Glossary

Terms are in alphabetical order. Units are given in Field first, then Metric, as Converge shows them. Pressures are absolute unless a term says otherwise.

#A

Absolute open flow (AOF): the rate a well would deliver at a bottomhole flowing pressure of zero. Nobody produces a well at AOF; you use it to compare wells and to bound the rate axis of an inflow curve. See Well performance.

Al-Marhoun: a black-oil correlation set for bubble point, solution GOR and Bo, one of the five oil sets in Black-oil PVT.

API gravity: stock-tank oil density on the American Petroleum Institute scale, °API = 141.5 / SG − 131.5, with SG the specific gravity at 60 °F relative to water. Water is 10 °API; lighter oils have higher values.

Aquifer model: a model of the water influx (We) into a reservoir as pressure falls. Converge offers Schilthuis (steady state), Fetkovich (pseudo-steady state), van Everdingen-Hurst (unsteady state) and Carter-Tracy (an approximation to van Everdingen-Hurst that needs no superposition). See Material balance.

Arps decline: the empirical rate-time relation q = qi / (1 + b·Di·t)^(1/b). The exponent b sets the shape: b = 0 is exponential, b = 1 is harmonic, and 0 < b < 1 is hyperbolic. A b above 1 usually reflects transient flow and needs a terminal decline to give a finite EUR. Converge holds Di in 1/day. See Decline & RTA.

#B

Bg (gas formation volume factor): reservoir volume of gas per unit volume at standard conditions, in rb/scf (m³/Sm³). For a real gas, Bg = 0.005035·Z·T / p rb/scf, with T in °R and p in psia.

Binary interaction parameter (BIP, kij): a correction to the attraction term of a cubic equation of state for each pair of components. BIPs between methane and the heavy pseudo-components most affect saturation pressure; Converge uses Chueh-Prausnitz for those by default.

Black-oil model: a fluid description with two surface components, stock-tank oil and surface gas, whose properties (Bo, Rs, Bg, viscosity) depend on pressure only. It suits most oils and dry gases; volatile oils and condensates need Rv as well, or a compositional model.

Bo (oil formation volume factor): reservoir barrels of oil, with its dissolved gas, per stock-tank barrel, in rb/STB (m³/Sm³). Bo rises with pressure up to the bubble point as gas dissolves, then falls slightly above it as the liquid compresses.

Bootstrap: a resampling method that refits a model many times on perturbed data to build an uncertainty range. Decline uses it for P90/P50/P10 EUR.

Bubble point (pb): the pressure at which the first gas bubble leaves an oil at reservoir temperature, in psia (bara). Above pb the oil is undersaturated; below it, free gas forms in the reservoir.

Bw: water formation volume factor, in rb/STB (m³/Sm³). Close to 1.0; Converge calculates it with McCain's correlation from pressure, temperature and salinity.

#C

C7+ (plus fraction): the lumped heavy end of a lab composition, reported with a molecular weight and specific gravity. Characterisation splits it into single carbon numbers (Converge uses a gamma distribution) and lumps them into a few pseudo-components with estimated critical properties. See Compositional PVT.

CCE (constant composition expansion): a lab test that expands a fixed mass of fluid in steps at reservoir temperature with no material removed. It gives the saturation pressure, relative volume V/Vsat and, for a condensate, liquid dropout.

CIT (company income tax): the corporate tax on assessable profit. The Nigeria PIA 2021 templates apply 30 %, with hydrocarbon tax not deductible. See Economics.

Contingent resources: in SPE-PRMS, recoverable volumes from known accumulations that are not yet commercial, reported as 1C/2C/3C (incremental C1/C2/C3). See Reserves.

Cricondenbar, cricondentherm: the highest pressure and the highest temperature on a phase envelope at which two phases can coexist.

Critical point: the pressure and temperature on a phase envelope where the bubble-point and dew-point curves meet and the liquid and vapour become identical.

CVD (constant volume depletion): a lab test for gas condensates and volatile oils. At each pressure step below the dew point, gas is removed to return the cell to its original volume. It gives liquid dropout, produced-gas composition and Z-factor as the reservoir depletes.

#D

Derivative (pressure derivative): the Bourdet derivative, dΔp / d ln(Δt), plotted with Δp on log-log axes in well-test analysis. Its shape identifies flow regimes: a unit slope for wellbore storage, a flat line for infinite-acting radial flow, a half slope for linear flow. See Well test.

Dew point: the pressure at which the first liquid drop forms from a gas at a given temperature. A retrograde condensate has an upper and a lower dew point at the same temperature.

