To all who were bold enough congratulations on taking the 2023 exam!
Any comments you take the time to make can help future test-takers prepare. And of course suggestions for blog/Guidebook/Companion improvements are always welcome and appreciated. I enjoy hearing from all.
Please remember the blog rule: specific prior PE Exam questions cannot be discussed. General topics, resource suggestions, and testing techniques only please. Try not to discuss specific problems from prior exams, such as comments like: "...several of the drilling questions with probability...” it too specific as per the test-writers. Thanks, folk!
There is a delay between comment submission and when it appears; please be patient.
Any comments you test-takers have will help future test-takers to prepare. And any suggestions for blog/Guidebook/Companion improvements are always welcome and appreciated. I really enjoy hearing from everyone.
Please remember the blog rule: specific prior PE Exam questions, in whole or in part, cannot be discussed. General topics, resource suggestions, and testing techniques only please. Try not to "cross the line" into discussing specific problems from prior exams, such as comments like: "...several of the drilling questions with probability...” it too specific as per the test-writers. Thanks, folk!
There is a delay between comment submission and when it appears; please be patient.
11-7-22 UPDATE: Thanks everyone for the excellent comments!
If you didn't pass his year and need some help prepping for 2023, let me know in the next few weeks and I'll try to set up a free class or two by Zoom or email. Sometimes all it takes is some basic advice. I do these classes just to keep mentally 'up-to-date', so don't worry about putting me out.
A company has two good but highly speculative opportunities to invest in, gas field A and oil field B, yet only enough capital to invest in one due to a stiff interest rate of 15% for both. The investments and expected cash flows are below. Which alternative should be selected based on NPV analysis?
A) Investment A; NPV of A >$50,000 more than “B”
B) Investment A; NPV of A <$50,000 more than “B”
C) Investment B; NPV of B <$50,000 more than “A”
D) Investment B; NPV of B >$50,000 more than “A”
A and B
Initial invest: $200M and $300M
Annual revenue: $100M and $150M
Annual expense: $10M and $25M
Invest life (yrs): 7 and 7
Salvage Value: $50M and $175M
Which mechanisms of water intrusion into oil wells are relatively easily controlled (select four only):
__ Watered-out layer without crossflow.
__ Fractures between injector and producer.
__ Moving oil/water contact.
__ Coning.
__ Cusping.
__ Casing leaks.
__ Edge water from poor areal sweeps.
__ Gravity segregated layer in a thick reservoir layer with high-vertical permeability.
__ Channel flow behind the casing from primary cementing that does not isolate water-bearing zones from the pay zone.
__ Fractures or faults from behind the water zone.
A fairly straighforward problem; you will either know it or you won't (depending on how well read or experienced one is). I'll update this problem answer later, to let the problem "sink in" and become ingrained in your mind. Remember, there are a dozen ways this probllem could be asked, so one must have a true understanding if it to be safe!
X Watered-out layer without crossflow (HS4 P381).
__ Fractures between injector and producer (HS4 P381). X Moving oil/water contact (HS4 P381).
__ Coning (HS4 P381).
__ Cusping (HS4 P381). X Casing leaks (HS4 P381).
__ Edge water from poor areal sweeps (HS4 P381).
__ Gravity segregated layer in a thick reservoir layer with high-vertical permeability (HS4 P381). X Channel flow behind the casing from primary cementing that does not isolate water-bearing zones from the pay zone (HS4 P381).
__ Fractures or faults from behind the water zone (HS4 P381).
2021 is history. Comment away! Suggestions for blog/Guidebook/Companion improvements are always welcome and appreciated. I enjoy hearing from all.
Please remember the blog rule: prior PE Exam questions, in whole or in part, will NOT be discussed. General topics, resource suggestions, and testing techniques only. Please don't "cross the line" by discussing specific problems from prior exams. Comments like: "...several of the drilling questions with probability...” is crossing the line. Thanks, folk!
There will be a delay between comment submission and when it appears; please be patient.
A casing string is to be cemented at 10,000 ft in a well containing 10-lbm/gal mud, which will be displaced from the annulus by 500 ft of 8 lbm/gal mud flush, 1,500 ft of 12.5 lbm/gal filler cement, and 1,000 ft of 16.5 lbm/gal cement. The pump pressure (Mpsig) required to completely displace the cement from the casing with 9-lbm/gal brine is closest to: A) 1; B) 1.1; C) 1.2; D) 1.3.
True statements about casing design include (select any that apply):
__ Wells without H2S are called “sweet”.
__ A mixture of water and carbon dioxide is very corrosive.
__ Casing grade C-90 was developed with special metallurgy to resist sulfide stress cracking.
__ Casing grade T-95 was developed with special metallurgy to resist sulfide stress cracking.
__ Typically, high temperatures and lower-stress states accelerate hydrogen embrittlement.
__ For sour service, tubular-material selection is based on minimum temperature, yield strength, manufacturing process, and application.
__ Gas systems are sour when the maximum pressure exceeds 265 psi and partial pressure of H2S is greater than 0.05 psi.
__ Multiphase systems are considered sour if the maximum gas/oil ratio is less than 5,000 scf/bbl and the maximum pressure exceeds 265 psi, and H2S partial pressure in the gas phase is greater than 0.05 psi.
__ Multiphase systems are considered sour if the maximum gas/oil ratio is less than 5,000 scf/bbl and the maximum pressure is less than 265 psi, and H2S partial pressure in the gas phase is greater than 10 psi.
__ Multiphase systems are considered sour if the maximum gas/oil ratio is less than 5,000 scf/bbl and the gas phase contains more than 15 H2S.
These types of questions come from Textbook Series and some are pretty detailed. Much of the information ia also in the Handbook Series. At a minimum, I would know the basics, and these these types of questions have been selected as such.
X Casing is classified according to five properties: the manner of manufacture, steel grade, type of joints, length range, and the wall thickness unit weight (HS2 P288). X Wells without H2S are called “sweet” (TS12 P405). X A mixture of water and carbon dioxide is very corrosive (TS12 P405). X Casing grade C-90 was developed with special metallurgy to resist sulfide stress cracking (TS12 P405). X Casing grade T-95 was developed with special metallurgy to resist sulfide stress cracking (TS12 P405).
__ Typically, high[low] temperatures and lower[higher] stress states accelerate hydrogen embrittlement (TS12 P405). X For sour service, tubular-material selection is based on minimum temperature, yield strength, manufacturing process, and application (TS12 P406). X Gas systems are sour when the maximum pressure exceeds 265 psi and partial pressure of H2S is greater than 0.05 psi (TS12 P406). X Multiphase systems are considered sour if the maximum gas/oil ratio is less than 5,000 scf/bbl and the maximum pressure exceeds 265 psi, and H2S partial pressure in the gas phase is greater than 0.05 psi (TS12 P406). X Multiphase systems are considered sour if the maximum gas/oil ratio is less than 5,000 scf/bbl and the maximum pressure is less than 265 psi, and H2S partial pressure in the gas phase is greater than 10 psi (TS12 P406). X Multiphase systems are considered sour if the maximum gas/oil ratio is less than 5,000 scf/bbl and the gas phase contains more than 15 H2S (TS12 P406).
