an overview of the antrim shale a broad based evaluation of the natural gas resource
DESCRIPTION
Evaluation of the Antrim Shale formation in MichiganTRANSCRIPT
1
An Overview of the Antrim Shale: A Broad‐based Evaluation of the Natural Gas Resource
John Maxwell
GER 396
November 22, 2011
2
Table of Contents
I. Abstract
II. Introduction
III. Geologic Features of the Michigan Basin
a. Subsidence Patterns
IV. Geology of the Antrim Shale
a. Natural Fractures
V. Hydrocarbon Formation of Antrim Shale
a. Thermogenic Generation
b. Biogenic Generation
VI. Antrim Shale Natural Gas Development
VII. Production and Well Completion
a. Drilling Cost
b. Low Reservoir Pressure
c. Water Co‐production
d. Hydraulic Fracturing
VIII. Regulatory Environment
IX. Future of the Antrim Shale
a. Use of Vacuum Pumps
b. Technological Developments
c. A Hybrid Approach to Drilling
d. CO2 Sequestration and Enhanced Gas Recovery
X. Conclusion
XI. Figures
XII. Works Cited
3
Abstract
The Antrim Shale is an unconventional natural gas in the north of the lower peninsula of
Michigan. There have been estimates of the Antrim Shale containing between 35 and 76 TCF of
natural gas. Up through 2009, there has been about 3.0 TCF recovered (Agrawal (2009) p.
12).The peak of production was in the late 1990’s as the graph below illustrates.
The main reason for the boom in the late 1990’s was rigs coming online from earlier years
drilling. There was a rush of drilling permits right before the ending of the federal Section 29
Non‐Conventional Fuels income tax credit were expiring in the early 1990’s. Once the credits
expired, the permitting dropped off substantially. While operators in the Antrim Shale have used
hydraulic fracturing for many years, they have done so though using traditional vertical drilling
to access the gas. The reasons for this are threefold: low drilling cost, low reservoir pressure and
high water co‐production. Of these factors, low reservoir pressure and high water co‐production
are barriers to increase the practice of horizontal drilling. Deployment of vacuum pumps to
increase reservoir pressure (currently under Michigan regulation) and a successful utilization of
a hybrid vertical‐horizontal drilling technique called the “J” shape may be the answers to extend
the life of the reservoir.
0
50
100
150
200
250
Antrim Shale Gas Production 1991‐2010 (bcf) Source: (MSPC)
4
Introduction
The aim of the paper is to cover the detail of the Antrim Shale, from the past geologic features
through the current production and finally the future of this mature natural gas resource that
has produced gas for the state of Michigan. The organic‐rich black shales of the Antrim
sequence has produced natural gas since the 1940’s, but only in the past 20 years has the scale
of production expanded. [Figure 1] The Antrim Shale is an unconventional reservoir that is
located in the Michigan Basin. This is an interesting time in the Antrim Shale as the sequence has
properties that make the industry‐wide practice of horizontal drilling for gas in shales very
difficult in the Antrim formation (Agrawal (2009) p.60). This paper will cover those reasons for
the lack of horizontal drilling adaptation as well as the geology of the Michigan Basin, its
subsidence pattern and the geology of the Antrim Shale. Next, the natural fractures and
development of the natural gas will be explored. A discussion of the nature of formation of the
gas, thermogenic versus biogenic, will also be covered. The history of production, current well
completions, production techniques, and regulatory environment are then discussed. Lastly, an
evaluation of possible options for the future of this mature basin will be considered.
