PEC EPE Petro-Gas cheat sheet

Steady-state radial oil flow in field units: q = 0.00708 k h (Pe − Pwf) / (μ B ln(re/rw)), with q in STB/day, k in mD, h in ft, and μ in cp.

Material balance for a volumetric oil reservoir with no water influx and no gas cap: N = Np Bt / (Bt − Bti), neglecting rock and water expansion.

Mobility ratio M = (krw/μw)/(kro/μo); M > 1 means water is more mobile than oil and tends to finger, reducing sweep efficiency.

Fractional flow of water without gravity or capillary effects: fw = 1 / [1 + (kro μw)/(krw μo)].

Exponential decline q = qi e^(−Dt); hyperbolic decline q = qi / (1 + b D t)^(1/b), where b = 0 is exponential and b = 1 is harmonic.

Productivity index J = q/(Pr − Pwf); pseudosteady-state radial flow gives J = 0.00708 k h / (μ B [ln(re/rw) − 0.75 + s]).

Buckley-Leverett frontal advance: the saturation front velocity equals (q/(φA)) times dfw/dSw.

Drive indices from rock/fluid expansion, solution gas, gas cap, and water influx sum to one when all voidage is accounted for.

Capillary pressure Pc = Pnw − Pw; drainage and imbibition hysteresis affect initial saturation and relative permeability.

Hydrostatic pressure in psi = 0.052 × mud weight in ppg × true vertical depth in ft; use TVD, not measured depth.

Equivalent circulating density ECD = MW + (annular pressure loss)/(0.052 × TVD), with annular pressure loss in psi and TVD in ft.

MAASP = formation fracture pressure at the shoe − current mud hydrostatic pressure at the shoe; recalculate after any mud weight change.

Kick indicators include pit gain, flow with pumps off, increasing ROP, gas-cut mud, and reduced pump pressure; confirm the influx before shutting in.

Driller's method circulates the kick out at constant mud weight in two circulations; wait-and-weight raises mud weight first and kills in one circulation.

Leak-off test records surface pressure at which the formation begins to take fluid; fracture gradient = (surface leak-off pressure + mud hydrostatic at shoe)/shoe TVD.

Dogleg severity in degrees per 100 ft = (dogleg angle in degrees × 100)/course length in ft; high DLS increases torque, drag, and casing wear.

Casing seat selection requires mud hydrostatic below fracture pressure at the shoe and above pore pressure in the next hole section.

Cement plug bump pressure is the surface pressure increase after the plug lands; it confirms displacement and can be used for shoe integrity testing.

Vogel IPR for solution-gas-drive oil wells: q/qmax = 1 − 0.2(Pwf/Pr) − 0.8(Pwf/Pr)^2.

Productivity index J = q/(Pr − Pwf); a straight-line IPR applies for undersaturated oil when Pwf exceeds bubble point pressure.

Gas well stabilized deliverability: q = C(Pr^2 − Pwf^2)^n, where n is typically between 0.5 and 1 and C is the deliverability coefficient.

Nodal analysis evaluates pressure drops from reservoir to separator; the selected node determines whether inflow or outflow controls the operating point.

Critical rate for water coning increases with vertical permeability and density contrast and decreases with oil viscosity and perforated interval length.

ESP performance is described by head-capacity, efficiency, and power curves; gas locking occurs when free gas enters the pump intake.

Gas lift injects gas to reduce the tubing fluid gradient; valve spacing and injection depth control unloading and production stability.

Choke flow: subcritical flow depends on downstream pressure, while critical gas flow is nearly independent of downstream pressure when Pdown/Pup is below about 0.55.

Skin factor s > 0 indicates damage, s < 0 indicates stimulation or a fracture, and ΔPskin = 141.2 q B μ s/(k h) in field units.

Real gas law PV = Z n R T; R = 10.73 psia·ft³/(lbmol·°R) in oilfield units.

Gas compressibility cg = (1/P) − (1/Z)(∂Z/∂P)_T; at low pressure cg approaches 1/P.

Standing-Katz chart estimates Z from reduced pressure Pr = P/Pc and reduced temperature Tr = T/Tc.

Sutton pseudocritical correlations: Ppc = 756.8 − 131.0 γg − 3.6 γg² psia and Tpc = 169.2 + 349.5 γg − 74.0 γg² °R.

Gas specific gravity γg = Mg/28.97; methane is about 0.55 and CO2 is about 1.52 relative to air.

Gas formation volume factor Bg = 0.02829 Z T/P ft³/scf with T in °R and P in psia.

Gas expansion factor E = 1/Bg = 35.37 P/(Z T) scf/ft³ with P in psia and T in °R.

Hydrates form at high pressure and low temperature when water and small gas molecules are present; methanol or MEG lowers the hydrate formation temperature.

Rawlins-Schellhardt backpressure equation qg = C(Pr² − Pwf²)^n; a log-log plot of q versus pressure-squared difference gives n and C.

TEG dehydration removes water vapor from natural gas; glycol regeneration must stay below the glycol degradation temperature, roughly 400°F (204°C).

