) >> compression from state (1) to state (2)

20. Give compressor classification based on flow rates. a. For HIGH FLOW rates Centrifugal pumps are used; For LOW FLOW rates reciprocating pumps are used.

DRILLING ENGINEERING + CASING DESIGN + WELL STIMULATION (HYDRAULIC FRACTURING)

Questions on Pore and fracture pressure, Casing Design
1. What are the methods of estimating pore-pressure gradients?

2.

3.

4.

5. 6.

7. 8.

9.

- Data provided by geoscientist i.e. Seismic - Data from offset well in the same structure - Predicting pore pressures from dc exponent/sigma log/resistivity log How fracture pressure gradient are estimated? - Correlations like Eaton‟s equation - Leak off test Abnormal pressures are a) Formation pressure is greater than normal pressure at that depth b) Formation pressure is less than normal pressure at that depth c) Formation pressure is greater or less than normal pressure at that depth d) None of the above Why Casings are used? - Borehole stability - Isolates wellbore fluids from sub surface formations and its fluids - High strength flow conduit for drilling fluid - Selective isolation of formations What do you mean by 3CP? 3 Casing Policy What does a casing with specification H-40 Signifies? a) Grade H, 40,000 psi Tensile Strength b) Grade H, 40,00 psi Tensile Strength c) Grade H, 40,000 psi Minimum Yield Strength d) Grade H, 40,00 psi Minimum Yield Strength What are the factors considered in Casing Design? Collapse Pressure, Tensile Strength and Burst pressure Casing is subjected to maximum burst pressure at a) Every point in the casing b) Bottom c) Surface d) Central Portion Considering collapse pressure, strongest pipe should be placed at a) All pipes should be of uniform strength b) Bottom c) Surface d) Central portion

10. Surface casing is used for a) Erosion of Surface Formations b) Seal off the long open hole or zones causing trouble c) Provide a work shaft of a known diameter to the pay zone. d) Provide a means for attaching well head and the blowout preventer 11. Casing /tubular are classified in terms of Size (O.D), Weight, Grade and connection type 12. What size of casing would you use for an 8 ½ inch hole ? 5 ½ inch Casing 13. Which equipment allows casing to be suspended from the surface? Casing hanger 14. Length of a casing pipe is approximately 27-30 ft 15. What is Casing shoe assembly? A short assembly typically manufactured from a heavy steel collar and profiled cement interior that is screwed to the bottom of a casing string. The rounded profile helps guide the casing string past any ledges or obstructions that would prevent the string from being correctly located in the wellbore. 16. What is the function of Float collar ? An integral check valve in the float shoe prevents reverse flow, or U-tubing, of cement slurry from the annulus into the casing or flow of wellbore fluids into the casing string as it is run. 17. Common API grades of casing used are: N-80, P-110 18. An example of a slurry mixture is 60:40:2. What do these three numbers refer to? 60 % fly ash , 40 % cement, 2 % other additives (such as gel) 19. Most operators wait on cement to reach a minimum compressive strength of 500 psi before resuming drilling operations. 20. What is a casing coupling? Couplings are short pieces of casing used to connect the individual joints

Hydraulic Fracturing
1. What is hydraulic fracturing? Hydraulic fracturing is a well stimulation technique in which fluid is pumped into the well faster than the fluid can escape into the formation. 2. What are the reasons for hydraulic fracture? Hydraulic fracture operations may be performed on a well for one (or more) of three reasons: • To bypass near-wellbore damage and return a well to its “natural” productivity • To extend a conductive path deep into a formation and thus increase productivity beyond the natural level • To alter fluid flow in the formation 3. What are the additives used in fracturing fluid? a) Cross linkers b) Breakers c) Fluid-loss additives d) Bactericides e) Stabilizers f) Surfactants g) Clay stabilizers

4. What is fracture conductivity? Fracture conductivity is the product of fracture conductivity and propped fracture width left after the fracture has closed. 5. In which direction does the fracture propagate? Fracture propagates in the direction perpendicular to the direction of minimal stress. 6. What is pad fluid? First stage of fluid pumped where no proppant is added 7. Why do we add cross linkers in the fracturing fluid? We add cross linkers to increase the viscosity of fracturing fluid. 8. What is closure pressure? The fracture closure pressure pc is defined as the fluid pressure at which an existing fracture globally closes. Mathematically, for a linear relation between the fracture width and pressure, pc min, the minimum principal in-situ stress in the reservoir.

DRILLING FLUIDS
1) What is a drilling fluid? : Drilling fluid is usually a mixture of water, clay, weighing material and a few chemicals. Sometimes oil may be used instead of water, or oil added to the water to give the mud certain desirable properties. 2) What are the different types of drilling fluids? 1. Water-base mud This fluid is the mud in which water is the continuous phase. This is the most common drilling mud used in oil drilling. 2. Oil-based mud This drilling mud is made up of oil as the continuous phase. Diesel oil is widely used to provide the oil phase. This type of mud is commonly used in swelling shale formation. With water-based mud the shale will absorb the water and it swells that may cause stuck pipe. 3. Air and foam There are drilling conditions under which a liquid drilling fluid is not eh most desirable circulating medium. Air or foam is used in drilling some wells when these special conditions exist. 3) Why drilling fluids are used? : Properly designed drilling fluids offer many benefits to drilling operations such as it –        Inhibit shale and clays. Suspends solids Stabilizes the bore hole. Controls water loss. Reduces “bit-balling”. Reduces rotary torque. Reduces friction on drill pipe and utility

4) What are the main constituents of drilling fluid?

Many substances, both reactive and inert, are added to drilling fluids to perform specialized functions. The most common are:  Alkalinity and pH Control Designed to control the degree of acidity or alkalinity of the drilling fluid. Most common are lime, caustic soda and bicarbonate of soda.  Bactericides Used to reduce the bacteria count. Paraformaldehyde, caustic soda, lime and starch preservatives are the most common.  Calcium Reducers These are used to prevent, reduce and overcome the contamination effects of calcium sulfates (anhydrite and gypsum). The most common are caustic soda, soda ash, bicarbonate of soda and certain polyphosphates.  Corrosion Inhibitors Used to control the effects of oxygen and hydrogen sulfide corrosion. Hydrated lime and amine salts are often added to check this type of corrosion. Oil-based muds have excellent corrosion inhibition properties.  Defoamers These are used to reduce the foaming action in salt and saturated saltwater mud systems, by reducing the surface tension.  Emulsifiers Added to a mud system to create a homogeneous mixture of two liquids (oil and water). The most common are modified lignosulfonates, fatty acids and amine derivatives.  Filtrate Reducers These are used to reduce the amount of water lost to the formations. The most common are bentonite clays, CMC (sodium carboxymethylcellulose) and pre-gelatinized starch.  Flocculants These are used to cause the colloidal particles in suspension to form into bunches, causing solids to settle out. The most common are salt, hydrated lime, gypsum and sodium tetraphosphates.   Foaming Agents Most commonly used in air drilling operations. They act as surfactants, to foam in the presence of water. Lost Circulation Materials These inert solids are used to plug large openings in the formations, to prevent the loss of whole drilling fluid. Nut plug (nut shells), and mica flakes are commonly used.  Lubricants These are used to reduce torque at the bit by reducing the coefficient of friction. Certain oils and soaps are commonly used.  Pipe-Freeing Agents



Used as spotting fluids in areas of stuck pipe to reduce friction, increase lubricity and inhibit formation hydration. Commonly used are oils, detergents, surfactants and soaps.

5) What are the different functions of drilling fluid? : A- Assists in making hole by: 1. Removal of cuttings 2. Cooling and lubrication of bit and drill string 3. Power transmission to bit nozzles or turbines B- Assists in hole preservation by: 4. Support of bore hole wall 5. Containment of formation fluids C-It also: 6. Supports the weight of pipe and casing 7. Serves as a medium for formation logging D-It must not: 8. Corrode bit, drill string and casing and surface facilities 9. Impair productivity of producing horizon 10. Pollute the environment. 6) What is annular velocity? : Annular Velocity (m/min) = [(Pump output (m3/min.) / Annular Volume (m3/m)] 7) What are Non- Inhibitive Drilling Fluids? : Those drilling fluids which do not significantly suppress clay swelling, are generally comprised of native clays or commercial bentonite with some caustic soda or lime. They may also contain deflocculates and/or dispersants such as: lignite, lignosulfonates or phosphates. Non-inhibitive fluids are generally used as spud muds. Native solids are allowed to disperse into the system until rheological properties can no longer be controlled by water dilution. 8) What are Inhibitive Drilling Fluids ? Those which appreciably retard clay swelling and achieve inhibition through the presence of cations; typically Sodium (Na+), Calcium (Ca++) and Potassium (K+). Generally, K+ or Ca++, or a combination of the two, provide the greatest inhibition to clay dispersion. These systems are generally used for drilling hydratable clays and sands containing hydratable clays. Since, the source of the cation is generally a salt; hence disposal can become a major portion of the cost of using an inhibitive fluid. 9) What are Pneumatic drilling fluids? : Pneumatic (air/gas based) fluids are used for drilling depleted zones or areas where abnormally low formation pressures may be encountered. An advantage of pneumatic fluids over liquid mud systems can be seen in increased penetration rates. Cuttings are literally blown off the cutting surface ahead of the bit as a result of the considerable pressure differential. The high pressure differential also allows formation fluids from permeable zones to flow into the wellbore.

10) What are different drilling fluid complications?      Kick Stuck-up Lost Circulation Dog leg Fishing

11) What is Flocculation? : A condition in which clays, polymers or other small charged particles become attached and form a fragile structure, a floc. In dispersed clay slurries, flocculation occurs after mechanical agitation ceases and the dispersed clay platelets spontaneously form flocs because of attractions between negative face charges and positive edge charges. 12) What is Aniline point? : Common term used when dealing with oil-based drilling fluids is the aniline point of that fluid. The aniline point is the temperature below which an oil containing 50% by volume aniline (C6H5-NH2) becomes cloudy. The solvent powers for rubber are related to the solvent power for aniline. Oils having an aniline point above 140 degF are considered acceptable to use. 13) What are properties that needs to be measured for drilling fluids ? Density Plastic Viscosity Yield Point Gel Strength pH Filtrate/Water Loss Filter Cake Thickness Alkalinity, Mud Alkalinity, Filtrate Salt/Chlorides Calcium Sand Content Solids Content Water Content Oil Content Funnel Viscosity ml/30 min 1/32 inch Pm Pf/Mf ppm or gpg ppm % vol % vol % vol % vol sec/qt pounds/gallon (lb/gal) centipoise (cps) lbs/100 sqft lbs/100 ft sq.(10 sec/10min)

14) Explain Drilling fluid classification systems. Non-Dispersed System This mud system consists of spud muds, “natural” muds, and other lightly treated systems. Generally used in the shallower portions of a well.

Dispersed Mud Systems These mud systems are “dispersed” with deflocculants and filtrate reducers. Normally used on deeper wells or where problems with viscosity occur. The main dispersed mud is a “lignosulfonate” system, though other products are used. Lignite and other chemicals are added to maintain pecific mud properties. Calcium-Treated Mud Systems This mud system uses calcium and magnesium to inhibit the hydration of formation clays/shales. Hydrated lime, gypsum and calcium chloride are the main components of this type of system. Polymer Mud Systems Polymers are long-chained, high molecular-weight compounds, which are used to increase the viscosity, flocculate clays, reduce filtrate and stabilize the borehole. Bio-polymers and cross-linked polymers, which have good shearthinning properties, are also used. Low Solids Mud System This type of mud system controls the solids content and type. Total solids should not be higher than 6% to 10%. Clay content should not be greater than 3%. Drilled solids to bentonite ratio should be less than 2:1. Saturated Salt Mud Systems A saturated salt system will have a chloride content of 189,000 ppm. In saltwater systems, the chloride content can range from 6,000 to 189,000 ppm. Those at the lower end are normally called “seawater” systems. Workbook 1 980270H Rev. B / December 1995 ConfidentialDrilling Engineering Drilling Fluids And HydraulicsThese muds can be prepared with fresh or salt water, then sodium chloride or other salts (potassium, etc.) are added. Attapulgite clay, CMC or starch is added to maintain viscosity. Oil-Based Mud Systems There are two types of systems: 1) invert emulsion, where water is the dispersed phase and oil the continuous phase (water-in-oil mud), and 2) emulsion muds, where oil is the dispersed phase and water is the continuous phase (oil-inwater mud). Emulsifiers are added to control the rheological properties (water increases viscosity, oil decreases viscosity). Air, Mist, Foam-Based Mud Systems These “lower than hydrostatic pressure” systems are of four types: 1) Dry air or gas is injected into the borehole to remove cuttings and can be used until appreciable amounts of water are encountered, 2) Mist drilling is then used, which involves injecting a foaming agent into the air stream, 3) Foam drilling is used when large amounts of water is encountered, which uses chemical detergents and polymers to form the foam, and 4) Aerated fluids is a mud system injected with air to reduce the hydrostatic pressure. Workover Mud Systems Also called completion fluids, these are specialized systems designed to

1) Minimize formation damage, 2) Be compatible with acidizing and fracturing fluids, and 3) Reduce clay/shale hydration. They are usually highly treated brines and blended salt fluids. 15) What are the selection criteria for Drilling Fluids?      Formation Pressures Formation Temperatures Lithology Connate water encountered during drilling Availability of soft water Economics



PIPING
1) What is the difference between Pipe and Tube? Ans. The primary difference between pipe and tubing is how the size is designated. Pipe is designated by a "Nominal Pipe Size" based upon the ID (inside diameter) of the most common wall thickness. Tubing is designated by the measured OD (outside diameter). For Example: A 3/4 inch iron pipe has an OD of 1.050 inches, while a 3/4 inch steel tube has an OD of 0.75 inches.