Geologic Features of the Michigan Basin
The Michigan Basin is a fairly shallow basin which covers most of the lower peninsula of the
state. It ranges into the surrounding states of Illinois, Indiana, Ohio, and Wisconsin. The rock
structure of the basin ranges in age. The earliest basement rocks are Cambrian and the youngest
in the basin are glacial deposits. [Figure 2] Due to ice ages, the basin is covered by thick layer of
glacial deposits (Catacosinos et al. (1990) p.561). Having a circular shape, the basin has a 200 km
radius and is about 5 km thick (Howell & van der Plujm (1999) p. 974). The Michigan Basin
formed by marine sedimentary rocks that have an average thickness of 4800 m (Catacosinos et
5
al. (1990) p.561). The basin’s round geometry and its multiple layers of subsidence cannot be
attributed to any one specific factor. The main dispute in the formation of the basin focuses on
the observation that the subsidence rates are not homogenous throughout the basin. Two of
the theories that are proposed are: subsidence as a consequence of a “stress‐induced crustal‐
weakening mechanism” and “thermal contraction” through a subsidence period (Howell & van
der Pluijm (1999) p.974). The Michigan Basin is an interior cratonic basin. An interior cratonic
basin is a stable area of crust that has been stable and immobile for many millions of years. The
dense crust is stable in a relative sense and has kept its position in relation to sea level. A stable
cratonic zone may be buckled, but the crust has been immobile and in a solid state for a very
long time. The Michigan Basin is a sag basin [Figure 3] (Leighton (1990) p.1&9). Some interior
cratonic basins like the Illinois and Paris basins, have experienced swift and frequent subsidence
events in their past. In contrast, the Michigan Basin has experienced many events of subsidence
throughout its history including up to near geologic time (Howell & van der Pluijm (1999) p.974).
The area of Michigan Basin is 205 km2 and in terms of cratonic basins, it is smaller than the
Williston basin in Montana and southern Canada, but is larger than the Illinois basin. The
Michigan Basin was created on top of a Precambrian basement rock (Leighton et al. (1990)
p.729‐736). The basement subsidence patterns can help to show the age of the specific
stratigraphy of the different areas of the basin (Howell & van der Plujm (1999) p. 976‐77). The
specific basement rocks that underlie the Michigan Basin are gneiss, granites, mafic intrusions,
and volcanics (Catacosinos et al. (1999) p. 563).
Subsidence Patterns
The basin has the unique circular structure with four main types of subsidence: trough‐shaped,
narrow basin‐centered, broad basin‐centered and regional tilting. The two basin centered
6
subsidence patterns are the majority of the subsidence seen in the Michigan Basin (Howell &
van der Plujm (1999) p. 974). Howell & van der Plujm (1999) identified six main sequences in
the basin with one minor sequence. [Figure 4] A major sequence of subsidence has an age of
Upper Devonian through Mississippian. In this sequence, there is a regional eastward tilt to the
subsidence. The rock types in this sequence consist of: shales, sandstones and anhydrites. This
sequence also contains the Antrim shale group which will be discussed further in the next
section (Howell & van der Plujm (1999) p.983‐4). The thin minor sequence that has been
identified is of Upper Devonian age, is comprised of sandstone and shales. It also has a broad
basin‐centered subsidence pattern (Howell and van der Plujm (1999) p.982‐3). Overall, the
Michigan Basin has had many periods of great subsidence activity and then no activity. The basin
and its rich organic history have led to the formation of sedimentary layers where highly
enriched organic rocks were formed. The next section will discuss the geology of one of the
enriched layers: the Antrim Shale.
Geology of the Antrim Shale
Nearly all of the Lower Peninsula of Michigan has Antrim Shale beneath it (Manger et al. (1991)
p.511). The overlying layer of the Antrim is called the Ellsworth Shale. The layer beneath the
Antrim is the Traverse Formation. The Traverse Formation is mainly composed of limestone, but
has also been called Mud Lake Gray Shale (Dellapenna (1991) p.12 ‐18). The Lower Antrim Shale
with a Devonian‐Mississippian age was created as a result of a large sea which is known as the
“Black‐Shale Sea”, which spread throughout what is now the North American continent. On top
of the Devonian and Mississippian sequences is a section of hundreds of feet of glacial remnants
[Figure 5] (Kuuskraa et al. (1992) p.210). The mineral make‐up of the Antrim is: “50‐60% quartz,
20‐35% illite, 5‐15% kaolinite, 0‐5% chlorite and 0‐5% pyrite” (Dellapenna (1991) p.8). The
7
Antrim shale has a composition of two main types of shales. The first is highly organic black
shale and the second is a low organic, carbonate mixed gray‐green shale (Dellapenna (1991) p.