Amine sweetening removes H2S and CO2; MDEA is selective for H2S and needs less regeneration energy than MEA.

Cryogenic turboexpander NGL recovery uses expansion to low temperature; the demethanizer produces methane overhead and NGL bottoms.

Gas pipeline capacity equations such as Weymouth and Panhandle A/B depend on diameter raised to about 2.5–2.7, pressure drop, temperature, and gas gravity.

MAOP is the maximum allowable operating pressure and is limited by pipe design pressure, class location, and hydrostatic test pressure.

Pigging removes liquids and inspects pipelines; smart pigs use magnetic flux leakage or ultrasonic testing to detect metal loss.

Compressor power rises with pressure ratio and flow; intercooling between stages reduces power and discharge temperature.

Two-phase flow regimes include stratified, slug, plug, annular, and dispersed bubble; slug flow causes pressure surges at receiving facilities.

Wobbe index W = heating value/√(gas specific gravity); it compares fuel gas interchangeability at the same pressure.

A working petroleum system requires source rock, reservoir, seal, trap, migration pathway, and correct timing.

The oil window is roughly 60–120°C (140–250°F); the gas window is roughly 150–200°C (300–390°F), depending on kerogen type and heating rate.

Kerogen types: I is sapropelic and oil-prone, II is marine mixed, III is humic and gas-prone, and IV is inert.

Seismic two-way travel time TWT = 2 × depth/velocity; depth conversion requires an interval velocity model.

AVO analysis uses amplitude variation with offset to detect gas sands; a Class III gas sand shows increasing amplitude with offset.

Sandstone porosity generally decreases with burial depth through compaction and cementation; permeability depends on pore-throat size, not porosity alone.

Structural traps include anticlines, fault blocks, and salt domes; stratigraphic traps include pinch-outs, reefs, and unconformities.

Sequence stratigraphy uses unconformities and flooding surfaces to correlate lowstand, transgressive, and highstand systems tracts.

Gravity and magnetic surveys map basin structure, while seismic reflection is the primary tool for trap definition.

Archie equation: Sw = [(a Rw)/(φ^m Rt)]^(1/n); a ≈ 1, m ≈ 2, and n ≈ 2 for clean water-wet sandstones.

Density porosity φD = (ρma − ρb)/(ρma − ρf); use ρma = 2.65 g/cm³ for quartz and 2.71 g/cm³ for calcite.

Neutron-density crossover occurs in gas-filled porosity because neutron porosity reads low and density porosity reads high.

Gamma ray shale volume Vsh = (GR − GRmin)/(GRmax − GRmin), optionally with nonlinear scaling.

Induction logs work in oil-based mud and nonconductive boreholes; laterologs require conductive mud.

The SP log detects permeable beds and formation water salinity through electrochemical and electrokinetic potentials.

NMR logs measure free fluid, bound fluid, and permeability; the T2 distribution reflects pore-size distribution.

A Pickett plot graphs log Rt against log φ; the water-bearing trend gives Rw and m, and points above the trend indicate hydrocarbon.

Cement bond logs use acoustic amplitude to evaluate cement-formation bond; low amplitude indicates a good bond and high amplitude indicates free pipe or poor bond.

NPV = Σ CFt/(1 + r)^t − initial investment; accept independent projects with NPV > 0.

IRR is the discount rate that makes NPV = 0; accept if IRR exceeds the hurdle rate, but IRR can mislead for nonconventional cash flows.

Expected monetary value EMV = Σ probability × outcome value; decision trees use EMV for sequential exploration and development choices.

P90 means a 90% probability that the value is equaled or exceeded; P10 means a 10% probability of being exceeded.

Payback period is the time to recover undiscounted investment; it ignores cash flow after payback and the time value of money.

WACC = (E/V)Re + (D/V)Rd(1 − tax); use it as the discount rate for projects of average risk.

A risk matrix plots probability against impact; risk tolerance and ALARP determine mitigation priority.

Net cash flow = revenue − royalties − operating costs − taxes − capital spending; depreciation is noncash but affects taxes.

Monte Carlo simulation samples input distributions to produce P10/P50/P90 outcomes; correlations among variables can change the result.

Risk = probability × severity; ALARP means reducing risk as low as reasonably practicable by balancing control cost and risk reduction.

Hierarchy of controls: elimination, substitution, engineering controls, administrative controls, then PPE; PPE is the last line of defense.

HAZOP uses guide words such as no, more, less, reverse, and as well as with process parameters to identify deviations and consequences.

A permit to work controls hot work, confined-space entry, and lockout/tagout; gas testing must precede entry.

H2S is toxic at low ppm; IDLH is 100 ppm, and concentrations above 700 ppm can cause rapid unconsciousness and death; use supplied-air breathing apparatus.

LOPA evaluates independent protection layers; mitigated frequency = initiating frequency × product of protection-layer probability of failure on demand.

Produced water is reinjected or treated before disposal; flaring is minimized, and spills require immediate containment and notification.

Professional ethics require disclosing conflicts of interest, protecting confidential data, reporting unsafe practices, and working only within competence.

Safety culture includes management commitment, blame-free reporting, and learning from near misses and incidents.

