The Bakken Rocks:

Oil Development in Northwestern North Dakota

Geology, Economics, and Rural Economic Development





The state North Dakota has a history of producing oil that now extends back over 50 years. However, historically it has always been a far less important producer of crude oil than states such as Texas and Oklahoma. The first producing well was the so-called Clarence Iverson #1 well that went into production in 1951 near the town of Tioga North Dakota, (Source:  ) the town of Tioga North Dakota has long been associated with oil production within the state. This picture shows a celebration taking place at the time of dedication in 1953, apparently a couple years after the oil was discovered. As will soon become apparent, there are many similarities between what appears in this photo and in current wells being placed in production (See additional detail at the Source:  )



While it has long been known that substantial quantities of oil existed within the state, production of oil over the period 1951-2006 has been very limited. There are probably two basic reasons for this, both relating to how oil is normally found in geological formations. We can separate these formations into two major categories: 1. Small, disconnected pools of oil that can be found in porous rock at relatively shallow depths, perhaps typically 8,500 feet or less, and 2. Much larger interconnected formations made of oil-bearing shale that occurs as about 10,000 ft, or two miles down.


For a driller interested in tapping into the category 1 pools, oil drilling has always been a hit-or-miss proposition involving sinking many vertical holes. Whether or not an economic pool was found was as much a matter of chance as skill. But the geologic structures containing this oil typically gave up the crude relatively easily, that is, oil drilling was mostly a matter of piping this oil once found to the surface. However, depths of only 8,500 ft or less are not ideal for the generation of top quality crude oil. Often the oil found at shallower depths was sour, and high in sulfur (Think hydrogen sulfide gas or the smell of rotten eggs, and very viscous or tarry,) These characteristics indicate poor quality oil that is discounted as not only as sour, but as expensive-to-refine crude in the marketplace. Further, a pool of this oil might be in a very small area, within the confines of a single section of land (1 square mile) or even less, and once the driller ventured outside the very small area there was nothing but dry holes. A quite successful well in one of these disconnected pool formations might come in at 100 barrels of oil per day (bopd).


As a driller descends into the earth, pressures on hydrocarbons found underground get stronger.  At shallow depths, there is coal which must be mined via strip mines or at greater depths as underground mines. At still greater depth and with more pressure, some of this coal gets converted into tarry crude oil, with the oil becoming less viscous and better quality as the pressure increases. 10,000 feet, about 2 miles down, is widely viewed as the ideal “kitchen” for the generation of top quality crude oil. It is here that the pressures are ideal for the generation of what is known in the oil markets as light sweet crude. However, even at this depth the pressures will be strong enough to convert at least a portion of the hydrocarbons into natural gas. However, drilling of natural gas typically goes to greater depth. The Barnett and Haynesville shale formations in Texas and Louisiana, formations that will contribute greatly to the US natural gas supply, typically are drilled to depths of around 13,000 ft. In this instance, the hydrocarbons are found so deep that what would have been crude oil at 10,000 feet comes out of the ground as natural gas.


Tapping into the much larger, interconnected category 2 oil bearing formations at greater depth has posed its own set of problems. It has long been known that a substantial area within western North Dakota, Northeastern Montana and extending into Saskatchewan to the north is underlain with very large and a nearly continuous layer of shale containing hydrocarbons, potentially very high quality light crude oil all at approximately 10,000 feet. The oil-bearing shale looks not unlike a black granite countertop, but if a flame is held to the shale, curiously, the rock will ignite and burn a weak flame, as it contains about 40% hydrocarbons. However, historically, this so-called Bakken shale has held on to its hydrocarbons tightly, and merely drilling a simple vertical hole to 10,000 feet seldom yielded an economic oil well, unless the driller was lucky enough to have happened to drill close to a point where the shale contained some natural fractures.


The over 50 year history of oil development in North Dakota was hampered by the fact that attempts to drill into porous pools of oil typically occurring at shallow depths was very hit or miss, and attempts to drill to the shale at 10,000 ft was equally limited because finding the natural fractures in the rock that would allow the oil to flow was equally hit-or-miss. As a consequence, a lot of drillers drilled a lot of vertical holes in various locations and to various depths with marginal results at best. There were oil booms in the region, but these were inevitably followed by subsequent busts particularly when a combination of low crude oil prices met drillers who were investing a lot of money drilling holes for wells that quickly became, at best, marginal producers. Western North Dakota is dotted with dry holes that were plugged after attempts were made to fine economic oil in the 1980s and 1990s. Up until the start of the 21st century, drilling for oil in western North Dakota was generally seen as an activity only for those who had more money than brains, a Las Vegas style gamble involving spending a couple million dollars on a hole with no certainty whatsoever that even a portion of the investment would ever be recovered. Big exploration companies like Hess and Marathon continued to explore by drilling vertical holes to various depths and sometimes found economic wells but often not.


By the start of the 21st century, nearly everyone in the industry generally knew that the area containing the oil–bearing hydrocarbons was not only huge, but in large measure, interconnected. The tricky part was coming up with a technology that would allow the shale to release the oil without having to rely on serendipitous natural fractures in the rock.


In case no one has noticed, North Dakota is about as land-locked as a state can be, being neither close to the oceans or to the Gulf.



Map courtesy the Department of Geography at the University of Alabama


 The US located refineries near the coasts and particularly in Texas, a long way from North Dakota, in part to take advantage of the heavy oil production in Texas and Oklahoma, but also because ocean-going tankers increasingly supplying oil from the Middle East could easily dock there. As will be noted later, this infrastructure geography is just now coming back to haunt us.


The Bakken area, the area is thought to be underlain with the hydrocarbon bearing shale at approximately 10,000 feet, and consists of a sizable chunk of land in northwestern North Dakota, Northeastern Montana and extending into Canada approximately as I have circled on the following map. Exactly where the Bakken starts and stops continues to be debated.



Right now, there are four basic questions:


  1. Is this layer of oil bearing shale largely uniform in that entire large area at the near ideal 10,000 feet for crude oil generation, or does it vary quite a bit so that there are substantially better areas for crude oil generation within the space and areas that would not be so good?
  2. Can the rock be made to give up its hydrocarbons without relying on locating naturally occurring fractures has been very much hit or miss?
  3. What level of extraction cost is reasonable and prudent? $25 a bbl? $50? $100? $200? $500? still more?
  4. How much oil is there, or could there be if proper extraction technologies are applied?

No one yet knows the full answer to question 1, but there does appear to be better places to drill within the Bakken as well as places that are not as good.


Question 2 I will address in considerable detail in the discussion that follows.


Question 3 is extremely important, because if there is a huge supply of oil that can be extracted but only at $500 a bbl, then at current prices, it is not economic for any company to come in and attempt to extract it.


Indeed, Question 4 is highly dependent on the answer to question 3. As any introductory student of resource economics knows, the amount of a non-renewable resource that is available is heavily tied to the assumption one makes with respect to the price of the nonrenewable resource being analyzed. The term “proven reserves of oil” can only be used with full knowledge of the extraction technologies in place and the current market price for the oil. Proven reserves are not some fixed number independent of market prices nor are proven reserves independent of the specific extraction technology being employed. If crude oil suddenly spiked to $500 a bbl, then within a year or two we would see a likely  equally spectacular spike in proven reserves, as the price incentive encourages the application of all sorts of extraction technologies unheard of at  $50 to $100 a bbl. That is how the economics of nonrenewable resources works. I’ve long felt that the term nonrenewable resource was misleading in that it makes people think of the supply of nonrenewable resources as something of a fixed supply. In the case of oil, this conjures up the notion that oil supplies exist in fixed underground “ponds”, that wells drilled into these ponds eventually suck out all the oil contained in each of these ponds, and once the ponds are dry there is no more oil to be extracted period as the fixed supply has now been used up. Unfortunately, most of the public tends to view oil production like this, and nothing could be further from the truth, especially so if we are looking at a geologic formation like the Bakken.