i). These two main categories are further broken into four categories: lower gray shale facies,
lower black shale facies, middle gray facies and upper black shale facies (Manger et al. (1991)
p.517). The names of the shales located in the Antrim section are the Norwood, Paxton and
Lachine members (Kuuskraa (1992) p.2). The Lachine and Norwood are the hydrocarbon
production areas and have the highest organic content (Agrawal (2009) p. 15). The main area of
focus for the natural gas development is in the black shales, Norwood and Lachine which are
highly enriched with organic material and contain up 16 wt. % total organic content (TOC)
(Martini et al. (2008) p. 328). The TOC of the shale influences the color of the shale in a direct
way. The shales which are darkest have the highest TOC wt. % (Dellapenna (1991) p.25). Interior
cratonic basins are known to contain Upper Devonian sedimentation in thick layers as well as
high TOC black shales (Martini et al. (2003) p.1358). The measurement of the TOC of the shales
is measured by the gamma ray magnitude for which the Norwood and Lachine formations have
the highest relative reading. [Figure 6] The formation of hydrocarbons in the Antrim Shale will
be discussed in the following section. Some other interior cratonic basin shales that contain
black shales similar to the Antrim Formation are New Albany Shale, Woodford Shale, and
Bakken Shale (Dellapenna (1991) p. 18).
Natural Fractures
Although the source and reservoir rocks are the same in the formation, the Antrim Shale is also
highly fractured which allows for the migration and concentration of the gas (Martini et al.
(2003) p.1359). These natural fractures are very significant to the production of shale gas. The
natural fractures make the shale brittle and allow for hydraulic fracturing to take place. The
8
current natural fracture system and the hydraulic fracturing allow for connection of the gas
generation area to recovery area (Matson (2010) p.5). The fractures in the Norwood and Lachine
members are most significant (Goodman & Maness (2008) p. 23). [Figure 7] These fractures
were likely created by the glacial process that took place in the Pleistocene and the subsequent
melting of those glaciers. The recurrence of glaciers moving back and forth across northern
Michigan, aided in the expansion of existing fractures (Martini et al. (1998) p. 1719). [Figure 8]
The northern margin of the Antrim Shale is a unique shale reservoir in that its environment has
low thermal maturity and system of naturally formed fractures. The fractures have been a
catalyst in the flow of glacial water to recharge and the hydrocarbons to transmigrate to
reservoir rock (Martini et. al (2003) p. 1359). The mass of the movement of multiple glacial
events on the basin may have been the contributing factor for the creation of the fractures. The
water from the melted glaciers moved into these fractures and provided an influx of fluid. These
fluids with low saline content are conducive to an environment for microbial activity. This
positive relationship of the water and bacterial activity has been the key to gas formation (Shurr
& Ridgley (2002) p.1959).
Hydrocarbon Formation
There is evidence that the interior cratonic basins are containers for the development and
storage of hydrocarbons (Leighton (1990) p.13). In the Antrim Shale, the primary hydrocarbon
developed is natural gas. The source rocks of the gas are the highly organic black shales that
were discussed in the previous section (Dolton & Quinn (1996) p.4). Unlike conventional natural
gas basins, where there is significant migration of hydrocarbons from source rocks to reservoir
rocks, the black shales are unconventional as the gas is created and stored in the same rock
(Martini et al. (2003) p.1359). The data shows that there has not been migration on a significant
9
scale. Within the Antrim Shale, approximately 70‐75% of the gas is released from the organic
material in the shale. Fractures and porosity makes up the balance. The Antrim Shale is similar
to the properties of coal‐bed methane reservoirs. Some of these shared features of the gas
production are: generation and storage in‐situ, a higher reservoir fraction of CO2 (Martini et al.
(2008 p.330). There are three methods that lead to the creation of natural gas. First is the
“thermal cracking of kerogen”. Second, is “secondary cracking of oil”. The last is biogenic
creation from bacteria. The natural gas in the Antrim Shale is thought to have been produced
both thermogenically and biogenically. The tool used to distinguish between the production of
the two different types of gas is to observe the δ13C isotopes (Martini et al. (1998) p. 1699‐
1701).
Thermogenic Gas Production
The source for thermogenic generation of natural gas is kerogen. The kerogen in the Antrim
Shale is mainly Type I. The Type I kerogen is known as liptinite. The lipinite has a “high hydrogen‐
to‐carbon ratio”, however the oxygen amount is small. Kerogen of this type is formed by algae
and its adulteration into gas is due to the cracking of the kerogen. The optimal formation
environment is in dark muds with low oxygen content (Dellapenna (1991) p.58‐9). The range of
the δ13C values in a thermogenic gas production environment is between ‐55 to ‐40% (Martini et
al. (1998) p. 1701). The thermogenic gas component of the Antrim Shale has been important,
but the real production of natural gas has focused on the natural gas that originated biogenically
(Shurr & Ridgley (2002) p.1957).
