Petroleum Production Operations: Completion, Workover, Formation Damage and Stimulation, Artificial Lift, Nodal Analysis, Surface Processing, Flow Assurance and Equipment

A producing well is capped by the wellhead (casing heads and spools that hang and seal each casing string, and the tubing head that hangs the tubing) and the Christmas tree of master valves, wing valve, swab valve and choke that controls flow at surface. Downhole, the production tubing carries the fluid; a packer seals the tubing-casing annulus so that the casing is protected from well pressure and corrosive fluid; a subsurface safety valve (SSSV), usually tubing-retrievable and held open by control-line pressure, closes automatically if surface control is lost; landing nipples accept wireline plugs and gauges, sliding sleeves open or close communication between tubing and annulus, and side-pocket mandrels hold gas-lift valves.

Completion techniques differ in how the reservoir meets the well. An open-hole completion leaves the pay uncased — maximum inflow, no zonal control, only for competent rock. A cased-and-perforated completion cements casing across the pay and opens it with shaped-charge perforating guns, giving selective zonal control; perforating underbalanced (wellbore pressure below reservoir pressure) cleans the perforation tunnels of crushed-zone debris at once. A liner completion hangs a short string across the pay. Sand control completions — gravel packs, frac packs, standalone screens — hold back formation sand in weak rock. Completions are single or multiple (dual completions produce two zones separately through two tubing strings), and intelligent completions add remotely operated downhole valves and gauges.

The common well production problems are sand production (erosion, fill, collapse), excessive water or gas (coning, channelling behind casing, early breakthrough), paraffin and asphaltene deposition, scale, corrosion, emulsions and liquid loading of gas wells. Well servicing is the routine work done without pulling the completion — wireline and slickline runs, coiled tubing (a continuous reel of tubing run under pressure for cleanouts, nitrogen lifts, acid placement and logging) and snubbing (jointed pipe forced into a live well). A workover is heavier: it kills the well and pulls or modifies the completion to repair casing, isolate water, recomplete to a new zone, change the lift method or sidetrack.

Workover and completion fluids must control pressure while doing the least possible harm to the pay, so they are solids-free clear brines whose density is chosen by salt: sodium and potassium chloride for light fluids, calcium chloride and calcium bromide for heavier ones, and zinc bromide blends for the heaviest. They are filtered to remove fine solids, and chosen to be compatible with the formation water (to avoid scale) and the clays (to avoid swelling). Formation damage is any reduction of near-wellbore permeability: fines migration, clay swelling, solids and filtrate invasion from mud and cement, emulsion and water blocks, wettability alteration, scale and organic deposits, and perforation crushed zones. It is quantified by the skin factor s, the extra dimensionless pressure drop at the well: a damaged well has s > 0, a stimulated one s < 0.

Stimulation removes or bypasses damage. Matrix acidizing injects acid below fracture pressure: in carbonates hydrochloric acid (typically 15% HCl) dissolves the rock and cuts conductive wormholes through the damaged zone; in sandstones the damage (clays, fines) is dissolved by mud acid, an HCl-HF blend, preceded by an HCl preflush that removes carbonates so that insoluble calcium fluoride does not precipitate, and followed by an overflush. Hydraulic fracturing pumps fluid above the fracture pressure to split the rock, then carries proppant (sand or ceramic) into the fracture to hold it open, creating a conductive path of half-length x_f. Its effectiveness is measured by the dimensionless fracture conductivity F_CD = k_f w/(k x_f); acid fracturing in carbonates etches the fracture faces unevenly instead of propping them.

A well flows naturally while reservoir pressure can lift the fluid column to the separator; when it cannot, artificial lift adds energy. Sucker-rod (beam) pumping: a surface pumping unit reciprocates a rod string that works a downhole plunger pump; theoretical displacement is PD = 0.1166 S_p N D² bbl/d, with plunger stroke S_p in inches, N strokes per minute and plunger diameter D in inches. Gas lift injects gas through valves in side-pocket mandrels to lighten the fluid gradient in the tubing (continuous) or to push slugs to surface (intermittent). The electrical submersible pump (ESP) is a multistage centrifugal pump driven by a downhole motor, for high rates. The progressing-cavity pump (PCP) suits viscous and sandy oil. Hydraulic (piston or jet) pumps use a power fluid; plunger lift unloads liquid from gas wells.