The Amazing Dr. Price!


The name of Dr Leigh Price, a US Geological Survey (USGS) geologist who worked out of Denver Colorado, stunned the world, when in an unpublished paper from work done in the 1990s, he noted that based on his own calculations, his best estimates of the amount of oil in the Bakken formation in North Dakota, Montana and Canada could be anywhere between 271 and 503 billion barrels of oil.  Dr Price died shortly after making this assessment and before his paper and techniques for estimating the reserves were reviewed by the scientific community, but his numbers to this day continue to haunt geologists and others who are attempting to make reasonable estimates of the amount of oil contained in the Bakken. An obvious question is whether these numbers represent reserves that could be obtained under any possible technology or at any price. At the time Dr. Price was doing his analysis and proposed these numbers, in the late 1990s oil prices were fluctuating between  as little as $7 up to $20.


To put Dr. Price’s numbers in perspective, it has been estimated that since crude oil was first discovered in the 19th century, human beings on earth have used up approximately 1 trillion barrels (1,000 billion bbls) If Dr. Price’s 500 billion barrel number is correct for the Bakken, the Bakken supply would represent as much as half of what all of humanity has already use.The obvious question, however, is what price is necessary to make extraction of the crude economic?


There are other scientists who claim that the world is not at all running out of oil, and two thirds of the total supply or two trillion barrels (that is, 2,000 billion barrels) remain underground to be produced at the right time, at the right price, with the right technology. The 500 billion barrel Bakken reserve proposed by Dr. Price could potentially represent as much as a quarter of the world’s remaining supplies of crude.


These numbers are highly controversial and certainly nothing that the advocates for alternative energy sources are proposing as accurate. Furthermore, just because two trillion barrels of oil might still exist worldwide, this does not mean that a significant share could be recovered at a reasonable price. If the only technology available to recover some new source of oil costs $1000 a bbl, that oil might as well not exist at all!


However, I would caution you to be skeptical of reports in the media that somehow suggest that scientists definitely “know’ that the world is running out of oil that is economic to recover as well as to be skeptical about reports that suggest some specific date or range of dates (I’ve heard estimates as low as 10 or 15 years) at which the crude oil supply will be depleted and the bas pumps will run dry. Alternative energy advocates are generally highly enthusiastic about some new experimental technology yet to be successfully employed at any reasonable scale of operation (Ethanol from straw, for example). What many of these advocates fail to realize is that technologies for recovering crude oil are proceeding as well, and there is nothing better than a spike in crude prices to encourage oil drillers to make the necessary investments to test the newly emerging drilling and recovery technologies.



Since his death, Dr. Price and his estimation methods has had a large number of both detractors and proponents, those who think his numbers are crazy, and Bakken believers, who still believe his estimates are right on the mark. Further detail on the controversy can be found at


This is no small matter! The total known reserves of Saudi Arabia right now are estimated at somewhere around 250 billion barrels of oil. So a 500 billion barrel figure would mean that the Bakken would contain approximately twice the known reserves of Saudi Arabia.


Just recently, the US Geological survey made another estimate of the reserves under the Bakken. Their more conservative methodology led them to an estimate closer to 3-5 billion barrels not 500 billion barrels. To put this in perspective, Dr Price’s reserve numbers are 100 times larger that the current numbers being generated by the USGS.


All of this is very important. The US recently has been using about 7.5 billion barrels of crude oil annually

Were the total reserves of the Bakken 5 billion barrels, the total would be a nice addition to domestic production, but the totality represents less than a year of crude oil use in the US at current rates. However, the 500 billion barrel number represents more than a 50 year supply of US crude use, without importing any oil from countries other than, perhaps Canada, which includes part of the formation. If this were true, production from the Bakken could not only reduce if not eliminate the need for imports from unfriendly nations, it would also shake up arguments that call for the rapid transition to alternative sources of energy. Of course if the oil in the Bakken is truly there, but requires technology costing $1000 a bbl to recover, other energy sources will continue to be increasingly economic.


EOG Resources


What I have described above basically traces the history of oil production in western North Dakota from 1951, when the first Iverson well was drilled, through about 2000. This history consisted of many companies making many attempts to drill vertical wells with only a few substantial successes within very small areas and a lot of dry holes. No one seemed to know the answer to the problem of how to get the large, interconnected Bakken shale to release its hydrocarbons for a reasonable price per barrel. 

Starting around 2000, a number of companies began to use horizontal drilling techniqies, that allowed them to penetrate the bakken formation horizontally for lengths of a mile or more. These wells were more expensive to drill, but producton per well was often sufficient to offset the higher drilling cost. Further discussion on horizontal drilling as atechnique for penetrating the Bakken follows later.

About 2005, a publically traded company called EOG Resources entered the scene. EOG has a fascinating history. The initials, now claimed to stand for Energy, Opportunity and Growth, originally was the acronym for Enron Oil and Gas. In the late 1990s, the senior executives at the company we knew as Enron, were trying to move the company in new more growth-oriented areas, and needed money to do so. The company consisted of an old-line oil and gas exploration company along with the purported new economy growth components. Around 1998, the senior executives decided to spin off the “old economy” gas and oil exploration company as a completely separate company to be run by the executives who were then employed running the subsidiary for Enron. This raised money for Lay and Skilling’s new-economy enterprises, and at the same time freed the oil and gas executives to do as they wished no longer having to follow the corporate rules laid down by Enron.


The rest, of course is history. It turned out that most of the new economy ventures of Enron sans the oil and gas exploration unit were fluff with no basis for making money, Enron sans the oil and gas driller quickly went bankrupt and Enron executives Ken Lay and Jeff Skilling were convicted of fraud and sentenced to prison, although former Enron CEO Ken Lay died just after the trial before his conviction could be appealed. Meanwhile the old Enron Oil and Gas, by then a completely separate company known as EOG resources, profited as both oil and natural gas prices rose and they started having success in employing some rather new technologies to gas fields in Texas, most notably the so- called “Barnett” field in East Texas. EOG became an S&P 500 oil and gas driller, and has been running a market cap of around 30 billion $. Indeed, it was the one really valuable asset that the old Enron owned, which Skilling and Lay dumped because it was not consistent with where they wanted the company to own.


By the early 2000s EOG was having good success with two then relatively unused technologies for extracting natural gas from gas-bearing shale. The two technologies were 1. Horizontal drilling, and 2. Hydraulic fracturing of the hydrocarbon bearing shale rock along the horizontal portion of the leg. What they were finding is that by combining these two technologies, they could dramatically increase the production from a well, and in addition reduce the number of wells that needed to be drilled, with consequent impacts on drilling costs.


Horizontal drilling


Imagine a well going into the ground typically 10,000 ft in the case of crude oil in the Bakken or perhaps 13,000 or 14,000 feet in a natural gas bearing shale layer, or about 2+ miles down, and then making a 90 degree turn to create a horizontal leg 5000 feet long or longer. Here is an illustration of Horizontal drilling as it appeared in EOG’s 2006 corporate report to shareholders. The distances in this drawing are distorted in that the vertical depth of the well to the layer of hydrocarbon bearing sand is much longer than it appears here.



Much of the oil-bearing shale in the Bakken is not unlike an Oreo sandwich cookie. There are three layers. There is an upper Bakken layer and a lower Bakken layer corresponding to the chocolate pieces of the cookie, whereas the middle Bakken, the main target area for drilling, represents the “filling” of the cookie.



