PE Petroleum flashcards

32 cards. Read the term and the definition here. The deck at the top of this page is optional.

Volumetric OOIP equation

N = 7758 * A * h * phi * (1 - Swi) / Boi, where A is drainage area in acres, h is net pay in feet and Boi is in res bbl/STB; 7758 converts acre-feet to barrels.

Radial steady-state flow equation

q = 0.00708 * k * h * (Pe - Pw) / (mu * Bo * [ln(re/rw) + s]) in STB/day, with permeability in mD, thickness in ft, viscosity in cp and pressures in psi.

Skin factor

A dimensionless pressure-loss term concentrated at the wellbore. Positive skin indicates damage, negative skin indicates stimulation, and it adds dp = 141.2*q*mu*B*s/(k*h) psi.

Gas p/Z material balance

Plotting p/Z against cumulative gas production gives a straight line whose extrapolation to p/Z = 0 equals original gas in place for a volumetric, normally pressured gas reservoir.

Mobility ratio

M = (krw/mu_w)/(kro/mu_o). Values below one indicate a favorable waterflood with a stable front; values above one promote viscous fingering and early water breakthrough.

Buckley-Leverett frontal advance

Distance travelled by a saturation is x = (q*t/(phi*A)) * (dfw/dSw). The tangent drawn from the initial saturation on the fractional-flow curve gives the breakthrough front saturation.

Arps exponential decline

q = qi*exp(-D*t). A semilog plot of rate versus time is a straight line and D = ln(qi/q)/t. It applies when the hyperbolic exponent b equals zero.

Arps hyperbolic decline

q = qi*(1 + b*Di*t)^(-1/b) with b between 0 and 1. The case b = 1 is harmonic decline and b = 0 is exponential; common for unconventional and solution-gas-drive wells.

Archie water saturation

Sw = [(a*Rw)/(phi^m*Rt)]^(1/n). For clean sandstones a is about 1, the cementation exponent m about 2 and the saturation exponent n about 2.

Volumetric waterflood recovery factor

RF = (1 - Swi - Sor)/(1 - Swi). It assumes piston-like displacement with no areal or vertical losses, so actual recovery is lower after sweep efficiencies are applied.

Real gas pseudopressure

m(p) = 2 times the integral of p/(mu*Z) dp from a reference pressure to p. It linearizes the gas flow equation when viscosity and Z vary strongly with pressure.

Hydrostatic pressure equation

p (psi) = 0.052 * mud weight (ppg) * true vertical depth (ft). The 0.052 factor converts the ppg-and-feet product directly into pounds per square inch.

Equivalent circulating density

ECD = (hydrostatic pressure + annular friction loss)/(0.052 * TVD). It represents the effective mud weight the formation sees while the mud is being circulated.

Kill mud weight

KMW = current mud weight + SIDPP/(0.052 * TVD). Shut-in drillpipe pressure sets the kill weight, while slow-circulating pressure sets the initial circulating pressure.

Leak-off test

A low-rate test conducted below the casing shoe. Fracture gradient equals (surface leak-off pressure + hydrostatic pressure)/TVD and defines the upper bound of the mud weight window.

Dogleg severity

DLS = 100 * (angle change in degrees)/(course length in ft), reported in degrees per 100 ft. It governs torque and drag, casing wear and drillstring fatigue.

Casing design loads

Burst arises from internal pressure, collapse from external hydrostatic pressure and tension from string weight. Commonly used minimum design factors are approximately 1.1, 1.125 and 1.8 respectively.

Cement plug bump pressure

Additional pressure, typically 500 to 1000 psi, applied after displacement to land the top plug on the float collar and confirm the plugs and float valves held.

Bit hydraulic horsepower

HHP = (bit pressure drop * flow rate)/1714, with pressure in psi and rate in gpm. Total nozzle flow area is sized to maximize horsepower or jet impact at the bit.

Annular velocity

AV (ft/min) = 24.5 * Q/(Dh^2 - Dp^2), with Q in gpm and hole and pipe diameters in inches. It must exceed cuttings slip velocity for effective hole cleaning.

Mud weight window

The safe density range bounded below by formation pore pressure and above by fracture gradient. Leaving the window causes either a kick or lost circulation.

Kick tolerance

The maximum influx volume, expressed as an equivalent mud weight at the casing shoe, that can be circulated out without fracturing the weakest exposed formation.

Vogel inflow performance

q/qmax = 1 - 0.2*(Pwf/Pr) - 0.8*(Pwf/Pr)^2. It predicts inflow performance for solution-gas-drive wells producing below the bubble point pressure.

Productivity index

J = q/(Pr - Pwf) in STB/day/psi. For radial flow J = 0.00708*k*h/(mu*B*[ln(re/rw) - 0.75 + s]); it forecasts rate at a given flowing pressure.

Souders-Brown separator sizing

v_max = K*sqrt((rho_liquid - rho_gas)/rho_gas). The empirical K depends on vessel type and mist eliminator, and the equation sets separator gas capacity and diameter.

Separator liquid retention time

Liquid volume held between the inlet and the oil weir is set by residence time, typically 1-3 minutes for two-phase and 3-5 minutes for three-phase separators.

API RP 14E erosional velocity

Ve = C/sqrt(rho_mixture), with C about 100 for continuous service and higher for intermittent clean service. It caps line velocity to limit erosion by produced solids.

Choked choke flow

For gas, when flowing wellhead pressure divided by upstream pressure drops below roughly 0.55, flow is critical and the rate depends only on choke size, not downstream pressure.

Beam pump displacement

PD (bbl/day) = 0.1166 * D^2 * S * N, with plunger diameter and stroke in inches and N in strokes per minute; volumetric efficiency reduces the actual produced volume.

Water cut

WC = qw/(qw + qo). Total liquid rate equals oil rate divided by (1 - WC), which sizes surface facilities and drives emulsion-treating requirements.

TEG gas dehydration

Triethylene glycol absorbs water from natural gas, reaching about 7 lb H2O/MMscf pipeline specification. Glycol is regenerated in a reboiler held below about 204 C to avoid degradation.

Nodal analysis operating point

The intersection of the inflow performance relationship and the tubing outflow performance curve. It defines the stable producing rate and bottomhole flowing pressure for the well system.