Biogenic Gas Production
Biogenic gas production is created by a process known as methanogenisis. There are two
processes for this to occur. One process is known as CO2 reduction. In the formation of the gas
10
in the Antrim Shale, the hypothesis is that it was produced via CO2 reduction. [Figure 9] The
process needs non‐organically produced CO2 and four H2 molecules which then are transformed
via bacterial activity into two H2O molecules and CH4. This is a simplification of a longer series of
reactions, but the process is similar to what happens when there is methane gas generation
within a landfill (Martini et al. (1998) p. 1715‐16). To determine if natural gas has been created
biogenically, one must look for evidence. The evidence of a natural gas that was created by
bacteria is to explore the isotopes of the produced gas and water and then fit that data into a
framework of past gas and water samples. Gas with an incidence of δ13C values of <‐55 per mil
(carbon isotopes) are the signature of biogenic gas production (Martini et al. (2003) p. 1356).
Initially it had been thought that the natural gas in the Antrim Shale was mainly of thermogenic
origin. However, the research has shown that the structure of the gas leans more toward a
biogenic origin of the gas due to the fact that Antrim Shale natural gas has a δ13C values in of
approximately ‐50 per mil (Martini et al. (1998) p. 1699). Also, the waters in the gas reservoirs
are compared to glacial ground waters to look for evidence of microbial activity. The high values
of δ13C in the water produced from the gas wells relative to glacial waters further cements the
conclusion of biogenic gas production for the Antrim Shale (Martini et al. (1998) p. 1714). The
evidence conducted on the Antrim Shale gas puts the ratio of gas formation at 80% biogenic and
the rest thermogenic. Due to the geology of the Antrim Shale and the presence of large amounts
of water, microbial gas production takes place at a much younger time period than that of
conventional type of methane production. This process also can be repeated many times over
when the correct conditions manifest. In the Antrim Shale the formation of the biogenic gas in
the most economic accumulations are in the northern part of the state known as the northern
margin (Shurr & Ridgley (2002) p.1956). [Figure 10]
11
Antrim Shale Natural Gas Development
The Antrim Shale main hydrocarbon is natural gas. The gas plays are numbered 6319 and 6320
respectively. The plays together make up an area of about 39,000 square miles (Dolton & Quinn
(1996) p.1). The Antrim Shale may have been one of the first shale formations to be drilled for
gas in the 1920’s (Agrawal (2009) p.52).The Antrim Shale has been known to have reserves of
gas since the 1940’s. There was not any large scale production of the gas until about the 1980’s
when extraction technology was developed and the U.S. federal Section 29 Non‐Conventional
Fuels income tax credits were enacted [Figure 11] (Goodman & Maness (2008) p.1). The permits
peaked in 1992, the year before the credit window closed. The tax credit made producing this
gas economic. The main production lies along the northern production trend (NPT) also called
the fairway. The group of hydrocarbons can be viewed as a “collection of cells” when
economically define the boundaries of the Antrim Shale play (Dolton & Quinn (1996) p. 6). The
NPT area has seen an explosion of production gas wells between 1986 and 2008. As of 2010,
there were roughly 9700 wells producing in the Antrim play. The 2010 production amount of gas
was 120.2 BCF. The production of the Antrim Shale peaked in 1999 at 199.5 BCF of production.
[Figure 12] As of 2010 only 53 permits had been issued down from 1210 permits in 1993 (MSPC‐
1 (2011)). The total natural gas resource estimate in the Antrim Shale is between 35 and 76 TCF
with 2.6 TCF having been produced through 2008 (Agrawal (2009) p.12). A standard wellfield in
the Antrim Shale will have numerous wells with the spacing at an average of 100 acres, produce
its peak water in about five months, and peak gas within 20 months (Goodman & Maness (2008)
p. 38). As of July 2011, the largest operator in the Antrim Shale is Chevron Michigan. [Figure 13]
12
Production and Well Completion
As an unconventional reservoir, the Antrim Shale blends features of coal‐bed methane
reservoirs and dry gas shales (Hopkins et al. (1998) p. 177). Although most shales in the United
States are produced via horizontal drilling, the distinct properties of the Antrim Shale make it
difficult to produce the gas with the horizontal drilling method. The Antrim Shale is the only
major shale gas resource that does not employ horizontal drilling as the main technique, vertical
drilling is the only method used for these three reasons: minimal drilling cost, low reservoir
pressure and high water co‐production (Agrawal (2009) p.60).