It has been known for some time that the so called middle Bakken layer is likely the best target area for the generation of oil from a well within the shale. This is the subject of considerable controversy as well, with some believing that hydrocarbons in the upper and lower layers both drain into  the middle or “filling” layer, so if the horizontal leg goes a mile or perhaps longer, through the middle Bakken layer, significant oil is drained from the outside layers of the cookie as well. The middle Bakken layer is typically only 5 to 25 feet in thickness, and is not necessarily level. The driller has to drill not only horizontally but perhaps change the depth of the horizontal pipe along the leg as the leg proceeds. This is quite tricky drilling, but the drillers now know how to do this with consistent results..


Hydraulic Fracturing Employing Sand


The other technique being employed in the Barnett shale gas field was something called hydraulic fracturing, better known in the oil field as “fracing”. While natural fractures in the shale are still of some interest to geologists, the whole idea of fracing is to create artificial fractures in the shale with the aid of a fracing gun  and by pumping sand under hydraulic pressure in the horizontal leg of the well. Charges are set off by the fracing gun within the horizontal leg of the well at perhaps 8 or 10 different points all along the lateral. These charges perforate the well casing all along the horizontal leg. Sand combined with water (perhaps a million gallons of water), is then injected into the well in a process called “stimulation, which creates natural fractures in the middle Bakken shale all along the horizontal portion of the casing traversing the middle Bakken. These fractures result in oil draining into the horizontal leg at various points along its mile long length through the perforations in the casing created by charges set off with the fracing gun and ideally the result is a lot more oil generation using the combination of the horizontal leg and the fracing than would have ever occurred had an attempt to be made  to simply take out the oil in the middle Bakken using a simple vertical well to 10,000 feet.


The Big Decision


Since about the year 2000,orizontal drilling had already been employed by many other drillers attempting to tap into the Bakken. Sometime probably in 2005, or perhaps even a ltlle earlier than that, executives at EOG, at that point primarily a Texas natural gas producer, started to believe that the combination of horizontal drilling and fracing technologies could prove valuable in extracting crude oil, particularly from shale rock that had been reluctant to release its hydrocarbon bounty even when horizontal drilling was employed . Prior to this, there had been almost no attempts in western North Dakota to employ the two techniques in combination for this purpose, with many drillers still employing vertical wells. If a well were drilled to the depth of the Bakken, a driller might drill horizontally, but then try to locate natural fractures which was akin to a driller’s version of trying to find the proverbial needle in a haystack. The middle Bakken was easy to find and relatively uniform over a comparatively large area, but figuring out how to get the oil everyone knew was there to the surface was the tough part.


What happened subsequently is fascinating. EOG geologists spotted two areas that looked like possible targets for experimentation, one in eastern Montana and another in western North Dakota. They then started accumulating leases in both areas realizing that if the tests were successful they could quickly have a large oil field. The leases were generally available for almost nothing in part because other drillers had concluded that it was infeasible to produce oil in economic amounts. Some of the leases they bought even included dry holes drilled in the 1980s and 1990s. I cannot verify this, but I have heard that the data from a particular dry hole interested the EOG geologists a lot, in that it showed exactly the shale formation they were seeking to run their horizontal drilling and fracing tests. This well is known as 8071 in section 3 of Parshall Township, drilled by Lear Petroleum, in 1981, and declared a dry hole. What I do know for certain is that the first well EOG drilled in North Dakota, Parshall 1  in section 36 of Wayzetta township, is only a few hundred yards from the old number 8071 Lear dry hole. The two test wells were both on section 36 of Wayzetta township, each with short, half mile long laterals, both running diagonally, with the vertical portion of eich well in the NW or SE corner of the same section.

It was EOG's intention to drill Parshall 1 36 152 90 with a 5000 foot lateral, but they hit gas at 2300 feet. Since it was their first well, being prudent, they stopped at 2300 feet.



The initial results on both these wells were good  if not phenomenal, in the 500 bopd range initial production. On a personal note these wells are located about 2 ½ miles from the farm I spent my youth from 1-21 years of age


EOG proceeded to drill a third well, Bartelson 1, employing the longer approximately mile long lateral at about 10,000 feet, as well as their fracing techniques and the initial output from this well was nothing short of spectacular, initial production of approximately 1,800 bopd—this in an area close to a dry hole drilled by Lear as a simple vertical well in 1981. Indeed, the whole idea of a single well producing an initial output of 1,800 bopd in North Dakota, or for that matter at any onshore site within the US was all but unheard of. Bartelson 1 goes down in history as perhaps having a greater impact on oil development in North Dakota than even the 1951 Clarence Iverson well.


At this point, executives at EOG knew that they had uncovered something with enormous potential. They were looking at wells that could recover their direct drilling costs within the space of a few months, perhaps even less. EOG was soon making the following statements in corporate presentations to investors.


1. The project analysis work that rationalized going into the Bakken to drill was based on an assumed oil price of about $60 a bbl, and at any price that high or higher, drilling by EOG would surely continue.


2. Estimated direct drilling costs were actually running about $22 a bbl, far lower than anticipated because of far greater than anticipated initial well production.


3. Anywhere between 350,000 and 800,000 bbl of oil should be recoverable from under each section (1 square mile) in the field drilling a single 10,000 foot hole with a mile long lateral in a NW-SE direction diagonally across the section. These numbers represent 7-10 percent of the total quantity of oil thought to ultimately be under each section, with the remainder waiting for recovery employing downspacing or other yet to be developed technologies.


This map, from the EOGresources Web site, shows the scope of EOG operations in the continental US. As you can see, most of EOG’s drilling activity has been concentrated in Texas, and the area encompassed by their Bakken activities in Western North Dakota appears rather small on this map in comparison.



EOG also has drilling operations in Canada, but these are primarily gas fields and located further west, outside of the Bakken.



The area EOG chose for their initial experiment in drilling the Bakken in North Dakota was located in the south central portion of Mountrail county. This location, while still within the Bakken was a substantial distance east of where oil extraction had been taking place in the state since the 1950s.


Currently, the belief is held that the size of the primary field, while fairly narrow, may include a band that extends through Dunn county to the South and West, and north through Burke county to the Canadian  border, and perhaps northward beyond. Right now, Dunn county is a secondary center of drilling activity, also with some excellent wells being drilled. Continental Resources, and Marathon, among others, not EOG, are the primary drillers in Dunn county. West of the EOG developed field in Mountrail county, Whiting Oil is the major player. These companies all are about the size of EOG if not considerably larger.


This is a GIS map of North Dakota from the division of Mineral Resources GIS map server showing the locations of existing oil fields since the 1950s along with the current location of drilling rigs. The date on this map is August 8, 2008. The map is changed at least weekly to show where drilling rigs have moved and the status of each well. As can be seen from this map, the concentration of current drilling activity is in Mountrail and in Dunn county. Currently there are approximately 75 drilling rigs engaged in oil exploration in the state. Of that total, just over 1/3 of the total or 27 rigs are drilling in Mountrail county, while Dunn county currently has about 14 active rigs.


If we blow up this map further, we can see that the concentration of rigs currently is along the western edge of the Parshall field and the Eastern edge of the Sanish field. This is because most of the more centrally located leases within the Parshall field have already been drilled and efforts are underway to expand the field at the edges. There are also efforts to expand the field both north of the current field, and south.



This map blows up the Parshall field further and shows the individual wells along with what is happening. Black dots with long laterals are wells producing oil for sale. Generally there is one well or lateral per section or square mile. This is known as a 640 acre spacing unit. EOG-drilled wells are generally located in the far NW or SE corner of each section, with a mile-long lateral running to the opposite corner. The driller is permitted to keep information about a well confidential for a period of 6 months, and not tell anyone outside the company how a new well might be doing. Confidential wells are shown on themap as gold dots. Most of these confidential wells appearing as gold dots have already been drilled and all that have been drilled have similar diagonal laterals running from them. Open circles are wells that have been  located surveyed as to an exact site for the drill bit to enter the earth for making a vertical hole, staked and permitted. These yet undrilled wells are in line to be drilled, probably still during 2008.