Pipe

Tube

2) What do you mean by following terms ? 1) SMAW Ans. 2)TIG

SMAW - Shielded Metal Arc Welding TIG - Tungsten Inert Gas Welding

3)List different modes of transportation of Petroleum products. Why pipeline is preferred ? Ans. Tankers Rail Cars Road Transport Barges Pipelines Pipeline is preferred because of these reasons: 1)Low Unit cost ($/Ton/Km) 2)very low number of incidents/Km/year 3)low environmental impact 4)High reliability (immune to weather condition) 4)Function of Block Station Valve Ans. Block Valve Stations are used to isolate section of the pipeline and limit the release of line contents in the event of a leak or pipeline rupture 5)What is “Economic Diameter” and on which parameters it depends? Ans. Economic diameter will be the one which makes the sum of amortized capital cost plus operating cost minimum. The total cost can be per unit time or per unit of production. Economic diameter depends on Mass flow rate Fluid Density Fluid Viscosity

6) The facilities piping code is governed by: Ans. ANSI-(B31.3)

7)The liquid pipelines are governed by: Ans. ANSI-(B31.4) 8) The Gas pipelines are governed by: Ans. ANSI-(B31.8) 9) The most common industry standard for steel linepipe Ans. API-5L 10)Define MOP , MAOP ,MAIP in Pipeline. Ans.

11)Uses of PIGS. Ans.
  

To batch or separate dissimilar products; For displacement purposes; For internal inspection.

12)Different type of PIGS. Ans.
  

Utility Pigs, which are used to perform functions such as cleaning, separating, or dewatering. In Line Inspection Tools, which provide information on the condition of the line, as well as the extent and location of any problems. Gel Pigs, which are used in conjunction with conventional pigs to optimize pipeline dewatering, cleaning, and drying tasks.

13) Define Cathodic Protection. Ans. Cathodic protection is an electrochemical means of corrosion control in which the oxidation reaction in a galvanic cell is concentrated at the anode and suppresses corrosion of the cathode in the same cell. 14) Main Objectives of SCADA System. Ans. • To provide effective & efficient monitoring and control of entire pipeline network • To optimise use of equipment and manpower and to protect equipment. • To check pipeline integrity • Remote control of important station equipment, process set poin ts & block valves from Monitoring and Control system (MCS) • Emergency shutdown of entire pipeline from MCS • Acquisition & display of pipeline parameters, alarms from attended stations, scraper stations, C.P. stations & block valves at MCS 15) Define Pre-commissioning and Commissioning. Ans. Pre-commissioning: Pipeline is to be commissioned prior to it is put on regular use. Pre-commissioning refers to preparing the line for testing, inspection and certification. In this stage, the line is to be cleaned of debris, dust particles, weld materials etc. Pipeline is to be cleaned with the help of water and removal of debris etc. This operation needs cleaning pigs to be inserted and taken out along with waste/ unwanted material from pipeline.

Thus the plug is used for displacement purpose. Commissioning: In this stage, pipeline is pressurized to test pressure as per recommended practice and certified for regular use if the parameters were found to be as per recommendations. After the test, Intelligent is inserted into the pipeline and forced to travel at predetermined speed. Necessary data like pipe thickness are recorded throughout the length for recording the initial data and integrity assessment prior to putting the line in use. Two pigs are inserted – one after the other. The Anti corrosion Chemical is placed in between these two pigs. Anti corrosive coating will be installed on the inner side of the pipe save the pipeline from corrosion.

STRENGTH OF MATERIALS AND ROCKS
1. How does design of a component and its usage play an important part forming engineering materials? 2. What do you understand by vrittle and ductile materials? How are they different from each other? Give examples. 3. Explain with the help of schematic representation, the tensile stress-strain curve for brittle and ductile materials when it is loaded to fracture. 4. How a fracture does spreads in brittle and ductile materials? Explain with a help of a diagram. 5. Which fracture is more preferred over the other and why? Give two reasons. 6. What is rhe difference between intergranular and transgranular fracture ? 7. Explain the mechanism of failure of engineering materials. 8. What are the different types of metallic materials used in the industry? 9. Explain the difference between low-carbon steel, medium-carbon steel and high-carbon steel in terms of composition. 10. Explain the various purposes of alloying. 11. What is stainless steel and how is it classified? Explain the various types. 12. What do you understand by Heat Treatment and why is it carried out? 13. What is the most important parameter in the heat treatment procedures? 14. What is annealing? Why is it carried out and explain the stages involved. 15. What are the quenching characteristics of a liquid? 16. What may be the possible reasons for the development of internal residual stresses in metal pieces? 17. What do you understand by the terms ‘normalising’, ‘hardenong’ and ‘tempering’? 18. What do you understand by hardness of a material? Explain Brinell’s Hardness test along with the formula. 19. Which are the two most commonly used indenters for hardness testing? What is the difference between them? 20. Explain the difference between elastic deformation and plastic deformation. 21. With the help of a graph, explain the relationship between true stress and strain. Also, explain the engineering stress-strain graph. 22. Enlist and explain the various mechanical properties of any material.

FLOW ASSURANCE
1) What is Flow Assurance? Ans: Flow assurance covers the whole range of possible flow problems in pipelines such as hydrate formation, wax & asphaltene deposition, corrosion, erosion, scaling, emulsions, foaming, and severe slugging. The avoidance or remediation of these problems is the key aspect of flow assurance. 2) What are the problems faced for flow assurance in each segment? Ans: 3) What are the main types of flow? Ans: SINGLE PHASE : GAS /OIL /WATER MULTIPHASE:GAS/WATER, GAS/OIL, OIL/WATER, GAS/OIL/WATER 4) Elaborate for flow in horizontal and vertical pipes. Ans : Horizontal pipes: 1. 2. 3. 4. 5. 6. Dispersed Bubble Flow Annular flow with mist Elongated bubble flow Slug flow Stratified flow Stratified wavy flow Vertical pipes: Dispersed Bubble flow Slug flow Churn flow Annular flow Annular flow with droplets

7. 8. 9. 10. 11.

5) What are typical flow assurance problems? Ans : Slugs, Hydrates, Wax , Asphaltene, Scale, Corrosion, Erosion 6) How does wax deposition occur? Ans: 1. PARAFFIN WAXES REMAIN AS SOLUBLE CONSTITUENT OF CRUDE OIL UNDER MOST RESERVOIR CONDITIONS

2. WHEN EQUILIBRIUM CHANGES ( TEMP/ PRESS.), CRYSTALLIZATION TAKES PLACE

3. LOSS OF VOLATILE LIGHT ENDS ALSO LEAD TO PRECIPITATION 4. SOLUBILITY OF PARAFFIN IN PETROLEUM DECRESES WITH SUM OF TARS AND ASPHALTENES 5. WAX DEPOSITION DECREASES AS TAR AND ASPHALTENE CONTENT INCREASE 7) What are the problems that occur due to wax crystallization? Ans : 1. 2. 3. 8) HIGH VISCOSITY LEADING TO PRESSURE LOSSES HIGH YIELD STRESS FOR RESTARTING THE FLOW DEPOSITION OF WAX CRYSTALLITES ON SURFACES What are the factors affecting wax deposition and different wax control methods?

Ans: 1. FLOW RATE 2. TEMP. DIFFERENTIAL AND COOLING RATE 3. SURFACE PROPERTIES The different wax control methods are 1) Mechanical - scrappers, cutters, pigs etc 2) Thermal - steaming the flow lines, installing bottom hole heaters and circulation of hot oil and hot water 3) Chemical - 1) those in which a solvent is used to dissolve the deposit once it has formed, and 2) those which inhibit wax crystal growth or inhibit its adherence to the tubing walls 9) What are asphaltenes and their properties? Ans : THEY ARE THOUGHT TO BE THE BYPRODUCT OF COMPLEX HETRO-ATOMIC AROMATIC MACRO-CYCLIC STRUCTURES POLYMERIZED THROUGH SULFIDE LINKAGES ASPHALTENE-RESIN MICELLS ARE ELECTRICALLY CHARGED AND CAN BE PRECIPITATED BY ELECTRICAL FORCES LIKE ONES GENERTATED IN SAND FLOW 10) Important factors that influence oil field corrosion Factors that influence oilfield corrosion rates include the presence of gasses, especially CO 2, O2, and H2S. These gasses make the water an aggressive electrolyte. Other influences are flow velocity, metal composition, temperature, water quality issues(including the pH and presence of microbes, bicarbonates, chlorides and organic acids), temperature, and pressure 11) What are the different corrosion prevention methods? Ans : 1. Design Improvement 2. Material selection: Change of Composition, Change of Microstructure, elimination of tensile stresses 3. Change of Environment: Removal of Gases, Inhibitors, Change of operating variables: Temp. , Velocity, pH 4. Change of EP- cathodic, anodic

5. Coatings – Metallic, Non- Metallic 12) What are the different types of scales and prevention methods? Ans: there are two types of scales: Carbonate scales and sulphate scales. Prevention methods: Water softeners and scaling inhibitors. 13) What are Gas hydrates and their prevention methods? Ans: Hydrates can occur when light hydrocarbons and water are present at thermodynamically favorable pressure and temperature. In offshore production systems, they typically are seen in long flow lines, but also can appear anywhere in the system where gas and water are present under high pressure and low temperature Gas hydrates are crystalline, cage-like structures. The “cage” is water molecules stabilized by small gas “guest” molecules trapped in the cavities under high-pressure and low-temperature conditions. Most commonly, the small guest molecules are light hydrocarbons (methane, ethane, propane) and other gases that may be present (H2S, CO2, N2). The most common way to prevent hydrates is chemical inhibition. There are two main methods of chemical inhibition: thermodynamic inhibitors (methanol, ethylene glycol) and LDHIs (low dose hydrate inhibitors).

1. Can you explain in detail three or more major differences between code ANSI B31.1 and code ANSI B31.3? Answer: There is only one major difference between the two, B31.1 is for Power Piping and B31.3 is for Refinery/Chemical Plant Piping. 2. There is a power plant inside a Process refinery. Where exactly the ANSI B31.1 & ANSI B31.3 scope break occurs? Answer: B31.1 stopped at the Power Plant Unit block valves. Thus all piping inside the Power Plant was B31.1. B31.1 stopped at the equipment (Boiler) isolation block valves and then all other piping was B31.3. This is normally the choice of the owner/operator/client. 3. Which of the following piping system is more health hazardous. A) Fuel oil piping b) Process piping with Caustic c) process piping with HF acid d) Sulphuric acid piping. Answer: c) process piping with HF acid 4. There is a steam piping with low pocket but without steam trap. What will be worst consequence of this layout? Answer: There will be a build up of condensate to the point that a slug will be pushed by the steam flow. This slug of condensate will cause “water hammer” and could rip the piping apart. 5. In what circumstance, the reducer of a pump suction piping will be in bottom flat position. Explain why the reducer should be so. Answer: When reducers are placed in pipe Rack they are generally bottom side flat to maintain BOP to facilitate supporting.

