Vogel IPR: 2005 #64 (similar)

Vogel IPR problems generally involve: 1) calculating Vogel IPR using the qo/qmax equation (see 7 PRD 1 on how to calculate qmax from a given well test, in this case say, 600 BOPD), 2) calculate qo for a range of FBHP that crossover the TBG curve, and 3) note that the well's natural flow rate is where the IPR & TBG curves cross. That's it.

From the calculated and plotted IPR example below, it's easy to see the roughly 338 psi crossover. For this example, the TBG curve is simply given and the IPR calculated (using as few points as possible, just the crossover area).

For a good explanation of this problem type, see Well Performance by Golan (P29), or Production Optimization by Beggs (P142). Both these resources are excellent (I own both even though they have quite a bit of overlap).

Note that neither of these sources are SPE. Personally, I find the lack of example problems for nodal analysis (or total system analysis) to be a major gap in the SPE Handbook and the SPE Textbook Series. For this reason, I've never spent much time on this problem type. However, I get continual questions about it so I'm showing a detailed similar solution and how to use the Guidebook's applicable section for it. Also, for anyone interested in more explanation the SPE 6th Edition (1991) has an excellent example problem they walk you through as well.

However: Vogel IPR as a "concept" is definitely fair game and is found in HS IV P1-40 (albeit with a lack of example problems or number examples). So understand IPR (including Vogel, Fetkovich, Jones, and Wiggins, who wrote HS IV C1). I'll try and fit an IPR-style problem into the Guidebook Companion 2018 41-80 to help with reviewing this problem type.

IPR Vogel Equation
bopd psia
259 1600
329 1400
392 1200

Given TBG curve 
bopd psia
200 1450
300 1390
400 1350

 

Economics Present Worth: 2005 #27 (similar)

Assume a $700M investment, a lease abandonment cost of $50M, and a 15% discount rate. Then assume the following years of revenue (minus expenses & taxes):  $650M, $330M, $150M. For Present Worth, use the standard NPV formula:

-700M + 565M + 250M + $99M - $33M = $180M

This is painfully easy except for the abandonment cost part, which must be both subtracted and discounted (it's easy to space out on either of these; the typical problem uses salvage value, which is added not subtracted). Watch for the answer options to offer solutions for either mistake.

I can't implore enough to warily check these "easy" economics problems. The number of smart guys who miss these problems is myriad. I triple check these because they are so easy yet so easy to slip up on. Because overconfidence. 

Vogel & Flow Efficiency: 2005 #26 (similar)

Vogel problems often involve flow efficiency (FE). Why? They both need Pwf & Pr.

Example: Say Pwf = 1M and Pr = 2M psi at q = 490 BOPD. What is qmax?
Go to the Vogel table (7 PRD 1) with Pwf/Pr = 0.5; note qo/qmax = 0.7.
So qmax = qo/0.7 = 490/0.7 = 700 BOPD.

But what then if FE is 0.7 and we stimulate to an FE = 1? See 12 WLT 2:

Another way to describe FE: the percentage of well fluid producing at a given drawdown compared to what it would produce with zero skin (FE = 1).

So at FE = 1.7M/0.7 = 1,000 BOPD.

Hydrostatic: 2005 #24 (similar)

Sand at 9,000 ft. Pr = 4,000 psi. Two fluids. Which A-B-C option below is 500 psi underbalanced?

(A) 3,000 ft 0.1 ppf N2 cushion, 6,000 ft 10 ppg, 80-psi surface pressure.
(B) 2,000 ft 0.1 ppf N2 cushion, 7,000 10 ppg, 160-psi surface pressure.
(C) 2,500 ft 0.1 ppf N2 cushion, 6,500 10 ppf, 400-psi surface pressure.

Use the hydrostatic pressure equation (2 DRL 1). Calculating pressures p = 0.052(D)MW) + gradient(D) + surface pressure - reservoir pressure for:

(A) 300 + 3,120 + 80 - 4,000 = -500 psi
(B) 200 + 3,640 + 160 - 4,000 = 0 psi
(C) 250 + 3,380 + 400 - 4,000 = 30 psi

Expect this sort of problem with any fluid, depths, or pressures. Just remember to line them up in an orderly fashion; speed is of the essence.

Net Piston Force: 2005 #23 (similar)

Tubing movement problems often ask for a specific force (Guidebook 6 DTC 9).
Here the "Net Piston Effect" is shown.

Say Csg & Tbg pressure changes are:
     dPcp = 500 psi (often given as pre-post job csg pressure).
     dPtp = 3,000 psi (often calculated by hydrostatic).
Packer, Tbg, & Csg areas: Apb, Ati, Ato = 7.1, 7.0, 9.2 sq in (given or from dia).

The packer (7.1) is larger than tbg id (7); so the GB predicts a negative (up) force:
Fp = dPCp(Apb-Ato) - dPTp(Apb - Ati)
Fp = 500(7.1-9.2)-3,000(7.1 - 7.0) = -1,385 lbf (up).
Fp = 500(-2.1) - 3,000(0.1)
Fp = -1,050-300 = -1,385
Fp = 500(7.1-7) - 3,000(7.1-9.2) = -1,385 lbf (up). This checks.

To calculate tbg length change? Say the tubing is 10,000'; tbg area is 9.2 - 7 = 1.8 sq in:
LtF/EAt = (10,000 ft*1,385 lbf)/(30M*1.8) = 0.15'*12 = -1.8 inches (up)

The entire tubing move section is a single page, with all the variables listed to the right.

