Back to the Basics of Oil and Gas Well Data

Knowing the inner-workings of a well can tell you a lot about the data, and vice versa

For this blog I’m starting with a story. This one is mostly true but I’ve changed the names and the story slightly to protect the guilty. 

At a previous employer a coworker came to me and told me that a group within our company had asked for all the KB (kelly bushing) elevations for every well in Colorado. I replied that it made no sense and asked my coworker to see if the reference elevations were what they really wanted. The coworker returned the next day and indicated that they had insisted on the KB elevations. We supplied the KB elevations and sure enough, about a week later they came back and asked for the reference elevations.

Data sometimes takes on an almost mystical quality, where the meaning and intent have been lost because of inaccurate use or overuse. The oil and gas industry has so many buzz words and so many things that are typically done that we sometimes lose the actual meaning of why or how things are done and worse still, fail to understand the data.

It’s really important to understand the data you’re working with – what it is, where it came from, and what it can be used for. The problem is sometimes actually harder than it seems. If we use the example above, most logs are measured from the KB elevation, correct? So you want KB elevations when normalizing logs to the sea-level datum?

Yes, most logs are measured from the KB. No, never use just the KB. Some logs are measured from the DF (derrick floor), GR (ground), or CHF (casing head flange), and there are a few other strange places logs are measured from. In today’s world, where multiple rigs can drill multiple sections of a well, the KB can have different elevations depending on the run of the log. It’s really important to put things back together on a common reference point so the logs aren’t off and formations can be correlated and depth corrected. (Side note: the definition of MSL, mean sea-level, is also probably a good topic of future discussion. It’s probably not what or where you think it is).

I really like to use the CHF as the reference elevation because after surface casing is run and cemented in, it is a constant point that has a single elevation point throughout the drilling and completion cycle. No matter what the elevation of the rig or completion is, the CHF is always at the same elevation.

So the KB is a physical place on the rig and the reference elevation is the physical place where the log was measured from. They can be the same thing but equating them everywhere will certainly create incorrect data.

Where the elevations come from is another question. Elevations are often supplied on the drilling permit, the completion report, the logs, and probably a couple of other reports.

The elevation starts when the surveyor goes out and measures precisely where the oil and gas company wants the well. Today everything is done by GPS, and the surveyor gets a latitude, longitude, and elevation. At the precise spot, the surveyor pounds a steak into the ground and ties an orange surveyor’s ribbon on it. It’s usually in some pasture and hopefully not on the side of a hill or in the middle of some pond. That does happen, however, despite the fact that the geologist spends months studying the subsurface. The thing is, they probably don’t spend more than 10 minutes looking at the surface.

A day or two before the well spuds, a bulldozer arrives and scrapes the land flat so the rig will have a solid footing while it is drilling the well. The excess dirt gets piled up so that any water gets trapped on site and doesn’t run off to the nearest stream or pond. A curious artifact often appears on one of the piles of dirt – a surveyor’s stake with an orange ribbon on it.

I’ve been at a few rig locations and as I drove on site and glanced over at the surveyor’s stick sitting in the dirt pile, I often wondered how the guys setting up the rig knew the exact spot where the hole was supposed to be located with the location stick sitting far away in the dirt. The answer is they don’t. They position the rig on the pad where it will best fit given the generator, tanks, pipe, and all the other equipment that needs to be located, along with space for parking.

Some companies will actually call back the surveyor to have him give a final elevation of the ground and of the KB and/or DF. If you’re really lucky, the company will have also asked the surveyor to respot the well location so there is an updated lat/long, but don’t count on it. One of the most shocking comments I’ve heard about well locations is, “I don’t worry about well locations anymore because everyone uses a GPS.” Yes, the surveyor used a GPS to place the stake in the ground … just before the bulldozer pushed it into the dirt pile.

If the ground elevation changed between the permit and the completion report, there’s an excellent chance the surveyor came back and resurveyed (and hopefully he also included an elevation to something permanent, like the CHF).

