Drilling engineering

In short

Drilling engineering is the design and execution of a borehole from surface to a target reservoir: selecting the rig, bits and drill string, designing the hydraulics, the casing scheme and the well programme, controlling formation pressure, steering the hole to a geological target, and doing all of it at the lowest safe cost per metre. It is the highest-capital activity in upstream oil and gas — an onshore rig day costs several lakh rupees and an offshore day crore-scale — so every design choice is also an economic one. In Indian universities it is a core paper in B.Tech Petroleum Engineering (IIT(ISM) Dhanbad, PDEU Gandhinagar, UPES, MIT Manipal, Anna University) and a large share of the GATE PE syllabus (Oilwell drilling, Petroleum production). Interviewers at ONGC, Oil India, Vedanta Cairn, Reliance E&P, Halliburton, Schlumberger, Baker Hughes, Weatherford, Jindal Drilling, Deep Industries and Aban Offshore probe it in every technical round, usually starting with hydrostatic pressure and a kill sheet. This note covers the engineering of the hole itself; mud chemistry and completion equipment are separate topics.

Explained

The rotary drilling rig and its five systems

• Rotary drilling cuts rock with a rotating bit loaded by the weight of drill collars, while fluid circulated down the pipe and up the annulus removes cuttings and controls pressure. It replaced cable-tool percussion drilling because it can hold back formation pressure continuously.
• Hoisting system: derrick/mast, crown block, travelling block, hook, drawworks, drilling line (wire rope), deadline anchor with a weight indicator. Raises and lowers the string; a trip is tripping out/in.
• Rotating system: either rotary table + kelly + swivel (older rigs) or a top drive (motor on the travelling block). A top drive drills with 27 m stands instead of 9 m singles, can rotate while tripping to free a stuck string, and is standard on new ONGC rigs.
• Circulating system: mud pumps (triplex, single-acting), standpipe, rotary hose, string, bit nozzles, annulus, flowline, shale shakers, desander/desilter, degasser, centrifuge, mud tanks.
• Well-control system: BOP stack, choke and kill lines, choke manifold, accumulator (Koomey) unit, mud-gas separator, trip tank.
• Power system: diesel engines driving either mechanical compounds (old) or AC/DC generators — diesel-electric SCR or AC-VFD rigs dominate now.
• Rig classification by hook load/depth capacity (e.g. 1,000 HP ≈ 3,000 m, 2,000 HP ≈ 6,000 m). Offshore: jack-up (shallow water, legs on seabed), semi-submersible and drillship (deep water, dynamic positioning, marine riser and subsea BOP), and fixed platform rigs. ONGC drills Mumbai High from jack-ups and uses deep-water drillships off the KG basin.
• Crew and hierarchy: driller, assistant driller, derrickman, floormen (roughnecks), roustabouts, mud engineer, mud logger, directional driller, company man (drilling supervisor), toolpusher, drilling engineer.

Drill string, bits and the bottom-hole assembly

• Drill string (top to bottom): kelly/top-drive saver sub → drill pipe → heavy-weight drill pipe (HWDP) → drill collars → bit. Drill pipe is in tension; collars are in compression and supply weight on bit (WOB).
• Drill pipe is specified by OD, nominal weight (lb/ft), grade (E-75, X-95, G-105, S-135 — the number is minimum yield in ksi), range (R2 ≈ 9.1 m) and tool-joint connection, per API Spec 5DP / 7-1. Classified New, Premium, Class 2 by wall loss.
• Neutral point is where axial stress changes sign; design keeps it inside the collars, normally using only 80–85% of the buoyed collar weight as WOB so the pipe never buckles.
• BHA components: stabilisers (control hole deviation), reamers, shock sub, jars (impact to free stuck pipe), bit sub, float sub, MWD collar, mud motor or rotary steerable system.
• Bit types:
  1. Drag / fixed-cutter bits — PDC (polycrystalline diamond compact) cutters shear the rock; now the workhorse in soft to medium-hard formations, long life, high ROP. Impregnated/diamond and TSP bits for very hard abrasive rock.
  2. Roller-cone bits — three cones with milled steel teeth (soft rock) or tungsten-carbide inserts (TCI) for hard rock; they crush and gouge. Bearings: roller/ball, journal (friction) with sealed lubrication.
  3. Core bits for coring; hole openers and bi-centre bits for enlarging.
• IADC codes classify bits: roller cone by a 3-digit + letter code (series/type/bearing-seal + features), fixed cutter by a 4-character code (cutter material, body material, profile, cutter size/density).
• Bit nomenclature and wear: jet nozzles sized in 1/32 in; dull grading by the IADC 8-character system (inner/outer tooth wear, dull characteristic, location, bearings, gauge, other, reason pulled). Reasons to pull: bit wear (BHA), ROP drop, hole problem, TD.
• Bit selection uses offset-well records, formation drillability, cost per metre and specific energy, not catalogue preference.