Balloon Force: 2005 #22 (similar)

6 DTC 9 is one of my favorite Guidebook pages (TBG Move). It shows all the forces you will need on a single page. It was a labor of love.

So if you are asked for the force from say the ballooning effect, it's just a glance: Keep in mind the dPt and dPc are pressure changes, so find the initial and final pressures in both the casing and the tubing.

You typically chase down the BHTP using hydrostatic. For example at 10,000 ft, 8 ppg:
Initial Tubing: 0.052(8)10,000 = 4,160 psi. If surface: 0 psi, dPTa1 = 2,100 psi
Final Tubing: Surface & BHP say 6,000 & 7,900 psi you average: dPTa2  = 6,950 psi
From initial & final tubing psi, find the change by subtracting: 6,950 - 2,100 = 4,850 psi

Casing pressure change is often just given as an increase, say 1,000 psi.
Calculate or look up the tubing ID & OD area. That's easy; here we will use 7.0 & 9.6 in.
Thus: -0.6 [(4850*7) - (1000*9.6)] = -14,600 psi (up).

The units are negative (note the sign in front) which means tension.
Since pressure increased, we should indeed see tension if the packer is fixed.
These problems can be very confusing. Go slow; be sure the numbers make sense. Once you've done a few, it's fairly easy.

Beam Counterbalance: 2005 #20 (similar)

Counterbalance is calculated fairly easily. No fancy charts; it's all in the Guidebook.
Rod Pump equations are found on a single page 7 PRD 9.
The counterbalance equation (CBE) is step #27. It references steps #1, #5, #15-16.  Again, easy:

#1: Wr is found on 7 PRD 10 in C3, and is the Wgt Rods / ft in air (lbf/ft)
#5: Fo = 0.340(G)D^2(H) which is Fluid Weight On Pump (lbf)
#15: W = Wr∙L which is Weight Rods total in air (lbf)
#16: Wrf = W(1−0.128 G) which is the Weight Rods total in fluid (lbf)
#27: CBE = 1.06(Wrf + 0.5 Fo)

The GB makes this calculation simple plug-and-chug. Just march through the steps.
Here, I'll assume standard 76 rods, 1.5 plunger, & SG = 0.85 (get this from oil API as needed).

#1: Wr = 1.833 (7 PRD 10 column 3 for 76 rods)
#2: Fo = 0.34(0.85)1.5^2(8,800') =  5,850 lb
#15: W = 1.833 lb/ft(8,800') = 16,500 lb
#16: Wrf = 16,500 lb [1-(0.128*0.85)] = 14,700 lb
#27: CBE  1.06 (14,350 + 0.5*5720) = 18,700 lb.

In real life, you may measure CB to find the difference between calculated CBE and actual CB.
For example, if measured CB was 18,500 lb, you are 200 lb short.

Be careful on these problems to keep it simple. Don't panic at all the possible options from extra data like dyno cards, unit type, etc. Just assume it's going to be simple, focus, and march through the steps.

Every item on this type of problem can be found in the GB: Wr, Fo, W, CBE. It's in tables on 7 PRD 9, in order, with a typical number.

Rod Pump Volumetric Efficiency: 2005 #17 (similar)

Volumetric Efficiency for a rod pump is an easy problem. So do it fast.

7 PRD 9 is the Guidebook page for all Rod Pump equations. It's got everything; no flipping pages! For a quick example from the page:

1) Pump volume displaced equation: PD = 0.1166(Sp)D^2(N).
2) Total fluid pumped is usually given: say 370 BFPD.
3) Given pump data: Sp = 90"*, D = 2", N = 10 SPM.
        *Sp, or stroke, is often presented as the pump third number (see 7 PRD 9).

Calculation: 0.1166(90)2^2(10) = 420 BPD
Volumetric Efficiency = BFPD/PD = 380/420 = 90%

Rod Pump: 2005 #18 (similar)

Q: What pumping unit change reduces torque the least? 1) Reducing stroke length or speed, 2) Changing rotation direction, or 3) Installing larger rods?

A: Reducing stroke length or speed lowers torque. Larger rods? This doesn't "reduce" torque at all. So that would be my choice.

On a sidenote: changing direction is a bit more tricky to consider. Why? Class III (& Mark II) API specs recommend the crank arm rotate in the counterclockwise direction only. Class I can operate in either direction but this is not recommended for many reasons. Greater torque spikes clockwise is one of them. 

PBU: 2005 #16 & #68 (similar)

The standard pressure buildup (PBU) question wants skin, pressure drop, or radius of investigation (ROI). 12 WLT 12:

Variables:
B FVF bbl/STB
ct compressibility 1/psi
h thickness reservoir ft
k permeability md
MTR middle time region
p pressure psia
pwf pressure well flow psia
q flow rate well last STB/hr
ri radius investigation ft
rw radius wellbore ft
tp time produced pre-SI hr
Δt time new well SI after tp hr
ϕ porosity x.xx
μ viscosity cp

