Advanced Petroleum Engineering interview questions

125 questions with answers (PET-301 to PET-425). Try each one aloud before reading the answer.

Petroleum Geology

PET-301 · A discovery well finds a gas-water contact well above the mapped spill point. What does this tell you?

The trap is underfilled. Either charge was limited, or the seal could only hold that column height before leaking. Compare the column's buoyancy pressure with the seal's capillary entry pressure and check fault-seal and charge timing before booking volumes down to spill.

PET-302 · A seal has a capillary entry pressure of 100 psi. Water gradient is 0.45 psi/ft and gas gradient 0.10 psi/ft. What is the maximum gas column?

h = Pc,entry/(γw − γg) = 100/(0.45 − 0.10) ≈ 286 ft. A taller column would exceed the entry pressure and gas would leak through the seal.

PET-303 · How is pore pressure predicted from sonic data with Eaton's method?

Pp = σv − (σv − Pn)·(Δtn/Δt)³, where Δtn is the normal-compaction trend transit time and Δt the observed value in shale. Higher-than-trend Δt indicates undercompaction and overpressure. The resistivity form uses an exponent of about 1.2.

PET-304 · How is overburden stress calculated?

By integrating bulk density with depth: σv = ∫ρb·g·dz, using density logs and estimates for the shallow section and water column offshore. Onshore it is often near 1 psi/ft; offshore, low-density water and sediments make it lower at the same depth below sea level.

PET-305 · How can reservoir compartmentalisation be detected before production?

Different pressure-depth trends between wells, different fluid contacts, fluid composition or geochemical fingerprints, and seismic evidence of sealing faults. It matters because each compartment needs its own drainage point and reduces connected volume.

PET-306 · What does basin modelling contribute to exploration?

It reconstructs burial, thermal and pressure history to predict when and where source rocks generated and expelled hydrocarbons, migration paths and whether traps existed in time. It helps rank prospects on charge risk and fluid type.

PET-307 · What are AVO classes for gas sands?

Based on the shale-sand impedance contrast: Class I (higher impedance sand, amplitude dims with offset), Class II (near-zero contrast, may reverse polarity), Class III (lower impedance, bright spot that brightens with offset) and Class IV (low impedance, brightness decreasing with offset).

PET-308 · How is fault seal assessed?

By juxtaposition analysis (what rock lies across the fault from the reservoir) and fault-rock analysis such as the shale gouge ratio. Higher SGR generally means more clay smeared into the fault and higher sealing capacity; values above about 15–20% are often taken as sealing.

PET-309 · Why are carbonate reservoirs harder to characterise than sandstones?

They combine intergranular, vuggy and fracture porosity, rapid diagenetic changes and variable wettability. Archie's m varies widely, and permeability poorly correlates with porosity. Image logs, NMR, cores and well tests are integrated, often with dual-porosity models.

PET-310 · What is usually the biggest uncertainty in gross rock volume, and how is it handled?

Depth conversion of seismic times, driven by velocity uncertainty, plus structural interpretation and contact depths. Ranges are handled probabilistically, combining distributions of area, thickness, porosity, saturation and contacts in Monte Carlo to give P90, P50 and P10 volumes.

Petrophysics & Well Logging

PET-311 · Why does Archie's equation fail in shaly sands, and what replaces it?

Clay minerals conduct electricity through exchange cations, so Rt is lower than Archie assumes and Sw is overestimated. Shaly-sand models such as Simandoux, Indonesia, Waxman–Smits and dual water add a clay conductivity term.

PET-312 · A zone has net pay 40 ft, φ = 0.25 and Sw = 0.30. What is hydrocarbon pore thickness?

HCPT = h·φ·(1 − Sw) = 40 × 0.25 × 0.70 = 7.0 ft. Multiplying by area gives hydrocarbon pore volume.

PET-313 · What causes low-resistivity pay and how is it identified?

Thin sand-shale laminations, conductive minerals such as pyrite, high irreducible water in fine-grained rock, or very saline formation water. It is identified with high-resolution and triaxial induction tools (comparing Rv and Rh), NMR, formation testers and cores.

PET-314 · Oil gradient is 0.33 psi/ft with 3000 psi at 8000 ft; water gradient is 0.45 psi/ft with 3080 psi at 8200 ft. Where is the free water level?

Set 3000 + 0.33(D − 8000) = 3080 + 0.45(D − 8200). Solving gives 0.12D = 970, so D ≈ 8083 ft, where both pressures are about 3027 psi.

PET-315 · What is a saturation-height function?

