Oil! A Primer on Petroleum Exploration & Production

Once again, I am terribly sorry about the slow progression of this series. I will add at least one more update this weekend. The baby is not here yet, but she is tentatively scheduled to be here in the next two weeks (albeit a little early). My wife and I have been going doctor appointments almost daily at this point, but so far, so good except for a few minor hiccups. Again, I am sorry this is dragging on so long, but it will be finished at some point.

 

So the last time I left off, a long, long time ago, we had completed drilling a successful exploration well - a very rare occurrence indeed. We sent our collected fluid samples to the lab for analysis, along with core samples to be tested for porosity, permeability, lithology, etc. We have also analyzed the results from our flowback tests, and we have some sort of an estimate of the volume of the reservoir.
So, say we just received all of our data back from the lab, and the oil is fully saturated with gas in solution, and the crude oil is of the light, sweet variety. Light crude oil is defined by having an API gravity greater than 31.1 degrees. API gravity is a highly specialized "oilfield unit" that basically amounts to specific gravity. Saying that the crude is sweet means that it does not have hydrogen sulfide in significant quantities. Hydrogen sulfide is a weak acid that is extremely lethal in its gaseous state, and it also presents some major corrosion issues as well as complicates matters during the refining process.
As I mentioned, we also have an estimate of the volume of the field based on flowback and shutin tests performed on the exploration well. The data gathered during well testing can be analyzed via a very, very abstract methodology called Pressure Transient Analysis (PTA). PTA is a very interesting topic of study, and a few (literally a handful of true experts at the global level) very smart folks have built careers on its premise in both industry and academia. In simplest terms, the flowrate that can be sustained, and the rate of recovery of pressure after the flowing well is shut in can be used to make a reasonably accurate estimate of reservoir volume, and it can even give hints about things like reservoir geometry, faults, and anisotropy. Let's assume that our results indicate that we have an economically significant reservoir volume. In fact, let's say our estimate is approximately 100 MM bbls (in the upstream petroleum industry M = 1000, thus MM = 1000*1000 = 1,000,000; also, bbl = barrel*). We shall assume 100 MM bbls for the sake of simplicity in calculations later on, but I should mention that a 100 MM bbl field is not particularly large.
We have also analyzed our core samples in the lab, and we have arrived at some estimates for porosity, permeability, and wettability. The core samples show porosity on the order of 25-35%, which is quite good. The permeability, which has a much greater degree of uncertainty, has a range of 20 millidaricies to 2 Darcies. I mention uncertainty, and that is perhaps the single thing that defines reservoir engineering - narrowing uncertainty. You can never have enough data, and the information you have as well as estimates are in a continuous state of flux as they become ever more refined as new information becomes available. Narrowing uncertainty is key to developing fields economically by mitigating risk.
So, we have completed a large amount of analysis, and have seemingly discovered a field which warrants closer examination. The process thus far has probably taken years and 10's of millions of dollars have been spent with nary a return on investment - exploration is stressful work. If this field were on the North Slope of Alaska, we would be packing up our equipment and waiting until next year, as the exploration season only lasts as long as the tundra is frozen and all exploration work is done from pads constructed of thick ice to minimize environmental impact. That being said, our imaginary field is in a location where we can proceed with appraisal drilling.
Appraisal drilling is exactly what is sounds like. We have identified a candidate, and it is time to narrow our uncertainty about the field by trying to find out how expansive and continuous/discontinuous it is. The objective is to drill a few (perhaps 1 to 4) more wells in an attempt to delineate the structure of the field and find an oil water contact, if one exists. Our field is an anticlinal structure with a domed shape. Our oil sample analysis revealed that our oil is fully saturated with gas in solution, which suggests that a "gas cap" exists at the crest of the geologic structure. A gas cap is free gas that cannot go into solution, as the oil is already saturated. This is a good thing from a reservoir standpoint, as it provides a drive mechanism - a source of pressure to push the oil to surface. Though we suspect, and rightly so, that a gas cap is present, we will not drill an appraisal well at the crest of the structure to confirm this. Doing so would provide little useful data, and it would only serve to prove/disprove our hypothesis about the gas cap, which is not reason enough to spend money. We actually want to drill our appraisal wells near the flanks of the reservoir structure to search for its edge and/or an oil water contact. We are proposing to drill three appraisal wells, but we will only drill one at a time, so that planning for the subsequent wells can be revised and refined.
So moving forward, we drill our first appraisal well using the same process as the exploration well. It is located nearer the flank of the structure than the original exploration well, though not quite at what we think to be the extreme margin (we don't want to drill a dry hole, as this provides no usable data). This second well again strikes oil in the same rock interval as the exploration well, and presumably the two are in the same reservoir. We did not gather core samples while drilling this well. We did, however, conduct flowback tests while monitoring pressure on our shut in exploration well. We saw a very, very slight drop in pressure in the shut in well while flowing the other, and this established that the two are both drilled into a continuous interval within the reservoir. This is good, as it indicates that our reservoir is laterally continuous and rather permeable. With this information, we proceed with the drilling of our second appraisal well, which is located nearer the flank of the structure than the first appraisal well. We strike the same interval as the first to wells, but this well is different. Oil is present, but so is a significant volume of water. We have found the oil water contact. Oil being less dense than water, migrates up in the reservoir and sits atop the water which sits lower in the reservoir, at the flanks of the dome structure. So we have now established that we have oil in significant quantities, a gas cap is likely present, the structure is flanked by water, and the producing interval appears to be porous, permeable, and continuous. Huzzah! We have a field that is likely worth being developed. Based on this, we will save some money and forgo drilling our third appraisal well, unless our lease stipulates that we must drill more wells in a given time period (let's assume we face no such stipulations).
So the next step is to conduct a study and arrive at a development plan for the field. Development plans, and the research that they entail, are, in my opinion, the most interesting facet of upstream petroleum engineering, but I am a little biased.
In the next installment, we shall create a development plan for the field - ahhh, science. This requires much simulation work and uncertainty analysis as well as a plethora of economic analyses. Thank you all for bearing with me during my slow updates to this series.

*bbl is the standard unit of measurement for oil field volumes in the US, and indicates a volume of 42 US gallons. There is some dispute about origin of this abbreviation "bbl". I http://www.amazon.com/Prize-Epic-Quest-Money-Power/dp/0671799320 that its origins lie with "blue barrels" which held 42 gallons and were originally used for shipping fish, but were adopted in the early Pennsylvania oil fields. However, wikipedia provides a couple of [ame="http://en.wikipedia.org/wiki/Barrel_(unit)"]alternate hypotheses[/ame] about the origin of bbl.

 

Thanks. You are absolutely right about hydrology pump tests being similar to flowback tests. The premise is exactly the same. You draw down the reservoir or aquifer and monitor pressure and flow rates. The information is even more valuable if more than one well can be monitored simultaneously, as this establishes continuity across the field/aquifer. These tests can be used to establish an inflow performance curve, which is an indication of production rates. This curve is then used for things like simulation studies, sizing production tubing, and sizing surface production facilities.

Hydrology and reservoir engineering are basically parallel fields of study. They are nearly identical except for units of measure, and I am actually partial to hydrology units as they are consistent and less abstract than "oilfield units". Hydrology classes were some of my favorite in school, and I considered pursueing a career in the field, but, alas, $ conquers all (most).

Jayman - still no baby. We have another appointment in about two hours, and the delivery is tentatively slated for next wednesday. Stressful but exciting times.