Drilling hydraulics, ROP and energy

• Functions of circulation: lift cuttings, cool and clean the bit, transmit hydraulic power to the bit, hold back formation pressure, suspend cuttings when static.
• Pressure losses around the circuit: surface equipment + inside pipe + inside collars + across the bit + annulus losses. Standpipe pressure = sum of all. Only the bit loss does useful cleaning work — hydraulics design maximises it (typically 50–65% of pump pressure) subject to pump pressure and horsepower limits.
• Optimisation criteria: maximum bit hydraulic horsepower (HSI, hp per in² of hole, target ≈ 2.5–5), maximum jet impact force, or maximum nozzle velocity (≈ 80–120 m/s). Flow rate is also bounded below by hole cleaning and above by hole erosion and ECD.
• Hole cleaning: cuttings settle at a slip velocity; annular velocity must exceed it. Transport ratio = (AV − Vslip)/AV. In high-angle holes cuttings form beds on the low side — cured by high flow rate, pipe rotation, sweeps and good rheology, not by viscosity alone.
• ECD (equivalent circulating density) = static mud weight + annular friction (plus cuttings loading); it is the pressure the formation actually sees while circulating, and it is what fractures a weak shoe.
• Rate of penetration (ROP) rises with WOB and RPM up to a founder point (bit balling, poor cleaning), falls with increasing bit tooth wear, differential pressure (overbalance) and rock strength; cleaner bottom and lower overbalance both help. Classical models: Bourgoyne–Young (8 functions), Bingham, Maurer.
• Mechanical specific energy (MSE) is the energy to remove unit volume of rock; drilling at MSE close to rock strength means the system is efficient — rising MSE at constant ROP indicates vibration, dull bit or poor cleaning. Vibration modes: axial (bit bounce), lateral (whirl), torsional (stick-slip).

Pore pressure, casing design and cementing

• Pressure definitions: hydrostatic (normal gradient ≈ 0.0981 bar/m per unit SG; normal formation water ≈ 0.105 bar/m), abnormal/overpressure, subnormal. Overbalance = mud pressure − pore pressure. Overburden gradient ≈ 0.226 bar/m (1 psi/ft).
• Pore-pressure detection: seismic velocity before drilling; while drilling — drilling rate/d-exponent, torque and drag, cuttings size and shape, gas levels (background, connection, trip gas), flowline temperature, shale density; after drilling — resistivity, sonic, density logs, RFT/MDT and DST measurements.
• Fracture pressure from leak-off tests (LOT/FIT) at each shoe; the window between pore and fracture pressure narrows with depth and dictates the casing scheme.
• Casing-seat selection: work from the bottom up (or top down) placing each shoe where the mud needed below it will not fracture the shoe, including a kick-tolerance and trip margin.
• Casing string functions and names: conductor (supports surface, returns flow), surface casing (protects aquifers, anchors the BOP), intermediate (isolates problem/overpressure zones), production casing, liner (hung off, saves steel and wellhead space), tie-back.
• Casing design loads: burst (internal pressure, worst case gas kick or tubing leak), collapse (external pressure, worst case evacuation or cementing), axial tension (own weight, shock, overpull), plus biaxial/triaxial (von Mises) effects, buckling, corrosion and wear. Design factors typically ≈ 1.1 burst, 1.0–1.125 collapse, 1.6–1.8 tension — operator-specific.
• Casing specification per API Spec 5CT/ISO 11960: OD, weight, grade (H-40, J-55, K-55, N-80, L-80, C-90, T-95, P-110, Q-125), connection (API round/buttress, or premium gas-tight), range.
• Primary cementing bonds casing to formation, isolates zones and supports the string: shoe track with float collar/shoe, centralisers, bottom and top plugs, spacer, lead and tail slurry, displacement to the plug bump, then WOC (wait on cement). Classes A/G/H with accelerators, retarders, extenders, weighting agents and loss-control material. Verified by CBL/VDL and temperature logs; failures are repaired by squeeze cementing. (Equipment that goes in after the casing is set belongs to well completion.)