Whiting oil, drilling in the Sanish field to the immediate west of the Parshall field, in their corporate presentation, have some interesting maps.  In this map, they show wells drilled since 2000 in western North Dakota, with the size of the circle or bubble indication how productive each well was. Keep in mind that the combination of horizontal drilling and fracing has only been used extensively in the Bakken as a technology since early 2006. As you can tell from this map, the largest bubbles representing the most productive wells are in Mountrail county, and all of these wells employ both horizontal drilling and fracing. The Dunn county wells, mostly drilled by Continental and Marathon. look quite good, but they have not been consistently as large producers as the Mountrail county wells, mostly drilled by EOG. Whiting oil in the Sanish field immediately west of the Parshall field is starting to bring in some excellent wells too, but they have not yet drilled nearly the number of wells EOG has drilled. White circles are EOG wells, Yellow are Whiting drilled.




The entire presentation can be downloaded at


This map shows the differences between the Whiting and EOG approach. EOG has been using a 640 acre spacing with a single well per section, with a mile long lateral running in the NW and SE direction diagonally across the section. Whiting has been using a 2-section, 1280 acre spacing, running two-mile long laterals across both sections. Initially they experimented with complicated triple or what I have dubbed “birdsfoot” laterals and you can see some of these on the map. But they have largely abandoned this in favor of a plan that drills two wells in each 1280 acre spacing with simple parallel laterals. At this point they are largely drilling just the first well on each 1280 acre spacing with the idea of going back at some later point in time to drill the second well in each spacing.


The color code on the map is as follows

Black= drilled wells producing oil for sale

Green = drilled wells currently being completed or in the fracing stage

Red = drilling underway currently

Turquoise = a permitted well in which the Authorization for Expenditure (AFE) has been approved by company officials

Gray = planned wells. Frequently these have been permitted but the rig has not yet moved on to the location   

Whiting has an ambitious plan and has sited a lot of wells, but actual drilling activity is far less than in the Parshall field (and gray lines still dominate that side of the map)


At the moment, Whiting is running a total of 4 rigs in Mountrail county compared with 8 or 9 on a typical day for EOG.


The speed by which the companies are drilling and completing wells has been improving. A year ago, it was not uncommon for the driller to take 45 to 60 days to do the basic vertical and horizontal drilling, with another 45 days or more to finish the fracing and other completion operations before the well can be brought into production for sale. But recently Pioneer Drilling, drilling under contract to EOG, completed a well in about 21 days of actual drilling time. They had moved on and off the site in less than 30 days. And the remaining fracing and other completion operations took about thirty days. A well in which the drill bit first hit the ground at the site May 25th, 2008, was producing oil for sale by the first week in August, 2008. If a well is to be drilled and fraced this fast everything really has to happen without a hitch, and problems are not uncommon. But the faster the well can be drilled, the less costly and more profitable it will be for the driller, other things being equal.


This chart, also courtesy of Whiting, shows some initial production rates for wells drilled in Mountrail county since 2000. The White and yellow-dot wells were all completed using a combination of horizontal drilling and fracing. The typical well has been coming in with production averaged over the first 30 days of at least 700 bopd, with one well as high as 3,000 bopd average production.




This chart, somewhat controversial, purports to show how the middle Bakken layer lies under the Parshall and Sanish field, as well as provide an explanation as to why the two fields are so productive relative to other areas in the Bakken. Some of the oil people who have looked at this chart claim it is misleading if not completely inaccurate.


This chart distorts the Oreo cookie aspect of the Bakken. In reality the middle Bakken targeted by the horizontal leg is very thin in comparison with the upper and lower Bakken shale layers. And of course the thickness of all the shale relative to the approximately 2 mile depth of the well is distorted tremendously. The three forks layer below the Bakken is being investigated as an oil bearing layer of its own. One company, Continental, drilling in Dunn county, claims to have brought in a well by targeting the Three Forks layer below the Bakken,


with initial bopd output similar to a Bakken well, at 693 bopd. But the debate among geologists centers on the issue of whether the Three Forks layer should be treated as a geological structure separate from the Bakken or whether it is simply part of the Bakken with oil that largely already draining into a well that targets the Middle Bakken. This issue will not be resolved without more targeted drilling.


Oil Production in Photos, from Permits to Production


The following photos trace the development of an oil well in western North Dakota from before the time the permit is issued to the first production of oil for sale.


Prior to 2006, the vast majority of oil wells drilled in North Dakota produced only modest amounts of oil. An excellent well was one that came in at 100 bopd initial production, and many wells produced far less. These were essentially all vertical holes with no laterals. Spacings were often tight as in one vertical hole per 40 acres or less, so a single 640 acre spacing could have 10 or more holes on it if it was found to be a “hot spot” But the area in which the oil was found typically covered only a few sections (square miles) and once drilling occurred outside the small area the wells were dry. So drilling itself was hot or miss. Typically these wells were drilled in the 1980s and early 1990s.


Typical of these are a well shown south of Plaza, North Dakota, several miles to the east of the Parshall field. A shallower well, this is a vertical hole drilled into the Madison formation, part of a series of disconnected oil bearing pools quite separate from the Bakken shale. The Hydrogen Sulfide (H2S, the smell of rotten eggs) odor present attests to the fact that this is “sour” crude coming from a shallower depth, probably about 8500 feet. The three small storage tanks each probably hold 200 barrels each and the well may be currently producing 50 bbl a day or so, if that. A small mechanical “duck-style” counterweighted pump is sufficient as the well is not that deep nor is it pumping that great a volume. A truck periodically transfers oil from the storage tank.



Oddly enough, Whiting chose to include a  photo of one of their older wells located in McKenzie county to include in a recent corporate presentation. I think they liked the rustic Badlands backdrop for the photo. But this is not one of their current wells, and looks very similar to the one shown in the Plaza field photo. It probably produces similar amounts of oil too.



This is the well that began the Parshall Field for EOG, the first well they drilled, with an initial production in the 400 bopd range. The setup does not look terribly different from the previous photos, but note that the 5 storage tanks each hold 400 not 200 bbl, and the pump pulling oil from a greater depth and in considerably more volume, is larger.



As drilling continued, the wells started to produce more, and more storage tanks were needed. This well, Geving 9 152 90, first produced oil for sale mid August, 2007, and came in at an initial production rate of  895 bopd. The site has nine 400 bbl storage tanks. Oil is pumped by a mechanical pump and loaded on to trucks for transport.


Just a mile or so west of Geving 9 is the so called School 16 152 90. It was drilled at the end of 2007. Recent wells have been coming in under so much internal pressure that they do not need a pump of any sort to bring the oil to the surface, at least for the first few months of production. This well is still on the confidential list, but according to the Whiting chart, initial production for this well averaged over the first 30 days of production was 2,150 bopd, a very good, even outstanding well for the field. This well is being connected to directly to the pipeline. I suspect that it is likely being pumped using a submersible pump at this point. EOG has all but abandoned the duck style mechanical pumps on wells completed this year in favor of submersible pumps that are all but invisible to passersby. This well probably recovered its direct drilling and completion cost (~5.5 million $, more or less) with the sale of oil produced in the first month. This shot was taken in early June, 2008. (This well is only about ¾ mile north of the farm I grew up on.)


The shot below shows the facilities for connecting the pipeline to the School 16 well showing equipment not in place in early June when the other shot was taken. Obviously there are some major advantages to being able to put the oil directly into a pipeline without relying on trucks to move.