Steady-state radial oil flow in field units: q = 0.00708 k h (Pe − Pwf) / (μ B ln(re/rw)), with q in STB/day, k in mD, h in ft, and μ in cp.

Material balance for a volumetric oil reservoir with no water influx and no gas cap: N = Np Bt / (Bt − Bti), neglecting rock and water expansion.

Mobility ratio M = (krw/μw)/(kro/μo); M > 1 means water is more mobile than oil and tends to finger, reducing sweep efficiency.

Fractional flow of water without gravity or capillary effects: fw = 1 / [1 + (kro μw)/(krw μo)].

Exponential decline q = qi e^(−Dt); hyperbolic decline q = qi / (1 + b D t)^(1/b), where b = 0 is exponential and b = 1 is harmonic.

Productivity index J = q/(Pr − Pwf); pseudosteady-state radial flow gives J = 0.00708 k h / (μ B [ln(re/rw) − 0.75 + s]).

Buckley-Leverett frontal advance: the saturation front velocity equals (q/(φA)) times dfw/dSw.

Drive indices from rock/fluid expansion, solution gas, gas cap, and water influx sum to one when all voidage is accounted for.

Capillary pressure Pc = Pnw − Pw; drainage and imbibition hysteresis affect initial saturation and relative permeability.

Hydrostatic pressure in psi = 0.052 × mud weight in ppg × true vertical depth in ft; use TVD, not measured depth.

Equivalent circulating density ECD = MW + (annular pressure loss)/(0.052 × TVD), with annular pressure loss in psi and TVD in ft.

MAASP = formation fracture pressure at the shoe − current mud hydrostatic pressure at the shoe; recalculate after any mud weight change.

Kick indicators include pit gain, flow with pumps off, increasing ROP, gas-cut mud, and reduced pump pressure; confirm the influx before shutting in.

Driller's method circulates the kick out at constant mud weight in two circulations; wait-and-weight raises mud weight first and kills in one circulation.

Leak-off test records surface pressure at which the formation begins to take fluid; fracture gradient = (surface leak-off pressure + mud hydrostatic at shoe)/shoe TVD.

Dogleg severity in degrees per 100 ft = (dogleg angle in degrees × 100)/course length in ft; high DLS increases torque, drag, and casing wear.

Casing seat selection requires mud hydrostatic below fracture pressure at the shoe and above pore pressure in the next hole section.

Cement plug bump pressure is the surface pressure increase after the plug lands; it confirms displacement and can be used for shoe integrity testing.

Vogel IPR for solution-gas-drive oil wells: q/qmax = 1 − 0.2(Pwf/Pr) − 0.8(Pwf/Pr)^2.

Productivity index J = q/(Pr − Pwf); a straight-line IPR applies for undersaturated oil when Pwf exceeds bubble point pressure.

Gas well stabilized deliverability: q = C(Pr^2 − Pwf^2)^n, where n is typically between 0.5 and 1 and C is the deliverability coefficient.

Nodal analysis evaluates pressure drops from reservoir to separator; the selected node determines whether inflow or outflow controls the operating point.

Critical rate for water coning increases with vertical permeability and density contrast and decreases with oil viscosity and perforated interval length.

ESP performance is described by head-capacity, efficiency, and power curves; gas locking occurs when free gas enters the pump intake.

Gas lift injects gas to reduce the tubing fluid gradient; valve spacing and injection depth control unloading and production stability.

Choke flow: subcritical flow depends on downstream pressure, while critical gas flow is nearly independent of downstream pressure when Pdown/Pup is below about 0.55.

Skin factor s > 0 indicates damage, s < 0 indicates stimulation or a fracture, and ΔPskin = 141.2 q B μ s/(k h) in field units.

Real gas law PV = Z n R T; R = 10.73 psia·ft³/(lbmol·°R) in oilfield units.

Gas compressibility cg = (1/P) − (1/Z)(∂Z/∂P)_T; at low pressure cg approaches 1/P.

Standing-Katz chart estimates Z from reduced pressure Pr = P/Pc and reduced temperature Tr = T/Tc.

Sutton pseudocritical correlations: Ppc = 756.8 − 131.0 γg − 3.6 γg² psia and Tpc = 169.2 + 349.5 γg − 74.0 γg² °R.

Gas specific gravity γg = Mg/28.97; methane is about 0.55 and CO2 is about 1.52 relative to air.

Gas formation volume factor Bg = 0.02829 Z T/P ft³/scf with T in °R and P in psia.

Gas expansion factor E = 1/Bg = 35.37 P/(Z T) scf/ft³ with P in psia and T in °R.

Hydrates form at high pressure and low temperature when water and small gas molecules are present; methanol or MEG lowers the hydrate formation temperature.

Rawlins-Schellhardt backpressure equation qg = C(Pr² − Pwf²)^n; a log-log plot of q versus pressure-squared difference gives n and C.

TEG dehydration removes water vapor from natural gas; glycol regeneration must stay below the glycol degradation temperature, roughly 400°F (204°C).