Well control: kicks, BOPs and kill methods

• A kick is an unplanned influx of formation fluid; uncontrolled it becomes a blowout. Immediate cause: bottom-hole pressure falls below pore pressure.
• Causes: insufficient mud weight; failure to fill the hole while tripping; swabbing (pulling too fast) and lost circulation; abnormally pressured zone drilled undetected; gas-cut mud; drilling into an adjacent well.
• Warning signs while drilling: drilling break, increase in ROP, torque and drag changes, cuttings volume, flowline temperature, chloride trend, gas increase. Positive indicators (kick in progress): pit gain, flow with pumps off, increase in return flow rate, drop in pump pressure with pump speed rising.
• Shut-in procedure (hard or soft shut-in): space out, stop rotation, pick up off bottom, stop pumps, close the annular/pipe ram, read SIDPP and SICP, record pit gain, notify.
• BOP stack (API 16A): annular (spherical/bag type — seals on any shape, strips over tool joints), pipe rams, variable-bore rams, blind-shear rams (cut the pipe and seal), drilling spool with choke/kill outlets, below-stack casing head. Controlled from the driller's panel and remote panel via a nitrogen-charged accumulator unit. Also: IBOP/float valve inside the string, rotating head, mud-gas separator and flare line. Stack rated 2,000–15,000 psi; tested at prescribed intervals.
• Kill methods (constant bottom-hole pressure principle — keep BHP slightly above pore pressure by manipulating the choke):
  1. Wait and weight (engineer's) — weight up the mud, then one circulation; lowest annulus and shoe pressures; needs waiting time.
  2. Driller's method — first circulation removes the influx with original mud, second circulation displaces kill mud; simple, two circulations, higher casing pressure for longer.
  3. Concurrent — weight up while circulating; needs careful bookkeeping.
  4. Volumetric/lubricate-and-bleed — when the string is off bottom or plugged. Bullheading — pump the influx back into the formation. Stripping/snubbing — run pipe back under pressure.
• MAASP (maximum allowable annular surface pressure) is set by the weakest point, usually the last casing shoe; exceeding it breaks down the shoe and risks an underground blowout.
• Pressure-control alternatives: MPD (managed pressure drilling) with a closed, rotating-control-device system for narrow windows; underbalanced drilling to protect the reservoir; air/foam/aerated drilling in hard-rock and lost-circulation areas.
• Indian practice: well control certification (IWCF/IADC WellSharp) is mandatory for supervisory drilling staff; kick drills and BOP drills are logged every tour.