A relation giving Sw as a function of height above the free water level, derived from capillary pressure data. Pc = h·Δγ (psi = ft × psi/ft), and the Leverett J-function J = [Pc/(σ·cosθ)]·√(k/φ) normalises curves from rocks of different quality.

PET-316 · How should petrophysical cutoffs be chosen?

Tie them to flow: pick a permeability cutoff suited to fluid and drive, then translate it to a porosity cutoff using core crossplots and apply matching Vsh and Sw cutoffs. Test sensitivity, because cutoffs can change net pay and volumes a great deal.

PET-317 · How is saturation monitored behind casing?

With pulsed-neutron tools. Capture cross-section (sigma) logging works well where formation water is saline. In fresh or unknown-salinity water, carbon/oxygen ratio logging distinguishes oil from water directly.

PET-318 · How is permeability estimated from NMR?

The Timur–Coates model k = (φ/C)⁴·(FFI/BVI)² uses free and bound fluid volumes. The SDR model k = a·T2lm²·φ⁴ uses the log-mean T2. Both need core calibration.

PET-319 · What can borehole image logs reveal?

Bedding dips and sedimentary structures, natural fractures and their orientation, thin beds, and drilling-induced features. Breakouts and tensile fractures show in-situ stress directions for wellbore stability and frac design.

PET-320 · What steps are needed to integrate core data with logs?

Depth-shift cores to logs (often using core gamma), correct core porosity and permeability to overburden stress, compare grain density and lithology, then use the calibrated relationships for porosity, permeability and saturation interpretation in uncored wells.

Reservoir Engineering

PET-321 · What are the main reservoir drive mechanisms and typical recoveries?

Solution gas drive (roughly 5–30%), gas cap drive (about 20–40%), water drive (often 35–60% or more), gravity drainage (can be high in thick, steeply dipping, permeable reservoirs) and compaction drive. Most reservoirs have a combination.

PET-322 · How can you identify the drive mechanism from production data?

Solution gas drive shows fast pressure decline and GOR rising sharply once below bubble point. Gas cap drive shows slower decline and rising GOR in up-structure wells. Water drive shows well-supported pressure and rising water cut. Material balance plots confirm the diagnosis.

PET-323 · How is the Havlena–Odeh method used for aquifer diagnosis?

Write F = N·Et + We and plot F/Et against We/Et for a chosen aquifer model. A straight line with slope 1 and intercept N confirms the model; upward or downward curvature shows the aquifer model or N is wrong.

PET-324 · A volumetric gas reservoir has initial p/z of 5000 psi. After 20 Bcf production, p/z is 4000 psi. What is GIIP?

p/z falls linearly with cumulative production: G = Gp/(1 − (p/z)/(p/z)i) = 20/(1 − 0.8) = 100 Bcf.

PET-325 · Which aquifer models are used in material balance?

Schilthuis steady-state, Hurst–van Everdingen unsteady-state (radial or linear), Fetkovich pseudo-steady-state and Carter–Tracy approximations. The right model depends on aquifer size, permeability and how fast it responds.

PET-326 · What is the workflow for a reservoir simulation study?

Build a static model, upscale to a simulation grid, add PVT (black-oil or compositional), SCAL and well data, initialise and history-match pressure, rates and water and gas breakthrough. Then forecast development cases with uncertainty ranges.

PET-327 · What are key waterflood design decisions?

Pattern (five-spot, line drive, peripheral), well spacing, injection rate and pressure below fracture limits, water quality and compatibility, and voidage replacement ratio. VRR = injected reservoir volumes/produced reservoir volumes, typically targeted at about 1 or slightly above.

PET-328 · A gas condensate well loses productivity as pressure drops below dew point. Why, and what can be done?

Retrograde liquid drops out near the wellbore, forming a condensate bank that cuts gas relative permeability. Remedies are pressure maintenance or gas cycling, hydraulic fracturing, solvent or methanol treatments, wettability alteration, or simply accepting it and designing for it.

PET-329 · A field produces 10,000 STB/d oil (Bo = 1.3) and 5000 bbl/d water (Bw = 1.0) with no free gas. What water injection gives VRR = 1?

Reservoir voidage = 10,000 × 1.3 + 5000 × 1.0 = 18,000 rb/d. With Bw ≈ 1.0 for injected water, inject about 18,000 bbl/d.

PET-330 · Why do horizontal wells help in thin oil rims with water and gas coning?

They spread drawdown over a long length, so the same rate needs much lower drawdown and the critical coning rate is much higher. Placement relative to the contacts, and ICDs to balance inflow, delay breakthrough further.

PET-331 · How does SPE-PRMS classify reserves and uncertainty?