Amine sweetening removes H2S and CO2; MDEA is selective for H2S and needs less regeneration energy than MEA.

Cryogenic turboexpander NGL recovery uses expansion to low temperature; the demethanizer produces methane overhead and NGL bottoms.

Gas pipeline capacity equations such as Weymouth and Panhandle A/B depend on diameter raised to about 2.5–2.7, pressure drop, temperature, and gas gravity.

MAOP is the maximum allowable operating pressure and is limited by pipe design pressure, class location, and hydrostatic test pressure.

Pigging removes liquids and inspects pipelines; smart pigs use magnetic flux leakage or ultrasonic testing to detect metal loss.

Compressor power rises with pressure ratio and flow; intercooling between stages reduces power and discharge temperature.

Two-phase flow regimes include stratified, slug, plug, annular, and dispersed bubble; slug flow causes pressure surges at receiving facilities.

Wobbe index W = heating value/√(gas specific gravity); it compares fuel gas interchangeability at the same pressure.

A working petroleum system requires source rock, reservoir, seal, trap, migration pathway, and correct timing.

The oil window is roughly 60–120°C (140–250°F); the gas window is roughly 150–200°C (300–390°F), depending on kerogen type and heating rate.

Kerogen types: I is sapropelic and oil-prone, II is marine mixed, III is humic and gas-prone, and IV is inert.

Seismic two-way travel time TWT = 2 × depth/velocity; depth conversion requires an interval velocity model.

AVO analysis uses amplitude variation with offset to detect gas sands; a Class III gas sand shows increasing amplitude with offset.

Sandstone porosity generally decreases with burial depth through compaction and cementation; permeability depends on pore-throat size, not porosity alone.

Structural traps include anticlines, fault blocks, and salt domes; stratigraphic traps include pinch-outs, reefs, and unconformities.

Sequence stratigraphy uses unconformities and flooding surfaces to correlate lowstand, transgressive, and highstand systems tracts.

Gravity and magnetic surveys map basin structure, while seismic reflection is the primary tool for trap definition.

Archie equation: Sw = [(a Rw)/(φ^m Rt)]^(1/n); a ≈ 1, m ≈ 2, and n ≈ 2 for clean water-wet sandstones.

Density porosity φD = (ρma − ρb)/(ρma − ρf); use ρma = 2.65 g/cm³ for quartz and 2.71 g/cm³ for calcite.

Neutron-density crossover occurs in gas-filled porosity because neutron porosity reads low and density porosity reads high.

Gamma ray shale volume Vsh = (GR − GRmin)/(GRmax − GRmin), optionally with nonlinear scaling.

Induction logs work in oil-based mud and nonconductive boreholes; laterologs require conductive mud.

The SP log detects permeable beds and formation water salinity through electrochemical and electrokinetic potentials.

NMR logs measure free fluid, bound fluid, and permeability; the T2 distribution reflects pore-size distribution.

A Pickett plot graphs log Rt against log φ; the water-bearing trend gives Rw and m, and points above the trend indicate hydrocarbon.

Cement bond logs use acoustic amplitude to evaluate cement-formation bond; low amplitude indicates a good bond and high amplitude indicates free pipe or poor bond.

NPV = Σ CFt/(1 + r)^t − initial investment; accept independent projects with NPV > 0.

IRR is the discount rate that makes NPV = 0; accept if IRR exceeds the hurdle rate, but IRR can mislead for nonconventional cash flows.

Expected monetary value EMV = Σ probability × outcome value; decision trees use EMV for sequential exploration and development choices.

P90 means a 90% probability that the value is equaled or exceeded; P10 means a 10% probability of being exceeded.

Payback period is the time to recover undiscounted investment; it ignores cash flow after payback and the time value of money.

WACC = (E/V)Re + (D/V)Rd(1 − tax); use it as the discount rate for projects of average risk.

A risk matrix plots probability against impact; risk tolerance and ALARP determine mitigation priority.

Net cash flow = revenue − royalties − operating costs − taxes − capital spending; depreciation is noncash but affects taxes.

Monte Carlo simulation samples input distributions to produce P10/P50/P90 outcomes; correlations among variables can change the result.

Risk = probability × severity; ALARP means reducing risk as low as reasonably practicable by balancing control cost and risk reduction.

Hierarchy of controls: elimination, substitution, engineering controls, administrative controls, then PPE; PPE is the last line of defense.

HAZOP uses guide words such as no, more, less, reverse, and as well as with process parameters to identify deviations and consequences.

A permit to work controls hot work, confined-space entry, and lockout/tagout; gas testing must precede entry.

H2S is toxic at low ppm; IDLH is 100 ppm, and concentrations above 700 ppm can cause rapid unconsciousness and death; use supplied-air breathing apparatus.

LOPA evaluates independent protection layers; mitigated frequency = initiating frequency × product of protection-layer probability of failure on demand.

Produced water is reinjected or treated before disposal; flaring is minimized, and spills require immediate containment and notification.

Professional ethics require disclosing conflicts of interest, protecting confidential data, reporting unsafe practices, and working only within competence.

Safety culture includes management commitment, blame-free reporting, and learning from near misses and incidents.