6. A P&ID shows a spec break (at Flange) between carbon steel & stainless steel specification. What additional arrangements you have to make for that dissimilar material flange joint? Answer: Use the Gasket and bolts from the SS spec. 7. A stainless steel piping specification mentions Galvanized carbons steel bolts. What is your first reaction to this and how do you rectify it? Answer: If that is what the Spec calls for then that is what I am supposed to use. But, I would ask the Piping Material Engineer (PME) why he/she specified galvanized bolts. 8. How many types of piping specialty items do you know? Why it is called a piping special? Why not we include them in standard piping specification. Answer: I could possibly count 50 or more depending on the PME and how the piping material specs were developed. They are called them SP items because they are NOT written into the normal Piping Material (Line Class) Specifications. They are not included because they are normally of limited use, purchased from a limited product line vendor and are often after thoughts. 9. Draw a typical steam trap station layout and explain why the existence of a by-pass line around the trap is not a good idea, when the condensate is returning to a condensate header? Answer: (No drawing) It is not advisable to have a bypass around a steam trap because the block valve could be left open and defeat the purpose of the trap. 10. Explain what is a “Double block & Bleed” valve? Why we need a bleed valve? When do we use this? Answer: The primary purpose of a “Double Block & Bleed” is Safety. However it is not fail safe. The next better “Safety” set-up would be Double Block Valve with a Spec Blind between the valves. The higher level of safety would be double block valves with a removable spool for absolute isolation. 11. In a typical tie-in where should the spectacle blind be inserted? a) after block valve and towards existing plant b) before block valve and towards new plant. Explain why. Answer: The Spec Blind shall be placed on the Unit side of the Unit Block valves. This placement allows for the closing of the Unit isolation block valve, the unit side is depressured and drained. Then the spec blind can be installed for isolation of the unit. 12. “Stress intensification factor (SIF)” Where do we use this? Explain this term. How many types of these SIF‟s exist? Answer: Stress Intensification Factor (SIF) is a multiplier on nominal stress for typically bend and intersection components so that the effect of geometry and welding can be considered in a beam analysis. Stress Intensification Factors form the basis of most stress analysis of piping systems. As for the quantity, ask a Stress Engineer. 13. When all design parameters are same, whose thermal expansion is higher among the following? A) Carbon steel b) Stainless steel c) Duplex steel d) Cast Iron e) Galvanized Carbon steel. Answer: b) Stainless steel

14. In a hose station the hose couplings used for water, air & steam should be different type. Do you agree? Explain your view. Answer: I agree. If they are all the same then the hoses can be connected to the wrong services and could result in the injury of an operator (i.e.: thinking the hose is connected to water when it is connected to steam). 15. What is your view on the usage of Metallic expansion joints? When they become necessary and when they could be avoided? Answer: I do everything I can as a piping designer to avoid the use of all types of expansion joints. Expansion joints are always the weakest point in any system where they are used.

16. In what order do you arrange the pipes in the Pipe rack and why? How much % of area should be reserved for Future expansion? Specify a range. Answer: The largest hottest lines on the outside edge of the pipe rack working in with cooler lines in towards the middle of the rack. This allows the longer loop legs as you lay the loops back over the other lines to the other side of the rack and back. The lower temperature loops would be “nested” inside the larger, hotter loops. “Future rack space” is normally at the direction of the Client. It may be anything from 0% to as much as 25%. 17. When a utility line (like condensate or water etc) is connected permanently to a process piping what precaution we have to take to avoid cross contamination? Answer: Option #1, double block valve with a drop-out spool. Option #2, Double block valve with a spec blind. Option #3, double block valves with a bleed valve. 18. A air fin cooler (2 air coolers with each having 2 inlet nozzles) needs a Typical piping arrangement. How many types of piping arrangement is possible. Answer: There are a number of ways to pipe a Fin-Fan cooler depending on what the P&ID call for?

WELL PLANNING
Q1 – What is well planning? Ans - Well Planning is defined as those, primarily engineering activities, which follow on from the identification of a subsurface target for a well (exploration, appraisal, or development well) until the completion of that well. Q2- What are the main objectives of Well Planning? Ans- The objective of well planning is to formulate a program from many variables for drilling a well that

has the following characteristics: o safe

o minimum cost o usable
Q3- What are the main steps involved in Well Planning? Ans- Steps considered in order are :I. II. III. IV. V. VI. VII. VIII. IX. X. XI. Data Collection Pore pressure analysis Fracture gradient determination Casing point selection Mud plan Bit selection Cementing plan Casing desgn Tubing design Drill string design Rig sizing and selection

Q4-What are the different types of wells that are drilled? Ans-Wildcat well, exploratory well, step-out well, infill /production wells, reentry wells. Q5-How is the pore pressure of the formation to be drilled determined? Ans-Wireline log analysis , Eaton’s method of pore pressure determination , offset well data , well production data , equivalent depth method ( assuming pore pressure is hydrostatic in nature ). Q6- How is the mud weight for drilling a formation selected? Ans- the Mud weight to be used should lie between the pore pressure and the fracture gradient at the particular depth , this range is further narrowed by imposing safety factors for surge and swab pressures . Q7-What is differential sticking and how is it prevented? Ans- Differential sticking typically occurs when high-contact forces caused by low reservoir pressures, high wellbore pressures, or both, are exerted over a sufficiently large area of the drill string. The sticking force is a product of the differential pressure between the wellbore and the reservoir and the area that the differential pressure is acting upon. This means that a relatively low differential pressure (delta p) applied over a large working area can be just as effective in sticking the pipe as can a high differential pressure applied over a small area. To prevent differential sticking the pressure difference between the well bore and reservoir should be kept below 2300 psi (for normal pressure formation) and 2500-3000psi (for abnormal pressure zones) this can be done by altering the mud weight or the casing setting point . Q8-What are the main criteria for selecting the casing type? Ans- Collapse pressure, burst Pressure, Bi-axial forces, tensile forces. Q9- How is Bit selection done? Ans –the bit to be used is selected on the basis of the following criteria :-

I. II. III.

Offset well data Formation type and hardness ( IADC code basis) Dull bit study

Q10- What is a leak-off test ? How many LOTs would you conduct for a 3 casing point (CP) well ? Ans. A test to determine the strength or fracture pressure of the open formation, usually conducted immediately after drilling below a new casing shoe. During the test, the well is shut in and fluid is pumped into the wellbore to gradually increase the pressure that the formation experiences. At some pressure, fluid will enter the formation, or leak off, either moving through permeable paths in the rock or by creating a space by fracturing the rock. The results of the leakoff test dictate the maximum pressure or mud weight that may be applied to the well during drilling operations. 3 LOTs should be conducted for a 3 cp well , one for each casing type . Q11-What is available weight on bit (AWB)? Ans- Available weight on bit= (In air weight of drill collars) x (Buoyancy factor), it is the weight which is exerted on the bit to provide downward thrust necessary for drilling into the formation.

PRODUCTION OPTIMIZATION

LOGGING
____ is the process evaluation/completion) of recognizing a commercial well when you drill one(formation

Conventional cores are cut using a ______core bit Special core analysis measures _____ permeability (rel/abs) Logging techniques are _____in nature (direct/indirect) Mud jetting out of the holes in the bit causes cuttings to move _______ the hole (up/down) a wellsite geologist or mud logger uses a _______to determine the lithology of the formation being drilled (high power/ low powered stereoscopic microscope) A portable ultraviolet light chamber or ______ is used to examine the cuttings for fluorescence. (Spook box/black box) Infrared analyzer is used for the detection of (methane/propane) Rate of penetration is recorded in (minutes per foot/ minutes per inch/secs per yard) If weight on the derrick (weight on the hook) is A and the weight of the drill string is B ,then weight on bit is ____ [ (A-B),(A+B),(B-A) ] Surface recording system (Data Acquisition System) uses _____ tools and down hole data to surface system. (optical/electrical) ____ holds the ~9000 mts of multiconductor steel armored cable, with a pulling capacity of several tons (Principal winch/ Auxiliary winch) A BRIDLE – a cable, insulated on the outside with ______which serve as remote returns (single lead electrode/ two lead electrodes) General log convention define ____ tracks or areas where data will appear(5/6/7) Width of track 5 is ____( 6.4 cms/1.9 cms) Track 1 is _____ in correlation and format.(linear/non linear) Track 4 is for ___ format(detailed/simple) Track __ is for depth label(2/5) TEMPERATURE MEASUREMENTS are important for For understanding.......... Local variation in geothermal gradients may be due to............ The transfer of heat at the mud-rock contact is by......(conduction /convection) two BOREHOLE TEMPERATURE MEASUREMENT techniques..?? the temperature profile of a well can be established by ___ method The recording of temperature is usually made while going ____ the hole in order not to disturb the thermal equilibrium.(up/down) cable for transmitting power to

3 BOREHOLE CALIPER MEASUREMENT techniques. For precise measurement of the hole shape and of the hole volume – Caliper tool with____ arms could be used (2/4) The essence of the acoustic reflection technique is to measure the .........( one / two way travel time) in SP log, potential ___ from formation to formation.(varies/remain constant) SP is measured relative to the level in _____? measurement principle of the SP...? The SP opposite a formation can be attributed to two processes involving the movements of ions.name them...?? The SP deflection has _______relationship with PERMEABILITY with POROSITY . (direct / no direct). The SP can not be measure in holes filled with _____muds (conductive /non conductive) The electrokinetic potential appears when filtrate is forced into _____under the differential pressure between the mud column and the formation.(mud /formation). _______potential must be recognized before interpreting the SP deflection for Rw calculation DIFFUSION POTENTIAL is an emf established at the______contact of the mud filtrate and connate water at the_____of the invaded formation. MEMBRANE POTENTIAL develops when two electrolytes are separated by ___ ? oil and gas _____ effect in sp deflection. (increasing /reducing). in SSP no cURRENT IS ALLOWED TO FLOW IN THE BOREHOLE. (T/F ) SSP being zero all deflections are measured relative to the _____line.(shale base / sand base ) The SP deflection (peak value) is ______ than the SSP.(greater/ less) The SP ______ as the invasion deepens(increases /decreases). ________caused by gravity segregation of filtrate and formation water.? for any given mud resistivity, the SP log is ____by higher resistivity formation.(affected / not affected ) An SP base-line shift occurs where zones are separated by shale that is _____ cationic membrane. ( perfect / not perfect) The essential target of resistivity logging is that of the resistivity of the ______and its saturation in hydrocarbon In archie's relation , the resultant resistivity of a given core sample was always related to the water resistivity by...................? resistivity is a function of ______ saturation.(oil /water) The parameter most significantly affected by wettability is..... (n / m) if a clean core is used to measure the saturation exponent and the reservoir is actually oil-wet, the _____saturation can be underestimated when logging.(water / oil )

Clay consists of stacked silicate layers which, in the presence of water, become _______ charged.(+vely , -vely) knowledge of the ________ at a certain depth is necessary to determine correctly the resistivity of the mud filtrate or the formation water. the normal config of electrode works best in _______ sediments .(soft /hard) lateral config is best in _____ sediments .( thin / thick) the radius of investigation ________ with the spacing of the electrode array ,keeping other factors equal. the lateral logs works best in muds of ____ resistivity( low/high) use of proximity log ?

advantage of induction log over electric log
Current focusing minimizes the effects that the borehole, the invaded zone, and surrounding formation may have on the log’s response.(t / f) use of geometrical factor? importance of Compton scattering, occurs mainly in _____measurement. Natural radiation in rocks comes essentially from only three elemental sources. what are they ? The most commonly used detector in standard logging is _____ ?? U will tend to precipitate or concentrated in ______environments.(reducing / oxidising) common constituent of the detrital fraction of sediments is _____ (Th / U) traditional approach for estimating the volume fraction of shale in the formation, Vsh, is ______ For conventional g-ray log, the observed spectrum takes a______ form (continous/ descrete) pure clean sands or sandstones exhibit very _____ radioactivity(high/low) Abrupt changes in the mean Th/K ratio are generally indicative of___ The computer gamma ray (CGR) trace is computed from the GR trace by subtracting the concentration of _______ (U,Th ,K) A U-rich formation would be misinterpreted ( in simple GR analysis) as being___ ? In distinguishing of mica from shale_______tool is important .(SGR / induction logging ) The density log is a _____record of a formations bulk density.(continous/descrete) The logging technique of the density tool is to subject the formation to a bombardment of _______energy (0.2 – 2.0 meV) focused gamma ray.(medium high/low) the anomalous Z/A value for H results in 11 % discrepancy between the bulk density and electron density index in case of ____ ? The______is the locus of the two counting rates without mudcake.(spine / rib)

EOR

QUESTIONS ON ENHANCED OIL RECOVERY
1. What is Primary Oil Recovery? Ans: Primary oil recovery is limited to hydrocarbons that naturally rise to the surface. This phase of oil production begins with the discovery of an oilfield using the natural stored energy to move the oil to the wells by expansion of volatile components and/or pumping of individual wells to assist the natural drive. 2. What is Enhanced Oil Recovery? Ans: It refers to the oil recovery over and above that obtained through the natural energy of the reservoir. 3. Why is Enhanced Oil Recovery necessary? Ans: Its purpose in not only to restore formation pressure, but also to improve oil displacement or fluid flow in the reservoir. 4. When is EOR necessary? Ans: It is used after both primary and secondary recovery methods have been exploited to their economic limits. Along with the economic reasons technical reasons also exist. It is used to mobilize trapped oil held inside pore due to capillary and viscous forces. It also used to exploit the oil which is present in less accessible parts of the reservoir but at higher saturations. 5. Name the different EOR techniques? Ans: Chemical flooding, Miscible gas flooding and thermal methods 6. What are the basic mechanisms involved in Chemical EOR? Ans:  Reduction in interfacial tension between oil and brine  Solubilization of released oil  Change in the wettability towards more water wet  Reducing mobility contrast between crude oil and displacing fluid. 7. What are the various chemical EOR processes? Ans:  Micellar/surfactant polymer flooding

   

Alkaline flooding Alkali-surfactant flooding Alkali-surfactant-polymer flooding Polymer flooding

