Oil and Gas Well Drilling Technology: Rigs, Drilling Fluids, Bits, Strings, Casing and Cementing, Drilling Problems, and Directional and Advanced Drilling

Well planning starts from the target and works back to the surface: the geological objective and its location fix the trajectory; the predicted pore-pressure and fracture-gradient profiles fix the mud-weight window at every depth and hence the casing setting depths; the casing programme fixes the hole sizes, the bits, the drilling fluid and the cement; and the whole is costed against a time-depth curve. Cable-tool (percussion) drilling, which lifts and drops a heavy bit on a wire rope and bails out the cuttings, is of historical interest only. Modern wells are drilled by rotary drilling: a rotating bit on a string of pipe, with drilling fluid pumped down the pipe and up the annulus to carry cuttings and control formation pressure.

A rotary rig is five systems. The power system (diesel engines driving generators, or grid power) feeds everything else. The hoisting system — derrick or mast, drawworks, crown block, travelling block, hook and drilling line — raises and lowers the string; with n lines strung between the blocks and a block-and-tackle efficiency E, the fast-line tension is F = W/(nE) for hook load W, and the dead line carries W/n. The rotating system turns the string, either by a rotary table and kelly or, on modern rigs, by a top drive that can rotate while tripping and drill with full stands. The circulating system — mud pumps, standpipe, rotary hose, string, bit nozzles, annulus, return line, mud-treatment equipment and pits — moves the drilling fluid. The well-control system — the blowout preventer (BOP) stack of annular and ram preventers, the choke and kill lines and the choke manifold — closes the well when formation fluid enters it.

A drilling fluid must: control formation pressure by its hydrostatic head; carry cuttings to the surface and suspend them when circulation stops; cool and lubricate the bit and string; build a thin, low-permeability filter cake that stabilises the wall and limits invasion; transmit hydraulic power to the bit nozzles and downhole motors; and carry the signal of mud-pulse telemetry — all without damaging the pay zone or corroding the string. Water-based muds (bentonite, polymer, inhibitive salt muds) are cheapest; oil-based and synthetic-based muds inhibit reactive shale, lubricate and resist high temperature, at a higher cost and environmental burden; air, mist and foam are used where very low bottom-hole pressure is wanted.

The properties measured on every tour: density (mud weight, by the mud balance), from which the hydrostatic pressure is P = 0.052 × MW × TVD; rheology by the rotational (Fann) viscometer, read at 600 and 300 rpm and interpreted by the Bingham-plastic model — plastic viscosity PV = θ₆₀₀ − θ₃₀₀ in cP, yield point YP = θ₃₀₀ − PV in lb/100 ft², apparent viscosity AV = θ₆₀₀/2 in cP — plus the 10-second and 10-minute gel strengths that measure the fluid’s ability to suspend cuttings at rest; the API filtrate and cake thickness from the low-pressure filter press; sand content, solids content by retort, pH and alkalinity, and for inhibitive muds the chloride and calcium concentrations. Barite (specific gravity about 4.2) is the standard weighting material.

While circulating, the bottom-hole pressure exceeds the static head by the frictional pressure loss in the annulus, and that total is expressed as an equivalent circulating density, ECD = MW + ΔP_annulus/(0.052 × TVD). ECD, not static mud weight, is what must stay below the fracture gradient while drilling. Solids-control equipment removes drilled solids in order of decreasing size: shale shakers (screens), then hydrocyclone desanders and desilters, mud cleaners (a desilter over a fine screen, which saves barite), and decanting centrifuges for the finest solids; a vacuum degasser removes entrained gas before the mud reaches the pumps.

Roller-cone bits crush and gouge rock with teeth on rotating cones: long milled steel teeth for soft formations, shorter tungsten-carbide inserts (TCI) for medium to hard ones. Fixed-cutter bits have no moving parts: PDC (polycrystalline diamond compact) bits shear rock and dominate soft-to-medium-hard, non-abrasive intervals at high rates of penetration; natural-diamond and impregnated bits grind very hard, abrasive rock slowly and are often run on turbines or high-speed motors. Bit selection follows formation hardness and abrasiveness, and dull grading of pulled bits (the IADC system) feeds back into the next selection.

The drill string is drill pipe in tension above a bottom-hole assembly (BHA) of heavy-weight drill pipe, drill collars, stabilisers, jars, and the MWD/LWD tools and motor. Weight on bit is applied by the collars, not the pipe: the string is designed so that the neutral point (where axial stress changes from compression to tension) lies within the collars, because drill pipe buckles and fatigues in compression. In mud the string weighs less by the buoyancy factor BF = 1 − MW/65.5 (65.5 ppg being the density of steel), so the collar length for a given weight on bit is WOB × safety factor/(BF × collar weight per foot). Drill pipe is selected for tension (with a margin of overpull for getting unstuck), torsion, collapse and burst, and graded by steel grade (E, X, G, S).