Directional, horizontal and deviated drilling

• Why: multiple wells from one offshore platform or urban cluster pad; sidetrack past a fish or collapsed hole; reach under a town, river or forest; relief well for a blowout; horizontal section to maximise reservoir contact; fault and salt-dome avoidance; ERD (extended reach).
• Well profiles: build-and-hold (J), S-shape (build, hold, drop), deep-kick-off, horizontal (build to 90°), multilateral. Radius classes: long, medium, short.
• Deflection tools: whipstock, jetting bit (soft rock), positive displacement mud motor (PDM/Moineau) with a bent housing, turbodrill, and rotary steerable systems (RSS — push-the-bit or point-the-bit) which steer while rotating the whole string, giving smoother holes and better cleaning.
• Terms: KOP (kick-off point), build-up rate (°/30 m), tangent/hold section, drop-off, inclination, azimuth, MD, TVD, departure/horizontal displacement, vertical section, dogleg severity (DLS), toolface, closure, target circle.
• Surveying: MWD (measurement while drilling — inclination, azimuth, toolface, by accelerometers and magnetometers, transmitted by mud-pulse telemetry) plus gyro and wireline surveys; LWD adds resistivity, gamma, density, neutron, sonic for geosteering.
• Survey calculation methods: tangential (crude, over-estimates), balanced tangential, average angle, radius of curvature, and minimum curvature — the industry standard, which fits a circular arc between stations.
• Torque and drag rise with DLS and hole length; soft-string and stiff-string models predict them. Anti-collision analysis with ellipse-of-uncertainty separation factors is mandatory on crowded pads.

Drilling problems, costs and the Indian regulatory frame

• Stuck pipe: (a) differential sticking — pipe pressed into permeable filter cake by overbalance (cure: reduce overbalance, spot lubricant/oil pill, torque and jar); (b) mechanical/pack-off — cuttings beds, shale sloughing, keyseat, undergauge hole, ledges, cement blocks, junk; (c) wellbore geometry — dogleg, mobile salt creep.
• Fishing with overshot, spear, junk basket, magnet, washover pipe, and jars; if it fails, cut and sidetrack off a cement plug or whipstock.
• Lost circulation in natural fractures, vugs, high-permeability sands or induced fractures — cure with LCM, cement/gunk plugs, lowering ECD; total losses can precipitate a kick in another zone.
• Other hazards: well-bore instability, bit balling, twist-off and washout, shallow gas (diverter, not BOP), H₂S zones (sour service casing, SSR training), HPHT wells, hydrate formation in deepwater risers, casing wear.
• Drilling cost per metre is the decision metric for bit runs; rig day rate, bit cost, trip time and ROP all enter it. AFE (authorisation for expenditure) and the daily drilling report (DDR), IADC report form and time-depth (days-vs-depth) curve are the working documents.
• Indian framework: upstream policy and licensing (HELP/OALP) sit with MoPNG, with the Directorate General of Hydrocarbons (DGH) as technical regulator of E&P operations and well data; PNGRB regulates downstream/midstream pipelines and marketing, not drilling. Safety in oil mines is enforced by the DGMS, which administers the Oil Mines Regulations, 2017 (framed under the Mines Act, 1952); the Mines Act has been subsumed into the Occupational Safety, Health and Working Conditions Code, 2020, in force from 21 November 2025, with existing regulations continuing until replaced — check the current DGMS circulars before quoting a clause. OISD standards (under MoPNG) cover drilling-rig safety, well control, BOP testing and emergency response. Technical specifications generally follow API standards (5CT casing, 5DP/7-1 drill stem, 16A BOP, 13 series mud testing, RP 7G string design), with environmental clearance under the EIA Notification, 2006 and CPCB/SPCB consents for drill-site effluent and drill cuttings disposal.