An oil well begins long before the site is surveyed and a stake for the drilling hole enters the ground. The Mountrail and Dunn county courthouses have been beehives of daily activity, with all sorts of people representing drilling and leasing companies checking who owns exactly what land and mineral rights. While many surface owners also own some or all of the mineral rights on their land, it is not uncommon for mineral rights to be severed from the surface right. Further complexities occur as mineral ownership is divided among children and grandchildren over generations, and sorting all of this out constitutes a major undertaking. The Mountrail county court house is a fabulous, turn-of-the-20th century structure filled with marble and terrazzo, all beautifully restored.



This is a pleasant afternoon in the halls of the Mountrail County courthouse, but there is not much room for people bearing laptops sorting through giant deed books recording the sale and transfer of property, and obviously, certain deed books are more in demand than others, forcing the so called “landmen” to wait their turn.



Most of the land currently being drilled accommodates a mixture of small grain and pasture for cattle. The scene here, near Shell 1 8 153 89, is typical.



An oil driller leasing some or all the rights on the proposed spacing (usually a section or one square mile), based on advice from company geologists makes a proposal to drill a well on the site. Generally the surface owner is contacted with a notice that the surveyor will be on site to locate the specific location for the surface hole. There is little evidence after the surveyor leaves, other than a simple stake in the ground with some notation. This photo illustrates the stake for Shell 3 5 153 89.



The surveyor will put specific information on the stake including the name of the well, its location and exactly how far the well is from the section line in both directions. in this case we know that the well is going to be placed exactly 400 feet south and 400 feet East of the most northwestern corner of the section line intersection. The ND division of mineral resources requires this so as to not suck significant quantities of oil from under adjoining sections.



The driller has a pretty good idea of how the rigs used in drilling will be moved from one well to be trilled to another, taking into account the typical time each drilling crew needs to drill a well. Oddly, a “driller” such as EOG does not actually drill a well. Instead, they contract out the drilling to a company such as Nabors that specializes in Contract drilling for a company like EOG. The other “drillers” typically do the same thing. Who EOG contracts to actually drill a specific well depends in large measure as to who has the rig and crew available., and rigs and crews have been in short supply. EOG has been using mostly Nabors as the contract driller but also has a few rigs operated by smaller contract drilling companies such as Pioneer Drilling (PDC). Obviously, with a lot of money at stake in drilling a well, EOG does have employees who closely monitor what each contract drilling crew is doing and in particular any problems they are encountering that would delay or jeopardize the completion of the well. But if everything goes according to plan, this work can proceed at a very rapid pace.


About 30-45 days prior to the commencement of drilling, site preparation work begins. This involves the use of heavy equipment similar to that used in road building to clear two to four acres for the actual well and drilling. If a new road is needed to the site, sometimes the case, this work will proceed earlier. This photo shows initial clearing for a well to be drilled by Hunt oil on section 7 153 89. In this area of northwestern Shell township, both Hunt and EOG may own leases on the same section, and they need to work out an agreement as to who is going to be the company responsible for actually drilling the well (The so-called well operator) and who is going to simply pay part of the drilling costs and share similarly in the revenues from the sale of the oil that is sold from the well. A Nabors crew will drill this well, but it will be employed by Hunt Oil not EOG. Hunt has a single Nabors rig working the area. Who owns exactly what leases on each section is not always clear. EOG may get some of the revenues from this well, or not. But the companies involved know.




This photo shows the site for Parshall 4 20 152 90, with EOG as the driller and operator just a day or two before the drilling rig moved in. The site is complete. A large pit has been dug on the right, and this pit is lined with black plastic. This pit holds the drilling “mud” In drilling, the drill bit, a $60,000 item drilling through often tough rock, must be kept lubricated. This is accomplished by pumping a drilling liquid down to the drill bit as the constantly as the well is being drilled. The liquid is stored in large tanks. Keeping this entire process going is extremely important, as the drill bit will fail in a very short period of time without the lubrication from the drilling liquid. It is helpful to think of this as just a giant version of applying 3-in-1 oil to a drill bit drilling in steel to make it easier for the bit to cut and to cool the bit. This liquid then has to be constantly flushed back out of the well along with the drilled particles of rock, and comes back as drilling mud that gets stored in the plastic-lined pit, as seen on the right side of this photo. Drillers like to get as much use out of each bit as possible, and replacing a drill bit is costly, time consuming and often dangerous work, because all the pipe down to the current depth must be pulled back of the well, say as much as perhaps 10,000 feet of pipe. The fewer bits that need to be replaced, the faster the drilling can proceed. Work proceeds 24/7 and crew quarters have been brought on to the site.



Scoria remains the surface material of choice for oil drillers. What amazes me is that drillers were using this same material around North Dakota wells 40 or 50 years ago. What appears to be a reddish rock is actually clay that has been naturally fired into a coarse brick-like material from underground veins of clay naturally occurring close to once burning veins of lignite coal. With all the wells being drilled the companies are using huge amounts of scoria, as every well, not to mention many of the new roads being constructed are being covered with this material that is commonly found in western North Dakota and in Eastern Montana.



Here are two closer shots of the drilling pit along with the pile of dirt removed to construct it.



The area covered in scoria is quite distinct from the gravel-covered area. The stairs will be used for the workers to climb on the rig.

Drilling can proceed in the summer as well as in the winter, and in the winter roads can become nearly impassible. This photo shows the road leading to the Shell 3 5H Well site, on the NE side of the Parshall field, early March, 2009.

In the winter months, substantial quantities of snow must be removed to prepare the site. In recent months, EOG has been employing truck-mounted Major 43 rig to drill the first 2000 feet of each well, before the main rig comes on-site. This shows that operation underway in early March 09. This rig is exactly on the spot where the Shell 3 5H state was located in the earlier photos.

Here is a closeup of the truck-mounted rig.



This photo shows the Pioneer 57 rig operated by the Pioneer Drilling company being moved into place, pn Parshall 4 20 152 90  with the help of a crane. This shot was taken about May 27th, 2008. Pioneer Drilling is the contract driller for EOG on this well.The rig is being assembled and is not yet operational. These rigs are a very new design that can be very quickly moved on and off a site in comparison with older rigs.



The four large green tanks hold the liquid used to lubricate the drill bit.



A curious thing about being in an area where oil development is taking place is that roads suddenly may appear in places where none existed before. This road, heading northward from ND 23, about 4 miles west of Parshall, leads to the School 16 well,  about ¾ mile up the road on the right, and will also be a connector to two other wells now being completed on sections 8 and 17. This road, covered with red scoria was always just a prairie trail before, and completely impassible during the winter months. Given that a well typically costs 5 or 6 million dollars to drill, the cost of building a road to the site may be a minor component. This is often done around the time the well site is being prepped with scrapers and other equipment.



It’s always fun to take a photo of the mail box at our home farm with the Pioneer drilling rig in the distance.



Drilling is underway on Parshall 4 by the Pioneer 57 crew, on a cloudy day, with the stair we saw on the ground in the earlier photo now in place. This photo was taken the first week in June, 2008.



This is a much nicer day, and drilling is proceeding at a rapid pace.



Work proceeds at night too, under bright lights. A little background on the construction of this drilling rig. The design is interesting. The drilling on this rig is accomplished using a 1000 hp electric motor, with an equally large diesel generator sufficient to generate the electrical current needed to run the electric motor. There is no external AC power to the site at this point. The technology is not unlike a diesel engine on a freight train, which also uses a diesel motor to generate the needed current to power the wheels. Not all rigs use a giant electric motor to turn the drill bit. Some are powered directly from a diesel motor. But this particular rig uses diesel-generated electricity and an electric motor. (number 57 on this Web site)



Nabors-run rigs, this one shown when it was drilling on section 5 of 151 90, Fertile Township, have a more nearly classic “taper” associated with oil well drilling than the Pioneer rig does.