Reserves are 1P (proved), 2P (proved plus probable) and 3P (plus possible). With probabilistic methods, there should be at least 90% probability of recovering 1P, 50% for 2P and 10% for 3P. Contingent and prospective resources lie outside reserves.

Drilling Engineering

PET-332 · Mud weight is 12 ppg, annular friction loss is 300 psi and TVD is 10,000 ft. What is ECD?

ECD = 12 + 300/(0.052 × 10,000) = 12 + 0.58 ≈ 12.58 ppg.

PET-333 · How do you drill a section with a very narrow pore-fracture pressure window?

Use managed pressure drilling with surface back-pressure to hold constant bottomhole pressure, low-ECD mud and hydraulics, wellbore strengthening, optimised casing points or extra liners, and possibly dual-gradient or casing-while-drilling methods.

PET-334 · What controls wellbore stability?

Mud weight must lie between the collapse limit, where shear failure causes breakouts, and the fracture limit, where tensile failure causes losses. The window depends on in-situ stresses, rock strength, pore pressure, well inclination and azimuth, and chemical interaction with shale.

PET-335 · How are torque and drag managed in extended-reach wells?

Model torque, drag and buckling with friction factors calibrated from offset wells (often around 0.2–0.3 in casing and higher in open hole). Reduce them with smooth trajectories, RSS, lubricants or OBM, good hole cleaning, non-rotating protectors and higher-grade pipe.

PET-336 · A well builds at 3°/100 ft. What is the radius of curvature?

R = 5729.58/BUR = 5729.58/3 ≈ 1910 ft, where 5729.58 = (180/π) × 100.

PET-337 · What are the key design steps for a horizontal well?

Define target, landing point and lateral length; choose kick-off depth and build rate to suit motors, RSS, casing and completion; check torque and drag, hydraulics and hole cleaning; plan geosteering with LWD to stay in the best rock.

PET-338 · What is mechanical specific energy and how is it used?

MSE = WOB/A + 120·π·N·T/(A·ROP), in psi, with N in rpm, T in ft-lbf, ROP in ft/hr and A in in². It is the energy used per unit volume of rock. MSE far above rock strength flags inefficiency like bit balling, vibration or dull bits.

PET-339 · Pulling 50,000 lbf extra stretches stuck pipe 20 in. Pipe area is 4.0 in² and E = 30 × 10⁶ psi. Where is the free point?

L = E·A·ΔL/F = 30 × 10⁶ × 4.0 × 20/50,000 = 48,000 in ≈ 4000 ft.

PET-340 · What makes deepwater drilling difficult?

Low fracture gradients because seawater replaces overburden, giving narrow mud windows; shallow hazards such as shallow water flow and gas; low seabed temperatures that favour hydrates; riser margin and long choke lines; and very high spread costs.

PET-341 · What is an HPHT well and what changes in its design?

Commonly a well with pore pressure above 10,000 psi and temperature above 300 °F (about 150 °C). Mud, cement, elastomers and electronics must be rated for heat, kick margins are tight, gas solubility in OBM masks kicks, and casing design must handle thermal loads.

PET-342 · How is drilling performance improved over a field campaign?

By analysing offset wells and non-productive time, benchmarking each phase, optimising bits, BHA and parameters using MSE and vibration data, standardising designs, and using real-time monitoring and after-action reviews to apply lessons.

Drilling Fluids & Cementing

PET-343 · How is mud weight selected for a hole section?

High enough to exceed pore pressure plus a trip margin and support wellbore stability, but low enough that ECD and surge pressures stay below the fracture gradient with a kick margin. The safe window may also change with inclination.

PET-344 · How much water must be added to 500 bbl of 12 ppg mud to bring it to 11 ppg?

Vw = V₁(W₁ − W₂)/(W₂ − Ww) = 500 × (12 − 11)/(11 − 8.33) ≈ 187 bbl of fresh water.

PET-345 · What properties are controlled in oil-based mud?

Oil-water ratio, emulsion stability (electrical stability test), excess lime, water-phase salinity (often CaCl₂) balanced against shale activity to prevent water uptake, plus rheology, density and HPHT fluid loss.

PET-346 · Calculate cement volume for 1000 ft of 9⅝ in casing in a 12¼ in hole with 20% excess.

Annular capacity = (12.25² − 9.625²)/1029.4 = (150.06 − 92.64)/1029.4 ≈ 0.0558 bbl/ft. Volume = 55.8 bbl × 1.2 ≈ 67 bbl, plus the shoe track volume.

PET-347 · What practices give good cement placement?

Good centralisation (high standoff), conditioning mud to low gels and yield point, spacers and flushes with proper density and rheology hierarchy, pipe reciprocation or rotation, adequate contact time, and correct slurry design for temperature and pressure.