Example: q = 100 BO/D, h = 50 ft, Bo = 1.4 RB/STB, μ = 0.8 cp, & a graph of psi vs (tp-Δt)/Δt with an MTR of m = 300 psi (use one log cycle):

k = [162.6(100 BO/D)1.4 rb/STB(0.8 cp)]/[300*50 ft] =  2.25 md

From here, the ROI from SI pressure transient (say after 2 days) calculates from a simple equation on 12 WLT 6. A few more variables like ϕ (say 12%) and ct (say 4E-6 /psi) are needed:

ri = [2.25 md(48 hr)]/[948(0.12)(0.8 cp)4.3E-6 psi]^0.5 = 540 ft

Skin is calculated using tp (say 72 hr) and PBU data (tp+Δt)/Δt. Use Δt = 1 hr (easier division); this means (tp+Δt)/Δt = (72 hr+1 hr)/1 hr = 73 hrs. Now: back-extrapolate MTR to 73 hrs for pressure; 2,500 psi is a typical value. Subtract from given Pwf for drawdown (say 1,000 psi) and then divide by slope m over one log cycle.This is the skin equation's first term. 6.5 would be typical.

Using our our prior data, plus the well diameter (assume 4 in diameter) we can calculate skin:

s = 1.151[(P1hr-Pfbhp)/m]-log[k/[(por)(vis)ct(rw^2)]+3.23
   = 1.151[6.5-log[2.25[(0.12*0.8*4.3E-6*0.125^2]+3.23
   = 1.151[6.5-6.7+3.23] = 3.5

Archie Cementation Factor m: 2005 #11 (similar)

Given a formation with known porosity (say 9%), Ro (say 25 ohmm), and Rw from a core test (say 0.25 ohmm): calculate the formation cementation factor (or exponent m; this may be called either).

Two equations for F are on 15 LOG 1, with 2 variables each. Given 3 of the variables (we are missing only m) this is easy to solve. The Guidebook actually gives the equation for m here so it's just plug-and-chug.

Problems like this may show many sample points; if so, it doesn't matter which you choose. But you can check your work using a second set if you have the time.

F = Ro/Rw = 25/.25 = 100
F = 1/por^m = 1/0.09^m
(m)log(por) = log(1/F)
m = log(1/F)/log(por)
m = log(1/100)/log(.09)
m = -2/-1.05 = 1.9

Be aware on other problems you may be asked for (or given) a tortuosity factor "a" (F=a/por^m) rather than a = 1 (the norm). It's all on the 15 LOG 1 page if this unlikely event arises.

Mud Cleaning: 2005 #7 (similar)

One must often select the most cost effective mud cleaning equipment given a desired particle size. Those problems are easy using 4 MUD 6 of the Guidebook (below is the relevant part):

Solid Control Equipment Order:
1. Shale Shaker: down to 75 μm particle size
Mesh ex: 70x30: 70 openings/in one direction, 30 in perpendicular
Degasser (vacuum pump) or Gas Separator (no pump)
2. Mud tank:
Mud Agitator: prevents “steeling”
Mud Gun: flushes tanks
3. Desander: down to 45 μm, Desilter down to 15 μm
…fine screens can replace desander/desilter for power savings
Mud Cleaner: parts 1-3
4. Hydrocyclone: changes flow path; solids into cones
5. Centrifuge: rotating drum; rotation speed variable
6. Additives: Chemical, Bentonite, Water

75 + μm? Shaker.
75 - 45 μm? Shaker + Desander.
45 - 15 μm? Shaker + Desander + Desilter.

Pump HP: 2005 #3 (similar)

Calculating drilling pump horsepower? Total pressure drop is needed (pipe, bit, annulus, surface).
We will assume annulus & surface pressure drop is 0.
All 5 equations needed are on a single Guidebook page, 3 HYD 1.

1) For pipe pressure drop (say MW=10ppg, PV=40cp, V=14 fps, 500 gpm, 10M ft):
 dP/dL= (ρ^0.75 V^1.75 μ^0.25)/1,800 d^1.25
dPd/10,000 = (10^0.75 14^1.75 40^0.25)/1,800*3.8^1.25
dPd = 1,500 psi.

2) Not given pipe ID? Merely back-calculate ID from your 14 fps & 500 gpm:
d=[q/2.448V]^1/2 = 500/[2.448*14)] = 3.8 in.

3) For bit pressure loss (given nozzle area = 0.39 si):
dPb = 8.311E-5 MW q²/[C_D² A_t²] dPb = 8.311E-5(10)500²/[0.95² 0.39²d
Pb = 1,500 psi.

4) So total pressure drop over the pumping system is 1,500 + 1,500 = 3,000 psi.

5) Enter this into the standard HP equation:
[dP q]/1,714 = 3,000*500/1714 = 875 HP.

This is a tricky problem; step 2 is especially mean. Yet the equations do logically progress on a single Guidebook page, making it easier.

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.

Petroleum PE Problems 2018: 1-40

The 2018 Guidebook Companion is available on Amazon. I only publish these on Kindle to keep the cost <$10.

The sample problems look great on a smartphone or computer using the free Kindle app. The format displays two problems per page; all you need is scratch paper.

These problems reference the 2018 Guidebook exclusively (which has new sections and additional material). It also leans heavy on the SPE Handbook (although every problem can be solved using the 2018 Guidebook alone).

These practice problems were reviewed by three different 2017 PE exam takers, each giving it the thumbs-up. Harder than the 2016 and 2017 versions in my opinion (with some new twists) so I think they offer a challenge to nearly everyone. However, I personally find the 2016 version the most applicable to reality, and many agree with me. YMMV. I've been surprised at the diversity of opinion out there: one person's yawn is another person's bane.