Here we are back at the Pioneer 57 rig on a day in which a thunderstorm was brewing. A tall rig like this is a dangerous place to be in the event of a thunderstorm. Drilling appeared to have stopped and the workers had gone for cover as the lightning and rain storm approached from the West.



Four weeks have now passed. The main drilling rig, the Pioneer 57 has moved on to drill Shirley section 17 152 90 a couple miles north. A new smaller, completion or “workover” rig is now in place, further prepping the drilled hole for oil production. The main job here is to put in the liners and tubing into the casing put in place by the main drilling rig. Seven permanent main storage tanks have also arrived and been set on the left of the photo. On the right, are 30 or more tanks mainly used to hold water used in the fracing operations. This photo was taken about July 16th, 2008



Here is a better shot of the fracing tanks, similar if not identical to the permanent storage tanks in size



This is yet another shot of the well as it is prepared for fracing.



At this stage, about a week later, the smaller workover rig has left the scene and has moved to the next well in sequence, a few weeks later on the EOG schedule. The site appears very calm. The wellhead where the tall rigs were now appears at the center right. Up on the hill is my parent’s farm. Seven permanent storage tanks on the left, and one of many temporary fracing tanks on the right.



Suddenly, just a couple days later, the site is a beehive of activity as the well is fraced. The crane in the center of the photo is the so-called fracing crane. This is the part involving the fracing gun, setting charges using the gun at 8 or 10 points along the lateral to perforate the well casing, and then injecting the well with water and sand to crumble the shale rock so that it more willingly gives up its hydrocarbons. Vehicles, tanks and equipment nearly completely cover the well site, with heavy traffic both in and out. THe main purpose of the sand is to keep the rocks created by the compressed water from closing again, The sand is called a "proppant: It props open the cracks.



This is a distance shot of the well site showing a typical gravel road, old ND 23 4 miles west of Parshall now known as 38th. These roads are suffering heavy under the constant truck traffic.



The production of oil for sale occurs only a short time after the fracing is completed. This photo shows a tanker truck drawing oil from storage tanks on Parshall 5 21 152 90, about a month ahead of Parshall 4 20 152 90.



At times there is more than one truck waiting its turn to load at this well. The pipeline here is staked but that is about it.



Further East, we had the opportunity to see both the Nabors and Pioneer 57 rigs drilling almost across the road from each other. This shot is looking west taken about a mile west of Parshall. In this photo, the Nabors 337 rig is drilling Parshall 13 26 152 90, and the Pioneer 57 rig is drilling  Parshall 6  22 152 90, which is where it moved after completing Shirley 17 152 90. The Nabors rig is the same one that drilled the Fertile 5 well in May. Then it moved North to drill Hovda 8 152 90, in late June, and it was on this site in July through early August 2008.




Just west of 26 152 90 is a place where a pipeline connection point is being built.



Coming back to Parshall 4 20 152 90, fracing is now complete and there are two flares. The first is the more or less permanent ground flare used to flare off natural gas coming along with the oil. The second flare is at the top of a 30 foot tall pile, and is being used to flare off natural gas that comes back along with the fracing sand during the fracing operation. Until abouit a year ago, the natural gas in the fracing sand was simply vented without flaring. However, it was discovered that this was dangerous. On a still night, shortly after completing fracing on the Zacher well, this gas collected near the ground. A spark from a diesel generator being started ignited the gas, and caused a major explosion and fire, seriously injuring several oil workers.

Bismarck Tribune fire article


The pipe you see is with the flare is the new “safer” way of removing the natural gas from the sand coming back from the fracing process. The idea is to get this gas up in the air and then burn it off, not accumulate low to the ground, This tall flare pipe is used for only a few days, then removed.


At this point the main, lower flare seems rather small. This is because there is still a lot of water in the well from the fracing operations that limit the size of the flare. As this water is flushed out, the flare will increase in size over the next several days



This is a shot of the flare a few days later, which is now quite a bit larger. The pipe and its flare burning gas from the fracing sand is now gone. It is an interesting site to see a flare like this coming from the middle of a North Dakota wheat field.



Flares are visible from long distances away, as this photo was taken of the same flare a day or two later



Here is a close up shot of the oil storage tanks. This well has 7 storage tanks, of which 6 are used to store crude oil while the 7th is used to store water that is coming up along with the oil.



A truck arrives to pick up some of the first oil being produced by Parshall 4 152 90. It is sometimes difficult to know whether the truck is removing oil or water, although I am pretty confident this truck was picking up oil not water.. Water from this well is stored in the 7th tank, collected and then taken to another well site to be used in the fracing operation. There has been some discussion over whether water recovered from wells can be used for fracing, but apparently at least the water from some wells can be used. The city of Parshall has also been supplying water for fracing from their city water supply obtained from lake Sakakawea, and this has put strains on the water supply.


A couple weeks later, the big tanks used to hold water for fracing have been moved to the fracing job forthe next well in sequence, probably Shirley 17 152 90 or Hovda 8 152 90.

The gas flare on a windier day, with the flare venting sideways. I am not certain what purpose the additional temporary storage tanks are serving at this point.


The flare from a still longer distance.



This is the actual wellhead. At this point in time here is no pump, only a big valve. The well is pumping under its own internal pressure and the pressures of the natural gas. I was told that the night this photo was taken, the well was producing  about 75 barrels of oil and thirty 30 barrels of water each hour, completely under its own pressure. This may continue for months before a pump is added as the internal pressures come down and production on its own tapers off. The liquids and the gas coming out of the well exit out of the small pipes you see coming from the wellhead



First, the gas is flared off. This photo was taken on August 1, almost exactly two months after spudding commenced (the drill bit for the well first hit the ground). At this point, on a still night, the natural gas flare extends 30 or more feet into the air. The flare is taller than the separator on the left, which I would estimate at about 25 feet high. Gradually over time as internal pressures in the well subside, the flare will become smaller, but at this point the flare is huge.


The unit on the center left is called the separator. Its job is to separate the crude oil from the water in the liquid, after the gas is flared off. Water regularly occurs along with crude oil, and sometimes exceeds the crude oil quantity. However I have learned that on the night this photo was taken, the well was generating approximately 75 bbl of crude per hour along with 30 bbl of water, all under its own pressure. This ratio is quite acceptable, particularly for a newly producing well.



Finally, here is a close up shot of the brilliant flare.




Rural and Community Development


The recent discovery of large amounts of crude oil, unprecedented amounts by historical standards, in south and central Mountrail county has led to the start of an equally unprecedented economic oil boom. It is sometimes difficult to grasp how productive these wells are relative to the oil wells drilled in the past. Three oil fields were developed in Mountrail and in Ward County to the east in the late 1980s and early1990s. These included the Plaza field and adjacent Wabek field, and a field in Northwest Ward county centered on the town of Berthold. Many of these wells still produce some oil. If we were to combine the entire production of all the wells in the Plaza and Wabek fields with the entire current production of Ward county, the TOTAL from perhaps as many as a hundred wells would be equal to the current production of a SINGLE moderate producer drilled in the past year in the Parshall field.


All of this new-found wealth has got to have enormous impacts in a county that for sure historically was not considered to be among the wealthier counties in the state. This is basic Great Plains cattle and grain land, in an area that averages perhaps 16 inches of moisture a year. Certainly not the place one would normally expect to find a lot of wealthy people.


Bruce Gjovig,  the director of the University of North Dakota's Center for Innovation, said his informal survey estimates the number of new millionaires in Mountrail County, one of the biggest drilling areas of the Bakken, may be as many as 2,000. This may not seem like a lot of people, but the population of the entire county is only 6500 people, according to recent Census numbers and so this represents nearly a third of the county's population, all in the next three to five years.


