Pumping: 2021 #29

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.

Solution:
10000-500-1500-1000 = 7000 ft 9-lbm/gal.
0.052*((500*8)+(1500*12.5)+(1000*16.5)+(10*7000))=5681psig.
10,000*9=4680 psig.
5946 – 4680=1001 psig, “A”.
(TS12 P186; GB 3 HYD 2; RG P41, P67).

Casing Design: 2021 #28

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).

Casing Design: 2021 #27

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).

Casing Design: 2021 #26

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).

Casing Design: 2021 #25

In problem #23 above, the deepest casing section should be run no higher than (ft):
A) 14,913
B) 14,923
C) 14,933
D) 14,943
E) 14,953

Find the csg with next lowest rating, max depth:
7755/(7800/15000)=14,913 (below neutral point), “A”.
References: (TS12 P430; GB 11 DCA 1; RG P41, P67).

Casing Design: 2021 #24

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).

Casing Design: 2021 #23

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:

Collapse (1.1) Burst (1.1) Tension (1.8).
23.0 lbf, C-95 3764 (4140) 6845 (7530) 486 (632).
26.0 lbf, C-95 5345 (5880) 7818 (8600) 552 (717).
29.0 lbf, C-95 7118 (7830) 8809 (9690) 618 (803).
32.0 lbf, C-95 8864 (9750) 9782 (10760) 681 (885).
29.0 lbf, C-110 7755 (8530) 10200 (11220) 715 (929).
Burst@surface=7780 psi.

Burst@TD: 7780+0.052*9*15000-0.052*10*15000=7000 psi.
Collapse surface=0 psi; Collapse@TD: 0.052*10*14000=7800 psi.
Neutral-Plane-BF=1-MW/65(P41)=1-11/65=0.846*15,000=12462’-NP-collapse-derate-above.
Section-1: TD-collapse-options>7800-is-8864 32 lbf, C-95, “A”.

References: (TS12 P430; GB 11 DCA 1; RG P41, P67).

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.

 

API Equation: 2016 #14

 Problem 14. An empty N180 pipe has 40,000 psi tension applied to it. The reduced collapse rating is closest to what percent of pre-tension rating? A) 0%, B) 45%, C) 55%, D) 65%.

This is straight out of the Guidebook on 6 DTC 3; the collapse pressure rating is reduced to 65.1%. 

Note the equation in the new  Reference Guide (provided with the exam) is on page 55 of Chapter 2. One really has to get used to this reference, since it's not very intuitive where one would expect to find it. You can waste a lot of time looking for it if you don't have it very well mapped out before the exam.

Note: it was pointed out to me today by a steely-eyed engineer that the Kindle problem asks for "percent reduction" making the answer 1-0.65 = 35% or (B), not (D). I actually like this mistake, since it gets one thinking about how clever and tricky the wording on these problems may be...one can't be too careful here. Read, read again, and then read once more...

Axial Stress: 2017 #71

Problem 71. Which action places the most axial force on a joint of 9 5/8 inch 47 lb/ft N-80 casing?

(A) Falling in a vertical hole at ½ foot per second until an abrupt & level impact.
(B) Injecting 10 lb/gal mud into the casing at 400 psig.
(C) Pulling it through a hole with a  3  0.6 per 100 ft dog leg severity.
(D) A & C are within 30% of each other & create the most axial force

Note this entire problem is solved on 6 DTC 1 (GB).
Answers are merely multiples of GB examples (lbf):

Use casing: 9.625 od & 8.681 ID (Redbook).
Δσz − shock = 1,780(Δv) = 1,780(1/2 ft/s) = 890 psi (1/20 Guidebook example)...
Fshock = Δσz − shock(As) = 890 lb/in2 (13.572 in2) = 12M...

Solution: A: 12M lbf (1/20 GB w/ conversion), B: 24M (1/10 GB), C: 17M (1/10 GB)

Casing Set Depth: 2017 #55

A well’s surface section is drilled to 8,000 ft TVD where the pore pressure is 3,000 psig and the fracture pressure is 6,000 psig. At 4,000 TVD the pore/fracture pressures are 1,500/4,000 psig, and 5,000/8,000 psig at 10,000 ft TVD.

Assuming a trip margin of 200 psi and a kick margin of 500 psi, and a future intention to drill to 10,000 ft TVD once the surface casing is set, the maximum mud weight allowed to drill the surface section is closest to:   (A) 14.1 lb/gal (B) 13.2 lb/gal (C) 13.5 lb/gal (D) 13.8 lb/gal

This is pretty simple once you've read through all the details. See 6 DTC 6 (csg set depth) and it has the single needed equation: Max MW=(Pff - KM)/0.052(TVDshoe) = (5,000-500)/(0.052*8,000) = 13.2 or (B). The GB has the exact problem as an example.