So the question is, now that we have established that we might have several different elevations, what is the best one to use? Oh how I wish that were the only question that needed answering. Elevations are reported to the state and elsewhere from lots of different sources. Permits, completions, activity reports, and logs are the main documents where this data can be found. Locations are a different story, and it is a rare event to see a correction.

The elevations off the log are probably the best to use. Though I have seen them wrong on the log, it’s a rare occurrence. The elevations are generally captured to support the geologist in making structure maps, so there’s a good chance they’ve been checked and verified.

The completion information is also another good place to grab the elevations. However, grabbing them from the permit would personally be my last choice, but it’s a lot better than nothing or an estimated elevation from a topo map or DLG file.

So the next time you are looking for an elevation, ask yourself, what was it referenced to, what document did it come from and, probably most importantly, is it a reasonable value?

Let’s look at another important piece of information on a well – total depth (TD).

Well depth is a very important piece of information. There are several TDs and several ways to measure them. The major TDs we deal with are the driller’s total depth (DTD) and the logger’s total depth (LTD). In general, the DTD is considered to be the official depth of the well.

The LTD is a nice backup that gives confirmation that the DTD is in the ballpark. The DTD and the LTD almost never agree exactly. A lot of that has to do with cable stretch and steel drill pipe. We don’t normally think that steel drill pipe stretches, but when it’s strung together to make a length of 2-4 miles, it does indeed stretch. The pipe is also under immense tension. At the bottom of the drill pipe, near the bit, there’s special drill pipe called drill collars. Drill collars are designed to put weight on the bit and make it drill better. However, rather than adding drill collars or removing them as the well drills, they add more weight than they will ever need at the start of the well and the driller uses a brake that holds the drill string, which prevents all of the weight from ending on top of the drill bit. Too much weight and the bit will not drill straight and it will prematurely wear out the bit. If there is too little weight, the drill bit will not drill efficiently. It is this tension on the drill string that adds to the stretching.

A couple of other TDs come into play when you are drilling directional or horizontal wells. MTD is the measured total depth, which is the distance along the wellbore. The other piece of information is the true vertical depth (TVD), which is the distance of the well from the surface. There is actually one other measurement, called true vertical depth subsea (TVDSS), which is the TVD as referenced from the reference elevation. In many instances this ends up with data below the sea level and the values are negative. Think of this like a thermometer, where some values are below zero (below sea-level).

When you ask for the TD of a well, you’re probably getting the DTD, but being precise or asking a clarifying question about what you’re getting is always best.

Operator is another thing that can cause confusion. Current operator and original operator can be two different companies, and often a property can be bought and sold several times. The original operator will have a lot of information with the state because they are the one who filed the permit, completion information, and other initial documentation. The current operator is the one listed on the production data file. If you are trying to match wells, never assume that two different operators are two different wells.

When working between states, well name and lease name will drive you crazy. I haven’t worked everywhere in the U.S., but my experience is they are often equivalent with a couple of exceptions. The lease name is the lessor of the minerals. However, where the state has a well name and a not a lease name, the operator is free to name the well whatever they want. In most cases they use the lease name. However, there are lots of well names with the word “lucky” in them. Prospect names are also used as the well name, which leads to some very interesting well names.

Some states have spud date while other states have first-activity date.

California and a couple of other states require operators to file a permit when plugging wells, recompleting them, or almost anything associated with a well. Other states just require a permit to drill and then have standard forms for plugging and other things.

Understand the origin of the data you are looking at, where it came from, and the correct use of it. Before you do any analysis, know what the limits or reasonable values of the data should be before you start.

Stay Tuned
In my next blog I’ll be talking about the physical values of the data we use. Sometimes they work for us and sometimes they just lie to us.
 

About The Author

John Fierstien is Director of Product Management for P2 Tobin Data. He started his career in oil and gas in 1978 after finishing his MS in Geology from the University of Pittsburgh and his BS in both Geology and Biology from Central Michigan University. He has worked as both a development and exploration geologist. John has been a product manager in oil and gas for the better part of the last 20 years. He’s also spoken at various meetings and conferences and written about sub-surface modeling, oil and gas software, and oil and gas data. John enjoys photography and growing his home automation system. John currently lives west of Austin, in the Texas Hill Country.