My intent is to have problems 41-80 out by September; wish me luck.

ESP

Some interesting points regarding ESPs: the older SPE Handbook (Bradley 1987) has two seemingly contradictory quotes on the same page (7-1):

a) The ESP has the broadest producing range of any artificial lift method.

b) The major disadvantage of the ESP is that it has a narrow producing rate range compared with other artificial lift forms.

What is correct?  Here's what the newer SPE Handbook says regarding ESPs:

1. 200 to 20M B/D typical (30M max).

2. High-Volume Lift Capacity excellent

3. Low-Volume Lift Capacity generally poor: low efficiency & high operation costs <400 BFPD. 

4. Limited by needed horsepower.

5. Can be restricted by casing size.

Hard to know what Bradley was trying to say. Just be aware of both SPE sources, and let this be a lesson on how language can make an otherwise simple question more difficult. I like to underline these "money quotes" in pencil in my Handbook when I run across them.

SPE Petroleum Engineering Certification and PE License Exam Reference Guide (Ghalambor, 2014)

Below is my Amazon review. I'm posting this here since I get so many questions about this book. As you can see, I like the book, but not for the PE Exam. Why? It's designed for a different exam, lacks number examples for the equations, and is not easy to search to find the correct formula. Feel free to ask questions or make your own assessment in the comment section below.

To be clear about what this book is: it’s a list of equations, graphs, and tables. They are broken up into the following six subjects:

Reservoir Engineering
Drilling Engineering
Formation Evaluation
Production Engineering
Facilities
Petroleum Economics

Strong points:

1. Comprehensive. I would add a few here and there, but one must draw the line somewhere.
2. Clear print. Big graphs.
3. Each variable listed after the equation.

Weak points:

A. No numbers shown with equations! This makes many hard to use, even if you understand them.
B. No explanations! You better understand these equations before you use them.
C. Let’s be clear: this book is just a list of equations/graphs/tables, nothing more.
D. No easy way to find what you need besides the six chapters. You have to know this book well to make it useful on an exam.
E. Ring bound. This is both a plus and minus, just be aware of it.

In summary: if you want a comprehensive book of equations without numbers or examples, this book is for you. I’ve found it makes for a useful office reference. Just don’t expect much more except some graphs and tables (which are not comprehensive, but pretty complete for general use). It is the primary and only allowed reference for the Certification Exam, but I wouldn't bring it to the Professional Engineering Exam unless I knew it very well and supplemented it with notes.

SPE Petroleum Engineering Handbook (Bradley 1987)

There are only a few useful SPE books for the PE Exam. Bradley's SPE Petroleum Engineering Handbook is one. On the used market it goes for $100 to $200. My Amazon review is here.

I bring this up because I'm often returning to Bradley. I'm amazed at how concise and well-organized this text is. I'm currently updating my reservoir section with a few "money quotes" from Bradley. Remember, this is still an SPE reference, and thus it's fair game on the PE Exam.

In fact, I know several people who used it exclusively for their PE Exam and did well. One of the reasons it still shines for the exam is how tight it is: no wasted words. Clear explanations. Simple format for quick reference. And it has a lot of practical, work-related stuff the newer Handbook series leaves out for some reason.

In summary: because the new Handbook Series is out, people are selling their old Bradley Handbooks thus making them at least "somewhat" affordable. Back in the day, it was a collector's item and very hard to even find. So while quite dated it's worth another look as a primary reference.

Petroleum Engineering Guidebook 2018: Now Available

Over the last two years, the Petroleum Engineering Guidebook has had five printings. And some major improvements along the way.

The original book was merely my own unedited notes, albeit carefully compiled for a decade. I gave copies of these away to friends and other engineers taking the PE Exam.

However, as new requests overwhelmed my limited printing resources (and my wife's patience) I listed it on Amazon to cover printing costs. I then slowly cleaned up the typos over 2016 and 2017 (with suggestions from other engineers; thank you, you know who you are!). The latest edition, an officially bound, paperback book, is sold, printed, and shipped directly from Amazon.

The Guidebook was always intended for industry use. Because of this, I kept practice problems separate. Upon request, however, I generated digital problems that test-takers can use alongside the Guidebook for practice. Note I provide digital format only and advise not bringing practice problems to the PE Exam itself. Why? If you waste time trying to find the "right" type of problem you will likely do yourself more harm than good. Those test-writers are smarter than that.

So the most current book (2018, 1st edition) is a $55 paperback. It's got new additions requested by 2016 & 2017 test-takers (such as hydrates, economics, probability, decision trees, bits, produced water, etc.).

Here's the thing: if you have purchased a spiral copy from me through Amazon I'll replace it with the new paperback at cost. Just mail me your old book with a self-addressed, stamped envelope and PayPal my email $3 (or put it in envelope) to offset printing costs (but email me first so I can verify you are an original purchaser & get a book ready). It's going to be a first-come, first-serve thing.

UPDATE: I'm mailing off 3 books today but I still a lot left. So even those who have plagiarized versions (there are a lot floating around), send me an email and we can arrange a swap of some kind. The new version is much better, especially for the exam.