Stanley, the county seat of Mountrail, may have grown from by as much as 400 people from its recent 2006 Census estimate of about 1,206 people. With oil development comes jobs and people earning incomes unheard of in the county just a few years ago. It is not uncommon for jobs in the oil industry in the county to start at as much as 70,000 a year and go up from there.



Joyce’s café, on the west side of Main street in Stanley, is a popular hangout for those in Stanley in some way connected to the oil business.



But the real oil hangout is at Scenic 23, a  restaurant and bar located at the intersection of ND 23 and ND 8, about 11 miles west of Parshall. Scenic 23 has been at that location for many, many decades, and has changed ownership and been rebuilt and rehabbed over the years. It is close to the Van Hook fishing crowd and the old town of Van Hook, so it caters to those who have spent the day on Lake Sakakawea whose Walleye fishing turned out to be less than adequate (Although, for a fee, they will cook and serve YOU your catch of the day0 In The last two years, however, increasingly it has catered to the oil workers in the area, since it serves perhaps the beft food in the area, generous quantities of seafood and steaks, at reasonable prices. Families receiving royalty checks like to take over tables in the dining room earlier in the evening, while workers and others gradually drift into the dining room from the bar area as the evening continues. In short, if you are somehow involved in Mountrail county oil, this is THE Place to see and be seen. (I’ve likened it to North Dakota’s own version of the Cattleman’s Club on the TV show “Dallas,” the restaurant and bar that the Ewing brothers liked to hang out at to cut oil deals.



The night I shot this photo, the special was the 16 ounce ribeye for $17.95. Just the meal after a long day roughnecking on an oil rig nearby. And the rigs are nearby! In July of 2008, you could almost reach out the window of the restaurant to Slawson’s Nabors “Payara” rig. just across the road on 23 (For those who do not know, the Slawson Payara well is named for a fish only in some Venezuela rivers. Sometimes dubbed the vampire fish, it has two overgrown incisors, and as a predator fish loves to munch on smaller Pirana. Unlike the other drillers, who tend to name wells either after the surface owner or the township name, Slawson has these marvelously creative names for their wells, names like Payara, Nightcrawler, or Goldeneye. Company employees must stay up nights dreaming these up)



How Everything Works from a Mineral Owner’s Perspective


Generally there is about a six month lag between when a well completes for the first sale of oil and when the first royalty check arrives to the mineral owner in the mail. The title searches necessary to assure that the mineral ownership is current and the proper individuals will be made of necessity have to be much more extensive than was the case when the leasing takes place, as the operator wants to make certain that the royalty checks go to the individuals who are legally entitled to them.


While the size of the spacing unit ordinarily employed by drillers active in a field is generally known, the spacing is not formally approved until after a pooling hearing takes place at the Department of Mineral Resources conference room in Bismarck. These are open hearings, and they are broadcast live over the Internet. Several weeks prior to the hearing, all mineral owners on the proposed spacing will receive legal documents from lawyers employed by the company providing notification of the pooling hearing as to date and time. Generally, if the mineral interest owner does not own the surface land upon which the well is drilled, this is the first contact the mineral interest owner will have had with the driller. The mineral interest owner will be asked if there is an objection to the proposed spacing that “pools” all of the mineral interests within the spacing. As suc, a mineral acre located anywhere within the spacing will receive the same royalty as any other mineral acre located anywhere within the spacing—that is, mineral owners with interest located physically closer to the wellhead do not receive large payments so long as the mineral owner is within the proposed spacing . Under normal circumstances the correct answer is “no”. If the mineral interest owner objects to the spacing, the owner may still receive royalties, but these royalty payments will be net of charges for a share of the cost of drilling the well. In the “normal” pooling, all drilling costs as well as the risks associated with the well being a dry hole are incurred by the driller or other interested parties who also own some of the leases on the spacing. IT is not uncommon for the driller to own only a percent of the leases on a spacing, and oil revenues and drilling costs will be shared with other companies who also own part of the leases.


Normally, pooling hearings proceed routinely and without objection. After the pooling hearing for a particular well and spacing takes place, the legal work necessary to actually cut royalty checks from oil sold from the well will typically take another 2-3 months before the first royalty payment is received. The first royalty check typically is quite large as it not only includes payments for the period of time when the well was most productive, it typically covers royalties for the first 2-3 months of production. After that royalty checks  generally are for a single calendar month of production, ending approximately 45 days prior to when the oil was actually produced and sold.


There is often a difference between the amount of oil produced by a well and the amount that is sold, the so-called production versus “runs.” Oil that is out of the ground in a particular month might remain in a storage tank and not be sold until the following month, Royalty checks are based on the actual sale of oil sent to the refinery, runs not production. This is not unlike a farmer unloading a truckload of grain at the elevator. The elevator operator keeps track of the price it paid for the grain and the exact quantity that was unloaded, and then periodically cuts the farmer a check for what might be the value of all the grain that was unloaded. The average price per bushel paid over the period is the ratio of the sum of the value of all the grain delivered during the period by the sum of the quantity of grain delivered. On any given day the farmer may receive a larger or smaller price for the grain delivered that day, and the farmer will deliver different quantities of grain with each load. Over the course of a month, this all averages out. And the driller/operator may try to get truckers move oil to market  as quickly as possible if the oil price appears to be decreasing each day.


How are Mineral Royalties Calculated?


1. The lease the mineral owner signs will indicate a percent that the mineral owner agreed to in signing the lease. This is normally expressed as a fraction. Leases signed before the drilling activity started in 2006 generally were 1/8 leases or 12.5 % (0.125). Then in about 2006 the leases typically got more generous, or 1/7 leases, which works out to
14.286%  (0.1428571). Most recently, some leases have been signed at 3/16 which works out to 16.75% (0.1675) and still more recently, a few leases have been signed at 1/5 or 20 % (0.20).

2. The size of the spacing unit along with the number of mineral acres owned by the individual is critical in determining the royalty payment. Nearly all Mountrail county EOG drilled wells are 640 acre spacing in the Parshall field, but the Sanish field wells drilled by Whiting are more commonly on a two-section or 1280 acre spacing. If two wells are drilled on a 1280 acre spacing, the mineral owner will receive royalties from both wells irrespective of where the individual wells are located within the spacing, which makes twin 1280 acre wells equivalent to being back to a 640 acre spacing..

3. All owners of mineral acres in the spacing unit share in the royalties from the well in the spacing unit irrespective of whose land the well is on or where the well is located within the spacing unit, by the ratio of the number of mineral acres the individual owns
divided by the number of acres in the spacing unit. Wells on adjacent spacing units pay no royalties to individuals owning mineral acres outside their own spacing unit. So it
could be that a well physically located closer to an individual’s mineral acres pays you no royalties at all whereas a well located a greater distance away but within your spacing unit is making royalty payments. What is critical here is that the well is being drilled on the spacing unit in which you own the mineral acres.

4. Ordinarily, section boundaries are used to define 640 and 1280 acre spacing units, either one or two sections, and a 1280 acre spacing unit is typically a rectangle, but it could be longer N-S or longer E- W.. There are exceptions to this rule, however, Some sections have more than 640 acres as they contain extra lots that are not part of quarters, and because of adjustments that need to be made for the curvature of the earth, some sections are slightly shy of 640 acres. These short sections are often in the northernmost row of sections in the township. Whatever the actual acreage of the spacing unit is in acres becomes the denominator for the calculation done in 3, above.