Differential liberation (DL): a lab test that drops an oil's pressure in steps below the bubble point and removes the liberated gas at each step. Its Bo and Rs are relative to residual oil, so Converge corrects them to a separator basis (McCain 1990) before comparing them with flash-basis values.

Drive indices: the fractions of production supported by each mechanism (oil and solution-gas expansion, gas-cap expansion, water influx, rock and water compressibility). They sum to 1 in a consistent material balance.

#E

Economic limit: the rate below which a well or field loses money on operating cost, in STB/d (Sm³/d). Decline forecasts and reserves stop there.

EOS (equation of state): an equation that relates pressure, temperature and molar volume for a mixture. Converge uses cubic equations of state (Peng-Robinson, SRK) for flash, saturation pressures, phase envelopes and lab-test simulation.

EUR (estimated ultimate recovery): cumulative production to date plus the forecast to the economic limit, terminal decline or time cap, in MMSTB (MSm³) or Bscf (MSm³).

#F

Floating seat: a module licence that belongs to the company, not a person. Opening a module takes a free seat; closing it, or 3 minutes without a browser check-in, gives it back. See Licences and seats.

Flowing material balance (FMB): a rate-transient method that plots normalised rate (q/Δp) against normalised cumulative production for a well in boundary-dominated flow. Extrapolating the line to zero rate gives the in-place volume the well drains.

#G

Gauge pressure (psig, barg): pressure measured relative to the local atmosphere. Absolute pressure = gauge + atmospheric, about 14.7 psi (1.013 bar) at sea level. Converge stores and calculates in absolute pressure.

GOR (gas-oil ratio): surface gas per stock-tank barrel, in scf/STB (Sm³/Sm³). Producing GOR is measured at the separator; solution GOR is Rs.

#H

Havlena-Odeh: a rearrangement of the material balance equation into a straight line, F = N·Et + We, with F the underground withdrawal and Et the total expansion per unit of oil in place. A straight line with the right intercept confirms the drive mechanism and gives N.

Horner plot: build-up pressure against log((tp + Δt)/Δt). The semi-log slope m in psi/cycle gives permeability-thickness from kh = 162.6·q·B·μ / m (Field units). MDH (Miller-Dyes-Hutchinson) plots against log Δt instead.

Hydrocarbon tax: under Nigeria PIA 2021, a tax on crude-oil profit from onshore and shallow-water acreage: 30 % for petroleum mining leases and 15 % for petroleum prospecting licences. It does not apply to gas.

#I

IOIP / OGIP: initial oil in place, in MMSTB (MSm³), and original gas in place, in Bscf (MSm³). Material balance estimates them from pressure and production; volumetrics estimate them from area, thickness, porosity and saturation.

IPR (inflow performance relationship): the rate a reservoir delivers into the wellbore against bottomhole flowing pressure. Converge offers constant PI, Vogel, Fetkovich, Jones, Darcy with skin, gas back-pressure, and horizontal and fractured well models.

IRR (internal rate of return): the discount rate at which NPV is zero, in % per year.

#L

LBC viscosity: the Lohrenz-Bray-Clark (1964) method for oil and gas viscosity from an EOS composition and density. Its density-polynomial coefficients are a common tuning parameter.

Lumping: combining components or single carbon numbers into fewer pseudo-components to cut run time while keeping the phase behaviour.

#M

Material balance: a zero-dimensional tank model that balances produced volumes against fluid and rock expansion plus water influx. It estimates in-place volumes, drive mechanism and aquifer strength without a grid. See Material balance.

MMP (minimum miscibility pressure): the lowest pressure at which an injected gas and a reservoir oil become miscible through multiple contacts, in psia (bara).

Monte Carlo: repeated random sampling of uncertain inputs to produce a distribution of results, used in Economics and the Integrated forecast.

#N

Nodal analysis: the method that finds a well's operating point where the inflow curve (IPR) meets the outflow curve (VLP) at a chosen node, usually the bottomhole.

NPV (net present value): the sum of each period's net cash flow discounted to today, NPV = Σ CFt / (1 + i)^t, in $MM. NPV10 uses a 10 % per year discount rate.

#P

P90 / P50 / P10: probabilistic estimates in the petroleum convention. P90 has a 90 % chance of being met or exceeded (low case), P50 is the median, and P10 has a 10 % chance (high case).

p/Z plot: average reservoir pressure divided by Z-factor against cumulative gas. A volumetric gas reservoir gives a straight line whose zero intercept is OGIP; upward bending suggests water drive.

Peng-Robinson (PR, PR78): a cubic equation of state. PR78 changes the κ term for components with an acentric factor above 0.49, so heavy components behave better. Converge offers PR 1976 and PR 1978.