Steady-state radial oil flow in field units: q = 0.00708 k h (Pe − Pwf) / (μ B ln(re/rw)), with q in STB/day, k in mD, h in ft, and μ in cp.

Material balance for a volumetric oil reservoir with no water influx and no gas cap: N = Np Bt / (Bt − Bti), neglecting rock and water expansion.

Mobility ratio M = (krw/μw)/(kro/μo); M > 1 means water is more mobile than oil and tends to finger, reducing sweep efficiency.

Fractional flow of water without gravity or capillary effects: fw = 1 / [1 + (kro μw)/(krw μo)].

Exponential decline q = qi e^(−Dt); hyperbolic decline q = qi / (1 + b D t)^(1/b), where b = 0 is exponential and b = 1 is harmonic.

Productivity index J = q/(Pr − Pwf); pseudosteady-state radial flow gives J = 0.00708 k h / (μ B [ln(re/rw) − 0.75 + s]).

Buckley-Leverett frontal advance: the saturation front velocity equals (q/(φA)) times dfw/dSw.

Drive indices from rock/fluid expansion, solution gas, gas cap, and water influx sum to one when all voidage is accounted for.

Capillary pressure Pc = Pnw − Pw; drainage and imbibition hysteresis affect initial saturation and relative permeability.

Hydrostatic pressure in psi = 0.052 × mud weight in ppg × true vertical depth in ft; use TVD, not measured depth.

Equivalent circulating density ECD = MW + (annular pressure loss)/(0.052 × TVD), with annular pressure loss in psi and TVD in ft.

MAASP = formation fracture pressure at the shoe − current mud hydrostatic pressure at the shoe; recalculate after any mud weight change.

Kick indicators include pit gain, flow with pumps off, increasing ROP, gas-cut mud, and reduced pump pressure; confirm the influx before shutting in.

Driller's method circulates the kick out at constant mud weight in two circulations; wait-and-weight raises mud weight first and kills in one circulation.

Leak-off test records surface pressure at which the formation begins to take fluid; fracture gradient = (surface leak-off pressure + mud hydrostatic at shoe)/shoe TVD.

Dogleg severity in degrees per 100 ft = (dogleg angle in degrees × 100)/course length in ft; high DLS increases torque, drag, and casing wear.

Casing seat selection requires mud hydrostatic below fracture pressure at the shoe and above pore pressure in the next hole section.

Cement plug bump pressure is the surface pressure increase after the plug lands; it confirms displacement and can be used for shoe integrity testing.

Vogel IPR for solution-gas-drive oil wells: q/qmax = 1 − 0.2(Pwf/Pr) − 0.8(Pwf/Pr)^2.

Productivity index J = q/(Pr − Pwf); a straight-line IPR applies for undersaturated oil when Pwf exceeds bubble point pressure.

Gas well stabilized deliverability: q = C(Pr^2 − Pwf^2)^n, where n is typically between 0.5 and 1 and C is the deliverability coefficient.

Nodal analysis evaluates pressure drops from reservoir to separator; the selected node determines whether inflow or outflow controls the operating point.

Critical rate for water coning increases with vertical permeability and density contrast and decreases with oil viscosity and perforated interval length.

ESP performance is described by head-capacity, efficiency, and power curves; gas locking occurs when free gas enters the pump intake.

Gas lift injects gas to reduce the tubing fluid gradient; valve spacing and injection depth control unloading and production stability.

Choke flow: subcritical flow depends on downstream pressure, while critical gas flow is nearly independent of downstream pressure when Pdown/Pup is below about 0.55.

Skin factor s > 0 indicates damage, s < 0 indicates stimulation or a fracture, and ΔPskin = 141.2 q B μ s/(k h) in field units.

Real gas law PV = Z n R T; R = 10.73 psia·ft³/(lbmol·°R) in oilfield units.

Gas compressibility cg = (1/P) − (1/Z)(∂Z/∂P)_T; at low pressure cg approaches 1/P.

Standing-Katz chart estimates Z from reduced pressure Pr = P/Pc and reduced temperature Tr = T/Tc.

Sutton pseudocritical correlations: Ppc = 756.8 − 131.0 γg − 3.6 γg² psia and Tpc = 169.2 + 349.5 γg − 74.0 γg² °R.

Gas specific gravity γg = Mg/28.97; methane is about 0.55 and CO2 is about 1.52 relative to air.

Gas formation volume factor Bg = 0.02829 Z T/P ft³/scf with T in °R and P in psia.

Gas expansion factor E = 1/Bg = 35.37 P/(Z T) scf/ft³ with P in psia and T in °R.

Hydrates form at high pressure and low temperature when water and small gas molecules are present; methanol or MEG lowers the hydrate formation temperature.

Rawlins-Schellhardt backpressure equation qg = C(Pr² − Pwf²)^n; a log-log plot of q versus pressure-squared difference gives n and C.

TEG dehydration removes water vapor from natural gas; glycol regeneration must stay below the glycol degradation temperature, roughly 400°F (204°C).