Key points

• Rotary drilling - bit rotation plus WOB cuts rock; circulating fluid removes cuttings and balances formation pressure.
• Five rig systems - hoisting, rotating, circulating, well control, power; name them in this order in interviews.
• Drill collars - supply WOB in compression; drill pipe must stay in tension, so WOB ≤ 0.85 × buoyed collar weight.
• Buoyancy factor - BF = 1 − ρmud/ρsteel (ρsteel ≈ 7.85 g/cm³); buoyed weight = air weight × BF.
• PDC vs roller cone - PDC shears, no moving parts, high ROP in soft/medium rock; TCI roller cone crushes, better in hard abrasive or interbedded rock.
• Bit hydraulics - maximise bit pressure drop (50–65% of pump pressure), HSI ≈ 2.5–5 hp/in², nozzle velocity 80–120 m/s.
• ECD - static mud weight plus annular friction; it, not the static weight, fractures a shoe.
• Pore–fracture window - narrows with depth; it, plus kick tolerance, fixes the casing seats.
• Casing loads - burst, collapse, tension (plus triaxial); API 5CT grade number = minimum yield in ksi.
• Kick - influx when BHP < pore pressure; positive signs are pit gain and flow with pumps off.
• SIDPP - shut-in drill pipe pressure gives the true underbalance, because the string holds clean mud; use it to get kill mud weight.
• Kill principle - hold BHP constant slightly above pore pressure by choke control at a constant slow pump rate.
• Wait-and-weight vs driller's - one circulation and lower shoe pressure vs two circulations and no waiting.
• MAASP - maximum annular surface pressure the weakest shoe can take, from the LOT.
• Blind-shear ram - the last barrier: cuts the drill pipe and seals the bore.
• DLS - dogleg severity in °/30 m; drives torque, drag, casing wear and fatigue.
• Minimum curvature - standard survey calculation; tangential method is obsolete and over-estimates displacement.
• Differential sticking - caused by overbalance across permeable rock; pipe is stuck but circulation is usually free.
• Cost per metre - C = (rig rate × (rotating + trip + connection time) + bit cost)/metres drilled; the only fair way to compare bits.

Formulas and examples

Example 1 — Hook load, collars and derrick load. 3,000 m well: 2,800 m of 5 in, 29 lb/ft drill pipe (43.2 kg/m) and 200 m of 6½ in × 2¼ in collars (147 kg/m), mud 1.20 g/cm³, WOB 20 tf, block 25 t, 10 lines, E = 0.81.

• BF = 1 − 1.20/7.85 = 0.847.
• Air weight = 2,800 × 43.2 + 200 × 147 = 120,960 + 29,400 = 150,360 kg ≈ 150.4 t → buoyed = 150.4 × 0.847 = 127.4 t.
• Collar check: usable WOB = 200 × 147 × 0.847 × 0.85 = 21,160 kgf ≈ 21.2 tf > 20 tf, so the neutral point stays in the collars. Minimum collar length = 20,000/(147 × 0.847 × 0.85) = 189 m.
• Hook load = 127.4 − 20 + 25 = 132.4 t. Fast line = 132.4/(10 × 0.81) = 16.3 t. Derrick load = 132.4(1 + 0.1 + 0.1235) = 162.0 t.

Example 2 — Pump output, annular velocity and bottoms-up. Triplex pump, 6 in liner, 12 in stroke, ηv = 95%, 100 spm; hole 8½ in, pipe 5 in OD (ID 4.276 in), 3,000 m hole with 2,800 m pipe + 200 m collars (take 8½ × 5 in annulus throughout for an estimate).

• Per stroke = 3 × 0.7854 × (0.1524)² × 0.3048 × 0.95 = 3 × 0.7854 × 0.023226 × 0.3048 × 0.95 = 0.01585 m³ = 15.8 L.
• Q = 15.8 × 100 = 1,585 L/min ≈ 1.6 m³/min.
• Annular capacity = 0.7854 × (0.2159² − 0.127²) × 1000 = 0.7854 × (0.046613 − 0.016129) × 1000 = 23.9 L/m.
• AV = 1,585/23.9 = 66 m/min = 1.1 m/s — adequate for a near-vertical hole.
• Bottoms-up = 3,000 × 23.9/1,585 = 45.3 min.

Example 3 — Bit hydraulics. Take Q = 2,000 L/min (0.0333 m³/s), three 14/32 in nozzles, mud 1,200 kg/m³, 8½ in bit.