Casing Design: 2017 #54

A well’s production casing will be set at a TD of 16,000 ft in 10.2 lb/gal mud. Which statement is most FALSE? 

(A) Production casing design should start at 16,000 ft and move uphole. 
(B) Casing collapse resistance must be reduced for tension if below 13,500 ft. 
(C) Casing collapse resistance needn’t be reduced for tension if below 14,500 ft. 
(D) Casing collapse resistance must be reduced for tension for casing above 12,500 ft. 

This problem has a lot of garbage you don't need (I don't include it here). (A) is clearly true (csg design starts on bottom and moves uphole; look up as needed). (B) through (D), however, are really the same question regarding collapse in relation to depth.

Solution: See Guidebook 6 DTC 9 that covers casing design and the neutral plane. Next, look up the 10.2 ppg buoyancy factor to calculate the hole section's neutral plane (16M*0.844 = 13,500 ft). The rest is academic; as TS 12 puts it on P430: Collapse performance properties will require derating for tension above the neutral plane. So (B) is false. 

But watch the wording on these types of problems like a hawk. You might work 5 minutes then mess up the answer due to some double-negative in the wording, confusion over "above" versus "below" the NP, or if the text is actually "true" or "false", even if you understand the problem fully. For this reason I always save 30 seconds for a check/re-read of each problem. Paranoia here is your friend.

Csg MW Max/Min: 2017 #36

For casing set depth:
MW max is limited by prior casing shoe fracture pressure (minus kick margin).
MW min is limited by BHP (plus trip margin).

In this problem:

3,000 psi = 0.052(MWmax)4,000 ft
...so MW max = 14.4 ppg

 6,000 psi = 0.052(MWmax)9,000 ft
 ...so MW max = 12.8 + 0.2 = 13.0 ppg

Pipe Collapse: 2017 #14

The problem reads: Given 5-1/2” 26 lb/ft N80 casing with 40,000 psi tension: find the reduced collapse rating (if your older copy is missing pipe weight, please assume it):

The whole problem can be solved never leaving 6 DTC 4.
The 80 clues us to an max axial stress of 80,000 psi. Add the internal pressure to compute: (40,000 + 20,000)/80,000 = 0.75.
Enter this into the GB table (ellipse of plasticity) for -0.385.
Solve using GB equation (with collapse rating from HES Redbook of 12,650 psi) for: 12,650(0.385)+20,000 = 24,875 psi.

Casing: 2018 #80

Problem 80: The most accurate statement about oilfield casing is: 

(A) API classifies casing by five properties, namely: manner of manufacture, steel grade... 
(B) There are only 12 steel API standard casing grades, which includes L-80 and Q-125. 
(C) If oilfield tubulars experience collapse, most do so in “elastic” & “transition” regimes. 
(D) A tieback provides pressure integrity from liner top to wellhead & can be partially cemented.

This solution is found on Guidebook 6 DTC 11. Further information is in HS II.

(A) Length range, not new or used. So false.
(B) 10 steel API standard casing grades, not 12. Also false.
(C) Most collapse is in “plastic” & “transition” regimes, sans "elastic". False.
(D) True; this is what a "tieback" is, and it can indeed be partially cemented. 

Casing Design: 2018 #66

Problem 66: The following 5.5-inch casing options are available for a 11,000 ft hole (the casing will be run empty into 11.5 lb/gal mud):

lb/ft Type $/ft.
14.0 J-55 6.50.
15.5 K-55 7.70.
17.0 K-55 8.80.
17.0 C-75 9.70.
20.0 N-80 10.30.
23.0 N-80 11.60.

Considering collapse, tension, and burst (use max. pressure of 5,000 psi) the most economical casing design option using safety factors of 1.25 (and ignoring buoyancy) will use mostly: (A) J-55 (B) K-75 (C) C-75 (D) N-80.

Use Guidebook 3 HYD 2.  Also A Guide to Professional Registration for Petroleum Engineers, 6th Edition 1991 has a similar example. Steps:

1. Pb = 5,000(1.25) = 6,250 psi. Thus J-55, K-55 fail due to burst; others good.
2. pc at bottom of hole = 0.052(11.5 ppg)11,000 ft(1.25) = 8,223 psi.
3. The next least expensive csg is 17 lb/ft C-75 pc = 6,040 psi.
4. Max. set depth of next least expensive csg: 6040/[0.052(11.5)1.25 = 8,080 ft.