Amine sweetening removes H2S and CO2; MDEA is selective for H2S and needs less regeneration energy than MEA.

Cryogenic turboexpander NGL recovery uses expansion to low temperature; the demethanizer produces methane overhead and NGL bottoms.

Gas pipeline capacity equations such as Weymouth and Panhandle A/B depend on diameter raised to about 2.5–2.7, pressure drop, temperature, and gas gravity.

MAOP is the maximum allowable operating pressure and is limited by pipe design pressure, class location, and hydrostatic test pressure.

Pigging removes liquids and inspects pipelines; smart pigs use magnetic flux leakage or ultrasonic testing to detect metal loss.

Compressor power rises with pressure ratio and flow; intercooling between stages reduces power and discharge temperature.

Two-phase flow regimes include stratified, slug, plug, annular, and dispersed bubble; slug flow causes pressure surges at receiving facilities.

Wobbe index W = heating value/√(gas specific gravity); it compares fuel gas interchangeability at the same pressure.

A working petroleum system requires source rock, reservoir, seal, trap, migration pathway, and correct timing.

The oil window is roughly 60–120°C (140–250°F); the gas window is roughly 150–200°C (300–390°F), depending on kerogen type and heating rate.

Kerogen types: I is sapropelic and oil-prone, II is marine mixed, III is humic and gas-prone, and IV is inert.

Seismic two-way travel time TWT = 2 × depth/velocity; depth conversion requires an interval velocity model.

AVO analysis uses amplitude variation with offset to detect gas sands; a Class III gas sand shows increasing amplitude with offset.

Sandstone porosity generally decreases with burial depth through compaction and cementation; permeability depends on pore-throat size, not porosity alone.

Structural traps include anticlines, fault blocks, and salt domes; stratigraphic traps include pinch-outs, reefs, and unconformities.

Sequence stratigraphy uses unconformities and flooding surfaces to correlate lowstand, transgressive, and highstand systems tracts.

Gravity and magnetic surveys map basin structure, while seismic reflection is the primary tool for trap definition.

Archie equation: Sw = [(a Rw)/(φ^m Rt)]^(1/n); a ≈ 1, m ≈ 2, and n ≈ 2 for clean water-wet sandstones.

Density porosity φD = (ρma − ρb)/(ρma − ρf); use ρma = 2.65 g/cm³ for quartz and 2.71 g/cm³ for calcite.

Neutron-density crossover occurs in gas-filled porosity because neutron porosity reads low and density porosity reads high.

Gamma ray shale volume Vsh = (GR − GRmin)/(GRmax − GRmin), optionally with nonlinear scaling.

Induction logs work in oil-based mud and nonconductive boreholes; laterologs require conductive mud.

The SP log detects permeable beds and formation water salinity through electrochemical and electrokinetic potentials.

NMR logs measure free fluid, bound fluid, and permeability; the T2 distribution reflects pore-size distribution.

A Pickett plot graphs log Rt against log φ; the water-bearing trend gives Rw and m, and points above the trend indicate hydrocarbon.

Cement bond logs use acoustic amplitude to evaluate cement-formation bond; low amplitude indicates a good bond and high amplitude indicates free pipe or poor bond.

NPV = Σ CFt/(1 + r)^t − initial investment; accept independent projects with NPV > 0.

IRR is the discount rate that makes NPV = 0; accept if IRR exceeds the hurdle rate, but IRR can mislead for nonconventional cash flows.

Expected monetary value EMV = Σ probability × outcome value; decision trees use EMV for sequential exploration and development choices.

P90 means a 90% probability that the value is equaled or exceeded; P10 means a 10% probability of being exceeded.

Payback period is the time to recover undiscounted investment; it ignores cash flow after payback and the time value of money.

WACC = (E/V)Re + (D/V)Rd(1 − tax); use it as the discount rate for projects of average risk.

A risk matrix plots probability against impact; risk tolerance and ALARP determine mitigation priority.

Net cash flow = revenue − royalties − operating costs − taxes − capital spending; depreciation is noncash but affects taxes.

Monte Carlo simulation samples input distributions to produce P10/P50/P90 outcomes; correlations among variables can change the result.

Risk = probability × severity; ALARP means reducing risk as low as reasonably practicable by balancing control cost and risk reduction.

Hierarchy of controls: elimination, substitution, engineering controls, administrative controls, then PPE; PPE is the last line of defense.

HAZOP uses guide words such as no, more, less, reverse, and as well as with process parameters to identify deviations and consequences.

A permit to work controls hot work, confined-space entry, and lockout/tagout; gas testing must precede entry.

H2S is toxic at low ppm; IDLH is 100 ppm, and concentrations above 700 ppm can cause rapid unconsciousness and death; use supplied-air breathing apparatus.

LOPA evaluates independent protection layers; mitigated frequency = initiating frequency × product of protection-layer probability of failure on demand.

Produced water is reinjected or treated before disposal; flaring is minimized, and spills require immediate containment and notification.

Professional ethics require disclosing conflicts of interest, protecting confidential data, reporting unsafe practices, and working only within competence.

Safety culture includes management commitment, blame-free reporting, and learning from near misses and incidents.