8. On what parameters chemical EOR processes are selected? Ans:  Type of reservoir  Rock mineralogy, clay, heterogeneity  Reservoir pay thickness, porosity, permeability  Reservoir temperature  Reservoir oil properties  Residual oil saturation  Salinity of formation water and presence on bivalent cations. 9. Name some of the surfactants used in EOR. Ans: In order of their thermal stabilityAAS (Alkyl-aryl-sulphonate)> IOS (Internal olefin Sulphonate)>AOS (Alpha olefin Sulphonate)>PS (Petroleum sulphonate)>ethoxylated Alcohol 10.Discuss the general procedure for alkaline-polymer technique. Ans:  Introduction of chemicals is preceded by a preflush (low salinity water) to place a compatible aqueous buffer of fluid between the highly saline reservoir brine and the chemical solutions.  The alkaline or other chemical solutions is injected after the reservoir conditioning preflush  Injection of chemical solutions is followed by the injection of a polymer solution to increase fluid viscosity, to aid in displacement of the chemicals through the reservoir and to minimize the loss due to dilution and channeling.  The salinity of the injected water following injection of the polymer is gradually increased to the normal concentration of the oilfield fluid. 11.What are the various types of Gas Flooding? Ans:  Hydrocarbon flooding (LPG, Enriched and Lean Gas)  CO2 flooding

 N2 and flue gas injection 12.What are principal mechanisms for hydrocarbon miscible gas mobilization of oil? Ans:  Reduction of the oil viscosity upon solution of the gas into the oil  Increase in the volume of oil by swelling  Generating miscibility  Immiscible gas displacement 13.What are the modes of carbon dioxide injection? Ans:  Injection of gas in slugs that are followed by water injection  Injection of water saturated with carbon dioxide  High pressure injection of gas itself. 14.What changes occur in the reservoir oil during the process of thermal EOR? Ans:  Reduction in viscosity  Reduction in specific gravity  Reduction in IFT 15.What are the types of Thermal EOR processes? Ans: Steam Flood and In-situ combustion 16.What is Microbial Enhanced Oil Recovery Process? Ans: MEOR involves injection of microbes and nutrients to improve production from the well/reservoir. 17.Is water flooding an EOR technique? Ans: No. The widespread application of water flooding to boost production after initial decline in production has led to this process being referred to as Secondary recovery. 18.When is the process of waterflood (or secondary recovery) process is halted? Ans: In a typical waterflood, the “Water-cut” in the produced fluid continually increases, and the expense of pumping, separation and disposal of the waterflood eventually exceed the income from the oil recovered. Then secondary recovery efforts are halted, even though oil remains in the reservoir. 19.What is the difference between IOR and EOR?

Ans:  . IOR is any method of producing or injecting (developing) a well that is not on primary production or commingled (not selective) production such as (secondary recovery like water flooding and tertiary like gas injection, chemical injection or microbial injection. Whereas EOR is tertiary recovery techniques for increasing the amount of crude oil that can be extracted from an oil field either by using Gas injection, Chemical injection, Microbial injection or Thermal methods.  IOR is well specific whereas EOR is reservoir specific.  IOR includes EOR and other practices like infill drilling, pressure maintenance. 20. List some major problems in EOR process. Ans:  Design of suitable EOR agents that will be effective under reservoir conditions  Minimizing the requirements for these expensive agents  Predicting and reducing losses of these agents.  Precipitation and deposition of asphaltenes and paraffins  It increases the potential for scale deposition (inorganic mineral deposits that form due to any change in thermodynamic equilibrium, which results in lowering of solubility of particular species in water)  Fluid compatibility  Special concerns while working with bacteria 21.What is volumetric sweep efficiency? Ans: It is the fraction of the total reservoir volume contacted by the injected fluid during the recovery. As the mobility ratio increases the sweep efficiency decreases. 22.What is displacement Efficiency? Ans: This refers to the fraction of oil that is swept from unit volume of reservoir upon injection. This depends on the mobility ratio, the wettability of the rock and the pore geometry. The wettability is determined by whether or not the grains preferentially absorb oil of water. 23.What is the average recovery factor of an oil well? Ans: It is defined as Volumetric Sweep x Displacement Efficiency. Generally it is less than 40% for primary and secondary methods combined. 24.Give some example of Indian oilfields that used EOR technique. Ans:

 Sanand Field- polymer flooding- because of mobility contrast and low primary recovery  Viraj ASP pilot- based on low primary recovery, mobility contrast and high acid number of the crude  Gandhar GS-12- Miscible HC gas injection  Balol – In-situ combustion  Duliajan- MEOR PRODUCTION ENGINEERING (IPR CURVE, VPR CURVE) OR SHALE GAS What is reservoir deliverability?
Reservoir deliverability is defined as the oil or gas production rate achievable from reservoir at a given bottom-hole pressure. It is a major factor affecting well deliverability. Reservoir deliverability determines types of completion and artificial lift methods to be used. A thorough knowledge of reservoir productivity is essential for production engineers.

What are the different factors on which reservoir deliverability depends?
Reservoir deliverability depends on several factors including the following:  Reservoir pressure  Pay zone thickness and permeability  Reservoir boundary type and distance  Wellbore radius  Reservoir fluid properties  Near-wellbore condition  Reservoir relative permeability.

What is inflow performance relationship?
An analytical relation between bottom-hole pressure and production rate can be formulated for a given flow regimen. The relation is called “Inflow Performance Relationship„„(IPR). IPR is used for evaluating reservoir deliverability in production engineering. The IPR curve is a graphical presentation of the relation between the flowing bottom-hole pressure and liquid production rate.

Describe IPR for Single Phase Reservoir.
All reservoir inflow models represented by equation (given below) derived on the basis of the assumption of single-phase liquid flow. This assumption is valid for under-saturated oil reservoirs or reservoir portions where the pressure is above the bubble-point pressure. The equations define the productivity index (J*) for flowing bottom-hole pressures above the bubblepoint pressure as follows:

Since the productivity index (J*) above the bubble-point pressure is independent of production rate, the IPR curve for a single (liquid)-phase reservoir is simply a straight line drawn from the reservoir pressure to the bubble-point pressure, shown in fig. If the bubble-point pressure is 0 psig, the absolute open flow (AOF) is the productivity index (J*) times the reservoir pressure.

Figure: Straight line IPR (for an incompressible liquid)

Describe IPR for Two Phase Reservoir.
The linear IPR model is valid for pressure values as low as bubble-point pressure. Below the bubble-point pressure, the solution gas escapes from the oil and become free gas. The free gas occupies some portion of pore space, which reduces flow of oil. This effect is quantified by the reduced relative permeability. Also, oil viscosity increases as its solution gas content drops. The combination of the relative permeability effect and the viscosity effect results in lower oil production rate at a given bottom-hole pressure. This makes the IPR curve deviating from the linear trend below bubble-point pressure, as shown in fig. The lower the pressure, the larger the deviation. If the reservoir pressure is below the initial bubble-point pressure, oil and gas two- phase flow exists in the whole reservoir domain and the reservoir is referred as a “two-phase reservoir”.

Figure: Inflow performance (for a two-phase reservoir) Only empirical equations are available for modelling IPR of two-phase reservoirs. These empirical equations include      Vogel„s (1968) equation extended by Standing (1971). Fetkovich (1973) equation. Bandakhlia and Aziz„s (1989) equation. Zhang„s (1992) equation. Retnanto and Economides„ (1998) equation

How reservoir depletion can be illustrated using IPR?
This is illustrated with data on the IPR of a saturated (or solution gas drive) oil reservoir. Figs below shows that the IPR rapidly decreases with increasing cumulative oil recovery. This is not only due to reservoir pressure depletion; but is also related to the increasing gas saturation which is making oil flow progressively more difficult.

Figure: IPR Curves during various stages of production Frequently, wells are completed on heterogeneous formations where production from several different zones is commingled. Reservoirs with differing permeability will be depleted at different rates - the resulting composite IPR being the sum of the separate individual IPRs. It will change as the well depth, fluid type, production rate etc. alter.

Figure: Composite IPR for heterogeneous formation

What is VPR?
The Vertical Performance Relationship (VPR) is obtained for the variation in tube intake pressure at the bottom of well vs. the liquid flow rate in the tube.

Figure: Showing VPR (actual vs. Ideal)

Why there is deviation between the actual and ideal VPR curve?
In actual practise we don‟t get an ideal VPR curve because some gas is always presents due to which the hydrostatic pressure decreases. Thus out of the four resistances that the fluid has to overcome, one resistance is lowered. Due to this for the same Pwf we get an increased flow rate, q. Thus a tick mark shape is obtained

What are the different parameters that affect VPR?
Parameters affecting VPR are followings:    GLR – As GLR increases, hydrostatic pressure decreases thus less flowing bottom hole pressure or Pwf is needed for the same flow rate, q. Tubing pressure (Pt) – As the tubing head pressure increases, more Pwf is needed for the same flow rate. Diameter of tubing – As the diameter of tubing increases the flow rate increases, pressure and depth being constant. Thus the flow rate increases implying an increase in Pwf.

SHALE GAS
The first commercial natural gas well in the United States was drilled in 1821 in Fredonia, New York. It produced gas from organic-rich Devonian-age shale. Since then many other wells have produced natural gas from shale. However, shale is most commonly thought of as a natural gas source rock rather than as the target of drilling activity.

1] What is shale gas? Shale gas is a natural gas (predominantly methane) found in shale rock. Natural gas produced from shale is often referred to as „unconventional‟ and this refers to the type of rock type in which it is found. „Conventional‟ oil and gas refers to hydrocarbons which have previously sought in sandstone or limestone, instead of shale or coal which are now the focus of unconventional exploration. However, the techniques used to extract hydrocarbons are essentially the same. What has changed are advancements in technology over the last decade which have made shale gas development economically viable. 2] What is the composition of shale?
Shale is a rock composed mainly of clay-size mineral grains. These tiny grains are usually clay minerals such as illite, kaolinite and smectite. Shale usually contains other clay-size mineral particles such as quartz, chert and feldspar. Other constituents might include organic particles, carbonate minerals, iron oxide minerals, sulfide minerals and heavy mineral grains. These "other constituents" in the rock are often determined by the shale's environment of deposition and often determine the color of the rock.

3] What is fracking? Hydraulic fracturing or “fracking” is a technique that uses water, pumped at h igh pressure, into the rock to create narrow fractures to allow the gas to flow into the well bore to be captured. 4] What is the process for a drilling a shale gas well? The process of obtaining consent to drill a well is the same whether the well is targeted at conventional or unconventional gas. DECC issues a license in competitive offerings (License Rounds) which grant exclusivity to operators in the license area. The licenses however do not give consent for drilling or any other operations. When an operator wishes to drill a well, their first step is to negotiate access to with landowners. Permission must also be granted from the Coal Authority, if the well encroaches on coal seams. Then the operator needs to seek planning permission from the Local Planning Authority (LPA). The operator must consult with the Environment Agency (EA) in England and Wales, or the Scottish Environmental Protection Agency (SEPA) in Scotland, who are also statutory consultees to the LPA. The LPA will determine if an environmental impact assessment (EIA) is required, and an environmental permit from the appropriate environment agency may also be required. Once the LPA has granted permission to drill, DECC will consider an application to drill and at least 21 days before drilling is planned, the HSE must be notified of the well design and operation plans ensure that major accident hazard risks to people from well and well related activities are properly controlled, subject to the same stringent regulation as any industrial activity. HSE regulations also require verification of the well design by an independent third party. Notification of an intention to drill has to be served to the environmental regulator under S199 of the Water resources act, 1991.

Once DECC checks the geotechnical information and that EA/SEPA and HSE are aware of the scope of the well operations, they may consent to drilling. If the well needs more than 96 hours of testing to evaluate its potential to produce hydrocarbons, the operator can apply to DECC for and extended well test of up to 60 days (once all other consent and permissions have been granted) which limit the quantities of gas to be produced and saved or flared. If the operator wished to drill an appraisal well or propose a development, they start again with the process described above; the landowner permissions and LPA planning consent, EA or SEPA consultation and HSE notification before DECC would consider approving the appraisal well or development. The LPA will also consider whether an EIA is required: for most developments, this is mandatory. 5] How are fracking operations regulated? From the outset, each application must go through the local planning authority process and before any drilling occurs, an application for authorization for any discharge must be made to the Environment Agency (EA) or Scottish Environment Protection Agency (SEPA) in Scotland, which will only be granted in the agency is confident that there is no risk to the environment, and in particular to drinking water. As part of this process, operators are required to disclose the content of fracking fluids to the Environment Agency. The Health and Safety Executive scrutinizes the well design for safety. The HSE then monitors progress on the well to determine if the operator is conducting operations as planned. The HSE are also notified of any unplanned events. If it is deemed necessary, inspections may be undertaken by HSE to inspect specific well operations on site. 6] Should there be a moratorium on shale gas? In the light of the robust controls in place, outlined above, to protect the environment and ensure safe operation, DECC see no need for any moratorium on shale gas. This is also the view of the Energy and Climate Change Select Committee which held an inquiry into shale gas earlier this year and took evidence from Government, regulators, the British Geological Survey, the oil and gas industry and environmental groups. The committee also concluded that hydraulic fracturing itself does not pose a direct risk to water aquifers, provided that the well-casing is intact. Rather, that any risks that do arise are related to the integrity of the well, and are no different to issues encountered when exploring for hydrocarbons in conventional geological formations. 7] How much shale gas is there in the UK? Exploration for shale gas in the UK is still at a very early stage with only a modest level of exploration activity. None of the wells drilled has been production tested, so a reliable reserve estimate (the amount of gas that can be technically and economically produced) cannot yet be made, In 2010, a DECCcommissioned British Geological Survey (BGS) study, by analogy with the productivity of Barnett Shale gas basin production in the US, estimated that the shale gas potentially recoverable resources could be 150 billion cubic meters of gas (5.3 trillion cubic feet). To put this in context, this is almost 2 years of UK gas consumption (86 billion cubic meters in 2009). 8] What does shale gas waste water contains? Shale gas wastewater contains high concentrations of total dissolved solids (salts). Shale gas wastewaters also contain various organic chemicals, inorganic chemicals, metals, and naturally occurring radioactive materials (NORM).

