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).
The quotient of API burst resistance and the API collapse-pressure rating of a 20-in., 133 lbf/ft, K-55 casing (nominal wall thickness 0.635 in.) is closest to: A) 0.5; B) 1.0; C) 1.5; D) 2.0; E) 2.5; F) 3.0.
Pb=(0.875*2*55000*0.635)/20)=3056=3060 psi.
d/t=20/0.635=31.496.
F5=0.036 use Table 2.3 pg 56 J-55 (F5 is same as K-55).
Pcr=YS(Fr/(d/t))-F5.
Pcr=55000*((1.980/31.496)-0.036))=1493=1490 psi.
3060/1490=2.05, “D”.
(RG P55-56; TS12 P399, P402; GB 6 DTC 2).
True statements about casing design include (select any that apply):
__ Casing is classified according to five properties: the manner of manufacture, steel grade, type of joints, length range, and the wall thickness (unit weight).
__ Oil country tubular goods (OCTG) include casing, tubing, and drillpipe but does not include line pipe.
__ Line pipe cannot be used in oil and gas wells below the surface.
__ The average cost of tubulars is typically more than 1/4 of the average cost of a completed well.
__ A well that will not encounter abnormal formation pore pressure gradients, lost-circulation zones, or salt sections may require only conductor casing and surface casing to drill to the objective for the well.
__ Surface-casing setting depths are usually from 3,000 to 9,000 ft into the sediments.
__ Liners are casing strings that do not extend to the surface but are suspended from the bottom of the next larger casing string.
__ Production liners are generally connected to the surface wellhead using a tieback casing string when the well is completed.
__ Casing is defined as tubular pipe cemented in the wellbore.
__ A casing grade code consists of a letter followed by a number which designates the minimum yield strength of the steel in thousands of psi.
__ The casing letter designation is used to distinguish between various tensile-strength requirements used on casing with the same minimum yield strength.
__ The casing letter designation is used to distinguish between different heat-treatment methods used on casing with the same minimum yield strength.
These long problems are tough. Read carefully but don't even bother to look in the provided Reference, because it won't be there. Add questions or comments in the comment box below.
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).
__Oil country tubular goods (OCTG) include casing, tubing, line pipe, and drillpipe (TS12 P385).
__Line pipe is sometimes used in oil wells because it is available in larger sizes (TS12 P385).
__The average cost of tubulars is approximately 18% of the average cost of a completed well (TS12 P385). X A well that will not encounter abnormal formation pore pressure gradients, lost-circulation zones, or salt sections may require only conductor casing and surface casing to drill to the objective for the well (TS12 P385).
__ Surface-casing setting depths are usually from 300 to 5,000 ft into the sediments (TS12 P386). X Liners are casing strings that do not extend to the surface but are suspended from the bottom of the next larger casing string (HS2 P387). X Production liners are generally connected to the surface swellhead using a tieback casing string when the well is completed (TS12 P385).
__ Casing is defined as tubular pipe with an OD range of 4.5 to 20 in. (TS12 P388). X A casing grade code consists of a letter followed by a number which designates the minimum yield strength of the steel in thousands of psi (TS12 P388). X The casing letter designation is used to distinguish between various tensile-strength requirements used on casing with the same minimum yield strength (TS12 P388). X The casing letter designation is used to distinguish between different heat-treatment methods used on casing with the same minimum yield strength (TS12 P388).
True statements about casing design include (select any that apply):
__ Conductor casing is the first string set below the structural casing.
__ Liner is a casing string that does extend back to the wellhead.
__ Tieback string is a casing string that provides additional pressure integrity from the liner shoe to the wellhead.
__ Tiebacks can be uncemented.
__ Tiebacks can be cemented.
__ Burst pressure conditions occur during well control operations and squeeze cementing.
__ Most oilfield tubulars experience collapse in the “plastic” and “transition” regimes.
__ For certain casing sizes, the threads are intended to be leak resistant when made up.
__ Buckling is typically a more critical design issue for production tubing than for casing.
The provided Reference Guide on the exam offers no help on word problems; hence, there is no escape from prior experience or study on these types of questions. Please provide comments or ask questions in the comment box below.
X Conductor casing is the first string set below the structural casing (TS2 P287)
__ Liner is a casing string that does [not] extend back to the wellhead (TS2 P288).
__ Tieback string is a casing string that provides additional pressure integrity from the liner [top] to the wellhead (TS2 P288). X Tiebacks can be uncemented. X Tiebacks can be cemented. X Burst pressure conditions occur during well control operations and squeeze cementing. X Most oilfield tubulars experience collapse in the “plastic” and “transition” regimes.
