The Bakken
Rocks:
Oil Development in
Geology, Economics, and Rural Economic
Development
History
The state
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
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
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,
Map courtesy the Department of Geography at the
The
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
Right now, there are four basic questions:
- 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?
- Can the rock be made to give up its hydrocarbons without relying on locating naturally occurring fractures has been very much hit or miss?
- What level of extraction cost is reasonable and prudent? $25 a bbl? $50? $100? $200? $500? still more?
- 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.
http://tdecorp.blogspot.com/2008/01/one-trillion-barrels-of-oil.html
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
https://www.dmr.nd.gov/ndgs/bakken/newpostings/07272006_BakkenReserveEstimates.pdf
This is no small matter! The total known reserves of
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
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
EOG Resources
What I have described above basically traces the history of
oil production in western
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,
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
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 What happened subsequently is fascinating. EOG geologists
spotted two areas that looked like possible targets for experimentation, one in
eastern
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 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, http://www.eogresources.com
shows the scope of EOG operations in the continental US. As you can see, most
of EOG’s drilling activity has been concentrated in
EOG also has drilling operations in
The area EOG chose for their initial experiment in drilling
the Bakken in
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 This is a GIS map of https://www.dmr.nd.gov/oilgas/riglist.asp
https://www.dmr.nd.gov/oilandgasims/viewer.htm 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
The entire presentation can be downloaded at http://www.whiting.com/download/GENERAL_CORPORATE_INFORMATION.pdf 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,
http://www.reuters.com/article/pressRelease/idUS87775+20-May-2008+PRN20080520 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 Prior to 2006, the vast majority of oil wells drilled in Typical of these are a well shown south of Plaza,
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
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
Most of the land currently being drilled accommodates a
mixture of small grain and pasture for cattle. The scene here, near Shell
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
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
Scoria remains the surface material of choice for oil
drillers. What amazes me is that drillers were using this same material around
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
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) http://www.pioneerdrlg.com/HTML/RigFleet.html
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
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
Just west of 26 152 90 is a place where a pipeline
connection point is being built.
Coming back to Parshall 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
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
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 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 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. http://www.msnbc.msn.com/id/25466382/
Joyce’s café, on the west side of
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
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
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 https://www.dmr.nd.gov/oilgas/docketindex.asp 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 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 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 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 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. 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. 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 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 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 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
dldebertin@aol.com
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).
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.
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.
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. 