9] What is done with this waste water? Currently, wastewaters associated with shale gas extraction are prohibited from being directly discharged to waterways and other waters of the U.S. In order to meet this prohibition, some of the shale gas wastewater is reused or re-injected, but a significant amount still requires disposal. Some operators reinject the wastewater into disposal wells. Other shale gas wastewater is transported to public and private treatment plants, which may not be equipped to treat this type of wastewater, resulting in the discharge of pollutants to rivers, lakes or streams where they can impact drinking water or aquatic life. 10] What are the benefits of shale natural gas extraction?  Natural Gas is the cleanest of all fossil fuels • Can reduce the emissions of pollutants into the atmosphere

 The main products of natural gas combustion are carbon dioxide and water vapor • Carbon dioxide is a less potent pollutant

 Natural gas does not contribute much to smog • Emits low levels of nitrous oxide and almost no particulate matter

 Can be used to fuel vehicles • Cut down on the emissions from gasoline and diesel.

11] What is fracturing fluids? How this fluid is used ?
Water is the driving fluid used in the hydraulic fracturing process. Depending upon the characteristics of the well and the rock being fractured a few million gallons of water can be required to complete a hydraulic fracturing job. When the water is pumped into the well the entire length of the well is not pressurized. Instead, plugs are inserted to isolate the portion of well where the fractures are desired. Only this section of the well receives the full force of pumping. As pressure builds up in this portion of the well, water opens fractures, and the driving pressure extends the fractures deep into the rock unit. When pumping stops these fractures quickly snap closed and the water used to open them is pushed back into the borehole, back up the well and is collected at the surface. The water returned to the surface is a mixture of the water injected and pore water that has been trapped in the rock unit for millions of years. The pore water is usually brine with significant amounts of dissolved solids. Chemicals are often added to the water used in hydraulic fracturing. These additives serve a variety of purposes. Some thicken the water into a gel that is more effective at opening fractures and carrying proppants deep into the rock unit. Other chemicals are added to: reduce friction, keep rock debris suspended in the liquid, prevent corrosion of equipment, kill bacteria, control pH and other functions.

WELL CONTROL
1) What is a kick? 2) What are the types of well control procedures? (Rig control, Mud control, Choke control) 3) What are the causes of kicks? 4) What is typical kick sequence? 5) What are the indications of a kick? 6) What are the kick control procedures (kick containment and removal of kick from wellbore)? 7) What are the considerations while selecting the kick control procedure? 8) Formulae for : - Hydrostatic pressure - Circulating pressure - Initial circulating pressure - Final circulating pressure - Kill mud weight - Formation pressure - Volume increase caused by weighting up - Barite increase required - Bottomhole pressure - Casing seat and tubing pressure 9) What is the driller’s method? 10) What is the engineer’s method? How is it different from driller’s approach? 11) What is the concurrent method? 12) What is dynamic kick control? 13) What comprises well control equipment? 14) What are the types of BOPs and their functioning principle?
ANSWERS 1) A kick is defined as an unscheduled, undesirable influx of formation fluid into the borehole. 2) - Rig Control: This includes the BOP's, pumps, drawworks and other rig equipment. - Mud control: This involves the addition of weighting material (most commonly barite) to the mud to increase its density, but also includes the correct operation of the mixing system and chemical additions. - Choke control: This includes the correct calculation of pressures and time relationships, as well as operating the choke and monitoring the pump rate. 3) - Failure To Keep The Hole Full: The majority of kicks occur when the bit is off bottom, while tripping. When the pumps are shut down prior to tripping, there is a pressure reduction in the borehole equal to the annular pressure losses. If the equivalent circulating density and the pore pressure are nearly equal, flow may occur when circulation stops. As pipe is removed, the mud-level in the borehole falls, causing a reduction in hydrostatic pressure.

- Swabbing of Formation Fluids Into the Borehole: When pipe is pulled it acts like a piston, more so below than above the bit. Both gel strength and viscosity of the mud have a large effect on swabbing. - Insufficient Mud Density - Lost circulation - Drilling into abnormally pressured zones: Could be due to poor well planning 4) 1. Kick indication 2. Kick detection -(confirmation) 3. Kick containment -(stop kick influx) 4. Removal of kick from wellbore 5. Replace old mud with kill mud (heavier) 5) 1. Drilling break: The fast drill-rate need not necessarily indicate an increase in porosity, permeability and pressure. 2. Increase in return flow rate 3. Increase in hook load. 4. Increase in pit volume. 5. Pump pressure decrease. 6. Reduction in flowline mud density as invading fluids reach surface. 6) Driller’s Method, Engineer’s Method and Concurrent Method 7) - The time required to execute any complex kill procedures - Surface pressures that will arise from circulating out the kick fluids - Downhole stresses that are applied to formations during kill operation - The complexity of the procedure itself relative to the implementation, rig capability and rig crew experience 8) Formulae for: - Hydrostatic pressure = 0.052 X MW (ppg) X TVD (ft)- Pressure Gradient - Pressure gradient (psi/ft) = HSP/TVD = 0.052 × MV (ppg) - Formation pressure - Overburden pressure = ρb× D×g

-Slow pump pressure - Shut in Drill Pipe Pressure (SIDPP) - Shut in Casing Pressure (SICP) FP = HSPmud + HSPinflux + SICP - Bottom-hole pressure -BHP = HSP + SIP + Friction + Surge – Swab

Capacity  ID2  1029 AnnularCap  DPdisp 
2 2 IDhole  ODpipe

1029

wt / ft 2600 wt / ft OD 2  ID2 DCdisp   2750 1029 Wetdisp  Capacity  disp
- Circulating pressure - Kill mud weight - Volume increase caused by weighting up - Barite increase required 12) Dynamic kick control: 1. Keep pumping. Increase rate! (higher ECD) 2. Increase mud density (0.3 units/gal per circulation) 3. Check for flow after each complete circulation 4. If still flowing, repeat 2-4. 13) Preventer, mud access line, kill line, diverter system, Kelly cocks, choke manifold, accumulator 14) Annular preventer Ram type preventer: Pipe ram, Blind ram, Shear ram

RESERVOIR PROPERTIES

1. How can you determine reservoir rock properties?  Core analysis, log analysis 2. How can you determine reservoir fluid properties?  Log analysis, lab analysis 3. Which properties are included under rock properties?  Porosity, Permeability, radioactivity, saturation 4. What are the disadvantages of core analysis? How can you overcome it?  It is quite expensive. Further only a small part of reservoir is obtained when core is obtained during drilling. If diamond bit is used, it can give 100 % core recovery. 5. In which order the reservoir properties are determined?  Storage Capacity (porosity), permeability, capillary pressure, Correlations (k-φ. S-k etc), lithological coefficient, electrical properties, statistical analysis, estimate of reserve. 6. Why core drilling is imp?  Because the rock properties (k, φ, s) vary spatially due to anisotropy and haterogenity. 7. exploratory phase of core analysis gives idea of?  Structure, physical characteristics, production possibilities. 8. Optimum completion phase of core analysis gives idea of?  Interval selection for testing, interpretation of DST, order of completion for multi layer, effectiveness of completion. 9. Development phase of core analysis gives idea of?  Limits of the field, fluid contacts and variation across the field, correlation, net pay, reserve, initial production. 10. What is Special core analysis?  It is done only on the selective samples. It helps to determine capillary pressure, F & Resistivity ratio, relative permeability, wettability. 11. Differentiate φ, φeff , φresidual.  Φ: gives idea of total void space in the rock Φeff: gives idea of interconnected voids in the rock Φres: gives idea of non connected pores 12. Define porosity  The percentage of pore volume or void space, or that volume within rock that can contain fluids. Porosity can be a relic of deposition (primary porosity, such as space between grains that were not compacted

together completely) or can develop through alteration of the rock (secondary porosity, such as when feldspar grains or fossils are preferentially dissolved from sandstones). 13. Define Permeability  The capability of a rock to allow passage of fluids through it. The term was basically defined by Darcy, who showed that the common mathematics of heat transfer could be modified to adequately describe fluid flow in porous media. 14. Does porosity depend on grain size, shape, distribution?  Yes. 15. What will be the porosity of a cube arranged grains?  47.6 % 16. What will be the porosity of rhombohedra arranged grains?  26% 17. What is average porosity of sand stone, limestone and clay?  10-40%, 5-25% & 20-45% respectively. 18. to determine the porosity accurately, the sample should be..  as large as possible. 19. How porosity can be determined using total volume (bulk volume) and grain volume?  Φ= *V(bulk)-V(grain)]/V(bulk) 20. Which are the methods used to prepare the sample for porosity determination?  Vacuum retorting (not for clayey sample), centrifuging, washing in sequence. 21. Which are the solutions used for washing the sample?  Toluene, xylene, methane tetrachloride, chloroform, acetone, hexane (solutions in which mostly oil is soluble) 22. How formation volume factor and porosity are related?  FF= Ro/Rw = a/φm (FF increases with Salinity) 23. How porosity can be determined using density log?  Φ= *ρg – ρ+/*ρg- ρf] 24. In sonic log, velocity in the medium depends on?  Nature of rock, porosity, density, pore size, cementation, fluid density and viscosity, elastic properties, temp and pressure. 25. Define Darcy unit for permeability.  A standard unit of measure of permeability. One darcy describes the permeability of a porous medium through
which the passage of one cubic centimeter of fluid having one centipoise of viscosity flowing in one second under a pressure differential of one atmosphere where the porous medium has a cross-sectional area of one square centimeter and a length of one centimeter. A millidarcy (mD) is one thousandth of a darcy and is a commonly used unit for reservoir rocks.

26. Give expression for darcy’s law.

 Q= - (k*A/µ)(dP/dL) 27. What are the assumptions made in the derivation of Darcy’s law?  No reaction between rock and fluid, single phase fluid flow, laminar flow, homogeneous fluid etc. 28. What is the effect for gas permeability called?  Klinkenberg effect 29. Define klinkenberg effect.  “ the permeability to a gas is a function of the mean free path of the gas molecules and thus depends on factors
which influence the mean free path ie. T, P and nature of gas. (permeability for the gas increases as pressure increases. And reaches to that of liquid at very high pressure)

