Natural gas engineering

Petroleum Engineering (B.E./B.Tech) · Production · free study notes for exams, placements and interviews

In short

Natural gas engineering covers the physical behaviour of gas mixtures, the flow of gas from reservoir to wellhead to pipeline, and the processing that makes it saleable — dehydration, sweetening, NGL recovery and liquefaction. It matters because gas is compressible: density, viscosity and volume all change strongly with pressure, so gas flow equations use pressure-squared or pseudo-pressure rather than the single-phase liquid forms. In India it underpins ONGC's and Oil India's gas fields, the KG-D6 and Krishna-Godavari deepwater output, GAIL's trunk pipelines, city gas distribution (CGD) networks bid out by PNGRB, and the LNG terminals at Dahej, Hazira, Kochi, Dabhol, Ennore and Mundra. It is examined in GATE Petroleum (PE) under natural gas properties, deliverability and gas transport, in university Production/Gas Engineering papers, and in interviews for ONGC, OIL, GAIL, Reliance, Cairn (Vedanta), Shell, Halliburton and SLB.

Explained

Composition, classification and gas properties

Natural gas is mainly methane (typically 70–95 mol%) with ethane, propane, butanes, pentanes-plus, plus inerts: N₂, CO₂, H₂S, water vapour and sometimes helium.
Dry gas: little condensable heavier ends; wet gas: yields NGL on surface separation; condensate (retrograde) gas: drops liquid in the reservoir below dew point; associated gas: produced with oil; non-associated (free) gas: from a gas cap or gas reservoir.
Sour gas contains H₂S (and often CO₂) above pipeline limits; sweet gas does not. Lean/rich refers to heavier-hydrocarbon content.
Apparent molecular weight Ma = Σ yᵢMᵢ; specific gravity γg = Ma/28.97 (air = 28.97 g/mol). Typical dry gas γg ≈ 0.6–0.7.
Real gas law pV = ZnRT. The compressibility (deviation) factor Z is the ratio of actual to ideal volume; it falls below 1 at moderate pressure (attraction dominates), passes a minimum around 2,000–3,500 psia for typical gases, and rises above 1 at very high pressure.
Z from correlations: compute pseudo-critical properties from composition (Kay's rule: ppc = Σ yᵢpcᵢ, Tpc = Σ yᵢTcᵢ) or from γg by Standing/Sutton correlations; then pseudo-reduced ppr = p/ppc, Tpr = T/Tpc; read Z from the Standing–Katz chart or compute by Dranchuk–Abou-Kassem / Hall–Yarborough.
Wichert–Aziz correction adjusts pseudo-criticals for CO₂ and H₂S; without it Z is badly wrong for sour gas.
Gas density ρg = pMa/(ZRT). Gas viscosity μg rises with temperature at low pressure (opposite to liquids) and is read from Carr–Kobayashi–Burrows or Lee–Gonzalez–Eakin correlations; order 0.01–0.03 cP.
Gas formation volume factor Bg = Vres/Vsc; gas expansion factor E = 1/Bg (scf/ft³). Isothermal gas compressibility cg = (1/p) − (1/Z)(∂Z/∂p)T — far larger than oil or water compressibility, which is why gas reservoirs deplete by expansion.
Heating value: gross calorific value of Indian pipeline gas is roughly 8,500–9,500 kcal/SCM depending on composition; gas is sold in SCM/MMBtu (1 MMBtu ≈ 252,000 kcal ≈ 26.8 SCM of 9,400 kcal/SCM gas). Indian standard reference conditions for gas measurement are commonly 15 °C and 1.01325 bar — contracts and the metering standard govern, so always check the stated base conditions.