PET-348 · Why does gas migrate through setting cement, and how is it prevented?

As cement gels and shrinks it stops transmitting full hydrostatic pressure before it is impermeable, so gas can enter. Prevention uses short transition (right-angle set) slurries, low fluid loss, latex or other gas-tight additives, expanding agents and applied annular back-pressure.

PET-349 · How can cement sheath integrity fail over well life?

Pressure and temperature cycling during testing, stimulation and production can debond cement, creating micro-annuli, or crack it. CO₂ and H₂S can degrade it chemically. Flexible, expanding and CO₂-resistant systems are used in severe cases.

PET-350 · How is a lost circulation treatment designed?

Find the loss zone, type and rate, then size the treatment: particle size distribution should match the estimated fracture or pore throat size, often a blend of granular, fibrous and flake materials. Wellbore strengthening props induced fractures to raise effective fracture gradient.

PET-351 · What problems affect drilling fluids in HPHT wells?

Barite sag in deviated wells, thermal degradation of polymers, high-temperature gelation, increased HPHT fluid loss, and gas solubility in oil-based mud that hides kicks. Formate brines or carefully formulated OBM are common solutions.

PET-352 · What are the limitations of cement bond logs?

A microannulus can make good cement look poorly bonded, so logs may be run with pressure applied. Fast formations, light cements and eccentred tools distort amplitude. Ultrasonic tools mapping acoustic impedance around the casing complement the CBL/VDL.

Well Control

PET-353 · Prepare key kill sheet values: TVD 10,000 ft, OMW 10 ppg, SIDPP 520 psi, slow circulating pressure 800 psi.

KMW = 10 + 520/(0.052 × 10,000) = 11.0 ppg. ICP = 800 + 520 = 1320 psi. FCP = 800 × 11/10 = 880 psi.

PET-354 · SIDPP is 500 psi, SICP 650 psi, pit gain 20 bbl, annular capacity 0.05 bbl/ft and mud 10 ppg. What is the influx?

Influx height = 20/0.05 = 400 ft. Gradient = 0.52 − (650 − 500)/400 = 0.52 − 0.375 ≈ 0.145 psi/ft, which indicates gas.

PET-355 · How does the volumetric method work?

Used when circulation is not possible and gas migrates. Casing pressure is allowed to rise by a safety and working margin, then mud is bled in small steps while holding casing pressure. Each bled barrel lowers hydrostatic by mud gradient/annular capacity, which is added to the casing pressure target.

PET-356 · When is bullheading used, and what are the risks?

When the influx cannot be safely circulated, such as H₂S, very large influx or no pipe in the hole. Fluids are pumped back into the formation. Risks include fracturing a weaker zone above, exceeding casing ratings and pushing the influx into an unintended formation.

PET-357 · What makes well control harder in deepwater?

Long, narrow choke lines add significant friction, the pore-fracture margin is small, hydrates can form in the BOP and lines, gas can enter the riser above the BOP, and the subsea BOP is remote. Choke line friction must be subtracted during kill start-up.

PET-358 · Why is a diverter used instead of shutting in for shallow gas?

Shallow formations have very low fracture strength. Shutting in could break down the formation and let gas broach to the seabed or surface around the conductor. A diverter routes flow away from the rig while the well is controlled or bridges.

PET-359 · LOT equivalent mud weight is 14 ppg at a 5000 ft TVD shoe and current mud is 11 ppg. What is MAASP?

MAASP = (14 − 11) × 0.052 × 5000 = 780 psi. It must be recalculated whenever mud weight changes.

PET-360 · What factors control kick tolerance?

Shoe fracture strength, mud weight, the expected kick intensity (pore pressure above mud weight), hole and BHA geometry, influx type and its expansion as it rises. Small open-hole annular clearance or a weak shoe reduces tolerance.

PET-361 · What is the two-barrier principle?

During all well operations there should be at least two independent, tested well barrier envelopes between reservoir fluids and the environment, such as the mud column as primary and the BOP, casing and cement as secondary. Losing one triggers restoring it before continuing.

PET-362 · What well control lessons came from the Macondo blowout?

A failed cement barrier was not detected because the negative pressure test was misinterpreted, the influx was recognised late, and the BOP did not seal because the pipe was off-centre when the shear rams closed. Barrier verification and kick detection are critical.

Well Completion & Stimulation

PET-363 · What is hydraulic fracturing?

Pumping fluid above fracture pressure to split the rock, then carrying proppant into the fracture to keep it open. It creates a high-conductivity path that bypasses near-wellbore damage and greatly increases contact area in low-permeability rock such as shale and tight sands.