5. To calculate the royalty payment, first multiply the percentage calculated in step 1 times the percentage of mineral acres in the spacing calculated in step 3.. The resultant number, carried out to 8 decimal places, is called the owner interest. Sometimes there are
other deductions, such as a situation whereby a previous owner kept a specific percentage, not a fractional share, of the mineral rights. These are deducted to calculate what is termed a settlement interest decimal. Normally, however, the owner interest decimal and the settlement interest decimal are the same. But technically it is the
settlement interest decimal not the owner interest decimal that is used in the actual calculation of the royalty check.

6. The well operator during any specific month keeps close track of the volume of oil and gas the well produces, and the wellhead price for each less transportation charges. By multiplying these numbers (volume x price per unit), the gross value of both the oil and gas is calculated.

7. To calculate the royalty check, the settlement interest decimal calculated in step 5 is multiplied by the gross value of the oil or gas (each separately). The resultant number (or summed numbers, if there is both oil and gas) represents the gross royalty payment.

8. The state of ND collects an 11.5% oil tax from the gross royalty payment each month, a combination of what is called a severance or oil extraction tax, which is automatically subtracted from the check amount from the operator each month. Recent changes in state law have reduced this rate to only 5 percent, but the law apparently reads that this rate applies only to the first 75,000 bbl of oil produced from the well. These severance and extraction taxes are above and beyond federal and state income taxes that the royalty owner must pay.

9. Ordinarily the federal government permits 15% of the gross royalty payment (before the severance tax deduction) to be subtracted from the gross royalty payment as a depletion allowance on schedule E, which is the Federal tax form a mineral interest owner would ordinarily file to report royalty income. The owner reports the gross royalty payment as the income line on schedule E. There is a row for the depletion allowance
to be subtracted on schedule E, as well as a row to report the deduction from the gross royalty income the severance and extraction taxes tax paid to the state as an expense also subtracted from the gross royalty payment. The well operator sends the mineral interest owner a 1099 reporting the gross royalty payment along with the amount of money paid as severance tax, so that these numbers can be reported on Schedule E. The schedule E income is thus the gross royalty payment less 15% of the gross royalty for depletion less the severance tax paid to the state as a tax expense.

The Future


The state of North Dakota as well as individual mineral interest owners owe a huge debt of gratitude for the decision by EOG Resources to run an “experiment” in Mountrail county starting about 2 ½ years ago, in 2005. North Dakota has been producing oil for over 50 years using general approaches and technology that I would argue had changed only in small increments over the years. It was becoming increasingly known that large amounts of hydrocarbons did exist in wide areas at about 10,000 feet. Dr Leigh Price at the USGS had certainly attracted some attention when he made his 500 billion barrel estimate in the late 1990s, but no one really felt that a significant quantity of this oil could be extracted at any sort of reasonable price. Price was making these estimates when the terms “horizontal drilling” and “fracing” were not part of ordinary conversations among oil drillers


I like to ponder the question as to whether the EOG executives were exceptionally smart relative to all of the drillers that had preceded them, or simply got exceptionally lucky. But perhaps this is not the proper issue. Sometimes one cannot get lucky without being at least a little bit smart or at least a little bit inventive which is much the same thing as being smart. Southern Mountrail county looked like a lot of other places in Western North Dakota in which futile attempts had been made to drill for oil employing simple vertical wells. A horizontal well with fracing costs perhaps 2-3 times as much as it costs to drill a vertical hole, so the stakes were raised if such an elaborate well were to come up dry.  Fortunately, EOG as a company had the financial resources necessary to place those bets. Prior to drilling a single hole, EOG was able to accumulate a substantial lease acreage for very little money because all the other drillers thought the odds of producing an economically viable well on the acreage were so long. This is the core of the game of trying to be both smarter as well as luckier than your competitor, which has always been the central part of the oil business.


Other than the experience of drilling for gas in the Texas Barnett field, EOG had drilled few horizontal wells for crude oil by the start of 2006, and had more guts than experience. They had a hunch that this might work equally well for crude but that was about it. By the summer of 2008 they have had way more experience doing this than anyone else in the industry. Companies learn fast when a 100+ % return on investment awaits!


Right now, fall 2008, the field is expanding both North and South—north into Burke past Austin Township, which is now almost completely drilled, and south past the last row of sections in Parshall township. There seems to be mounting evidence that the field does not extend eastward into Model or Shell townships past the first 3 or 4 westernmost sections in those townships, based on production results as wells are attempted on the Eastern side of the field. But to the west the Parshall field merges with the Sanish field, and although fewer wells by far as yet have been drilled by Whiting and a few other operators working that area, some of these wells have very recently been coming in at very high initial production levels, most notably 11 22 153 90 and 11 24 153 90 wells.


One developing problem could be that after the initial production burst, usually more than enough oil is recovered to more than offset the total well cost  production on many of the wells, after a year of operation, has perhaps declined in volume far more rapidly than the well operator had anticipated, or the mineral interest owner would have liked. It is not uncommon for a well that started production at a 750-1000 bopd rate to be producing at a 150-200 bopd rate one year later, or at perhaps 20 or 25 % of the initial production level. The pressure on these wells results in huge amounts of oil coming to the surface initially, comparable with the best wells ever drilled in the US, but after several months, as these internal pressures drop, production tapers off pretty rapidly.


EOG has two experiments underway in an effort to deal with the problem of rapid declines in production over time. One of these is to test the use of a CO2  injection system known as huff ‘n puff. In the “huff” portion CO2  is injected into the well to restore pressures more nearly similar to those occurring naturally when the well is first drilled. In the “puff” portion, the injected  CO2 brings the repressurized oil back to the surface. The first experiment on a Parshall field well is being done fall of 2008 on the earliest Austin township well, Austin 1 2 154 90. No one knows how successful this experiment will be.


The second experiment underway involves downsizing the spacing of wells from the existing 640 acre spacing to the equivalent of something smaller, perhaps the equivalent of 320 acres, or half-section spacing. This would be accomplished by creating two 1280 acre spacings involving adjacent sections for each current mineral interest owner, and drilling wells in between the existing wells. For example, if a mineral owner located on a 640 acre section 2 spacing, that mineral owner would also share in the royalties on a well located on a 1280 acre spacing that crossed the line between sections 2 and 3, as well as in the royalties on a well on a 1280 acre spacing that crossed the section line between sections 1 and 2. 


The following map shows a well that was recently completed with a lateral running between the laterals for the Patten and Bartelson wells.


In his report to investors last winter, EOG CEO Mark Papa indicated that this effort at downspacing was an experiment, and that the information from this well would constitute data useful in determining if such an approach was a viable method of increasing the productivity of the field. He expressed a fear that most of the oil pumped from the new well would merely reduce the output of the previous wells drilled on the adjacent sections, in this case the Bartelson and Patten wells, and that the net increase in production when the two older wells were totaled with the production might be minimal


However, field reports suggest that Papa’s fears have not been realized and that  the new well, while still confidential, came in as a very good producer. (Translated, this means that the substantial production from the new well did not in a significant way reduce output from the older wells, beyond what would have occurred anyway as production from existing wells declines over time and so that nearly all of the production from the new well represents a net gain.)


What these very preliminary results suggest is that new wells might very well be added at many different places to the existing Parshall field employing this same or a similar if not identical approach, and that this may be a effective way to maintain the productivity of the field as older wells decrease production over time. True, each new well costs 5 or 6 million dollars to drill and we are talking about a capital expenditure that could essentially double what has already been spent but if each new well comes in strong, it will recover its direct drilling costs in only a few months anyway.


The important question at this point is which of these two strategies, the huff ‘n puff involving repeated injections of carbon dioxide into an existing well, versus simply drilling new wells on closer spacings will do a better job of maintaining field productivity over time. EOG Undoubtedly would like to know the answer to this question as well. It could be that a combination of both techniques will be employed, or perhaps something new that no one has tried yet.




David L. Debertin