__ For [all] casing sizes, the threads are [not] intended to be leak resistant. X Buckling is typically a more critical design issue for production tubing than for casing (TS2 P304).
Design 7 in. production casing to be set in 11 lbm/gal mud in a vertical 15,000 ft well. Assume 10 lbm/gal pore pressure. Use three sections (minimum 2,000 ft each) based on pipe body performance properties. Design limits: 90M lbf overpull over buoyed casing weight...[see text]. What is the most cost-effective casing to use in the bottom of the hole?
A) 32 lbf, C-95
B) 29.0 lbf, C-110
C) 29.0 lbf, C-95
D) 26.0 lbf, C-95
Make sure you stay organized on this problem! Build a table of the needed information (provided in the problem or in the Reference on P41 and P67). Get be familiar with how the provided reference is organized; there is tons of data in a very small space and you need to be able to find and use it rapidly. Most importantly, the fomat is not overly similar to what you may be used to using. So here's our table:
This is a fairly tough problem. Remember, it's highly unlikely the design will be too complex, and your trick is to find the limiting factor as quickly as possible.
True statements about decline curve analysis (DCA) include (select any that apply):
__ DCA is the most widely used method of forecasting future production from gas fields.
__ DCA is the most widely used method of forecasting future production from oil fields.
__ All real wells have hyperbolic decline.
__ DCA has few fundamental theoretical foundations.
__ Harmonic decline is a particular case of hyperbolic decline.
__ Exponential decline is a particular case of hyperbolic decline.
__ Hyperbolic decline is a particular case of exponential decline.
__ Hyperbolic decline is a particular case of harmonic decline.
__ Harmonic decline is a particular case of exponential decline.
Of course the provided Reference Guide will offer no assistance on word problems; you must know the material from prior experience or study. Feel free to ask questions in the comment box below.
X DCA is the most widely used method of forecasting future production from gas fields (TS8 P170). X DCA is the most widely used method of forecasting future production from oil fields (TS8 P170). X All real wells have hyperbolic decline (TS8 P172). X DCA has few fundamental theoretical foundations (TS8 P172). X Harmonic decline is a particular case of hyperbolic decline (TS8 P172). X Exponential decline is a particular case of hyperbolic decline (TS8 P172).
__ Hyperbolic decline is not a particular case of exponential decline (TS8 P172).
__ Hyperbolic decline is not a particular case of harmonic decline (TS8 P172).
__ Harmonic decline is not a particular case of exponential decline. (TS8 P172).
Well 24-7X was drilled and capable of 2,000 STB/D. However, production was immediately choked back to 900 STB/D from first production due to a combination of contractual and facility issues. In July of the fourth year...24-7X’s percentage of total production over the last twelve months was closest to: A) 23; B) 23.5; C) 24; D) 24.5.
This is a standard DCA problem (with a few tricks). I'll post the solution later, but feel free to ask any questions/discuss in the meantime. It does take some time to get used to the format and equations in the new SPE Reference.
True statements about drive mechanisms include (select any that apply):
__ From a reservoir viewpoint, dry and wet gas cannot be treated similarly in terms of production characteristics.
__ From a reservoir viewpoint, dry and wet gas cannot be treated similarly in terms of pressure behavior.
__ From a reservoir viewpoint, dry and wet gas cannot be treated similarly in terms of recovery potential.
__ A retrograde-condensate gas reservoir initially contains a single-phase fluid, which changes to two phases (condensate and gas) in the reservoir when the reservoir pressure decreases.
__ The term “condensate” is often applied to light hydrocarbon liquid produced from a gas well.
__ The term “condensate reservoir” should be applied only to situations in which condensate is actually formed in the reservoir because of retrograde behavior.
__ For both wet and dry gasses, reservoir engineering calculations are based on a single-phase reservoir gas.
__ The effect of a weak to moderate waterdrive is often difficult to detect from a simple p/z plot.
__ Depletion behavior of retrograde-condensate reservoirs can be handled through the p/z analyses with the caveat that the z-factor must be the two-phase z factor.
Once again, remember the provided Reference Guide will offer no assistance on these types of word problems. Most of these word-style questions will come from the SPE Handbook Series (as well as the SPE Textbook Series (TS). So a good study plan is to read the parts of the HS you lack experience with.
Click the button for the answer, along with commentary and SPE references sourced. Feel free to ask questions in the comment box below.