Production system analysis follows the fluid from the reservoir to the separator and treats every component as a pressure loss. The inflow performance relationship (IPR) links rate to bottom-hole flowing pressure: above the bubble point it is the straight line q = J(p̄ − p_wf); for a solution-gas-drive well below the bubble point, Vogel’s relation q/q_max = 1 − 0.2(p_wf/p̄) − 0.8(p_wf/p̄)² describes the curve that gas liberation produces. The tubing performance relationship (TPR, or vertical lift performance) gives the p_wf needed to lift each rate to the wellhead against hydrostatic head, friction and acceleration. Nodal analysis picks a node — usually the bottom of the tubing — and plots the pressure available from upstream (the IPR) against the pressure required downstream (the TPR); their intersection is the operating point, and changes to tubing size, choke, separator pressure, lift or stimulation are evaluated by how they move it. Production testing routes a well through a test separator to measure its oil, gas and water rates, gas-oil ratio and water cut, which feed allocation and the IPR.

Well streams are separated at the surface. Two-phase separators divide gas from liquid; three-phase separators also divide oil from free water. Separation happens by gravity settling, helped by inlet diverters, mist extractors and enough retention time for liquid to degas and for water droplets to fall out — retention time is simply liquid volume in the vessel divided by liquid flow rate. Stage separation at successively lower pressures recovers more stock-tank liquid than a single flash. Emulsions are broken by heat, chemicals (demulsifiers), electrostatic fields and time in heater-treaters and electrostatic treaters. Gas is dehydrated by glycol (triethylene glycol) absorption or solid desiccants to prevent hydrates and corrosion, sweetened by amine absorption to remove H₂S and CO₂, and conditioned for its dew point.

Crude is held in atmospheric storage tanks: fixed-roof tanks for low-volatility liquids, and floating-roof tanks, whose roof rides on the liquid surface and eliminates the vapour space, for volatile crude — cutting evaporation losses and the fire risk of a flammable vapour space. Oil and gas move by pipeline (the cheapest per barrel over land, with pumping or compressor stations), by tanker at sea and by road or rail for small volumes. Metering is the basis of sale and allocation: gas by orifice meters (differential pressure across a plate, flow ∝ √Δp), turbine, ultrasonic and Coriolis meters; oil by positive-displacement, turbine and Coriolis (direct mass-flow) meters, and at custody transfer by a LACT unit (lease automatic custody transfer) that meters, samples and checks the quality of oil entering a pipeline, calibrated against a meter prover.

When gas and liquid flow together the pressure gradient has three parts — elevation (hydrostatic, usually dominant in vertical wells), friction and acceleration — and depends on the flow pattern. In vertical upward flow, as the gas rate rises the patterns run bubble (dispersed small bubbles), slug (large Taylor bubbles separated by liquid slugs), churn (chaotic), annular (a gas core with a liquid film on the wall) and mist (droplets in gas). Because gas slips past liquid, the in-situ liquid fraction, the holdup H_L, exceeds the no-slip fraction, and it is the holdup that sets the mixture density of the hydrostatic term. Empirical and mechanistic correlations predict holdup and friction — Hagedorn-Brown for vertical wells and Beggs-Brill for inclined and horizontal lines are the classic names — and horizontal flowlines add stratified and wavy patterns and severe slugging at riser bases.

Separators, treaters and scrubbers are pressure vessels. For a thin-walled cylinder of diameter D and wall thickness t under internal pressure p, the hoop stress is σ_h = pD/(2t) and the longitudinal stress pD/(4t) — hoop is twice longitudinal, so the wall is sized for hoop stress and a cylindrical vessel splits lengthwise; a sphere carries pD/(4t) in every direction. Code design adds a corrosion allowance and a joint efficiency, and every vessel is protected by a pressure relief valve set at or below its maximum allowable working pressure. Shell-and-tube heat exchangers pass one fluid through a tube bundle and the other across it inside a shell, guided by baffles; the duty is Q = UA·ΔT_lm, with the log-mean temperature difference ΔT_lm = (ΔT₁ − ΔT₂)/ln(ΔT₁/ΔT₂), which is larger for counter-current than for co-current flow between the same terminal temperatures; fouling adds resistance and lowers U over time.

Pumps move liquid. Centrifugal pumps add head by impeller speed, deliver smooth flow that falls as head rises along the pump curve, and are chosen at their best-efficiency point; positive-displacement pumps (reciprocating, gear, screw) deliver nearly constant flow whatever the discharge pressure and must never be run against a closed valve without relief. Every pump needs the net positive suction head available (NPSH_A) to exceed the NPSH required by the pump, or the liquid flashes at the impeller eye and cavitation erodes it. Compressors move gas: reciprocating compressors for high ratios and modest flows, centrifugal compressors for large flows at moderate ratios, and screw compressors in between. Compression heats the gas, so a large overall ratio is split into stages with intercooling, and for minimum total work the stage ratios are equal: with n stages each has ratio r = (p_d/p_s)^(1/n). Centrifugal compressors must be kept away from surge, the unstable low-flow reversal at the left of the performance map.