Steady-state radial oil flow in field units: q = 0.00708 k h (Pe − Pwf) / (μ B ln(re/rw)), with q in STB/day, k in mD, h in ft, and μ in cp.

Material balance for a volumetric oil reservoir with no water influx and no gas cap: N = Np Bt / (Bt − Bti), neglecting rock and water expansion.

Mobility ratio M = (krw/μw)/(kro/μo); M > 1 means water is more mobile than oil and tends to finger, reducing sweep efficiency.

Fractional flow of water without gravity or capillary effects: fw = 1 / [1 + (kro μw)/(krw μo)].

Exponential decline q = qi e^(−Dt); hyperbolic decline q = qi / (1 + b D t)^(1/b), where b = 0 is exponential and b = 1 is harmonic.

Productivity index J = q/(Pr − Pwf); pseudosteady-state radial flow gives J = 0.00708 k h / (μ B [ln(re/rw) − 0.75 + s]).

Buckley-Leverett frontal advance: the saturation front velocity equals (q/(φA)) times dfw/dSw.

Drive indices from rock/fluid expansion, solution gas, gas cap, and water influx sum to one when all voidage is accounted for.

Capillary pressure Pc = Pnw − Pw; drainage and imbibition hysteresis affect initial saturation and relative permeability.

Hydrostatic pressure in psi = 0.052 × mud weight in ppg × true vertical depth in ft; use TVD, not measured depth.

Equivalent circulating density ECD = MW + (annular pressure loss)/(0.052 × TVD), with annular pressure loss in psi and TVD in ft.

MAASP = formation fracture pressure at the shoe − current mud hydrostatic pressure at the shoe; recalculate after any mud weight change.

Kick indicators include pit gain, flow with pumps off, increasing ROP, gas-cut mud, and reduced pump pressure; confirm the influx before shutting in.

Driller's method circulates the kick out at constant mud weight in two circulations; wait-and-weight raises mud weight first and kills in one circulation.

Leak-off test records surface pressure at which the formation begins to take fluid; fracture gradient = (surface leak-off pressure + mud hydrostatic at shoe)/shoe TVD.

Dogleg severity in degrees per 100 ft = (dogleg angle in degrees × 100)/course length in ft; high DLS increases torque, drag, and casing wear.

Casing seat selection requires mud hydrostatic below fracture pressure at the shoe and above pore pressure in the next hole section.

Cement plug bump pressure is the surface pressure increase after the plug lands; it confirms displacement and can be used for shoe integrity testing.

Vogel IPR for solution-gas-drive oil wells: q/qmax = 1 − 0.2(Pwf/Pr) − 0.8(Pwf/Pr)^2.

Productivity index J = q/(Pr − Pwf); a straight-line IPR applies for undersaturated oil when Pwf exceeds bubble point pressure.

Gas well stabilized deliverability: q = C(Pr^2 − Pwf^2)^n, where n is typically between 0.5 and 1 and C is the deliverability coefficient.

Nodal analysis evaluates pressure drops from reservoir to separator; the selected node determines whether inflow or outflow controls the operating point.

Critical rate for water coning increases with vertical permeability and density contrast and decreases with oil viscosity and perforated interval length.

ESP performance is described by head-capacity, efficiency, and power curves; gas locking occurs when free gas enters the pump intake.

Gas lift injects gas to reduce the tubing fluid gradient; valve spacing and injection depth control unloading and production stability.

Choke flow: subcritical flow depends on downstream pressure, while critical gas flow is nearly independent of downstream pressure when Pdown/Pup is below about 0.55.

Skin factor s > 0 indicates damage, s < 0 indicates stimulation or a fracture, and ΔPskin = 141.2 q B μ s/(k h) in field units.

Real gas law PV = Z n R T; R = 10.73 psia·ft³/(lbmol·°R) in oilfield units.

Gas compressibility cg = (1/P) − (1/Z)(∂Z/∂P)_T; at low pressure cg approaches 1/P.

Standing-Katz chart estimates Z from reduced pressure Pr = P/Pc and reduced temperature Tr = T/Tc.

Sutton pseudocritical correlations: Ppc = 756.8 − 131.0 γg − 3.6 γg² psia and Tpc = 169.2 + 349.5 γg − 74.0 γg² °R.

Gas specific gravity γg = Mg/28.97; methane is about 0.55 and CO2 is about 1.52 relative to air.

Gas formation volume factor Bg = 0.02829 Z T/P ft³/scf with T in °R and P in psia.

Gas expansion factor E = 1/Bg = 35.37 P/(Z T) scf/ft³ with P in psia and T in °R.

Hydrates form at high pressure and low temperature when water and small gas molecules are present; methanol or MEG lowers the hydrate formation temperature.

Rawlins-Schellhardt backpressure equation qg = C(Pr² − Pwf²)^n; a log-log plot of q versus pressure-squared difference gives n and C.

TEG dehydration removes water vapor from natural gas; glycol regeneration must stay below the glycol degradation temperature, roughly 400°F (204°C).

Amine sweetening removes H2S and CO2; MDEA is selective for H2S and needs less regeneration energy than MEA.

