By: Andy Maslowski
Nov/Dec 2011

Too much information! That could be one motto for the modern world we live in.

From personal finances and politics to the Internet and all sorts of digital technology services, many of us are inundated with advice, opinions, entertainment choices and offers to live healthier, spend our money, swing a golf club and thousands of other suggestions.

The world is awash with data. Analysis paralysis!

The oil and gas business doesn’t escape a need for information either. From tax and regulatory issues to fleet management and the latest techniques to drill, service or produce a well, the rules or circumstances are always changing.

Wellhead production, pressure and prices can all be plotted over time

One of the purest forms of data collection in this industry involves the products that keep it in business — crude oil and natural gas. And tracking production at an individual well not only involves the bottom line, but is also a reflection of what lies in the well and rock formations below. Nothing shows this better than a production curve from the birth of a well to its retirement after plugging and abandonment.

Production curves
It should surprise no one reading this to say that oil and gas production normally declines over time. Following a period of flush production, most wells begin a long (hopefully), steady decline in production as recorded on their monthly or periodic run tickets.

Of course, in the oil and gas business, no rule applies for every well. And Murphy’s Law and all of its corollaries are always waiting in the wings: there are hundreds of ways to goof up a producing well, both man-made and natural ways! On the other hand, a well may get a second chance with a new stimulation, plugback, re-entry, etc., at any point along its life. Any of these procedures could possibly increase production for a short time.

Since the World War II era, when there really was serious concern about domestic oil production, petroleum engineers and others have been devising methods to predict production, theoretically and mathematically, in new areas as well as in established fields. Over the years a number of professional papers have been published on the subject by such organizations as the Society of Petroleum Engineers (SPE). Many of these papers employ detailed, scientific equations that use numerous engineering and geological functions, collected mainly from wireline logs, to estimate reservoir volumes and formation flow characteristics. These traits include, but are not limited to, such parameters as formation thickness, porosity and permeability, fluid viscosity, water saturation, drainage area and shape, reservoir pressure and time.

In Analysis of Production Decline Curves, a 2008 book published by the SPE (ISBN: 978-1-55563-144- 4), authors Steven Poston and Bobby Poe, Jr. describe past and recent developments in the topic. “Long ago, engineers recognized the characteristic decline of oil and gas well performance and attempted to predict its course by fitting equations to the production history,” they wrote. “Production decline-curve analyses are the most widely used tools in the industry for oil and gas reservoir production analyses.”

Some of the chapter titles from this book give further insight into the subject matter, including application of decline curves, type curves, the exponential decline curve, the hyperbolic decline curve, interpretation of field curves and production performance plots. Decline curves range from straight lines to logarithmic curves and curved lines that both converge and do not converge.

In recent years, more study has been directed toward deviated and horizontal well performance. With upwards of two-thirds of new wells being drilled directionally or horizontally in many areas, getting a handle on new laterally producing wells will only add to reservoir understanding. Straight holes and vertical wells are not dead yet. But drilling sites with smaller environmental footprints, putting down wells with offshoots in different directions, will be a key component to future industry activity.

Real world
Some petroleum engineers spend large portions of their careers researching and analyzing production data. They might discover that certain formulas work fine for one producing field, but not at others. For example, some wells might produce 10 or 15 percent of their eventual total production in their first full year of production. Others might go much higher, 25 or 50 percent, or even 100 percent, meaning they produce for one year or less and then give it up for dead because of declining pressure, influx of water, sand or paraffin problems, lower oil or gas prices, or other reasons. If you can imagine something at a wellsite or something in a wellbore going wrong, it has probably happened somewhere, some how, some time!

While theoretical computations may be wonderful, let’s take a look at a real world example. Right now, there are approximately three-quarters of a million producing oil and gas wells in the USA, including more than 260,000 in Texas, according to the Railroad Commission of Texas. Historically, something like four million wells have been drilled in our country since 1859. So how can we pick one well to evaluate? Let’s pick a great well — how about a well that produced more than one million barrels of oil during its life?