BASICS OF PRODUCTION TECHNOLOGY
Q1. What are the various drive mechanisms that exist in an oil reservoir? Ans : Oil reservoirs have the following driving mechanisms : a) Water drive reservoir: The oil zone is connected by a continuous path to the surface groundwater system or aquifer. The pressure caused by the ‘‘column’’ of water to the surface forces the oil (and gas) to the top of the reservoir against the impermeable barrier that restricts the oil and gas(the trap boundary). This pressure will force the oil and gas toward the wellbore. b) Gas cap reservoir : In a gas-cap drive reservoir, gas-cap drive is the drive mechanism where the gas in the reservoir has come out of solution and rises to the top of the reservoir to form a gas cap. If the gas in the gas cap is taken out of the reservoir early in the production process, the reservoir pressure will decrease rapidly. c) Dissolved gas drive reservoir: A dissolved-gas drive reservoir is also called a‘‘solution-gas drive reservoir’’ and ‘‘volumetric reservoir.’’ The oil reservoir has a fixed oil volume surrounded by noflow boundaries (faults or pinch-outs). Dissolved-gas drive is the drive mechanism where the reservoir gas is held in solution in the oil (and water). The reservoir gas is actually in a liquid form in a dissolved solution with the liquids (at atmospheric conditions) from the reservoir. Q2. Give a brief note on Inflow Performance Curve. Discuss in respect of two phase flow and the prescribed Vogel’s equation. Ans : IPR is used for evaluating reservoir deliverability in production engineering. The IPR curve is a graphical presentation of the relation between the flowing bottom-hole pressure and liquid production rate. The magnitude of the slope of the IPR curve is called the ‘‘productivity index’’. Well IPR curves are usually constructed using reservoir inflow models, which can be from either a theoretical basis or an empirical basis. It is essential to validate these models with test points in field applications. ( GRAPH) Below the bubble-point pressure, the solution gas escapes from the oil and become free gas. The free gas occupies some portion of pore space, which reduces flow of oil. This effect is quantified by the reduced relative permeability. Also, oil viscosity increases as its solution gas content drops. The combination of the relative permeability effect and the viscosity effect results in lower oil production rate at a given bottom-hole pressure. This makes the IPR curve

deviating from the linear trend below bubble-point pressure. The empirical relations used include Vogel’s . This is

written as : where qmax is an empirical constant and its value represents the maximum possible value of reservoir deliverability, or AOF. Q3. What do you mean by liquid hold up in terms of multiphase flow? Ans : In multiphase flow, the amount of the pipe occupied by a phase is often different from its proportion of the total volumetric flow rate. This is due to density difference between phases. The density difference causes dense phase to slip down in an upward flow (i.e., the lighter phase moves faster than the denser phase). Because of this, the in situ volume fraction of the denser phase will be greater than the input volume fraction of the denser phase (i.e., the denser phase is ‘‘held up’’ in the pipe relative to the lighter phase). Q4. Why do we need artificial lift methods? List a few methods used in the oil industry. Ans : Most oil reservoirs are of the volumetric type where the driving mechanism is the expansion of solution gas when reservoir pressure declines because of fluid production. Oil reservoirs will eventually not be able to produce fluids at economical rates unless natural driving mechanisms (e.g., aquifer and/or gas cap) or pressure maintenance mechanisms (e.g., water flooding or gas injection) are present to maintain reservoir energy. The only way to obtain high production rates of a well is to increase production pressure drawdown by reducing the bottom-hole pressure with artificial lift methods. The commonly used artificial lift methods include the following: . Sucker rod pumping . Gas lift . Electrical submersible pumping . Hydraulic piston pumping . Hydraulic jet pumping . Plunger lift . Progressing cavity pumping Q5. Enlist the pumping system of the sucker rod pumps with their working . Ans: Prime mover, V- belt, Crank arm, Walking beam, Horsehead, Pitman arm, Hanger cable, Polished rod, Stuffing box. Q6. What is the working mechanism of the beam pump? Ans: The pump is installed in the tubing string below the dynamic liquid level. It consists of a working barrel and liner, standing valve (SV), and traveling valve (TV) at the bottom of the plunger, which is connected to sucker rods. As the plunger is moved downward by the sucker rod string, the TV is open, which allows the fluid to pass through the valve, which lets the plunger move to a position just above the SV. During this downward motion of the plunger, the SV is closed; thus, the fluid is forced to pass through the TV. When the plunger is at the bottom of the stroke and starts an upward stroke, the TV closes and the SV opens.

As upward motion continues, the fluid in the well below the SV is drawn into the volume above the SV (fluid passing through the open SV). The fluid continues to fill the volume above the SV until the plunger reaches the top of its stroke. Q7. What are the prominent conditions of bean pump failure due to gas entry? Ans: Gas lock: Gas interference: No valves open during pumping cycle. No fluid lifted to surface. Valves function properly, but reduced efficiency as gas takes place of some fluid.

Pumped off condition : Pumping rate exceeds ability of fluid to flow into pump. Well does produce some fluid. Q8. What are the categories for applying gas lift to a field? Ans : There are four categories of wells in which a gas lift can be considered: 1. High productivity index (PI), high bottom-hole pressure wells 2. High PI, low bottom-hole pressure wells 3. Low PI, high bottom-hole pressure wells 4. Low PI, low bottom-hole pressure wells Q9. What are the different types of gas lift operations and what are their usage? Ans: A continuous gas lift operation is a steady-state flow of the aerated fluid from the bottom (or near bottom) of the well to the surface. In continuous gas lift, a small volume of high-pressure gas is introduced into the tubing to aerate or lighten the fluid column. This allows the flowing bottom-hole pressure with the aid of the expanding injection gas to deliver liquid to the surface. Intermittent gas lift operation is characterized by a start-and-stop flow from the bottom (or near bottom) of the well to the surface. This is unsteady state flow. USAGE:  Continuous gas lift method is used in wells with a high PI and a reasonably high reservoir pressure relative to well depth.  Intermittent gas lift method is suitable to wells with : (1) high PI and low reservoir pressure or (2) low PI and low reservoir pressure. Q10. Fill in the blanks: The potential of gas lift wells is controlled by ------------------------ rate. Ans : Gas Injection Rate

Q11. What are the surface and sub surface components of an Electrical Submersible Pump? On what principle does it work? Ans: a. subsurface components - Pump - Motor - Seal electric cable - Gas separator

b. Surface components - Motor controller (or variable speed controller) - Transformer - Surface electric cable Working: The overall ESP system operates like any electric pump commonly used in other industrial applications. In ESP operations, electric energy is transported to the down-hole electric motor via the electric cables. These electric cables are run on the side of (and are attached to) the production tubing. The electric cable provides the electrical energy needed to actuate the down-hole electric motor. The electric motor drives the pump and the pump imparts energy to the fluid in the form of hydraulic power, which lifts the fluid to the surface. Q12. How does PCP operate? Ans: The progressive cavity pump (PCP) is a positive displacement pump, using an eccentrically rotating single- helical rotor, turning inside a stator. The rotor is usually constructed of a high-strength steel rod, typically double-chrome plated. The stator is a resilient elastomers in a double-helical configuration molded inside a steel casing. Q13. What are the advantages of using PCP? Ans:  Progressive cavity pumping systems can be used for lifting heavy oils at a variable flow rate.  Solids and free gas production present minimal problems.  They can be installed in deviated and horizontal wells.  With its ability to move large volumes of water, the progressing cavity pump is also used for coal bed methane, dewatering, and water source wells. The PCP reduces overall operating costs by increasing operating efficiency while reducing energy requirements. Q14. What are the major flow regimes encountered in gas wells? Ans: a) Mist flow b) Annular flow c) Slug flow d) Bubble flow Q15. State the operating procedure of a hydraulic jet pump? Ans: It is a dynamic-displacement pump that differs from a hydraulic piston pump in the manner in which it increases the pressure of the pumped fluid with a jet nozzle. The power fluid enters the top of the pump from an injection tubing. The power fluid is then accelerated through the nozzle and mixed with the produced fluid in the throat of the pump. As the fluids mix, the momentum of the power fluid is partially transferred to the produced fluid and the increases its kinetic energy. Some of the kinetic energy of the mixed stream is converted to static pressure head in a carefully shaped diffuser section of expanding area. If the static pressure head is greater than the static column head in the annulus, the fluid mixture in the annulus is lifted to the surface. Q16. State the usage of a plunger lift system. Ans:    Essentially a low liquid rate, high GL lift method. Can be used for extending flow life or improving efficiency. Ample gas volume and/or pressure needed for successful operation.

Q17. What is a sick well and what are its possible causes ? Ans: A sick well displays the following characteristics:  low oil or gas production  high gas-oil ratio  high water cut  mechanical problems  Problems in injection or disposal wells The possible causes are :  . Inflow restrictions -- wellbore plugging -- perforation choking -- formation damage  Outflow restrictions --Increase backpressure -- limit drawdown --reduce production  Reservoir problems -- low reservoir permeability --low reservoir pressure

LAW OF THERMODYNAMICS
1. The pressure P and volume V of an ideal gas has both increase in a process. a) Such a process is not possible. b) The work done by the system is positive. c) The temperature of the system must increase. d) Heat supplied to the gas is equal to the change I internal energy. Ans B) , c) 2. The internal energy of an ideal gas decreases by the same amount as the work done by the system. a) The process must be adiabatic. b) The process must be isothermal. c) The process must be isobaric. d) The temperature must decrease. Ans A), d) 3. Internal energy change of system in one complete cycle process is a) Zero b) +ve c) –ve d) Dependent on the path Ans A)

4. Van laar equation deals with activity coefficients in a) Binary solutions b) Ternary solutions c) Azeotropic solutions d) None of these Ans A) 5. Solubility of a substance which dissolves with an increase in volume and liberation of heat will be favoured by the a) Low pressure and high temperature b) Low pressure and low temperature. c) High pressure and low temperature. d) High pressure and high temperature. Ans B) 6. In a working refrigerator, the value of COP always a) 0 b) <0 c) < 1 d) > 1 Ans D) 7. The theoretical minimum work required to separate one mole of a liquid mixture at 1 atm, containing 50 mole % each of n- heptane and n- octane into pure compounds each at 1 atm is a) -2RT In0.5 b) –RT In0.5 c) 0.5 RT d) 2 RT Ans B) 8. If the vapor pressure at two temperatures of a solid phase in equilibrium with its liquid phase are known, then the latent heat of fusion can be calculated by the a) Maxwell's equation b) Clayperon-Claussius equation c) Van Laar equation d) Nernst Heat Theorem Ans: B) 9. During Joule-Thomson expansion of gases a) Enthalpy remains constant. b) Entropy remains constant. c) Temperature remains constant. d) None of these. Ans: A) 10. Heat pump a) Accomplishes only space heating in winter. b) Accomplishes only space cooling in summer. c) Accomplishes both a) and b) . d) Works on Carnot cycle. Ans: C)

11. Maximum work that could be secured by expanding the gas over a given pressure range is the ___________ work. Ans: Isothermal 12. High ________ is an undesirable property of a good refrigerant. Ans: Viscosity 13. The temperature at which both liquid and gas phases are identical, is called the ________ point. Ans: Critical 14. The principle applied in liquefaction of gases is ___________. Ans: Joules-Thomson effect 15. A liquid under pressure greater than its vapor pressure for the temperature involved is called a _______ liquid. Ans: Sub cooled 16. For a stable phase at constant pressure and temperature, the fugacity of each component in a binary system __________ as its mole fraction increases. Ans: Increases 17. Measurement of thermodynamic property of temperature is facilitated by __________ law of thermodynamics. Ans: Zeroth 18. Equilibrium constant decreases as the temperature _________ , for an exothermic reaction. Ans: Increases 19. Water _______ on heating from 1 to 4°C. Ans: Contracts 20. In polytropic process (PVn = constant), if n = 1; it means a/an __________ process. Ans: Isothermal

DIRECTIONAL DRILLING
1. What is role of Directional drilling Engineer?

Responsibilities include planning and completions of directional wells. Designing the BHA for each specific direction well. Studying application of new technologies for performance drilling. Attending any type of complication met during the drilling of a well. 2. Define different type of well profile • • • • Straight Slant type(j type)- where the Radius of build is less than the total displacement of the target “S" type Horizontal

• •

Build and hold Extended reach

3. What are the main deflection tools used in directional drilling and explain? • Whipstock • Jetting • PDM (or Turbine) With Bent Sub • Steerable Positive Displacement Motor

Whip stock (hardly used) • It act as a deflection tool in open-hole or cased hole. • used for drilling sidetrack wells not directional wells Jetting • There will be 3 nozzles in the bit to circulate the drilling mud. • Here we closes 2 and 1 is open • This technique is used to deviate the wellbore in soft formations. PDM (or Turbine) With Bent Sub • Primary method of directional control. • Here, a bent sub is run directly above a PDM. • Bent sub allows deflection to occur by pushing the mud motor to one side of the hole.
Steerable Positive Displacement Motor

•

It is a major component of a BHA which can be used in oriented ("sliding") or rotary mode. In sliding mode, the steerable motor changes the course of the well

4. Give difference between drill collar and HWDP Drill collar

• •

Drill collars are heavy steel tubular. They are used at the bottom of a BHA to provide weight on bit and rigidity

HWDP (Heavy weight drill pipe) • HWDP is less rigid than DCs and has much less wall contact. Chances of differential sticking are reduced It permits high-RPM drilling with reduced torque

•

Today, the trend in BHA design is to minimize the number of DCs in the BHA and use HWDP to comprise a major portion of available weight on bit
5. Function of stabilizer

•

Stabilizers are used to: • Control hole deviation. • Reduce the risk of differential sticking. • Ream out doglegs and

6. Give difference between turbine and PDM The Turbine, • Works on the principle of centrifugal or axial pump • When circulating fluid enters, the blades are rotated, then transmitted to the shaft and then to the drill bit

The Positive Displacement Motor (PDM): • Uses technology of screw pump • Industry normally uses PD motors for DD

•

Power of PDM is generated by rotor and stator based on geometry

7. Applications of Directional Drilling
• • • • • • • Sidetracking Inaccessible Locations Salt Dome Drilling Fault Controlling Multiple Exploration Wells from a Single Well-bore Relief Well Horizontal Wells

8. what are the different survey method used in directional well.