Cryogenic turboexpander NGL recovery uses expansion to low temperature; the demethanizer produces methane overhead and NGL bottoms.

Gas pipeline capacity equations such as Weymouth and Panhandle A/B depend on diameter raised to about 2.5–2.7, pressure drop, temperature, and gas gravity.

MAOP is the maximum allowable operating pressure and is limited by pipe design pressure, class location, and hydrostatic test pressure.

Pigging removes liquids and inspects pipelines; smart pigs use magnetic flux leakage or ultrasonic testing to detect metal loss.

Compressor power rises with pressure ratio and flow; intercooling between stages reduces power and discharge temperature.

Two-phase flow regimes include stratified, slug, plug, annular, and dispersed bubble; slug flow causes pressure surges at receiving facilities.

Wobbe index W = heating value/√(gas specific gravity); it compares fuel gas interchangeability at the same pressure.

A working petroleum system requires source rock, reservoir, seal, trap, migration pathway, and correct timing.

The oil window is roughly 60–120°C (140–250°F); the gas window is roughly 150–200°C (300–390°F), depending on kerogen type and heating rate.

Kerogen types: I is sapropelic and oil-prone, II is marine mixed, III is humic and gas-prone, and IV is inert.

Seismic two-way travel time TWT = 2 × depth/velocity; depth conversion requires an interval velocity model.

AVO analysis uses amplitude variation with offset to detect gas sands; a Class III gas sand shows increasing amplitude with offset.

Sandstone porosity generally decreases with burial depth through compaction and cementation; permeability depends on pore-throat size, not porosity alone.

Structural traps include anticlines, fault blocks, and salt domes; stratigraphic traps include pinch-outs, reefs, and unconformities.

Sequence stratigraphy uses unconformities and flooding surfaces to correlate lowstand, transgressive, and highstand systems tracts.

Gravity and magnetic surveys map basin structure, while seismic reflection is the primary tool for trap definition.

Archie equation: Sw = [(a Rw)/(φ^m Rt)]^(1/n); a ≈ 1, m ≈ 2, and n ≈ 2 for clean water-wet sandstones.

Density porosity φD = (ρma − ρb)/(ρma − ρf); use ρma = 2.65 g/cm³ for quartz and 2.71 g/cm³ for calcite.

Neutron-density crossover occurs in gas-filled porosity because neutron porosity reads low and density porosity reads high.

Gamma ray shale volume Vsh = (GR − GRmin)/(GRmax − GRmin), optionally with nonlinear scaling.

Induction logs work in oil-based mud and nonconductive boreholes; laterologs require conductive mud.

The SP log detects permeable beds and formation water salinity through electrochemical and electrokinetic potentials.

NMR logs measure free fluid, bound fluid, and permeability; the T2 distribution reflects pore-size distribution.

A Pickett plot graphs log Rt against log φ; the water-bearing trend gives Rw and m, and points above the trend indicate hydrocarbon.

Cement bond logs use acoustic amplitude to evaluate cement-formation bond; low amplitude indicates a good bond and high amplitude indicates free pipe or poor bond.

NPV = Σ CFt/(1 + r)^t − initial investment; accept independent projects with NPV > 0.

IRR is the discount rate that makes NPV = 0; accept if IRR exceeds the hurdle rate, but IRR can mislead for nonconventional cash flows.

Expected monetary value EMV = Σ probability × outcome value; decision trees use EMV for sequential exploration and development choices.

P90 means a 90% probability that the value is equaled or exceeded; P10 means a 10% probability of being exceeded.

Payback period is the time to recover undiscounted investment; it ignores cash flow after payback and the time value of money.

WACC = (E/V)Re + (D/V)Rd(1 − tax); use it as the discount rate for projects of average risk.

A risk matrix plots probability against impact; risk tolerance and ALARP determine mitigation priority.

Net cash flow = revenue − royalties − operating costs − taxes − capital spending; depreciation is noncash but affects taxes.

Monte Carlo simulation samples input distributions to produce P10/P50/P90 outcomes; correlations among variables can change the result.

Risk = probability × severity; ALARP means reducing risk as low as reasonably practicable by balancing control cost and risk reduction.

Hierarchy of controls: elimination, substitution, engineering controls, administrative controls, then PPE; PPE is the last line of defense.

HAZOP uses guide words such as no, more, less, reverse, and as well as with process parameters to identify deviations and consequences.

A permit to work controls hot work, confined-space entry, and lockout/tagout; gas testing must precede entry.

H2S is toxic at low ppm; IDLH is 100 ppm, and concentrations above 700 ppm can cause rapid unconsciousness and death; use supplied-air breathing apparatus.

LOPA evaluates independent protection layers; mitigated frequency = initiating frequency × product of protection-layer probability of failure on demand.

Produced water is reinjected or treated before disposal; flaring is minimized, and spills require immediate containment and notification.

Professional ethics require disclosing conflicts of interest, protecting confidential data, reporting unsafe practices, and working only within competence.

Safety culture includes management commitment, blame-free reporting, and learning from near misses and incidents.