PEH Volume I Chapter 12: Crude Oil Emulsions

C1-3: Math
C4: Fluid Sampling
C5: Gas Properties
C6: Oil Correlations
C7: Thermo/Phase
C8: Phase Diagrams
C9: Asphaltene/Wax
C10: Produced Water
C11: Phase Behavior
C12: Emulsions
C13: Rock Properties
C14: Permeability
C15: Relative Permeability
C16: Economics
C17-18: Law

Emulsions are a common yet poorly-understood oilfield reality. Like hydrates, they seem to slip through the cracks and few want to claim them: do they belong to facilities, PVT, or production? I've just added yet another page to the Guidebook that deals with this complicated subject (7 PRD 13). The primary source? PEH chapter 12. See below:

Produced water: normally “free”; if an emulsion, typically:

water droplets dispersed (as internal phase, same surface area)…

…within oil or other (the external/continuous phase).

May be: “water in oil” (up to 80% water cut), or “oil in water” (>80% water cut), or more complex.

Emulsions: found everywhere; reservoir, wellbore, wellhead, facility, plant.

Created by: mixing (valves, pores, etc.) + emulsifier (stabilizing agent, such as fine solids & surfactants).

Surfactants: compounds partly soluble in oil and water.

Water-wet particles stabilize oil-in-water emulsions; Oil-wet particles stabilize water-in-oil emulsions.

Natural emulsions come from the “heavy” crude fraction.

Asphaltenes change wettability of solids so they act as emulsifiers.

Waxes crystalize if cooled below “cloud point” and create emulsions.

Tighter emulsions mean more, smaller droplets (more stable).

Sedimentation: settling water in an emulsion (due to oil/water density differences).

Creaming: raising oil droplets in the water phase (due to higher density of oil).

Emulsion treatment (demulsify) typically means removing water & associated salts.

Demulsification breaks emulsion to oil & water phases: 2 steps 1) flocculation, 2) coalescence.

Flocculation: aggregation/agglomeration/coagulation of component phases.

Coalescence: droplets irreversibly fuse (larger drops/lower surface area); high water cut enhanced.

Treatments: chemical (common), heating (common), electrostatic field (coalescence), settling.

Chemical demulsifiers: surface-acting compounds that neutralize emulsifying agent stabilizing effect.

Emulsion separation time: hours to days = “stable” or “tight”; minutes = “loose”.

Aromatic content in crude reduces emulsification.

Stability measured with a bottle test (estimates demulsifier phase separation time).

Mechanical emulsion-breaking: free water knockout drums/separators/desalters/settling tanks.

Emulsion prevention: reduce solids/chemicals/acids (make very tight emulsions)/mixing/turbulence.  

Macroemulsion & microemulsion differences because of formation and stability differences.

Macroemulsion: drop size >0.1 micrometer and will separate (thermodynamically unstable).

Most oilfield macro droplet coalescence can be reduced through a stabilization mechanism.

Microemulsion: drop size <10 nanometers, separate (thermodynamically stable).

Emulsion Separation Index Test (ESI): quantitative method for lab demulsifier testing (I-569).

…measure water amount separated at 5, 10, 15, 20 min; then 20 min centrifuged.

…bottle tests have a “qualitative” edge (due to sampling/operator/measurement error).

…uses dead crude (yet fresh emulsion samples to minimalize error).

Calculating ESI = [(Sum of Volume Separated with time)]/[(%BS&W)(# tests)]

Example: ESI = [0 + 4 + 12 + 19 + 25]/[(25)(5)] = 48% water separation

PEH Volume I Chapter 11: Phase Behavior

I've recently added a page to the Guidebook on Hydrates. Prior editions had the basics, but I found over time I wanted more detail on this complicated subject. 

C1-3: Math
C4: Fluid Sampling
C5: Gas Properties
C6: Oil Correlations
C7: Thermo/Phase
C8: Phase Diagrams
C9: Asphaltene/Wax
C10: Produced Water
C11: Phase Behavior
C12: Emulsions
C13: Rock Properties
C14: Permeability
C15: Relative Permeability
C16: Economics
C17-18: Law

Hydrates: the most common solid-phase flow-assurance problem.
H2O & HC typically have 2 separate phases…because H2O bonds >> strength than HC bonds.

Hydrates are found at Low Temperature and High Pressure.

    …OR in small-sized HC < n-pentane size (I-501).

3 hydrate structures common in HC yet some are unknown (I-508).

Intense variables: T, P, and compositions.

Gibbs phase rule (I-335).

F = C – P + 2 used for:

   …how many intensive variables important in phase equilibria.

   …for small number of components.

   …insight to max number phases that can form.

   …insight to number of intensive properties independently specified.

Example: 1 phase, 1 component: only 2 intensive properties can be specified (degree of freedom 2).

Example: 3 phases, 2 components: only 1 intensive property can be specified.

Gibbs P, T diagrams (I-512; semilog plots for nearly straight lines).

2-component system: “area”. 3-component system: “line”. 4-component system: “point”.

Single NG components Hydrate for 3-phase conditions (CH4, etc. Table 11.6).

Water Content (lbm) per HC wet gas (MMscf) 60 °F, 14.7psia; correct for salinity, gravity (I-502 Fig. 11.1).

4 Types of H2O-HC Equilibrium PT Diagrams that include hydrates (I-509-512).

1. gases or vapors (say CH4, N2).

2. gas + single condensate + water (HC may be vapor or liquid).

3. gas + mixed oil/condensate + water.