Casing is run and cemented to isolate formations, protect fresh-water aquifers, give the BOP a pressure-tight anchor and let the next section be drilled with a heavier mud. The strings, from the surface down: conductor (prevents washout of the unconsolidated surface layer and carries returns), surface casing (protects aquifers; the BOP is installed on it), intermediate casing (isolates troublesome zones — lost circulation, abnormal pressure, salt), and production casing or a liner (a string hung from the previous casing rather than run to surface). Each string is designed for burst (internal pressure exceeding external, worst at the top when the well is full of gas), collapse (external exceeding internal, worst at the bottom when the casing is evacuated) and tension (its own buoyed weight, worst at the top), with design factors applied to each. Setting depths are chosen from the pore-pressure and fracture-gradient plot: a string must be set before the mud weight needed to control the deeper pore pressure would fracture the shallower open hole.

Primary cementing fills the annulus between casing and hole to support the casing, isolate zones hydraulically and protect the casing from corrosive formation fluids. Oil-well cements are Portland cements graded by API class; Classes G and H are the basic well cements, used over a wide range of depths and temperatures with additives: accelerators (calcium chloride) and retarders (lignosulphonates) set the thickening time; extenders (bentonite, pozzolan, microspheres) lower density and cost; weighting agents (barite, hematite) raise density; fluid-loss additives and dispersants control filtrate and rheology. The thickening time must exceed the pumping time with a safety margin, and the slurry density must sit inside the mud-weight window.

The two-plug method is the standard job. The casing is run with a guide or float shoe at the bottom, a float collar one or two joints above it (the space between catches contaminated cement) and centralisers to keep it off the wall so that cement surrounds it evenly. After circulating to condition the mud, a spacer is pumped, then the bottom plug (which wipes mud off the casing wall ahead of the cement and ruptures at the float collar), then the slurry, then the top plug, displaced with mud or water until it bumps on the float collar with a pressure rise. The job is followed by waiting on cement (WOC) and evaluated by a cement bond log. Remedial work uses squeeze cementing (forcing slurry into perforations, channels or leaks) and plug cementing (a balanced plug to abandon, sidetrack or cure lost circulation). Slurry volume is the annular capacity × length, where the capacity of an annulus in bbl/ft is (D_hole² − D_casing²)/1029.4 with diameters in inches.

Kicks and blowouts. A kick is an influx of formation fluid because the bottom-hole pressure has fallen below the pore pressure — from too light a mud, failing to keep the hole full while tripping, swabbing, or lost circulation. Its warning signs are a drilling break, an increase in return flow or pit volume, flow with the pumps off, and a change in pump pressure. The well is shut in on the BOP and the stabilised shut-in drill-pipe pressure (SIDPP) and shut-in casing pressure (SICP) are read. SIDPP measures the underbalance directly, because the drill pipe is full of known mud, so the kill mud weight is KMW = OMW + SIDPP/(0.052 × TVD). SICP exceeds SIDPP when the influx in the annulus is lighter than mud. The kick is circulated out at constant bottom-hole pressure by the driller’s method (two circulations: first remove the influx with the old mud, then circulate kill mud) or the wait-and-weight (engineer’s) method (one circulation with kill mud, lower casing pressures).

• Lost circulation — mud escaping into fractured, vugular or highly permeable formations, or into fractures the mud itself has induced. Remedies: lower the mud weight or ECD, pump lost-circulation material (fibrous, flaky, granular), cement or gunk plugs, and in the worst case set casing.
• Differential sticking — a stationary string pressed into the filter cake of a permeable zone by the overbalance; the force to free it is about μ × ΔP × contact area. Prevented by keeping the string moving, minimising overbalance and using a thin, slick cake; freed by spotting a pipe-releasing fluid, jarring, or reducing hydrostatic pressure.
• Mechanical sticking and hole instability — key seats in doglegs, undergauge hole, packing off by cuttings, and shale that swells (water-sensitive clays) or collapses (too little mud weight for the rock stress). Remedies: inhibitive or oil-based mud, correct mud weight, reaming and good hole cleaning.
• Hole deviation, bit balling, fishing and sour gas — unwanted inclination in dipping beds (controlled by pendulum or packed BHAs), clay balling on PDC cutters, retrieving lost equipment with overshots and spears, and H₂S, which demands sour-service steels and gas detection.

A directional well is kicked off from vertical and built to an inclination and azimuth. The deflection tools are the whipstock (a steel wedge that turns the bit), jetting (washing a pocket with one enlarged nozzle in soft rock), the positive-displacement mud motor with a bent sub or bent housing (the workhorse: oriented, it slides to build or turn; rotated, it drills straight), and the rotary steerable system (RSS), which steers while the whole string rotates, giving better hole cleaning, less friction and a smoother hole. Trajectories are described as build-and-hold (J), build-hold-drop (S) and horizontal; the radius of a build section is R = 5729.58/BUR ft for a build rate BUR in degrees per 100 ft.

A directional survey measures inclination and azimuth at stations along the measured depth — by magnetic single- and multi-shot instruments, by gyroscopic tools where casing or nearby wells disturb the magnetic field, and continuously by MWD while drilling. Position is computed between stations by the tangential, balanced-tangential, average-angle, radius-of-curvature or minimum-curvature method; minimum curvature, which fits a circular arc through each pair of stations, is the industry standard and the most accurate of these, while the simple tangential method is the least accurate. The dogleg angle β between two stations comes from cos β = cos I₁ cos I₂ + sin I₁ sin I₂ cos(A₂ − A₁), and dogleg severity is β per 100 ft.