Gas flow in the reservoir and well deliverability

Combining Darcy's law, continuity and the real gas law for radial flow gives the gas diffusivity equation in terms of pseudo-pressure m(p) = 2∫ p dp/(μZ), which linearises the strong pressure dependence of μZ.
Three approximations:
1. p² (pressure-squared) method — valid at low pressure (below about 2,000 psia), where μZ ≈ constant.
2. p (pressure) method — valid at high pressure (above about 3,000 psia), where p/μZ ≈ constant.
3. m(p) pseudo-pressure method — valid at all pressures; the rigorous approach, and the one modern software uses.
Pseudo-steady state (stabilised) inflow, p² form: q = k h (p̄R² − pwf²) / [1,422 T μ̄ Z̄ (ln(0.472 rₑ/rw) + s + Dq)] in field units (q in Mscf/d).
Non-Darcy (turbulent) skin: the extra term Dq accounts for high velocity near the wellbore — significant in gas wells and absent in most oil IPR work. Total apparent skin s' = s + Dq.
Back-pressure (Rawlins–Schellhardt) equation: q = C (p̄R² − pwf²)ⁿ, with n between 0.5 (fully turbulent) and 1.0 (laminar). A log–log plot of (p̄R² − pwf²) against q gives a straight line of slope 1/n (equivalently, q against Δp² has slope n).
Forchheimer (LIT / Houpeurt) equation: p̄R² − pwf² = A q + B q², where A is the laminar and B the turbulent coefficient; plotting (Δp²)/q against q gives a straight line of slope B and intercept A.
AOF (Absolute Open Flow potential): the theoretical rate at pwf = atmospheric (often taken as 14.7 psia or 0) — the standard single number for gas well capacity.
Deliverability tests:
- Flow-after-flow (conventional back-pressure) test: several stabilised rates in sequence; needs long stabilisation, so it suits high-permeability wells.
- Isochronal test: equal flow periods, each followed by shut-in to near-initial pressure, plus one extended stabilised point — for low-permeability wells that will not stabilise.
- Modified isochronal test: equal flow AND equal (shorter) shut-in periods when even the shut-in cannot fully recover; uses the last shut-in pressure in place of p̄R.
Gas well transient testing: drawdown and buildup analysed on m(p) or p² against log t, giving k, s and p*; the Horner plot and Agarwal equivalent time apply as for oil.
Tubing flow: average temperature–average Z method gives the static column and flowing bottomhole pressure; Cullender–Smith integrates the energy equation stepwise and is the accurate hand method.
Static column: pws = pwh exp(0.01875 γg H / (T̄ Z̄)) with H in ft, T̄ in °R — the "flowing gradient" of a gas column is small, so gas wells hold high wellhead pressure.
Liquid loading: condensate or water accumulates when gas velocity falls below the Turner critical velocity; remedies are velocity strings, plunger lift, surfactants, intermittent production and wellhead compression. (Artificial lift mechanics belong to the production/lift topic.)

Gas reserves and reservoir performance

Volumetric GIIP G = 43,560 A h φ (1 − Sw) / Bgi (scf, with A in acres, h in ft, Bgi in ft³/scf).
Material balance for a volumetric (no water influx) dry gas reservoir: p/Z = (pi/Zi)(1 − Gp/G). The p/Z plot against cumulative production Gp is a straight line; extrapolating to p/Z = 0 gives G, and to abandonment p/Z gives recoverable gas. Recovery factors of 70–90% are common.
A p/Z plot that bends upward (flattens) indicates water influx or pressure support; a steeper-than-expected plot can indicate a smaller connected volume or interference from another well.
Geopressured gas reservoirs show a shallow early p/Z slope that later steepens, because rock compaction and water expansion give extra support early on; extrapolating the first straight line overestimates G.
Gas condensate reservoirs: below dew point, liquid drops out in the reservoir, causing condensate banking that reduces gas permeability near the well; remedies include pressure maintenance by gas cycling (reinjecting dry gas) and huff-and-puff.
Coal bed methane (CBM) gas is adsorbed on coal and desorbs as pressure falls — described by the Langmuir isotherm V = VL p/(pL + p); requires dewatering first, and production rises before it declines. India's CBM blocks are in Raniganj, Jharia, Bokaro and Sohagpur. Shale gas needs hydraulic fracturing and horizontal wells.