PET-364 · Closure gradient is 0.7 psi/ft at 10,000 ft, net pressure 500 psi, hydrostatic gradient 0.44 psi/ft and pipe friction 3000 psi. What is surface treating pressure?

BHTP = 7000 + 500 = 7500 psi. STP = BHTP − hydrostatic + friction = 7500 − 4400 + 3000 = 6100 psi.

PET-365 · Estimate fracture gradient with Eaton's method for ν = 0.25, overburden 1.0 psi/ft and pore pressure 0.465 psi/ft.

FG = [ν/(1 − ν)](σv − Pp) + Pp = (1/3)(1.0 − 0.465) + 0.465 ≈ 0.643 psi/ft.

PET-366 · How does reservoir permeability change the optimal fracture design?

For a given proppant volume, productivity is maximised near FCD ≈ 1.6. Low-permeability rock therefore needs long, narrow fractures. High-permeability rock needs short, very wide, highly conductive fractures, often made by tip screen-out frac packs.

PET-367 · How is a sandstone acid treatment designed?

An HCl preflush removes carbonates and displaces formation brine. The main HCl–HF mud acid dissolves clays and fines. An overflush pushes spent acid away from the wellbore. Volumes and strengths are limited to avoid precipitates such as calcium fluoride and fluosilicates.

PET-368 · Why is there an optimum injection rate for carbonate acidizing?

At low rates acid is spent at the face (compact dissolution). At very high rates it forms many branched, inefficient channels. At an intermediate rate, related to the Damköhler number, dominant wormholes form that penetrate furthest per volume of acid.

PET-369 · How is the sand control method selected?

From formation particle size distribution (sorting and fines content), rock strength, well type and rates. Well-sorted, clean sands may use standalone screens; poorly sorted sands with fines often need gravel packs; high-rate or damaged wells often use frac packs.

PET-370 · A newly completed well has skin of +15. How do you decide the remedy?

Split total skin into components: mechanical damage, perforation, partial penetration and rate-dependent non-Darcy skin, using test analysis and multirate data. Damage calls for acid or a frac; poor perforations call for reperforating; non-Darcy skin needs more perforations or a fracture.

PET-371 · What changes in completion design for HPHT sour wells?

Materials must resist sulfide stress cracking and corrosion, so corrosion-resistant alloys are chosen according to NACE MR0175/ISO 15156, along with high-temperature elastomers, metal-to-metal seals and careful tubing stress analysis for thermal and pressure loads.

PET-372 · How is production tubing size selected?

Using nodal analysis over the well's life. Larger tubing cuts friction at high early rates, but in later life low velocities cause slippage and liquid loading. The chosen size balances early deliverability with late-life lift, or plans a later velocity string.

Production Engineering & Artificial Lift

PET-373 · A saturated well produces 600 STB/d at Pwf = 1500 psi with P̄r = 2500 psi. Using Vogel, what is the rate at Pwf = 1000 psi?

At 1500 psi, ratio 0.6: 1 − 0.12 − 0.288 = 0.592, so qmax = 600/0.592 ≈ 1014 STB/d. At 1000 psi, ratio 0.4: 1 − 0.08 − 0.128 = 0.792, so q ≈ 803 STB/d.

PET-374 · How do you choose an artificial lift method?

Compare rate range, depth, GLR, sand, viscosity, deviation, temperature, power and gas availability, surface space, and intervention cost. ESPs suit high rates, rod pumps low-rate onshore wells, gas lift gassy or deviated offshore wells, and PCPs viscous sandy oil.

PET-375 · How is gas lift optimised across a field?

Each well's production versus injection-gas curve rises to a maximum and then falls as friction dominates. When gas is limited, it is allocated so each well has the same marginal oil gain per extra unit of gas, which maximises total oil.

PET-376 · Size an ESP for 5000 ft net lift, 200 ft friction loss and 100 psi wellhead pressure in water (0.433 psi/ft), with 25 ft head per stage.

Wellhead head = 100/0.433 ≈ 231 ft. TDH = 5000 + 200 + 231 = 5431 ft. Stages = 5431/25 ≈ 218 stages.

PET-377 · How are ESPs adapted to gassy wells?

Setting the pump deeper to raise intake pressure, using rotary or vortex gas separators, gas-handling or multiphase stages, and venting gas up the annulus. Too much free gas at the intake degrades head and can cause gas lock.

PET-378 · What is a flow assurance strategy for a long subsea tieback?

Prevent hydrates by insulation, MEG or methanol injection and depressurisation plans for shutdowns; control wax above the wax appearance temperature with insulation, inhibitors and pigging; manage asphaltenes and scale with inhibitors; and plan slug handling and cooldown times.