__ From a reservoir viewpoint, dry and wet gas can be treated similarly in terms of production characteristics (HS5 P981).
__ From a reservoir viewpoint, dry and wet gas can be treated similarly in terms of pressure behavior (HS5 P981).
__ From a reservoir viewpoint, dry and wet gas can be treated similarly in terms of recovery potential (HS5 P981). X A retrograde-condensate gas reservoir initially contains a single-phase fluid, which changes to two phases (condensate and gas) in the reservoir when the reservoir pressure decreases (HS5 P981). X The term “condensate” is often applied to light hydrocarbon liquid produced from a gas well (HS5 P982). X The term “condensate reservoir” should be applied only to situations in which condensate is actually formed in the reservoir because of retrograde behavior (HS5 P982). X For both wet and dry gasses, reservoir engineering calculations are based on a single-phase reservoir gas (HS5 P983). X The effect of a weak to moderate waterdrive is often difficult to detect from a simple p/z plot (HS5 P1022). X Depletion behavior of retrograde-condensate reservoirs can be handled through the p/z analyses with the caveat that the z-factor must be the two-phase z factor (HS5 P1024).
A gas reservoir produced 1 MMscf gas and 13 MSTB water. The current and initial gas formation value factors...reservoir modeling predicts two equally possible scenarios for water influx...The initial gas in place (MMscf) is most likely closest to: A) 27.1
B) 30.1
C) 33.1
D) There is likely not any water influx.
This problem is fairly simple; just watch the units. It try to crank these out quickly and let the chips fall where they may, so it wouldn't surprise me if I had an error floating around on this one. Just remember on gas reservoir problems, 90% of the errors are units, and the last 10% are just misreading the problem.
Anyway, I'm posting #19 to address any questions, or even to take suggestions on how it could be modified to better prepare one for gas reservoir problems.
This is a fairly tough word problem, and it shows how difficult reasonable questions can be when mixed in with so many different subjects on an 8 hour exam. To properly prepare one would have to read hundreds of pages out of the Handbook Series, have a very good memory, and then hope for the best.
This problem, in contrast, culls any direct SPE quotes that could "reasonably" be asked on the subject. So: simply read this problem set and thus get a basic understanding and be fully armed with little effort.
Make a point to avoid getting bogged down on the details, details that simply cannot be reasonably asked on this type of exam.
Question: I found your blog, thank you for all the information and practice questions and guide work. I am overwhelmed so far in my quest to study for the exam. Seeing your suggestions that I read SPE Textbook Series #1, #2, #12, and #4 and the 7 volume Petroleum Engineering books makes me think I need to start with a prep course to hone in on how to study efficiently. Based on commenters or private correspondence do you know which prep course is best suited for the newer CBT test?
Answer: I would merely 1) do as many practice problems as possible using the SPE Exam Resource. Once you've done that, you will have a solid idea of your weak areas and what resources you need to get. Only then would I consider taking a course as needed. Regarding which course, I think that depends on your specific weak areas. But since you will need to do practice problems anyway, start there.
Effective liquid permeability is found in the lab by graphing gas permeability versus the reciprocal mean flowing pressure and extrapolating the reciprocal mean pressure to zero.
In this problem, a rock core filled with gas “A” has a permeability of 40 md with an average flowing pressure of 1.25 atm and has a permeability of 30 md when said mean flowing pressure is doubled.
If this same rock core is filled with gas “B” and then has a permeability of 40 md with a flowing pressure of 2.5 atm, the permeability (md) for gas “B” at a flowing pressure of 5 atm is closest to: A) 30 B) 25 C) 20 D) 15.
3. Many problems are extremely difficult (but still fair in that any competent engineer should have a reasonable chance at solving). Examinees often must select multiple answers, and so know the exact answer. Bluntly, guessing is now unreliable.
4. Solutions are given in detail at the end of the text, with exact quotes and specific calculations, as well as the precise SPE and Guidebook source location.
Prior problem sets 2018, 2017, and 2016 were designed for the pre-2019 exam and to learn the Guidebook for the exam. They served this purpose very well. However, now that the exam is closed book, it is critical to use the SPE 2019 Reference Guide when doing problems to learn the equation locations. This problem set is designed to be used in this way.