Gas transport: pipelines and compression

Flow of gas in a pipeline is described by the general flow equation derived from the mechanical energy balance with the real gas law, gravity (elevation) term and a friction factor.
Weymouth equation uses a diameter-based friction factor — suits short, small-diameter gathering lines; Panhandle A and B use Reynolds-number-based friction factors and suit long, large-diameter, high-Reynolds trunk lines. AGA / Colebrook–White forms are used for design accuracy.
Key dependences: q ∝ d^2.667 (Weymouth), d^2.618 (Panhandle A) or d^2.53 (Panhandle B) — diameter dominates capacity; q ∝ √(p1² − p2²) and q ∝ 1/√(L γg T Z).
Series, parallel and looped lines: an equivalent-length or equivalent-diameter calculation converts them to a single line; looping a line increases throughput without raising pressure.
Line pack is the gas inventory in the pipeline; it provides short-term buffer (useful for peak shaving) and is also why depressurising a trunk line loses saleable gas.
Compression: reciprocating compressors for high ratio and low volume; centrifugal for high volume (gas trunk lines, LNG plants). Stage pressure ratio is kept to about 3–4 and total ratio split as r_stage = (pd/ps)^1/N for N stages, with intercooling.
Compressor power (adiabatic, per stage) depends on ratio, k = Cp/Cv and flow; discharge temperature Td = Ts (pd/ps)^(k−1)/k must stay within material and lubricant limits (commonly below about 150 °C).
Erosional velocity limits pipe gas velocity, Ve = C/√ρ with C ≈ 100 (ft/s with ρ in lb/ft³) per API RP 14E; gathering lines are typically designed at 40–70% of it.
Indian gas pipelines are laid to API 5L line pipe and designed/operated under ASME B31.8 and the PNGRB (Technical Standards and Specifications including Safety Standards) Regulations for natural gas pipelines and for city gas distribution networks; OISD standards (for example OISD-STD-226 on natural gas transmission pipelines) are enforced by the Oil Industry Safety Directorate under the MoPNG. CGD service lines use PE pipe (IS 14885) below 7 bar with steel above it.

Gas conditioning and processing

Separation: two- or three-phase separators and slug catchers remove free liquids first. (Vessel sizing belongs to surface facilities.)
Hydrates: ice-like solids of water and light hydrocarbons that form at high pressure and low temperature (can form well above 0 °C), plugging chokes, flowlines and valves.
- Predicted by the Katz gravity charts, the Kvsi (vapour–solid equilibrium) method or software; the Hammerschmidt equation gives hydrate depression by an inhibitor.
- Prevention: dehydrate the gas; inject methanol or MEG; insulate or heat; keep operating conditions outside the hydrate envelope; use low-dosage hydrate inhibitors (kinetic/anti-agglomerant).
Dehydration (water removal):
- Glycol absorption (TEG) — contactor, flash tank, filters, reboiler and stripping still; typical dew-point depression 30–60 °C; stripping gas or DRIZO extends it.
- Solid desiccant (molecular sieve, silica gel, activated alumina) — needed for very low dew points, as ahead of liquefaction or cryogenic NGL recovery.
- Refrigeration with inhibitor injection and membranes for specific duties.
- Pipeline specification in India typically requires water content of the order of a few mg/SCM (contractual; check the gas sales agreement and PNGRB/GAIL specification).
Sweetening (acid gas removal):
- Amine absorption — MEA, DEA, MDEA, formulated/activated MDEA; MDEA can be selective for H₂S over CO₂.
- Physical solvents (Selexol, Rectisol) for high acid-gas partial pressure; hot potassium carbonate (Benfield); solid bed/scavengers (iron sponge, ZnO, triazine) for small H₂S loads; membranes for bulk CO₂.
- Recovered H₂S goes to a Claus sulphur recovery unit (thermal + catalytic stages) with tail-gas treating; elemental sulphur is sold.
- H₂S is acutely toxic (immediately dangerous to life at a few hundred ppm) and causes sulphide stress cracking — sour service materials follow NACE MR0175 / ISO 15156.
NGL recovery: refrigeration, lean-oil absorption, or turboexpander (cryogenic) plants; fractionation trains separate C2, C3, C4 and C5+ (deethaniser → depropaniser → debutaniser). Ethane and propane feed GAIL's Pata and the OPaL/Dahej petrochemical complexes; LPG is bottled.
Nitrogen rejection (cryogenic) and helium recovery where present. Mercury removal beds protect aluminium cryogenic exchangers.
LNG: gas cooled to about −162 °C at near-atmospheric pressure, shrinking volume about 600 times; processes are cascade, propane-precooled mixed refrigerant (C3MR) and mixed fluid cascade. Regasification terminals use seawater or ambient-air vaporisers. CNG is compressed to about 200–250 bar for vehicles (BIS/CMVR cylinder and dispensing standards apply); LPG is the C3/C4 liquid product.
Gas monetisation routes: pipeline sales, LNG, CNG/CGD, GTL, methanol, urea (fertiliser plants are India's largest anchor gas users), and power.