Tangential Method • Use only the inclination and direction of the last survey/lower survey point and is the least accurate survey method • The well bore is assumed to be tangential to these angles Balanced tangential • Here, both the current and the previous survey results used. • The main reason for the higher accuracy of the balanced tangential method is that errors introduced into one calculation are largely canceled by the subsequent calculation

Average angle
• This method of calculation simply averages the angles of inclination and azimuth at the two survey stations

Radius of Curvature Method
• •
•

well path is assumed to be a smooth curve that can be fit to the surface of a cylinder As such the well
bore can be curved in both the vertical and horizontal planes

This is more accurate on long survey intervals and is able to handle higher changes. Fits the well path on the surface of a sphere of a particular radius using a method similar to the radius of curvature but using a ratio factor.

Minimum Curvature Method

FORMATION DAMAGE
1. What is meant by Formation Damage? Damage can be anything that obstructs the normal flow of fluids to the surface; it may be in the formation, perforations, lift system, tubulars or restrictions along the flowpath. Formation damage is a terminology used to delineate the undesirable reduction of permeability by various processes occurring in geological porous formations, and therefore reducing the natural inherent productivity of an oil or gas producing formation, or reducing the injectivity of a water or gas injection well. It specifically refers to the obstructions occurring in the near-wellbore region of the rock matrix. Regardless of the mode of reservoir flow, the near-well zone may be subjected to an additional pressure difference caused by a variety of reasons, which alters the radial (and horizontal) flow converging into the well. The damaged zone is commonly referred to as a “Skin” in formation damage calculations. 2. What is Skin-Effect? The total skin effect ‘s’ is a dimensionless term used to account for the additional pressure drop in the wellbore area that results from formation damage and other factors. Skin effect is a measure of the damage inflicted to the formation permeability in the vicinity of the wellbore. Hawkins pointed out that if the damaged (or stimulated) zone is considered equivalent to an altered zone of uniform permeability (k s ) and outer radius (rs), the additional pressure drop across this zone (∆ps) can be modelled by the steady-state radial flow equation. Skin effect describes a zone of infinitesimal extent that causes a steady-state pressure difference, conveniently defined as:

∆ps = qµ s / 2πkh
Where ‘s’ is defined as in terms of the properties of the equivalent altered zone (Hawkins equation) :

s = ( k / ks - 1 )ln rs / rw
Where, ks is the damaged/altered zone permeability in md and rs is the damage penetration/ outer radius of altered zone, beyond the wellbore in ft. Knowledge of the inflow relationship and Hawkin’s equation is essential to understand the effects of near-wellbore formation damage on well production. The ‘steady state’ inflow relationship for an oil well is given by:

q = 2πkh (pe – pwf ) / Bμ , ln(re / rw) + s}
or,

pe – pwf = qµ { ln(re /rw) + s- / 2πkh
suggesting that, for a constant rate ‘q’, a positive skin effect requires a lower pwf whereas a negative skin effect allows a higher value. For production or injection, a large positive skin effect is detrimental; a negative skin effect is beneficial. {*Point to be remembered: An altered zone near a particular well affects only the pressure near that well, i.e., the pressure in the unaltered formation away from the well is not affected by the existence of the altered zone.}

3. Explain the relative significance of formation damage and its remediation. Although the drainage radius may be several hundreds of feet, the effective permeability close to the wellbore has a disproportionate effect on well-productivity. The nature of radial flow is that the pressure difference in the reservoir increases with the “logarithm” of distance; i.e., the same pressure is consumed within the first foot as within the next ten, hundred, etc. If the permeability of the near-wellbore zone is reduced significantly it is entirely conceivable that the largest portion of the “total pressure gradient” may be consumed within the very near wellbore zone. Similarly, recovering or even improving this permeability may lead to a considerable improvement in the well production or injection. This is the role of matrix stimulation.

4. For formation damage remediation and prevention, what steps or aspects are needed to be considered beforehand for its identification? Aspects which need to be taken considered, step-wise, for Formation Damage Characterization (identification and investigation) include: • Types of damage and its mechanism • Location of damage • Extent and screening of damage • Effect of damage on well production or injection. 5. Classification of formation damage on the basis of its mechanism. Diagnosis of formation damage problems has led to the conclusion that formation damage is usually associated with either the movement and bridging of the fine solids or chemical reactions and thermodynamic considerations. The fine solids may be introduced from wellbore fluids or generated in-situ by the interaction of invading fluids with rock minerals or formation fluids. Formation damage is typically categorized by the mechanism of its creation as either “natural” or “induced”. Natural damages are those that occur primarily as a result of producing the reservoir fluid. Induced damages are the result of an external operation that was performed on the well such as a drilling, well completion, repair, stimulation treatment or injection operation. In addition, some completion operations, induced damages or design problems may trigger natural damage mechanisms. Natural damages include • Fines migration • Swelling clays • Water-formed scales • Organic deposits such as paraffins or asphaltenes • Mixed organic/inorganic deposits • Emulsions. Induced damages include • Plugging by entrained particles such as solids or polymers in injected fluids • Wettability changes caused by injected fluids or oil-base drilling fluids • Acid reactions • Acid by-products • Iron precipitation • Iron-catalyzed sludges • Bacteria • Water blocks • Incompatibility with drilling fluids. These mechanisms are described as follows:  FINES MIGRATION Formation damage can occur as a result of particle migration in the produced fluid. The particles can bridge across the pore throats in the near-wellbore region and reduce the well productivity. When the damaging particles come from the reservoir rock, they are usually referred to as fines. Migrating fines can be a variety of different materials, including clays (phyllosilicates with a typical size less than 4 µm) and silts (silicates or aluminosilicates with sizes ranging from 4 to 64 μm). Kaolinite platelets are thought to be some of the more common migratory clays. Damage from fines is located in the near-wellbore area, within a 3- to 5-ft radius. Structural differences determine the surface area exposed to the reservoir fluids for each clay. Clay reactivity is a function of this surface area. The location of the clay is also critical to its reactivity. Authigenic clay is in a pore throat as fill or as a lining (i.e., grown in the pore from minerals in the connate water). These clays have a large amount of surface area exposed in the pore and can be reactive. Detrital clay is part of the building material in the original matrix. These clays are usually less reactive than authigenic clays because they have

less surface area in contact with the fluids in the pore. The vast majority of detrital clays usually cannot be contacted by sufficient volumes of reactive fluids to cause problems.  SWELLING CLAYS Clays may change volume as the salinity of the fluid flowing through the formation changes. Changes in formation permeability resulting from the alteration of clay are due to the amount, location and type of clay minerals within the formation. The total quantity of clay inside the formation is a misleading indication of potential changes to permeability. It is the arrangement of the clay, its chemical state at the moment of contact and the location of the clay with respect to the flowing fluids that are responsible for the changes. The most common swelling clays are smectite and smectite mixtures. Smectite swells by taking water into its structure. It can increase its volume up to 600%, significantly reducing permeability. If smectite clay occupies only the smaller pore throats and passages, it will not be a serious problem; however, if it occupies the larger pores and especially the pore throats, then it is capable of creating an almost impermeable barrier to flow if it swells. Clays or other solids from drilling, completion or workover fluids can invade the formation when these particles are smaller than the pore throat openings. Any subsequent increase in flow rate through the invaded zone will force a high concentration of particles into the rock matrix. SCALES Scales are water-soluble chemicals that precipitate out of solution in response to changes in conditions or the mixing of incompatible waters. They can be present in the tubing, perforations and formation. The most common oilfield scales are calcium carbonate, calcium sulfate and barium sulfate. Scale usually consists of precipitates formed from mixing incompatible waters or upsetting the solution equilibrium of produced waters. A water that may be stable under reservoir conditions may become supersaturated with an ion when the pressure decreases, which allows carbon dioxide (CO2) outgassing, or the temperature changes. The supersaturated solutions react by precipitating a compound from solution. The deposition of scale is influenced by pressure drop, temperature, dissolved gases, flow viscosity, nucleation sites and metal type —in short, anything that upsets the solution equilibrium. The following scales are among the most troublesome. • Calcium carbonate or calcite (CaCO3) CaCO3 is usually formed when the pressure is reduced on waters that are rich in calcium and bicarbonate ions. The deposition can be affected by CO2 out gassing, which raises the pH value and makes the high concentrations of calcium unstable. • Gypsum (“gyp”) Gypsum may be the most common sulfate scale in the oil industry. It is also formulaically similar to the evaporite mineral anhydrite (CaSO4). • Barium sulfate (BaSO4) BaSO4 is a less common form of sulfate deposit, but it causes extensive problems. Almost any combination of barium and sulfate ions causes precipitation. It is difficult to remove, as it is not significantly soluble in acids and solvents unless it is finely ground or the structure is interrupted with impurities such as carbonate scale. Like calcium sulfate, barium sulfate is usually thought to be a product of mixing incompatible waters, with precipitation accelerated by pressure drop, out gassing or turbulence. Some barium sulfate is radioactive; this is part of naturally occurring radioactive material (NORM) scales. • Iron scales Iron scales such as iron carbonate and iron sulphide can be extremely difficult to remove. They are usually seen in wells that have both a high background iron count and a tendency to precipitate calcium carbonate. • Chloride scales Chloride scales, such as sodium chloride precipitation from water caused by temperature decrease or evaporation of the water, are common. There is no effective way to prevent salt precipitation, and cleanup



has been accomplished using water only. Salt has a limited solubility in acid (1⁄4 Lbm/gal in 28% HCl), so using acid is not generally considered. Redesigning the mechanical system to avoid temperature loss and water evaporation is also a possibility. • Silica scales Silica scales generally occur as finely crystallized deposits of chalcedony or as amorphous opal. They are associated with alkaline or steam flood projects and stem from the dissolution of siliceous formation minerals by high-pH fluids or high-temperature steam condensates. This dissolution can cause poorly consolidated sandstones to collapse or silica to Reprecipitation at a distance from the wellbore where the alkalinity, temperature or both of the floods has decreased.  ORGANIC DEPOSITS 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. Although the formation mechanisms of organic deposits are numerous and complex, the main mechanism is a change in temperature or pressure in the flowing system. Cooling of the wellbore or the injection of cold treating fluids has a much more pronounced effect. Organic deposits must not be confused with another type of deposit called sludge. Sludges are viscous emulsions produced by the reactions between certain crude oils and strong inorganic acids or some brines. Sludges cannot be easily dissolved. • Paraffins Paraffins are the simplest of hydrocarbons, composed of only carbon and hydrogen atoms, and the carbons occur as an unbranched chain. Carbon chain length associated with formation of solid paraffin deposits has a minimum of 16 carbon atoms per molecule and may have up to 60 or more. The precipitation of paraffins is triggered by a loss of pressure, loss of temperature or loss of short-chain hydrocarbon compounds (i.e., the light ends). Paraffins are normally found in the tubing near the surface, where the temperature and pressure drops are highest. • Asphaltenes Asphaltenes are organic materials consisting of condensed aromatic and naphthenic ring compounds with molecular weights of several hundred to several thousand. They are characterized by the nitrogen, sulfur and oxygen molecules they contain and are defined as the organic part of the oil that is not soluble in a straightchain solvent such as pentane or heptanes. Asphaltenes are generally found in one of three distinctive forms: – hard coal-like substance – blackened sludge or rigid-film emulsion (usually triggered by iron in solution) – in combination with paraffins. • 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.  MIXED DEPOSITS Mixed organic/inorganic deposits are a blend of organic compounds and either scales or fines and clays. When migrating, fines associated with an increase in water production in a sandstone reservoir become oil-wet, and they act as a nucleation site for organic deposits. EMULSIONS Emulsions are combinations of two or more immiscible fluids (including gas) that will not disperse molecularly into each other. Emulsions are composed of an external phase (also called nondispersed or continuous) and an internal phase (also called dispersed or discontinuous). The internal phase consists of droplets suspended in the external phase. Almost all emulsions found in the field are produced by the addition of some form of



energy that produces mixing. Natural surfactants help stabilize emulsions by stiffening the film around the droplet or by partially wetting small solid particles. The more common solid materials that stabilize oilfield emulsions are iron sulfide, paraffin, sand, silt, clay, asphalt, scale, metal flakes (from pipe dope), cuttings and corrosion products. Changes in the pH value can affect emulsion stability.  INDUCED PARTICLE PLUGGING In addition to naturally occurring migrating particles such as clays and fines, many foreign particles are introduced into the formation during normal well operations like drilling, completion, workover, stimulation, and secondary or tertiary production operations. Particle damage from injected fluids happens in the nearwellbore area, plugging formation pore throats. Problems include bridging of the pores, packing of perforations and the loss of large amounts of high solids fluid into natural fractures or propped fracture systems. The best method of avoiding this type of damage is to use a clean fluid in a clean flow system with a controlled range of particle sizes that will stop fluid loss quickly by bridging at the wellbore. Induced particles can be composed of a wide range of materials. WETTABILITY ALTERATION Formation plugging can be caused by liquid (or gas) changing the relative permeability of the formation rock. Relative permeability can reduce the effective permeability of a formation to a particular fluid by as much as 80% to 90%. The wettability and related relative permeability of a formation are determined by the flowingphase quantity and by coatings of natural and injected surfactants and oils. When a surface of a pore passage is oil-wet, more of the passage is occupied by the bound oil (thicker monomolecular layer), and less of the pore is open to flow than in a water-wet pore. Naturally, to get as much flow capacity as possible in a formation, it is desirable to change the wettability to water-wet (in most cases). Unfortunately, it is impossible to change most naturally oil-wet surfaces for long. Wettability can be modified by preflushing the formation with a wetting surfactant or a solvent that establishes a new coating on the face of the formation or cleans the current coating from the formation. Regardless of the altered condition of a surface, the wettability is eventually decided by the surfactants in the produced fluid. Thus, the water-wet condition of a formation following an acid job can revert to an oil-wet condition after a sufficient volume of strongly oil-wetting crude is produced. ACID REACTIONS AND ACID-REACTIONS BY-PRODUCTS Numerous problems that may occur during acidizing treatments include • damaging material from the tubing entering the formation • Oil-wetting of the reservoir by surfactants, especially corrosion inhibitors, which can create emulsion blocks • Water blocks • Asphaltene or paraffin deposition when large volume of acid is injected. • Sludge produced by the reaction between acids and asphaltenes, especially in the presence of some additives (particularly surfactants) or dissolved iron • By-products precipitated by the reaction of acids with formation materials. Gelatinous precipitates, such as ferric oxide, can completely plug pores and be particularly difficult to remove. Another class of by-products consists of species such as fluorosilicates precipitating in the form of individual crystals that can migrate toward pore throats and then bridge in the throats. Iron sulphide that precipitates, even at very low pH values during the acidization of sour wells, is another compound belonging to this category. BACTERIA Bacteria can be a serious problem in production operations because of what they consume and their byproducts. Bacteria can grow in many different environments and conditions: temperatures ranging from 12°F to greater than 250°F [–11° to >120°C], pH values ranging from 1 to 11, salinities to 30% and pressures to 25,000 psi. Bacteria are classified as follows: • Aerobic bacteria are bacteria that require oxygen. • Anaerobic bacteria do not need oxygen (in fact, their growth is inhibited by oxygen).