Drilling Cost
The cost of the vertical drilling is minimal due to the shallow location of the gas. The gas is
produced from depths between 500 and 2,300 ft. (Hopkins et al. (1998) p.177). Horizontal
drilling is more expensive than vertical drilling by a factor of two (Agrawal (2009) p. 60). A typical
project in the Antrim play has a vertical well drilling cost of approximately $350,000 (Goodman
& Maness (2008) p.38).
Low Reservoir Pressure
Low reservoir pressure in the Antrim Shale, with a pressure of 400 psi may compromise the
stability of horizontal wellbore. The pressure gradient of the shale ranges from 0.35 psi/ft. to
0.38 psi/ft. This low pressure is less than normal hydrostatic pressure so the vertical wells
produce absorbed gas along with free gas (Agrawal (2009) p.17, 59‐60).
13
Water Co‐production
The final reason is the elevated water rates which increase the costs to operate the well. The
production can reach up to 500 BW/D (Hopkins et al. (1998) p. 178). The mean amount of water
produced is 110 BW/D which complicates the production (Agrawal (2009) p.53 & 60). Water is
produced from the system and the pressure will decline. As the water production rate declines
with removal, the gas production will rise as the gas is freed from the shale. If the wells are
crowded near each other, this may help clear the water quicker, but will decrease the total
production of the gas (Jenkins & Boyer (2008) p. 94). An operator should balance these two
forces. In addition to the costs associated with the initial dewatering of the well, separate
disposal wells are also need to store the water (Hopkins et al. (1998) p.178). In the mid‐1990’s a
horizontal well was attempted in the Antrim Shale. Although it demonstrated that fracing could
be accomplished, the economics did not make sense at that time (Fink (1998) p. 191). Recently,
there have been horizontal wells drilled but due to the properties of the shale a dip could form
and block the drill hole. Low pressure at the bottom combined with the abundant presence of
water causes the section of the well to be inaccessible for production (Kreh (2008) p.1&4).
Besides the presence of water, horizontal drilling also presents difficulties in the form of cuttings
removal. As the cuttings accrue in the well bore, a grounded type of shale‐mud begins to form.
As shales are inert, attempts to use acid for removal are ineffective (Wood & Quinlan (2009) p.
14‐15).
Hydraulic Fracturing
Due to the geology of the Antrim Shale, even the vertically drilled wells do not become
economical until there is some form of stimulant placed in the well system. Hydraulic fracturing
has been used in Michigan since the 1960’s. (MDEQ (2011) p. 2‐3) In the early days, the initial
14
attempt at the stimulation of the shales was a simple fracturing with a water‐only arrangement
(Fink (1998) p. 187). In the early 1990’s experiments were taken on to determine what was the
most effective form of stimulation to yield gas production in the Antrim Shale. The tests that
were undertaken were acid ballout, high energy gas fracturing and hydraulic fracturing (Reeves
et al. (1993) p.6). The standard practice in the sequence that was developed in the 1990’s was
“…a two stage foam frac with a sand consolidating agent to prevent sand flowback” (Fink (1998)
p. 187). With about 90% of the gas dissolved in organics and the rest in natural fracture’s pores
spaces, the two stage technique to free the gas was a great success (Hopkins et al. (1998)
p.177). This form of fracing is still in practice today in the Antrim Shale (Goodman & Maness
(2008) p.39). The Antrim Shale has natural fractures throughout the sequence, hydraulic
fracturing is also utilized to reach these natural fractures and to smooth out pressure gradients
in the wellbore (Hopkins et al. (1998) p. 178). This form of fracturing was very successful from
the mid to late 1990’s and provided the greatest production from the Antrim Shale.
Regulatory Environment
The state of Michigan has highly regulated environment for the development of shale resources.