PET-379 · How do you diagnose and treat a well with rapidly rising water cut?

Use Chan diagnostic plots, production logs and reservoir data to tell coning from channelling, high-permeability streaks or casing leaks. Treatments include mechanical isolation, polymer gels, cement squeeze, rate reduction, recompletion or downhole water separation.

PET-380 · What is integrated asset modelling?

Linking reservoir, well and surface network models so that back-pressure, facility limits and well performance are solved together. It shows bottlenecks and lets engineers test compression, debottlenecking or lift changes on whole-field output.

PET-381 · How does API RP 14E estimate erosional velocity?

Ve = C/√ρm, with Ve in ft/s and mixture density ρm in lb/ft³. C is commonly 100 for continuous service without solids, with higher values allowed in some conditions. With sand present, more detailed erosion models are used.

PET-382 · What causes asphaltene deposition and how is it handled?

Asphaltenes become unstable as pressure falls toward bubble point, especially in light undersaturated oils, or when CO₂ or light gas is added. Deposits are removed with aromatic solvents such as xylene and prevented with inhibitors or by operating outside the instability range.

PET-383 · When is plunger lift suitable?

For gas wells with liquid loading and enough gas-liquid ratio and shut-in pressure to drive a free plunger. The plunger travels the tubing and lifts liquid slugs each cycle, using only well energy.

Well Testing

PET-384 · What is well testing used for?

Pressure transient analysis of drawdowns, buildups and other tests to estimate permeability, skin, average reservoir pressure, boundaries and connected volume, plus well deliverability and fluid samples. It guides completion, stimulation and development decisions.

PET-385 · What is the skin factor, and what is skin for a damaged zone of 2 ft with k = 100 mD, ks = 20 mD and rw = 0.354 ft?

Skin is a dimensionless extra pressure drop near the wellbore: positive for damage, negative for stimulation. Hawkins' formula s = (k/ks − 1)·ln(rs/rw) = (5 − 1) × ln(5.65) ≈ 6.9.

PET-386 · What is the pressure drop due to skin if m = 50 psi/cycle and s = 5?

Δps = 0.869·m·s = 0.869 × 50 × 5 ≈ 217 psi. Equivalently Δps = 141.2·q·B·μ·s/(k·h).

PET-387 · With drawdown P̄ − Pwf = 1000 psi and Δps = 217 psi, what is flow efficiency?

FE = (P̄ − Pwf − Δps)/(P̄ − Pwf) = (1000 − 217)/1000 ≈ 0.78. Removing the damage would raise rate about 28% at the same drawdown.

PET-388 · How do boundaries appear on a derivative plot?

A single sealing fault doubles the semilog slope, so the derivative steps up by a factor of 2. Parallel faults give a half-slope (linear) trend. A closed system gives a late unit slope in drawdown. A constant-pressure boundary makes the derivative fall.

PET-389 · How is distance to a sealing fault estimated from a buildup?

From the time Δtx where the two semilog straight lines intersect: L = 0.01217·√[k·Δtx/(φ·μ·ct)], with L in ft, k in mD, Δtx in hours, μ in cP and ct in psi⁻¹.

PET-390 · What must a well test design consider?

Test objectives, the time needed for wellbore storage to end, which is roughly (200,000 + 12,000s)·C·μ/(kh) hours, the radius of investigation needed, gauge resolution, rate control, downhole shut-in to reduce storage, safety limits and flaring or production constraints.

PET-391 · How is the wellbore storage coefficient found?

From the unit-slope line on a log-log plot: C = q·B·Δt/(24·Δp), in bbl/psi. In theory C = Vw·cw for a fluid-filled wellbore, or Vu/(ρ/144) for a rising liquid level, with ρ in lb/ft³.

PET-392 · How is non-Darcy skin separated in gas wells?

Apparent skin is s′ = s + D·q, where D is the non-Darcy coefficient. Testing at several rates and plotting s′ against q gives a straight line: the intercept is mechanical skin and the slope is D.

PET-393 · What are the well test signatures of a hydraulically fractured well?

An infinite-conductivity fracture shows linear flow with a half-slope derivative. A finite-conductivity fracture shows bilinear flow with a quarter slope first. Later the response moves to pseudo-radial flow with negative skin.

PET-394 · What is deconvolution and why is it useful?

A method that converts a variable-rate pressure history into an equivalent constant-rate drawdown response. It can reveal boundaries and connected volume over the full test or permanent gauge record, beyond the radius seen by any single buildup.

Enhanced Oil Recovery

PET-395 · What are the main EOR methods?