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

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• Facultative bacteria can grow either with or without oxygen because their metabolism changes to suit the environment. They usually grow about 5 times faster in the presence of oxygen.  OIL-BASE DRILLING FLUID Oil-base mud (OBM) is the drilling fluid of choice for the lubricity required in many highly deviated wells and for formations that are extremely sensitive to water-base mud (WBM). Most OBMs, and particularly those with densities greater than 14 Lbm/gal, contain sufficient solids to create silt-stabilized emulsions when mixed with high-salinity brines or acids. These emulsions are viscous and resist breaking. Some of these emulsions have been shown to be stable for several months, both in the laboratory and in the wellbore. A related problem with OBM is the relative permeability effects commonly created by the powerful wetting surfactants used for creating stable OBM. When these materials coat or adsorb onto the formation, the wettability of the formation is altered, and permeability may be only 10% to 20% of what they were initially. The most severe problems usually occur with muds weighing more than 14 Lbm/gal. The main cause of problems is oil-wetting of the fines from weighting and viscosifying agents and from cuttings.

{Note: Taking a microscopic look of the system, it is apparent that the fluids moving through the pores encounter some very critical conditions- tortuous paths; rough pore walls with large surface area; and a variety of reactive minerals such as clays, feldspars, micas, and iron compounds. These pore conditions provide an ideal medium for both physical entrapment of solids and chemical reactions between invading fluids and the clays or other minerals lining the pores.} 6. Derivation of the Hawkins formula: a relationship among the skin effect, reduced permeability and altered zone radius.

Figure 1-8 describes the areas of interest in a well with an altered zone near the wellbore. Whereas k is the “undisturbed” reservoir permeability, ks is the permeability of this altered zone. The Van Everdingen and Hurst (1949) skin effect has been defined as causing a steady-state pressure difference. It is dimensionless but reflects the permeability ks at a distance rs. A relationship among the skin effect, reduced permeability and altered zone radius may be extracted. Assuming that ps is the pressure at the outer boundary of the altered zone; the undamaged relation is given by:

and if damaged,

using the respective values of undamaged ideal and damaged real bottomhole flowing pressure (in the above equations). The above equations may be combined with the definition of skin effect and the obvious relationship: to obtain:

Also we have,

The above two equations can then be combined to obtain:

This is the well known Hawkins formula (1956). It also implies that if ks < k, the well is damaged and s > 0; conversely, if ks > k, then s < 0 and the well is stimulated. For s = 0, the near-wellbore permeability is equal to the original reservoir permeability. 7. What are the components of Skin effect? The total skin effect is a composite of a number of factors and may be written as:

st = sc+θ + sp + sd + ∑ pseudoskins
The first is the skin effect caused by partial completion and slant. The second term represents the skin effect resulting from perforations. The third term refers to the damage skin effect. The last term in the RHS of the above equation represents an array of pseudoskin factors, which result from obstructions to flow or because of rate- and phase-dependent effects and are not related to formation damage. 8. What are the tools and techniques available for Formation Damage Characterization? One or more type(s) of damage may exist or coexist in the wellbore and formation. A variety of techniques have come into the scenario, allowing the use of the available information to obtain a much better indication of the type and degree of damage (i.e. damage characterization) which different reservoirs may be sensitive to, thereby adjusting operating practices to attempt to minimize or reduce these permeability reducing factors. This data would include information such as production and pressure data, pressure transient data, log analysis, fluid and PVT data, well history and core, cuttings, special core analysis data. Formation damage is very “reservoir-specific”‖, but certain generalizations can be drawn based upon a database of experience. 9. What are the methods of remedying the formation damage? Techniques performed by hydrocarbon producers to increase the net permeability of the reservoir, which may have undergone a significant decrease in permeability due to formation damage, are referred to as ―stimulation techniques. Matrix Treatments are used to restore or improve the natural formation permeability “around the wellbore” and increase the well-productivity/injectivity‖by:

- either by reacting-&-dissolving the wellbore and/or near-wellbore damage plugging the pores (physical removal) or by enlarging the pore spaces [case of Matrix Acidizing in Sandstones], or, - by creating alternative flowpaths (conductive channels) for the hydrocarbons and bypassing the damage by reacting-&-dissolving small portions of the formation [case of Acid Fracturing in Carbonates], thus rather than removing the damage, the migrating oil is redirected around the damage.

MULTIPHASE FLOW
1) What are the types of flow regimes? ans. Number of flow regimes may be divided into two broad divisions •Where one phase is continuous. Eg; Bubble, Spray & Froth flow. Liquid is the continuous phase in bubble flow, while gas is the continuous phase in the other two. •Where both phases are continuous. 2) What is multiphase flow? Ans. It refers to more than one fluid medium, eg: oil, water and gas 4) What are the different flow regimes in multiphase horizontal flow? ans. Different flow regimes in multiphase horizontal flow are: a)Stratified Flow  Smooth Flow  Wavy Flow b)Intermittent Flow  Slug  Elongated Bubble c)Annular d)Dispersed Bubble 4)What are the different flow regimes in multiphase vertical flow? Ans.a)Buuble b)Slug c)Churn d)Annular 5)explain the following: Ans. a)Bubble: A multiphase fluid flow regime characterized by the gas phase being distributed as bubbles through the liquid phase. Occurs at relatively low liquid rates. b)Slug: A multiphase-fluid flow regime characterized by a series of liquid plugs (slugs) separated by a relatively large gas pockets. In vertical flow, the bubble is an axially symmetrical bullet shape that occupies almost the entire crosssectional area of the tubing. The resulting flow alternates between high-liquid and high-gas composition. c)Churn: A multiphase flow regime in near-vertical pipes in which large, irregular slugs of gas move up the center of the pipe, usually carrying droplets of oil or water with them. Most of the remaining oil or water flows up along the pipe walls. The flow is relatively chaotic, producing a frothy mixture. d)Annular: A multiphase flow regime in which the lighter fluid flows in the center of the pipe, and the heavier fluid is contained in a thin film on the pipe wall. The lighter fluid may be a mist or an emulsion. Annular flow occurs at high velocities of the lighter fluid, and is observed in both vertical and horizontal wells. 6)What are the effects of variables on multiphase horizontal flow? Ans. Effect of Variables

• • • • • • •

Pipe Diameter – Pressure loss (dP) decreases rapidly with increase in Pipe Diameter. Flow Rate – Higher flow rate increases dP GLR – Increased GLR increases friction, hence more dP, unlike to vertical flow. Viscosity – Viscous crude offers more problem in horizontal flow mode. Water Cut – Its effect is not pronounced. Slippage – Its effect is not pronounced. Kinetic Energy – For High flow rates & low density it is considered for computation.

7) What are the effects of variables on multiphase vertical flow? Ans. Effect of Variables • • • • • • • • Tubing Size – It has pronounced effect in deciding FBHP requirement.. Flow Rate – It establishes the required FBHP, which influences tubing size selection. GLR – Increase GLR reduces FBHP requirement, after a point reversal takes place. Density – Higher density increases dP. Viscosity – Higher viscosity increases dP. Water Cut – Higher watercut increases dP. Slippage – It is observed during unstable flow region. Kinetic Energy – For High velocity & low density it is considered for computation.

8)What is liquid hold up? Ans. Liquid hold up is defined as yL = VL/V where, yL is liquid holdup,fraction 3 VL is the volume of liquid phase in the pipe segment,ft 3 V is the volume of the pipe segment, ft 9)What are the different TPR models for multiphase flow wells? Ans. TPR models for multiphase flow is • Homogenous flow models-They treat multiphase as a homogeneous mixture and do not consider the effect of liquid hold up. They can handle three phase and four phase. • Separated flow models-They are given in the form of empirical correlations.The effect of liquid hold up and flow regime are considered.

WORKOVER OPERATIONS
1. When is a workover operation done? Is it scheduled as a timely operation or only done in case of a breakdown? 2. What is hydraulic workover in what conditions is it preferred? 3. Why is it that the amount of kill fluid required is proportional to the time required? 4. Explain a salt bridge. What are the main reasons for the condition? 5. What is drilling with tubing? Where is it used? 6. What is an Impression block and where is it used? What are the types? 7. What are the criteria for the selection of the kill fluid??

SUCKER ROD PUMP
1. What is sucker rod pump? Ans.- Sucker rod pump is a artificial lift system in which downhole plunger is moved up and down by a rod connected to an engine at the surface. The plunger movement displaces produced fluid into the tubing via a pump consisting of suitably arranged travelling and standing valves mounted in a pump barrel. 2. What is the effect of counter balance on SRP? Ans.- It reduces torque and horse power of prime movers. 3. Name any three problems which can be arises in SRP. Ans.- Gas locking, Sand problem, heavy Oil problems. 4. Name two types of valve present in sucker rod pump. Ans.- Travelling valve & Standing valve.

5. Which valve is open on each down stroke of pump? Ans.- Travelling valve 6. Which valve is open on each up stroke of pump? Ans.- Standing valve 7. What is gas locking? Ans.- When a barrel is completely filled with gas both the valve remains in closed position and This is known as gas locking. 8. Name the most widely used artificial lift system in onshore india? Ans.- Sucker Rod pump artificial lift system. 9. What is pump-off control. Ans.- The pump capacity will often be greater than the well inflow capacity – the pump motor must be stopped at regular intervals when the fluid level is reduced to a specified, minimum safety level above the pump. This is known as pump-off control 10. List up to 6 key features for sucker Rod Pumps. Ans. – The key features for sucker rod pumps are: The vast majority of wells produce at low rates (generally less than 100 bpd) and moderate depths.  Relatively cheap, so their use can be justified on such low rate wells  Rod pumps are mechanically simple to operate and easy to repair/maintain/replace.  Sensitive to gas and solids (wax/scale/sand) - Solids can cause wear as well as damage moving parts which then need to be replaced  Not suitable for (highly) deviated wells.  Obtrusive in urban locations. Equipment too heavy for offshore use.  Pump can be easily changed and performance monitored using relatively simple techniques.  Viscous oil can be pumped. Fill in the Blanks: 1. The low cost, mechanical simplicity and the ease with which efficient operation can be achieved makes rod pumps suitable for such low volume operations. pump get closed.

2. The connection between the surface pumping unit and the downhole pump is the polished rod and the sucker rods. 3. The polished rod moves up and down through a stuffing box mounted on top of the wellhead. 4. This stuffing box seals against the polished rod and prevents surface leaks of the liquids and gasses being produced by the well. 5. A standing valve is mounted at the bottom of the pump barrel while the travelling valve is installed at the top of the plunger. 6. The condition of the pump can be evaluated by measuring the load at the top of the polished rod as a function of its position i.e. as it moves up and down during the stroke length. 7. The pump rate (Q) is related to the volume displaced (V) by each pump stroke and the speed rate or number of strokes per minute (N). 8. In sucker rod pump, this maximum speed decreases as the length of the pump stroke increases. 9. Low pump speeds and large diameter plunges lead to the greatest energy efficiency, but also the largest equipment loads. 10. Free gas sucked into the pump will reduce the pump efficiency due to its compressible nature.