4. H2O-HC hydrate + inhibitors (MeOH, MEG, salts; note methanol most economical).

Hand Calculatable: 3-phase Lw-H-V system hydrate formation or wet-gas expansion through valves.

NOT hand calculable: Lw-H-Lh, I-H-V, 4-phase BUT a Lw-H-V hand calcs can check computer quality.

Hammerschmidt Expression for inhibitors finds ΔT (65-X °F) = 2,335W / (100M – MW) (I-516, 521).

ΔT = hydrate temperature depression and constant regardless of pressure (65 °F – T °F).

W = weight % of inhibitor (free-water phase) shifting Lw-H-V line left below lowest operating temperature.

M = molecular weight of inhibitor (M = 32 for MeOH, 62.07 for MEG).

Hammerschmidt calculation examples:

ΔT = 2,335W / 100M – MW = 2,335(25) / 100(32) – 32(25) = 24 °F.

W = 100MΔT / MΔT +2,335 = 100(32)24 / (32)24 +2,335 = 25 %wt (of water + MeOH lbm mix).

1. Find gas gravity, temperature, pressure (of hydrate formation conditions).

2. Find W from the Hammerschmidt expression.

3. Find mass of liquid water, from condensed and liquid water (lbm water/MMscf of gas).

4. Find rate of MeOH in the aqueous phase W = MeOH/(H2O+MeOH).

Hydrate Formation on Expansion Across Valve or Restriction (I-524-528).

PEH Volume I Chapter 10: Produced Water

C1-3: Math
C4: Fluid Sampling
C5: Gas Properties
C6: Oil Correlations
C7: Thermo/Phase
C8: Phase Diagrams
C9: Asphaltene/Wax
C10: Produced Water 
C11: Phase Behavior
C12: Emulsions
C13: Rock Properties
C14: Permeability
C15: Relative Permeability
C16: Economics
C17-18: Law

Produced Water Properties (I-466-494):

Meteoric Water = water recently in contact with atmosphere (from surface).
Connate = Original sedimentary interstitial = Fossil water (away from atmosphere since settling).
Juvenile Water = never contacts atmosphere (from deep; mineral diagenesis --> water expulsion.

Water: chemical signature may ID depth (strata).
Water produced: increases as oil produced increases (usually; even primary production).
Water: excellent solvent: reacts to dissolve many phases it contacts.
Scale deposits on ESPs: precipitates due to motor heat.
Reserves typically limited by water handling costs (even secondary & tertiary).
Volatile organic acids: formic, acetic, propionic, butyric.
Dissolved aromatic compounds: benzene, toluene, xylenes (often included in oil carryover by law).
Hydrocarbon carryover in produced water: important issue for surface engineers.
Common scales: calcium carbonate, calcium sulfate, barium sulfate, iron sulfide, iron carbonate.
Scale inhibition: uses organic compounds to slow growth sites.
Scale inhibition: lab experiments, not just computers, needed to select inhibition compounds.
Corrosion prediction less certain than scale-precipitation predictions.
DST water sample: TDS increase downhole; ideal sample when TDS constant or final water to tool.
Water samples: taken from flowline (above) or wellhead.
Water tests: for compressibility, density, FVF, resistivity, surface tension, viscosity, pH, pE.

It's a good idea to review this section in the Handbook and highlight if unfamiliar.

PEH Volume I Chapter 9: Asphaltenes and Waxes

The 18 chapters in the Petroleum Engineering Handbook (PEH) Volume I are as follows.
This post will review Chapter 9:

C1-3: Math
C4: Fluid Sampling
C5: Gas Properties
C6: Oil Correlations
C7: Thermo/Phase
C8: Phase Diagrams
C9: Asphaltene/Wax
C10: Produced Water
C11: Phase Behavior
C12: Emulsions
C13: Rock Properties
C14: Permeability
C15: Relative Permeability
C16: Economics
C17: International Law
C18: 21st Century Law

C9 Review:

PNA: Paraffinic, Naphthenic, Aromatic (includes resins & asphaltenes) fractions. (I-400)
SARA: Saturates, Aromatics, Resins, and Asphaltenes. SARA Analysis: weight fraction method.

Asphaltenes and Waxes (I-397-400)
Deposited solids: asphaltenes, waxes, or a mixture (with resins, crude oil, fines, scale, water) Characteristics: Light C6 fraction (with N2, CO2, H2S), heavy end C6

Asphaltenes 
Asphaltenes precipitation in reservoir: by decreasing pressure or mixing oil with injected solvent. Asphaltenes precipitation near wellbore: by drilling, completion, acid, fracs, etc.
Heavier crudes have less asphaltenes-precipitation problems than lighter crudes.
Primary production has maximum asphaltenes around the saturation pressure.
Asphaltene precipitation/deposition envelope (APE) has dependence on both P & T.
APE: the region which asphaltenes precipitation occurs.

Waxes 
Wax precipitation envelope vertical P/T curve; strong dependence on T but weak on pressure.
Wax crystals tend to fluid disperse (deposit on a surface more likely among fines, asphaltenes, clays). Temperature drop is most common cause of wax deposition; oil/gas expansion (sandface, orifices).

PEH Volume I Chapter 8: Phase Diagrams

Phase Diagrams:
     Critical Temperature: max T two phases exist (higher T only vapor).
     Critical Pressure: max P two phases exist (higher P only liquid).