• Nozzle d = 0.4375 in = 11.11 mm; area each = 0.7854 × 11.11² = 96.9 mm²; total At = 290.8 mm² = 2.908 × 10⁻⁴ m².
• v = 0.0333/2.908 × 10⁻⁴ = 114.6 m/s (in range).
• Δpb = 1200 × 114.6²/(2 × 0.95²) = 1200 × 13,133/1.805 = 8.73 × 10⁶ Pa = 87.3 bar.
• Bit power = 8.73 × 10⁶ × 0.0333 = 291 kW = 390 hp; bit area = 0.7854 × 8.5² = 56.7 in² → HSI = 6.9 hp/in² — above the 2.5–5 target, so nozzles could be opened up to save pump pressure.

Example 4 — Kill sheet. TVD 3,000 m, mud 1.20 g/cm³, shoe at 2,000 m with LOT 1.65 g/cm³, SIDPP = 30 bar, SICP = 45 bar, slow-circulating-rate pressure at 40 spm = 25 bar.

• KMW = 1.20 + 30/(0.0981 × 3,000) = 1.20 + 30/294.3 = 1.302 ≈ 1.30 g/cm³.
• ICP = 25 + 30 = 55 bar; FCP = 25 × 1.302/1.20 = 27.1 bar.
• MAASP = (1.65 − 1.20) × 0.0981 × 2,000 = 88.3 bar — SICP of 45 bar is within it, so the well can be circulated out.
• With APL of 18 bar while circulating, ECD = 1.20 + 18/294.3 = 1.261 g/cm³.

Example 5 — Dogleg severity, radius and cost per metre. Station A: 15°/030°; station B: 24°/042°; course length 90 m.

• cos DL = cos 9° − sin15 sin24 (1 − cos12°) = 0.98769 − (0.2588 × 0.40674 × 0.02185) = 0.98769 − 0.0023 = 0.98539 → DL = 9.81°.
• DLS = 9.81 × 30/90 = 3.27°/30 m; R = 1718.9/3.27 = 526 m — a comfortable long-radius build.
• Bit run: rig rate ₹6,00,000/day = ₹25,000/h; rotating 60 h, tripping 8 h, connections 2 h; bit ₹8,00,000; 250 m drilled. C = (25,000 × 70 + 8,00,000)/250 = (17,50,000 + 8,00,000)/250 = ₹10,200 per metre. A ₹20,00,000 PDC that drills 500 m in 70 h gives (17,50,000 + 20,00,000)/500 = ₹7,500/m — better despite 2.5 times the bit price.

Where it is used

• Operators: ONGC and Oil India (Assam–Arakan, Cambay, Krishna–Godavari, Rajasthan, Mumbai Offshore), Vedanta Cairn (Barmer), Reliance–bp (KG-D6 deep water), GAIL and ONGC CBM/shale pilots — drilling engineers and well planners build the well programme, casing design, mud and bit plans and the AFE.
• Drilling contractors and rig crews: Jindal Drilling, Deep Industries, John Energy, Aban Offshore, Dolphin Offshore and global contractors — toolpusher, driller, rig mechanic/electrician, rig manager roles.
• Service companies: Halliburton, Schlumberger, Baker Hughes, Weatherford and Indian service firms — directional drilling, MWD/LWD, bits, cementing, fishing, well control and MPD services.
• Adjacent industries using the same engineering: geothermal wells, CBM and shale, coal exploration boreholes (CMPDI), large-diameter water wells, HDD river crossings for pipelines, and tunnel/foundation grout holes.
• Regulatory, audit and training roles: DGH well-data review, DGMS oil-mines inspection, OISD safety audits, IWCF/WellSharp well-control instruction at ONGC's IDT Dehradun and institutes such as IIT(ISM), PDEU and UPES.
• Software and analysis: well-path and torque-drag modelling (Landmark COMPASS/WELLPLAN, Drillbench), real-time drilling optimisation and MSE dashboards, rig-automation engineering.