The No. 1-32 Simnioniw (API# 33-007-00297-0000) well was drilled in Billings County, North Dakota in 1979. Originally operated by Koch Exploration, it reached a total depth of 11,400 feet and was perforated in two different zones: a 14-foot section of the Duperow formation between 11,288-11,302 feet and an eight foot section of the Madison at 9,600-9,608. Records from the North Dakota Department of Mineral Resources, Division of Oil and Gas (NDDMR) also show the well eventually produced 1,292,649 barrels of oil (BO) before it was plugged and abandoned in October 2002. The operator at the end was the Williston Industrial Supply Corporation.

This well came on like gangbusters! It yielded 37,669 BO in it first month, March 1979, including 22,765 BO from the Duperow and 14,904 BO from the Madison. The next month, April, its first full month of production, was better (actually it was its best month) with 51,806 BO for an average daily total of 1,726 BOPD. After 12 months, through February 1980, it produced 355,960 BO or about 27.5 percent of its total lifetime production. Its second year it produced even more with 359,451 BO, or about 27.8 percent of its total. That means during its first two years the well made about 55.3 percent of its total or 715,411 BO. Not too shabby!

Most wells experience some momentous events. But more commonly, they live a life of repetition and drudgery, alone and isolated, producing hydrocarbons in a tedious, dull, menial way! Still, a detailed look at any production history provides some clues of what was going on down below.

The No. 1-32 well began producing water — 465 barrels of water (BW) a month — about six months after being competed in January 1980. In subsequent months this associated water production (and its disposal) increased to the tune of more than 20,000 BW/month. Naturally, this affected the well’s bottom line and it ultimately made more than 4.4 million BW after some 23 years.

Natural gas production began being marketed in November 1979, most likely following tubing and pipeline hookup (which may explain why oil production dropped during September and October 1979). Like its oil production, gas production peaked soon after it began. In December 1979, the well flowed about 97 million cubic feet of gas or about 3,100 Mcfg/day. In the end, the well produced about 1.2 billion cubic feet of natural gas from both the Duperow and Madison zones.

NDDMR statistics also indicate Duperow production petered out after 34 months in January 1982 when only 241 BO were produced. But it was a good reign! The formation produced 468,066 BO during 34 months.

After the Duperow section was plugged off, the well became a solo Madison producer for the next 20 years. From 1985 to about the end of 1998, it was a reliable well, making about 2,000 to 3,000 BO just every month. Into 1999, production fell off and became consistently lower, going from 1,003 BO in February 2000 (its last 1,000 BO month) to a number of non-producing months in 2001. The total take from the Madison formation was impressive: 893,274 BO and 757,052 Mcfg.

Every well has its own production history. But if there were more onshore producing wells like the No. 1-32 Simnioniw, America would not need to import so much foreign oil!

Slippery slope
As new wells are brought online across the country — horizontal wells, high pressure wells, wells stimulated with new technology, etc. — more data is plugged into the computer. Engineers are not yet certain what long-term production curves will look like. For instance, how much natural gas will a Marcellus Shale well make that has 1,000 feet of horizontal displacement and say 100 perforations? How about 2,000 feet of horizontal displacement and even more perforations made with a multi-stage frac? Or how much oil will a Bakken Shale well produce with 5,000 feet of horizontal pay? The combinations are almost endless.

Add fluctuating crude oil and natural gas prices to the mix and even more economic scenarios ensue. An operator might get more aggressive if $120 oil or $10 natural gas even returns, willing to drill in new areas or willing to try a new type of completion technique —things that have not been charted with production curves before.

So trying to estimate how much crude oil or natural gas a well is going to make is not an exact science. It is an estimate, a best guess made under changing conditions and parameters. Besides, no rule works for every well.

Likewise, many production decline curves contain a slippery slope. They can fall off at a moment’s notice, never to return.