Thermal: steamflooding, cyclic steam, SAGD and in-situ combustion. Gas: CO₂, hydrocarbon and nitrogen miscible or immiscible injection, often as WAG. Chemical: polymer, surfactant-polymer and alkaline-surfactant-polymer flooding. Others include low-salinity water and microbial methods.

PET-396 · Which EOR method would you screen for a 12 °API, 5000 cP oil at 1500 ft, and for a 35 °API oil at 8000 ft?

The heavy, shallow oil suits thermal recovery such as cyclic steam, steamflood or SAGD in a thick sand. The light, deep oil suits miscible CO₂ or hydrocarbon gas injection if reservoir pressure can be kept above MMP and a gas source exists.

PET-397 · What are the main design issues in polymer flooding?

Target viscosity to reach a favourable mobility ratio, polymer adsorption and retention, inaccessible pore volume, shear degradation in injection facilities and near-wellbore, thermal and chemical stability, injectivity loss, and slug size and concentration tapering.

PET-398 · Calculate mobility ratio for krw = 0.3, μw = 0.5 cP, kro = 0.8, μo = 10 cP, then with polymer raising μw to 5 cP.

M = (0.3/0.5)/(0.8/10) = 0.6/0.08 = 7.5, which is unfavourable. With μw = 5 cP, M = 0.06/0.08 = 0.75, which is favourable.

PET-399 · Why do gas floods suffer from poor sweep, and how is it improved?

Gas has much lower viscosity and density than oil, so it fingers through and overrides to the top. WAG, foam, gravity-stable injection from the crest, conformance treatments and well placement improve sweep.

PET-400 · What controls SAGD performance?

Reservoir thickness and vertical permeability, shale barriers, bitumen viscosity, bottom water or top gas thief zones, well pair placement and subcool control. Performance is judged by steam-oil ratio, commonly around 2–4 for good projects.

PET-401 · How is a surfactant-polymer or ASP formulation designed?

Phase-behaviour tests find the optimal salinity where a middle-phase (Winsor III) microemulsion gives ultra-low IFT, around 10⁻³ mN/m. Alkali reduces adsorption and forms soap. Core floods confirm recovery, followed by a polymer drive for mobility control.

PET-402 · How does CO₂ EOR relate to carbon storage?

Part of the injected CO₂ stays in the reservoir each cycle while produced CO₂ is separated and recycled. Combining EOR with storage requires monitoring, measurement and verification of where CO₂ goes, and well integrity checks on old wells.

PET-403 · How should an EOR pilot be designed?

After lab and simulation screening, run single-well injectivity or tracer tests, then a pattern pilot with observation wells. Define measurable objectives, baseline data and monitoring (rates, tracers, logs, pressure) so incremental oil can be separated from baseline decline.

PET-404 · What economic measures matter for EOR projects?

Incremental oil per unit of injectant, such as Mcf of CO₂ or lb of polymer per incremental barrel, capital for facilities and wells, operating and injectant costs, response time, oil price sensitivity, and any carbon credits or costs.

Unconventional Resources

PET-405 · What trade-offs are made in shale completion design?

Tighter stage and cluster spacing and higher proppant loading raise early production but cost more and give diminishing returns. Fluid type, pump rate and limited-entry perforation design control how evenly clusters take fluid. Designs are tuned using production results and diagnostics.

PET-406 · Calculate perforation friction for 80 bpm, 8.4 ppg fluid, 40 perforations of 0.40 in with Cd = 0.8.

ΔPpf = 0.2369·q²·ρ/(N²·d⁴·Cd²) = 0.2369 × 6400 × 8.4/(1600 × 0.0256 × 0.64) ≈ 486 psi. This drop helps spread flow across clusters in limited-entry design.

PET-407 · How is well spacing optimised in shale developments?

Closer spacing recovers more of the resource per section but causes interference that reduces each well's EUR. The optimum maximises section-level NPV, using pilots, diagnostics, production data and models that account for depletion and parent-child effects.

PET-408 · What is rate transient analysis?

Analysis of rate and flowing pressure data to estimate reservoir and fracture properties without shut-ins. For shale wells, the slope of rate-normalised pressure against √t in linear flow gives A·√k, and the end of linear flow indicates the drainage volume.

PET-409 · Why are Arps forecasts adjusted for shale wells?

Long transient linear flow often fits b > 1, which over a long forecast gives unrealistically large reserves. The modified hyperbolic approach switches to exponential decline at a terminal decline rate, Dmin, to keep EUR realistic.

PET-410 · Calculate adsorbed gas content for VL = 100 scf/ton, PL = 500 psi and P = 2000 psi.