Indian regulation, pricing and practice

Upstream: the Oilfields (Regulation and Development) Act, 1948 with the Petroleum and Natural Gas Rules; the DGH (Directorate General of Hydrocarbons) supervises reservoir management and reserves reporting under PSC/RSC/HELP-OALP contracts.
Midstream/downstream: the PNGRB Act, 2006 created the Petroleum and Natural Gas Regulatory Board, which authorises natural gas pipelines and CGD networks, fixes transportation tariffs and compression charges, and regulates access.
Safety: PESO (Petroleum and Explosives Safety Organisation) for CNG/LPG installations and cylinders; OISD standards for upstream and pipelines; the four Labour Codes in force from 21 November 2025 now govern occupational safety and working conditions at these installations in place of the Factories Act and allied laws.
Pricing: APM/domestic gas from legacy ONGC-OIL fields is priced by a government-notified formula linked to a crude benchmark with a ceiling and floor; gas from difficult/deepwater fields and HELP blocks has marketing and pricing freedom subject to a ceiling. The formula and ceilings have been revised more than once — quote the current MoPNG notification rather than a number from memory.
GST: natural gas is currently outside GST (VAT/central sales tax applies), while services and equipment attract GST at the applicable slabs (5%/18%/40% since 22 September 2025). CNG and PNG taxation varies by state — verify before quoting.
Metering and measurement: orifice (ISO 5167 / AGA 3), turbine and ultrasonic (AGA 9) meters with flow computers; custody transfer requires pressure, temperature and composition (gas chromatograph) correction to base conditions.

Key points

Real gas law - pV = ZnRT; Z is the single correction that makes all gas engineering different from liquid engineering.
Z-factor - from Standing–Katz chart using ppr and Tpr, with Wichert–Aziz correction when CO₂ or H₂S is present.
Specific gravity - γg = Ma/28.97; dry natural gas is about 0.6–0.7, so gas columns are light and wellhead pressures high.
Gas compressibility cg - two to three orders of magnitude larger than oil's, giving gas reservoirs high recovery by simple depletion.
Bg - reservoir volume per standard volume; its reciprocal E is the expansion factor in scf/ft³.
Pseudo-pressure m(p) - the rigorous linearisation; p² form for low pressure, p form for high pressure.
Non-Darcy skin Dq - rate-dependent turbulent skin unique to high-velocity gas wells; makes apparent skin rise with rate.
Back-pressure equation - q = C(p̄R² − pwf²)ⁿ with 0.5 ≤ n ≤ 1; AOF is the value at pwf ≈ atmospheric.
Isochronal test - equal flow periods with intermediate shut-ins, for low-permeability wells that cannot stabilise; modified isochronal shortens the shut-ins too.
p/Z plot - straight line against Gp for a volumetric gas reservoir; curvature upward signals water influx.
Langmuir isotherm - describes adsorbed CBM gas; CBM production rises before it declines because dewatering must come first.
Weymouth vs Panhandle - Weymouth for short small lines, Panhandle for long large lines; capacity scales roughly with d^2.5–2.67.
Hydrates - water + light hydrocarbons, solid at high pressure and low temperature; prevented by dehydration, methanol/MEG, heat or insulation.
TEG dehydration - the workhorse for pipeline dew point; molecular sieve when very low dew points are needed (LNG, cryogenic NGL).
Amine sweetening - MDEA for selective H₂S removal, with a Claus unit recovering sulphur; sour service needs NACE MR0175 materials.
LNG - −162 °C, about 600:1 volume reduction; India's terminals include Dahej, Hazira, Kochi, Dabhol, Ennore and Mundra.
Regulators - DGH upstream, PNGRB for pipelines/CGD tariffs and authorisation, PESO for CNG/LPG, OISD for safety standards.