Surfactant/Polymer Flood: oil/water soluble mix reduces interfacial tension oil/H2O interface.
Gas-Injection: miscible displacement eliminates oil/displacing phase interface capillary forces.

Phase Rule: component number determines max number of phases coexisting at fixed T, psi.

Phase Diagrams: Plait Point: where bi nodal curve liquid & vapor portions meet and compositions are identical.. 
          Binary: Vapor/liquid; fixed T; pressure-composition (p-x-y) 2 components (I-373-375). 
          Ternary: 3 components; each component equilateral triangle. (I-376-381). 
               …composition expressed in volume, mass, or mole fraction; 100% on each corner. 
               …line parallel to a side is a constant fraction of the opposite corner component.
               …perpendicular lines from any composition point to each side (LT) sums to any side.
               …two phase regions fall on the triangle sides. 
          Quaternary: 4 components; tetrahedral diagram, faces are ternary phase diagrams.

Reservoir Fluid Systems: See Guidebook 13 RES 10

Much of this material is being added to the Guidebook; in the meantime, feel free to pencil it in.

Note that ternary diagrams are a rich target for questions; read section 8.5 carefully. Understand how the ternary diagram is used, and underline the key passages relating my notes above. Often, what makes sense physically isn't so clear when put into words, and vice-versa.

Be warned: I've observed each person will have their own weak areas on this subject; your needed focus may be different than mine or others. So skim all the material and underline key passages (in pencil: in a year the subject may seem bloody obvious so leave the option to erase half of it later to keep your focus on weak areas).

PEH Volume I Chapter 5: Gas Properties

The next chapter in Volume I of the Petroleum Engineering Handbook worth reviewing is Chapter 5: Gas Properties.

Most of what you will need regarding gas properties is in the Petroleum Engineering Guidebook on page 9 PVT 2. Review this page closely, especially the notes and equations. Know how to use the chart.

Below is some additional material. Again, if unfamiliar with anything (especially terminology) read those sections in detail until it makes sense. Otherwise, the outline should suffice.

_______________________________________________ 
Gas Properties:
     CRITICAL: gas can't be liquid
     IDEAL: gas particle volume negligible compared to total gas volume
     PSEUDO: gas mixture
     PSEUDOPOTENTIAL: integral of pressure divided by z factor & viscosity (more accurate)
     REAL: gas particle volume considered; z = real/ideal volume; pV = znRT

Gas Viscosity:
     I-237-240    
     Estimate by chart, Carr et al

Vapor Pressure or Normal Boiling Point:
     I-241-252
     Pressure when vapor & liquid in equilibrium
     Use for pure substance only
     Estimate using: 
          Clausius-Clapevon equation (ideal gas only, accurate <~0.2 psi)
          Cox Chart 
          Calingeart & David or Antoine equation (generally <2% error) 
          Lee-Kesler equation (most accurate)

Petroleum Engineering Handbook: Volume I

The 18 chapters in the Petroleum Engineering Handbook (PEH) Volume I are as follows:

C1-3: Math
C4: Fluid Sampling
C5: Gas Properties
C6: Oil Correlations
C7: Thermo/Phase
C8: Phase Diagrams
C9: Asphaltene/Wax
C10: Produced Water
C11: Phase Behavior
C12: Emulsions
C13: Rock Properties
C14: Permeability
C15: Relative Permeability
C16: Economics
C17: International Law
C18: 21st Century Law

The first chapter in Volume I that is worth reviewing is C4: Fluid Sampling.
Below is an outline. If any of the material is unfamiliar (especially terminology) read those sections in detail until it makes sense. Otherwise, the outline should suffice.

I would especially note the section on "gas sampling for reservoir oil remix"; understand how to use the chart.

Note the list below seems pretty short and simple at first glance, but it's really not. It literally took hours to cull the wheat from the chaff to make this reference. Be aware: 90% of this chapter lacks utility for the average engineer but it's hard to sort it out at a glance.

_______________________________________________ 
Fluid Sampling: RP44

BS&W: Basic Sediment & Water

DST: Drill Stem Test; note samples often unconditioned (early flow)

GOR: Gas Oil Ratio; often largest sample error

P&T: Pressure & Temperature

RFT: Repeat Formation Tester; several depths gradient; note filtrate contamination.

SI: Shut In

WELL CONDITIONING: Flow until stable (WHP/mud filtrate/workover fluids/reaction products).

WHP: Well Head Pressure

Samples:

·           Preserve P&T state during handling/storage.

·           Multiple before excessive drawdown.

·           Asphaltenes: single-phase (monophasic) sampler keeps at reservoir psi.

·           Water: aquifers vary laterally & by depth; RP 45: pH, T, alkalinity, O2, CO2, H2S, iron, turbidity.

·           Waxes: use heated chamber samplers.

·           Separator sample method: 1) drop flow rate by steps, 2) take sample when GOR/flow stabilizes.

·           Separator gas sample volume for reservoir oil remix; need separator GOR & PSI: FIG 4.4 (I-190).

·           Wellhead/Flowline: single phase only (e.g. dry gas, very-low GOR, or high-P high-T condition).

·           Split-stream sample (isokinetic): two-phase; side stream equal velocity (e.g. gas condensate).

·           Choke may change GOR: due to 1) two-phase flow effect, 2) phase changes, 3) gas condensate.