True statements about drive mechanisms include (select any that apply):
__ Secondary recovery requires “repressurizing” or increasing the reservoir pressure.
__ Oil reservoirs are not classified according to their fluid type.
__ Black oil typically ranges from 70 to 150 in molecular weight.
__ Black oil can have a molecular weight of 210.
__ Oils with molecular weights over 150 are usually classified as heavy oils.
__ Volatile oils exhibit an initial oil FVF in the range of 1.5 to 3.0.
__ Black oils exhibit an initial oil FVF in the range of 0.6 to 6.
__ Black oils exhibit an initial oil GOR in the range of 200 to 900 scf/STB.
Keep in mind the the provided Reference Guide will offer no assistance on these types of word problems. There is really no shortcut except to know the material. Translation: study! Most of these word-style questions will come from the SPE Handbook Series (as well as the SPE Textbook Series (TS), especially TS12). So a good study plan is to merely read the parts of the HS you are unfamiliar with. The questions I provide in the 2021 practice problems give a good test of your knowledge.
Click the button for the answer, along with commentary and SPE references sourced. Note that the provided SPE Reference Guide will not help at all on these types of problems. Feel free to ask questions in the comment box below.
X Secondary recovery requires “repressurizing” or increasing the reservoir pressure. (HS5 P895)
__ Oil reservoirs are classified according to their fluid type. (HS5 P895) X Black oil typically ranges from 70 to 150 in molecular weight. (HS5 P896) X Black oil can have a molecular weight of 210. (HS5 P896)
__ Oils with molecular weights over 210 are usually classified as heavy oils. (HS5 P896) X Volatile oils exhibit an initial oil FVF in the range of 1.5 to 3.0. (HS5 P896)
__ Black oils exhibit an initial oil FVF in the range of 1.1 to 1.5. (HS5 P896) X Black oils exhibit an initial oil GOR in the range of 200 to 900 scf/STB. (HS5 P897)
If a 10,000 ft drillstring’s frictional pressure loss is 1,433 psi, and the 12 lbm/gal mud returns fill a 10 ft x 10 ft tank at 6-1/2 inches per minute, the pressure at the base of the drill collar is closest to? The ID of the drill collars is 2.5 in and pump pressure is 3,000 psi.
A) 7825
B) 7819
C) 7813
D) 7800.
This problem is solved using the standard mechanical energy balance equation. Note the only source truly needed to solve it is the SPE Reference (to calculate the pressure from gravity). If you don't include the KE effect will be off just slightly. Note KE is generally ignored in the field but don't dare ignore it on the exam and this problem shows how will get the wrong answer if you do (even though you don't need to know precisely what the KE value it is to get it right, just that it's there).
Sources: SPE Reference, Guidebook 8 FAC 6, TS2 P129.
A true vertical depth well log (all depths ss) shows a structure top at 7,980 ft and an OWC about 8,140 ft. The log also shows three porosity intervals 35 ft, 30 ft, and 30 ft thick, with porosity interval tops at 8,020 ft, 8,070 ft, and 8,100 ft, each separated by shale breaks. A true statement regarding calculating volumetric reserves in the above situation is (select any that apply):
This type of problem tests your knowledge of P2 and P3 reserves, logging data, and general oilfield knowledge. In the end, there is no shortcut to understanding the basics of logging data. So if it's not something you work with often, get familar with the applicable SPE Handbook and SPE Textbook material. The Guidebook has a good summary as well.
Well 34X was drilled and completed, but there is debate about the quality of the wireline logs. During well testing, 34X produced 10,200 SCF of 0.8 specific gravity gas with 20 STB of 30 API oil. If the reservoir has a FVF = 1.4 bbl/STB, the fluid gradient is closest to:
A) 0.28 psi/ft
B) 0.29 psi/ft
C) 0.30 psi/ft
D) 0.31 psi/ft.
This problem can be solved using the new Reference exclusively. A similar problem can be found in the Guidebook 13 RES 9. TS8 P33-35 has some good explanations as well.
Seismic fundamentals should include basic vocabulary. This includes source, receiver, 2D, 3D, structural, stratigraphic, amplitude, phase, frequency, and propagation velocity. Stick to the basics, as it is unlikely to get overly technical, especially on calculation problems. This problem is so-so, difficulty-wise, depending on your experience.
I find flaring, like DCA, tends to trip up the overconfident. This one is tricky; it tests your knowledge of "sour gas" and how combustion works chemically. Plus, it's a unit nightmare.
Sources include the Guidebook 8 FAC 9 (there isn't much else out there that I've found) and this problem can be solved using
the SPE Reference pages 189 and 191 only if you already know what you are doing. A word to the wise: spend time practicing emission-type problems using the new SPE resource, because you will likely need to know where to go quickly and you won't have the Guidebook available to hold your hand on a closed book exam.