Formulas and examples

Apparent molecular weight: Ma = Σ yᵢ Mᵢ (g/mol); Specific gravity: γg = Ma / 28.97
Real gas law: pV = Z n R T; Density: ρg = p Ma / (Z R T)
Pseudo-reduced properties: ppr = p / ppc, Tpr = T / Tpc; Kay's rule: ppc = Σ yᵢ pcᵢ, Tpc = Σ yᵢ Tcᵢ
Gas FVF: Bg = (psc / Tsc)(Z T / p) (ft³/scf, field units ≈ 0.02827 Z T / p with T in °R, p in psia)
Compressibility: cg = (1/p) − (1/Z)(∂Z/∂p)_T (psi⁻¹)
Volumetric GIIP: G = 43,560 A h φ (1 − Sw) / Bgi (scf; A in acres, h in ft, Bgi in ft³/scf)
Material balance (volumetric dry gas): p/Z = (pi/Zi)(1 − Gp/G)
Pseudo-steady radial gas inflow (p² form): q = k h (p̄R² − pwf²) / [1,422 T μ̄ Z̄ (ln(0.472 rₑ/rw) + s + Dq)], q in Mscf/d
Back-pressure: q = C (p̄R² − pwf²)ⁿ; LIT: p̄R² − pwf² = A q + B q²
Static gas column: pws = pwh exp(0.01875 γg H / (T̄ Z̄)), H in ft, T̄ in °R
Weymouth: q ∝ (d^2.667 / √(γg T̄ L Z̄)) × √(p1² − p2²)
Hammerschmidt hydrate depression: ΔT = 2,335 W / (M (100 − W)), ΔT in °F, W = wt% inhibitor, M = molecular weight of inhibitor
Compressor stage ratio: r = (pd/ps)^1/N; Discharge temperature: Td = Ts (pd/ps)^(k−1)/k (absolute T)
Erosional velocity: Ve = C / √ρ (ft/s, ρ in lb/ft³, C ≈ 100)

Example 1 — Gas gravity, density and Bg A gas has composition C1 0.85, C2 0.08, C3 0.04, N2 0.03 (mole fractions). Reservoir at p = 3,000 psia, T = 180 °F, Z = 0.88.

Ma = 0.85(16.04) + 0.08(30.07) + 0.04(44.10) + 0.03(28.01) = 13.634 + 2.406 + 1.764 + 0.840 = 18.64 g/mol.
γg = 18.64/28.97 = 0.643.
T = 180 + 460 = 640 °R. Bg = 0.02827 × 0.88 × 640 / 3,000 = 15.925/3,000 = 0.00531 ft³/scf → E = 188 scf/ft³.
ρg = p Ma/(Z R T) = (3,000 × 18.64)/(0.88 × 10.73 × 640) = 55,920/6,043 = 9.25 lb/ft³.

Example 2 — GIIP and reserves from a p/Z plot A dry gas reservoir: A = 1,200 acres, h = 40 ft, φ = 0.18, Sw = 0.25, pi = 3,500 psia, Zi = 0.90, T = 200 °F (660 °R).

Bgi = 0.02827 × 0.90 × 660 / 3,500 = 16.792/3,500 = 0.004798 ft³/scf.
G = 43,560 × 1,200 × 40 × 0.18 × 0.75 / 0.004798 = (43,560 × 1,200 = 52,272,000; × 40 = 2.0909×10⁹; × 0.18 = 3.7636×10⁸; × 0.75 = 2.8227×10⁸) / 0.004798 = 5.88 × 10¹⁰ scf ≈ 58.8 Bscf.
pi/Zi = 3,500/0.90 = 3,888.9 psia. At abandonment p = 500 psia, Z = 0.97 → p/Z = 515.5.
Gp/G = 1 − 515.5/3,888.9 = 1 − 0.1326 = 0.8674 → recoverable = 0.8674 × 58.8 = 51.0 Bscf, recovery factor 86.7%.

Example 3 — AOF from a back-pressure test Shut-in reservoir pressure p̄R = 2,000 psia (p̄R² = 4.00×10⁶ psia²). Two stabilised points:

Test	pwf (psia)	pwf² (10⁶)	Δp² = p̄R² − pwf² (10⁶)	q (Mscf/d)
1	1,800	3.24	0.76	1,200
2	1,400	1.96	2.04	2,900

n = log(q2/q1)/log(Δp2²/Δp1²) = log(2.4167)/log(2.6842) = 0.38294/0.42889 = 0.893.
C = q1/(Δp1²)ⁿ = 1,200/(0.76×10⁶)^0.893. ln(0.76×10⁶) = 13.5412; ×0.893 = 12.0923 → (Δp1²)^0.893 = e^12.0923 = 1.7867×10⁵. C = 1,200/1.7867×10⁵ = 6.716×10⁻³ Mscf/d/psia^1.786.
AOF at pwf = 0: Δp² = 4.00×10⁶. ln(4.0×10⁶) = 15.2018; ×0.893 = 13.5752 → 7.8524×10⁵. AOF = 6.716×10⁻³ × 7.8524×10⁵ = 5,274 Mscf/d ≈ 5.27 MMscf/d.