PI (productivity index, J): rate per unit drawdown, J = q / (p̄r − pwf), in STB/d/psi (Sm³/d/bar).

PIA: Nigeria's Petroleum Industry Act 2021. Economics includes PIA fiscal templates (royalty by production and price, hydrocarbon tax, CIT, levies, production allowance, PSC terms) as screening values, not tax advice.

Project fluid: the one fluid every module in a project reads. You choose it on the PVT page, from the black-oil model or a compositional model. See Project fluid.

PRMS (SPE-PRMS): the Petroleum Resources Management System, 2018 edition. Reserves are Proved, Probable and Possible, reported cumulatively as 1P, 2P and 3P or incrementally as P1, P2 and P3. See Reserves.

PSC (production sharing contract): a fiscal regime in which the contractor recovers costs from a capped share of production (cost oil) and splits the rest (profit oil) with the state.

psia: pounds per square inch absolute, measured from a vacuum. Field-unit pressures in Converge are psia; Metric pressures are bara.

PTA (pressure-transient analysis): interpreting pressure changes during a well test, usually a build-up or drawdown, to estimate permeability, skin, storage and boundaries. See Well test.

PVTO / PVDG / PVTG / PVTW: black-oil keyword tables for simulators. PVTO holds live oil (Rs, pressure, Bo, viscosity, with undersaturated branches). PVDG holds dry gas (pressure, Bg, viscosity). PVTG holds wet gas with Rv. PVTW holds water (reference pressure, Bw, compressibility, viscosity).

#R

Recovery factor: recovered volume divided by in-place volume, as a fraction or %. Use cumulative production for current recovery and EUR for ultimate recovery.

Royalty: the state's share of production or revenue, taken before costs. Under PIA 2021 the oil royalty depends on terrain, production rate and price.

RSVD / RVVD: simulator initialisation tables of Rs against depth and Rv against depth.

Rs (solution gas-oil ratio): gas dissolved in oil at reservoir conditions per stock-tank barrel, in scf/STB (Sm³/Sm³). Rs is constant above the bubble point and falls below it.

RTA (rate-transient analysis): analysing production rates and flowing pressures, rather than shut-in tests, to estimate permeability, skin, drainage area and in-place volume. Converge offers type-curve matching, linear-flow analysis and flowing material balance. See Decline & RTA.

Rv (vaporised oil-gas ratio): condensate carried in the reservoir gas per unit of surface gas, usually quoted in STB/MMscf. It is the gas-phase counterpart of Rs, needed for wet gas and condensate.

#S

Sample field: a read-only project shared by every account, with one consistent fluid, tank, wells and fiscal terms across every module. Make a copy turns it into an editable project. See Sample field and tutorials.

Separator test: a lab test that flashes reservoir oil through one or more separator stages to stock-tank conditions. It gives the stock-tank GOR, oil gravity and the Bo at the bubble point used to correct DL data.

Skin (S): a dimensionless measure of extra pressure drop near the wellbore. Positive skin means damage; negative skin means stimulation, such as a fracture or acid job.

SRK: the Soave-Redlich-Kwong (1972) cubic equation of state, offered alongside Peng-Robinson.

#T

Terminal decline: the minimum annual decline rate a hyperbolic forecast switches to, so the forecast becomes exponential and EUR stays finite.

Tuning (regression): adjusting EOS or correlation parameters within bounds to match lab measurements. See Fluid tuning.

Type curve: a dimensionless reference curve for a flow model. You match your data to it to read reservoir properties.

Typical value: a default input marked with a badge until you replace it with your own number. Results that depend on typical values are screening results.

#V

VLP (vertical lift performance): the bottomhole pressure a well needs to lift a given rate to a set wellhead pressure, from a multiphase flow correlation such as Hagedorn-Brown, Beggs-Brill, Gray or Duns-Ros. Lift curves, or VFP tables, tabulate VLP for simulators.

Volume shift: a constant per component (Peneloux) subtracted from the EOS molar volume to correct liquid density. It does not change the phase equilibrium.

#W

Wellbore storage: the effect of the wellbore volume on a well test, so the sandface rate lags the surface rate. The coefficient C is in bbl/psi (m³/bar). It shows as a unit slope on both Δp and the derivative at early time.

Wichert-Aziz: a correction to gas pseudo-critical properties for CO2 and H2S, applied before the Z-factor is calculated.

#Z

Z-factor (gas compressibility factor): the ratio of a real gas's volume to the ideal-gas volume at the same pressure and temperature, Z = pV / nRT. Black-oil PVT calculates it from Sutton pseudo-criticals and Dranchuk-Abou-Kassem.