So C-75 used from surface to 8,080 ft; more than half of the 11,000 ft thus (C).

This is an ugly problem for two reasons: 1) 6 csg options to work through, and 2) multiple casings could be together (which means a lot of calculations for tension & burst). So you have to be smart about how you work it plus not fall into the trap that only one casing type must be used (which gives the wrong answer of (D).

OCTG: 2018 #48

Problem 48. The statement regarding OCTG corrosion most TRUE is: 

(A) Higher fluid flow rates lower corrosion rates because the pipe is kept cleaner. 
(B) High temperatures and higher-stress states accelerate hydrogen embrittlement. 
(C) Grades such as C-090 and T-95 are especially susceptible to sulfide stress cracking. 
(D) Carbon dioxide alone is a is noncorrosive gas. 

The first thing to figure out: what is "OCTG"? If you know, great. If not, look it up fast:

1. Guidebook TOC: not there (the GB rarely has definitions).
2. Dictionary under O: not there (this surprises me, actually).
3. HS Index: not there (again this surprises me).
4. TS12 Index: I choose TS12 because the context suggests pipe/casing related: Bingo; P385 & 395. It stands for Oil Country Tubular Goods.

Note that TS2, the other SPE drilling book, does NOT have this in the index. TS2 simply doesn't cut it anymore, you must have TS12 as well (in my humble opinion).

Now that I confirm the subject I use 6 DTC and TS12 to discover:

A: High flow removes protective film. So this is false.
B: Low temp actually accelerates...  So again this is false.
C: These grades were developed to resist SSC. Once again false.
D: CO2 is very corrosive with water but alone is noncorrosive. True, and so the answer.

Get used to this way of testing. Never panic on an exam if you see terms you don't know, just march through your resources like a machine, never hesitating to quit if it's not there. Time is of the essence; don't spend more than 30 minutes on 5 problems is a good rule of thumb.

Combo Stress: 2018 #25

Problem 25. A 6 in., N-80 23 lb/ft casing has 20M psi of internal pressure. If 20M psi of total axial stress is applied to the casing, the annulus pressure (Mpsi) closest to the pipe's collapse rating is: (A) 22.8; (B) 28.8; (C) 25.8; (D) 31.8.

This is a standard combo stress problem; 6 DTC 4 has a cheat sheet that is faster to use than the ellipse of plasticity, and this page walks you through the calculation as well:

1) (σz + pi)/σyield = (40M + 20M)/80M = 0.75
2) Chart: --> 0.75 ---> -0.385 = (pi - pcrr)/pcr (note negative sign for collapse)
3) pcrr = pi - (-0.385)pcr) = pi + 0.385(pcr) = 20M + 0.385(pcr)
4) Redbook: 6 in. N-80 collapse rating of 7.180M psi.
5) pcrr = pi - (-0.385)pcr) = pi + 0.385(7,180) = 20M + 2.764M = 22.8 M (C).

Casing/Hole Sizes: 2018 #7

This is a standard problem, with the answer found on 6 DTC 7. The chart is found in many other places but the Guidebook version uses square, evenly spaced formatting for speed (other versions I've seen get fancy with the pipe more "real-looking" and slower to use, at least for me).

Note the answer (B) had incorrect wording on the original publication (it was missing the "do not require" part) but should now be corrected. Just re-download the new version to correct this as desired.

Collapse; Tension & Pressure: 2005 #2 (similar)

Given: 7 in. P-110 casing (D/t = 7/0.59) with axial tension of 50M & internal pressure of 11M psi. Collapse pressure (psi)?

Combined tension and pressure? Complex. Use 6 DTC 4:

1) (σz + pi)/σyield = (50M + 11M)/110M = 0.554
2) Chart: --> 0.544 ---> -0.60 = (pi - pcrr)/pcr (note negative sign for collapse)
3) pcrr = pi - (-0.60)pcr) = pi + 0.6(pcr) = 11M + 0.6(pcr)

We're here in less than 2 minutes but still need pcr. The Redbook shows 7 in. P-110 casing's collapse rating is 16,990 psi. Of course you can calculate it (from D & t; see the formula on 6 DTC 2) but it's faster to use the Redbook. This allows us to calculate collapse pressure in this situation:

pcrr = pi - (-0.60)pcr) = pi + 0.6(16,990) = 11M + 10.1M = 21.1M.

3 minutes. Not bad! We've lost at least half our engineers by now on an exam. Last but not least: do a quick mental check; does internal pressure strengthen or weaken collapse? Clearly strengthen, and that's what the equation shows. Just be careful; it's easy to make a sign mistake.