Example 4 — Static bottomhole pressure of a shut-in gas well Gas well: pwh = 1,500 psia, depth H = 8,000 ft, γg = 0.65, average T̄ = 150 °F = 610 °R, Z̄ = 0.90.

Exponent = 0.01875 × 0.65 × 8,000 / (610 × 0.90) = 97.5/549 = 0.17760.
pws = 1,500 × e^0.17760 = 1,500 × 1.19435 = 1,792 psia.
Static gradient = (1,792 − 1,500)/8,000 = 0.0365 psi/ft — compare about 0.433 psi/ft for fresh water, which is why gas wells are produced on high wellhead pressure.

Example 5 — Hydrate inhibition with methanol A flowline operates at 8 °C while the hydrate formation temperature at line pressure is 17 °C. Water production is 2 m³/d. Methanol M = 32 g/mol.

Required depression ΔT = 9 °C = 9 × 1.8 = 16.2 °F.
Hammerschmidt: W = ΔT·M/(2,335 + ΔT·M) × 100 = (16.2 × 32)/(2,335 + 16.2 × 32) × 100 = 518.4/(2,853.4) × 100 = 18.2 wt% methanol in the aqueous phase.
Methanol into the water phase = 2,000 kg/d water × 18.2/(100 − 18.2) = 2,000 × 0.2225 = 445 kg/d (plus vapour-phase and condensate losses, typically adding 20–40%, so dose about 540–620 kg/d).

Comparison table — pipeline flow equations

Equation	Friction factor basis	Best suited to	q dependence on d
Weymouth	f from diameter alone	Short gathering lines, small d, high Re	d^2.667
Panhandle A	f from Reynolds number	Long lines, moderate Re	d^2.618 (exponent 2.6182)
Panhandle B	f weakly Re-dependent	Long, large-diameter trunk lines	d^2.53
AGA / Colebrook	Full partially/fully turbulent	Design-grade accuracy, any line	implicit

Comparison table — dehydration and sweetening choices

Duty	Process	Typical outcome
Pipeline water dew point	TEG glycol absorption	30–60 °C dew-point depression
Very low dew point (LNG, cryo NGL)	Molecular sieve (4A/3A)	Below −100 °C dew point, ppm-level water
Bulk CO₂ removal	MDEA / physical solvent / membrane	Pipeline CO₂ spec (often ≤ 2–4 mol%)
Selective H₂S removal	Activated MDEA + Claus unit	H₂S to low ppm, sulphur recovered
Small H₂S load	Iron sponge / triazine scavenger	Non-regenerable, low capex

Where it is used

Upstream gas production: ONGC (Bassein, Hazira, Tripura, KG basin), Oil India (Assam), Reliance–BP KG-D6, Vedanta Cairn and GSPC — reservoir and production engineers do deliverability tests, nodal analysis, liquid-loading and compression studies.
Gas processing plants: GAIL's Vijaipur, Vaghodia, Gandhar, Usar and Pata plants and ONGC's Hazira and Uran complexes — amine units, glycol/mol-sieve dehydration, turboexpander NGL recovery and fractionation; roles in process, rotating equipment and operations engineering.
Pipelines and CGD: GAIL's HVJ, DVPL, Dahej–Uran and the Urja Ganga line; CGD networks (IGL, MGL, Adani Total, Torrent, Gujarat Gas) under PNGRB authorisation — hydraulics, compressor/CNG station design, metering and integrity roles.
LNG terminals and shipping: Petronet LNG (Dahej, Kochi), Shell Hazira, Dabhol, Ennore, Mundra — regasification, boil-off gas handling, custody transfer and commercial scheduling.
Anchor gas consumers: urea/fertiliser plants, gas-based power stations, refineries and petrochemicals (OPaL, HMEL), steel DRI plants — gas supply contracting, MMBtu accounting and calorific-value reconciliation.
Service and consultancy: SLB, Halliburton, Baker Hughes, Weatherford (well testing, PVT, flow assurance), EIL and plant EPCs (process design), and software roles using PIPESIM, OLGA, HYSYS/Unisim, Prosper/GAP and Eclipse/CMG.