V = VL·P/(PL + P) = 100 × 2000/2500 = 80 scf/ton. Only part of this desorbs before abandonment pressure.

PET-411 · How does proppant selection affect long-term shale production?

At high closure stress, sand crushes and fines migrate, so conductivity falls; resin-coated sand or ceramics resist crushing. Embedment into soft, clay-rich rock also lowers effective width. Local sand is cheaper and often enough at moderate stress.

PET-412 · What environmental issues are linked to unconventional development?

Large water volumes for fracturing, handling and disposal of flowback and produced water, induced seismicity from disposal injection, methane emissions, surface footprint and traffic. Recycling water, monitoring seismicity with traffic-light protocols and leak detection reduce impact.

PET-413 · How are refracture candidates selected?

Wells with poor original completions, such as wide stage spacing or low proppant, good remaining reservoir quality and pressure, and sound casing integrity. Diversion or a new liner is needed so fluid reaches unstimulated rock instead of existing fractures.

PET-414 · What is huff-and-puff gas injection in shale oil?

Gas such as produced gas or CO₂ is injected into a producing well, soaked and then produced back. It works by swelling, diffusion into the matrix, viscosity reduction and repressurisation, and can raise recovery from tight oil wells.

Surface Facilities, Pipelines, Refining & HSE

PET-415 · Find maximum gas velocity in a separator with K = 0.25 ft/s, ρL = 50 lb/ft³ and ρg = 2 lb/ft³.

Vmax = K·√[(ρL − ρg)/ρg] = 0.25 × √24 ≈ 1.22 ft/s. The vessel cross-section must keep actual gas velocity below this.

PET-416 · Calculate wall thickness for a 20 in pipeline at 1440 psi, X52 (SMYS 52,000 psi), design factor 0.72, joint factor 1.0.

Barlow: t = P·D/(2·S·F·E) = 1440 × 20/(2 × 52,000 × 0.72 × 1.0) ≈ 0.385 in, before adding any corrosion allowance.

PET-417 · How does gas pipeline capacity depend on pressure and diameter?

In equations such as Weymouth and Panhandle, flow depends on P₁² − P₂² and roughly on D^2.5–2.7. So compression pays off strongly, and a small diameter increase gives a large capacity gain.

PET-418 · What corrosion mechanisms affect oil and gas pipelines, and how are they managed?

CO₂ (sweet) corrosion, H₂S-related sulfide stress cracking and hydrogen-induced cracking, oxygen corrosion, and microbiologically influenced corrosion. Management uses inhibitors, corrosion-resistant alloys, coatings and cathodic protection, pigging, and monitoring with coupons, probes and inline inspection.

PET-419 · How are refinery configurations classified?

Topping and hydroskimming refineries mainly distil and reform. Cracking refineries add FCC or hydrocracking to convert gas oils. Coking refineries add cokers to convert residue. More conversion capacity raises the complexity index and lets the refinery run heavier, cheaper crude.

PET-420 · When would a refinery choose a hydrocracker over an FCC?

Hydrocrackers produce high-quality, low-sulfur diesel and jet fuel and handle tough feeds, but need much hydrogen and high-pressure equipment. FCC units are cheaper and favour gasoline and light olefins. The choice follows product demand and crude slate.

PET-421 · What does a delayed coker do?

It thermally cracks vacuum residue in large drums, producing lighter liquids and gas and leaving solid petroleum coke. Drums are filled and decoked in alternating cycles. It is the main route for upgrading the heaviest residues.

PET-422 · How is process safety risk managed in an oil facility?

With layered protection: inherently safer design, basic process control, alarms and operator response, safety instrumented systems sized by SIL, pressure relief, and emergency shutdown and response. LOPA and bow-tie analysis show whether layers are enough for each scenario.

PET-423 · What drives the design of a flare system?

Credible relief scenarios such as fire, blocked outlet, power failure and control failure set relief loads. The design covers PSV sizing, header back-pressure, a knock-out drum to remove liquid, flare stack height for thermal radiation and dispersion, and purge gas to stop air entering.

PET-424 · How can upstream methane emissions be reduced?

Leak detection and repair with optical gas imaging, replacing high-bleed pneumatic devices, capturing tank and compressor vent gas with vapour recovery, reducing routine flaring and venting, and measuring emissions to target the largest sources.

PET-425 · How do you choose a gas sweetening process?

Amines suit low to moderate acid gas partial pressures: MEA and DEA remove both H₂S and CO₂, while MDEA is selective for H₂S. Physical solvents such as Selexol suit high CO₂ partial pressure. Very small H₂S loads may use scavengers instead.

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