·           Downhole capture method: 1) SI for pressure, 2) flow low to clean near wellbore, 3) SI, 4) sample.

·           Downhole capture tools: by timer, mechanical clock, or electrical signal.

 

Petroleum Engineering Handbook: Overview

Petroleum engineers should be familiar with the Petroleum Engineering Handbook (PEH). See the Amazon link, lower left under "Useful Links" for further information. Many engineers have been slow to embrace the PEH for several understandable reasons:

First: seven volumes?! Clunky.
Second: each chapter is written by a different author so the quality is uneven. It lacks the unity of its single-volume predecessor by Bradley (see my Amazon review linked in the upper-right corner of this blog).

Regardless of one's opinion of the PEH, every PE should purchase and become familiar with it. Bradley is simply too dated, and there is some pretty good stuff in the PEH. After you get used to it, it's really not that bad. However, I do have suggestions to make it more manageable:

1) Tab each chapter in each volume, clearly labeled (see picture below).
2) Tape a chapter TOC (with page numbers) to both the cover and spine for quick reference.
3) Use pencil to mark passages. Forgo pens or highlighters. As you learn more and gain more experience a lot of the original marks will be obvious and make it hard to discern what's important. You really need to be able to erase and remark as you go.

I try to include relevant quotes from the PEH in the Guidebook. This process is ongoing.

Note the PEH is very long and detailed, so a good percentage of it is simply beyond the scope of the PE exam and most engineering work. Reading it cover-to-cover is not a wise investment of precious time for the typical engineer. So be selective when reading it. Make no mistake, it's a deep dive.

On this blog I'll include an ongoing outline of what I think are "relevant" PEH chapters (starting this week). These posts will be an excellent review for people taking the PE Exam. Everything I include I think is worth knowing and being prepared for.

2017 PE Exam Comments

2017 is history. Leave any comments (and suggestions for blog or GB improvements) in the comments below. I would enjoy hearing from anyone and everyone.

Please remember the blog rule: prior PE Exam questions, in whole or in part, will NOT be discussed on this blog. General topics, such as resources, testing techniques, or general problems only!

Test Taking Strategy - 2017

Note: I will not talk about specific problems from the exam.
Note: this is a re-post from 2016 with updates for 2017.

First: review the Petroleum Engineering Guidebook in detail and SPE Textbook Series #1, #2, #12, and #4 as time allows. Tab (by letter) a good Petroleum Dictionary. Have the Halliburton Red Book (or equivalent) and Well Control or something similar (for the pictures). Consider investing in the 7 volume Petroleum Engineering Handbook; you really should own it anyway and it helps a lot of folk on the exam. Regardless, know whatever resources you choose very well; never waste time searching through books on a hope during a timed exam.

Second: Take the Petroleum PE Problems 2016: 1-40 or the 2005 SPE Sample Exam 1-40. It's critical to take it under actual test conditions. Lock yourself in a room for four hours with your books, calculator, mechanical pencil, and whatever you will eat and drink. If you lack four uninterrupted hours, do 10 problems in 1 hour for the same effect.

Third: Take, practice, and completely understand every problem on the 2005 SPE Sample Exam 1-80. This is your calculation problem study time. Do every problem as many times as needed until each one takes less than 6 minutes each (on average).

Fourth: Review whatever reservoir textbook you are familiar with. If you have time, you might want to do and completely understand every problem on the 2014 SPE Practice Exam (this isn't like the actual exam, it's mostly easy and fast, but worth a look if you have extra time). Study any weak areas.

Fifth: Take the 2016 Petroleum PE Problems 2016: 41-80. If you don't have it, use the 2005 Practice Exam 41-80. This is your final check. If you can get 70% under exam conditions, you will probably pass the real thing. If you can get 60%, it's worth a shot. Use this test to hone your resources and test-taking skills under time constraints.

Sixth: Sometime in the month before the exam, take the Petroleum PE Problems 2017: 1-80. Take it as if it's real, including resources, food, and restroom breaks. Regroup and study as needed. If you have the opportunity to take review courses (Bing is highly recommended) do so. The lectures are invaluable, especially for engineers without a petroleum degree.


Regarding studying: I didn't find practicing calculation problems to help much past a certain point. If you can do every problem on the 2005 exam within time constraints (average 6 minutes per problem), you should be good to go on calculations.

Regarding the futility of studying calculation problems to prepare for the PE Exam? Read David Vaucher who after taking the 2014 exam said, "I think I did well. I’m confident because I spent ample time preparing..." and "...I am certain that I got all the calculation questions right...". But to his chagrin he then learned he did not pass. Think about that. He believes he didn't miss a single calculation problem...yet did not pass! This demonstrates the danger of relying on calculation problems.

So how should one prepare? Focus on high-quality (but limited) resources, achieve real understanding, and hone your test-taking skills. This was how I generated my study notes (now Guidebook) during the years I waited to take the exam. My notes summarized the main points from SPE textbooks. And little else. If there was something on the exam not in my notes (rare!) I merely skipped it, confident that the question was esoteric and thus a time sink to be avoided. A willingness to "let it go" is far more important than the natural (and normally healthy) urge to chase down the correct answer on every problem and thus run out of time.

You have probably heard the joke that to avoid being eaten by a charging bear you don't have to outrun the bear, just the other guy? Well you don't need to get every answer right on this exam. You just need more answers correct than about half the other guys.