Interview questions

Q: Why do gas flow equations use pressure squared instead of pressure? A: Because gas density is proportional to pressure, the product μZ is roughly constant at low pressure, and integrating Darcy's law with the real gas law then yields a difference of pressure squares rather than a simple pressure drop.
Q: When would you use pseudo-pressure m(p) instead of p² or p? A: At intermediate pressures (roughly 2,000–3,000 psia) or over a wide pressure range, where neither μZ nor p/μZ is constant; m(p) is rigorous everywhere and is the default in software.
Q: What is non-Darcy skin and why does it matter in gas wells? A: The rate-dependent pressure loss Dq caused by high velocity (inertial/turbulent) flow near the wellbore; it makes apparent skin increase with rate, so a single-rate test overstates mechanical damage unless multiple rates separate s from D.
Q: Why is an isochronal test used rather than a flow-after-flow test? A: In low-permeability reservoirs flow periods never reach stabilisation; equal flow periods separated by shut-ins give a repeatable transient curve, and one extended stabilised point fixes the true deliverability line.
Q: What does an upward-curving p/Z plot tell you? A: That pressure is being supported — usually water influx, sometimes a connected aquifer or an adjacent compartment — so extrapolating the early straight line would overestimate recoverable gas.
Q: Why is Z sometimes greater than 1? A: At very high pressure molecular repulsion and finite molecular volume dominate over attraction, so the gas occupies more volume than the ideal law predicts.
Q: Why must Z be corrected for H₂S and CO₂? A: Acid gases shift the true critical properties, so uncorrected pseudo-criticals give wrong ppr and Tpr; the Wichert–Aziz correction adjusts them, and errors otherwise propagate into Bg, reserves and inflow.
Q: Can hydrates form above 0 °C? A: Yes — at high pressure hydrates are stable well above 0 °C (commonly 15–25 °C in gas pipelines), which is why dehydration or inhibitor injection, not just freeze protection, is required.
Q: Weymouth or Panhandle for a 48-inch, 400-km trunk line? A: Panhandle B, because its Reynolds-based friction factor suits large diameters and high Reynolds numbers; Weymouth would under-predict capacity there and is meant for short, small gathering lines.
Q: How does gas viscosity behave with temperature and why is that odd? A: It increases with temperature, because in a gas viscosity comes from momentum transfer by molecular motion, which intensifies with temperature — the opposite of liquids, where it comes from cohesive forces.
Q: What is condensate banking and how is it managed? A: Liquid dropping out below dew point near the wellbore reduces gas relative permeability and well productivity; it is managed by keeping reservoir pressure above dew point, gas cycling, hydraulic fracturing or huff-and-puff solvent injection.
Q: What is liquid loading and how do you detect it? A: Accumulation of water or condensate when gas velocity falls below the Turner critical velocity; signs are erratic/falling rate, rising casing-tubing pressure difference and a liquid level building up, confirmed by comparing actual velocity against the critical value.
Q: Who authorises a city gas distribution network in India and on what basis? A: PNGRB, under the PNGRB Act, 2006, through competitive CGD bidding rounds, with authorisation covering a geographical area, minimum work programme, exclusivity periods and regulated tariffs.

Common mistakes

Treating gas as incompressible — using the liquid Darcy/Hagen–Poiseuille or oil IPR forms, and dropping Z from density, Bg and pipeline calculations.
Using the p² equation at high reservoir pressure (or the p equation at low pressure) instead of m(p), then reporting the error as reservoir behaviour.
Mixing up pseudo-reduced and pseudo-critical properties, or forgetting the Wichert–Aziz correction for sour gas.
Forgetting to convert temperature to absolute (°R or K) in Bg, density, the static column and compressor discharge formulas.
Ignoring the non-Darcy term, so skin from a single-rate test is taken as formation damage and a stimulation job is recommended wrongly.
Reading the early straight part of a p/Z plot in a water-driven reservoir and quoting the extrapolated G as reserves.
Confusing hydrates with ice, and assuming dew-point control alone handles both water and heavy hydrocarbon dropout (hydrocarbon dew point needs separate control).
Quoting SCM/MMBtu numbers without stating base conditions and calorific value — contracts differ, and 15 °C versus 0 °C changes the volume by about 5%.