Interview questions

• Q: Why must the neutral point lie within the drill collars? A: Drill pipe buckles and fails in fatigue under compression; collars are thick-walled and designed for it, so WOB is taken from collar weight only — typically 80–85% of its buoyed value.
• Q: A well is shut in with SIDPP = 0 but SICP = 40 bar. What does that mean? A: The drill string is not communicating — a plugged bit or float valve, or the string is out of the hole; you cannot read true underbalance and must break circulation carefully or use volumetric control.
• Q: Why is kill mud weight calculated from SIDPP and not SICP? A: The string contains known, clean mud, so SIDPP reflects only the underbalance; the annulus contains influx of unknown density, so SICP is always higher and would over-weight the mud.
• Q: What is the difference between mud weight and ECD, and which one breaks a shoe? A: ECD is the static mud weight plus annular friction (and cuttings load) while circulating; ECD is the pressure the formation actually sees, so ECD breaks the shoe.
• Q: How do you recognise differential sticking as against a pack-off? A: In differential sticking circulation remains free while the string will not move and torque rises; in a pack-off circulating pressure rises sharply or returns are lost.
• Q: Why does ROP stop improving when you add more WOB? A: Beyond the founder point the bit cannot clean — cuttings re-grind, teeth bury in cuttings (bit balling) and vibration grows, so extra WOB only adds wear and MSE.
• Q: What does a blind-shear ram do and why is it the last resort? A: It shears the drill pipe and seals the bore completely; it destroys the string and usually the well's current configuration, so it is used only when other barriers have failed.
• Q: Which survey calculation method would you use and why? A: Minimum curvature — it fits a circular arc between stations and gives the least error; the tangential method assumes the whole course has the lower station's attitude and over-estimates displacement.
• Q: Why do we prefer a top drive over a rotary table on deviated wells? A: It allows drilling with 27 m stands, rotating while tripping (which frees cuttings beds and stuck pipe), instant torque control, and simpler mud-motor orientation.
• Q: Give the main criterion for choosing a casing seat. A: The shoe must be strong enough, after an LOT, to withstand the maximum mud weight and kick pressure that will be imposed while drilling the hole section below it, with kick tolerance and trip margin.
• Q: A kick is taken while tripping out with the bit at 1,000 m in a 3,000 m hole. What is the first action? A: Stop, set the string on slips with a full-opening safety valve or stab an IBOP, shut in, then plan to strip back to bottom — never circulate a kick with the bit high if it can be avoided.
• Q: What is MPD and when is it used in India? A: Managed pressure drilling uses a closed, pressurised returns system with a rotating control device to hold bottom-hole pressure within a narrow pore–fracture window — used in HPHT and depleted/narrow-margin wells such as deep KG basin and some Cambay sections.
• Q: Who regulates drilling safety in Indian onshore oilfields? A: DGMS enforces the Oil Mines Regulations, 2017 (an oil field is a "mine"), with OISD standards under MoPNG and DGH as the technical E&P regulator; the Mines Act has been subsumed into the OSH Code, 2020, in force from 21 November 2025.

Common mistakes

• Using measured depth instead of TVD in hydrostatic, kill-mud and MAASP calculations — the single commonest error in exams and on kill sheets.
• Forgetting the buoyancy factor, or applying it to the travelling block and WOB as well as to the string.
• Mixing units: g/cm³ with ppg, bar with psi, L/min with gpm, m with ft — always state the unit system before starting.
• Taking SICP as the measure of underbalance, or weighting up on it.
• Treating a rule of thumb as design: quoting "HSI must be 3" or "overbalance 200 psi" without checking pump limits, ECD and the pore–fracture window.
• Assuming higher mud viscosity alone cleans a high-angle hole — flow rate, pipe rotation and sweeps matter more than viscosity above about 50° inclination.
• Confusing diverter with BOP for shallow gas: at shallow depths you divert and pump water/mud, because shutting in would break down the formation.
• In survey problems, adding inclination changes as if they were dogleg, ignoring the azimuth term in the dogleg equation.
• Quoting a withdrawn code or a stale Act clause — check the current DGMS/OISD circular and the API edition before citing a number.

Related topics

Drilling fluids · Well completion · Formation evaluation and well logging · Reservoir engineering fundamentals · Well control and blowout prevention · Oil and gas well cementing · Offshore drilling structures and HSE in petroleum operations