There are two agencies responsible for regulation: Michigan Department of Environment Quality
(MDEQ) which regulates oil, gas and water. In addition, the Michigan Public Service Commission
(MPSC) regulates gas and CO2 (MSPC (2011)). Since much of the leasehold acreage is on state
owned forest land, there is also interaction with the Michigan Department of Natural Resources
(DNR). There has been public concern with the migration of gas or fracture fluids, one of the
rules that the MDEQ has issued requires that surface casing and cement be placed 100 feet into
bedrock and also 100 feet below a fresh water table (MDEQ (2011) p.2‐3). These requirements
apply to all wells regardless of fracturing activity. Recently, the MDEQ has also added rules on
15
the ones already in place. The use of water in gas production is exempt from water withdrawal,
but if an operator uses 100,000 gallons of water per day over a 30‐day average, it is considered
a high‐volume well completion. If the operation falls under this designation a water source and
amount assessment must be disclosed. The other two major rules that have been recently
released are, one: a disclosure of fracing chemicals and the impacts to human health and, two: a
disclosure of records of the rates, volumes and pressures of the fracturing. Also, another
regulation that applies to the natural gas industry is a rule that states: “No gas well, pool, or field
shall be placed under vacuum…except with the approval of the commission.” (MSPC (2010)
p.39)
Future of the Antrim Shale
Although the Antrim Shale is considered a mature play, there have been developments that
seek to extend the productive life of the shale. Since only around 3.0 TCF have been recovered,
this represents only 8% of the 35 TCF estimate of the total resource. There have been attempts
to revise policy and use technology to prolong the life of the Antrim Shale.
Use of Vacuum Pumps
There are few areas where policy changes could increase the viability of the resource. The first
policy change that has been explored is to reform the vacuum regulation to allow vacuum
pumps to be used. Vacuum pumps can increase the ability to separate the gas from the other
materials produced and raise the pressure in the reservoir, thus increasing recovery. There were
several operators who wished to have their wells placed under vacuum. All applications were
withdrawn due to the MPSC and operators to come to an agreement (MSPC (2010) p. 34).
Among the operators, there seems to be consensus to allow the wells to be placed under
16
vacuum with 49% in favor, 39% opposed and 12% undecided (MSPC (2010) p.36). Another policy
area that could be revised is the permitting environment.
Technological Developments
Due to the high water content of the shale, horizontal drilling has been difficult and generally
uneconomic in the Antrim Shale. The natural dips and traps have slowed the use of horizontal
drilling. But, there have been techniques developed recently that seek to avoid the traps. An
elementary program that has been developed takes the True Vertical Depth (TVD) at various
intervals and notes the change from previous intervals. If there is no presence of a trap, the TVD
delta will remain negative. If it flips between negative and positive changes, there is likely a dip.
Avoiding these areas is central to developing a successful well (Kreh (2008) p.2). A practice used
to avoid these dips is called the bypass method. The first part of this method is to employ a
smaller string. This could be difficult if the trap is located too far out into the wellbore (Kreh
(2008) p. 4). If the trap is distant and the smaller drill string does not work, the next step would
be to use nitrogen to clear the trap. This can be used over multiple intervals to continue to
remove the water from the well (Kreh (2008) p.4). The employment of the simple model and
nitrogen trap clearing is an interesting research opportunity for the Antrim Shale.
A Hybrid Approach to Drilling
Since much of the gas in the Antrim Shale is shallow, vertical wells are optimal for extraction.
However, this also presents a challenge as surface concerns constrain the development of a
cluster of vertical wells. There is a need to prove to the state that a design demanding less wells
and a more effective drainage area to allow an expansion of this type of drilling (Wood &
Quinlan (2009) p.18). If the permitting applications for wells were restructured, there could be a
possibility of a hybrid approach combining vertical and horizontal drilling. The difficulties of
17
horizontal drilling in the Antrim Shale have been mentioned: water traps, shale‐mud paste and
cheaper relative cost of vertical wells. A test of the hybrid approach, called the “J’‐shape, was
performed by Jordan Development Company in which a vertical well was drilled and then began
a horizontal orientation. The lateral well was drilled at an angle of 90 degrees. This well, like
other “true” horizontals in the Antrim Shale was unsuccessful. However, when Jordan used a
higher angle, between 75 and 80 degrees, the gas production was greatly improved. This
technique, known as the “J” design was more successful at avoiding the water traps as shale
paste which has persisted in many horizontal wells drilled in the Antrim Shale in the past. [Figure
14] From the general model, a test of the hybrid approach at the Colfax 29 well, was attempted
which resulted in the “first time…that a lateral has been used to produce Antrim gas.” [Figure
15] (Wood & Quinlan (2009) p. 167). An expansion of this well type may be a key factor in the
continuation of the Antrim Shale as a productive gas reservoir.
CO2 Sequestration and Enhanced Gas Recovery
Given that depleted natural gas fields are worth relatively little, CO2 sequestration and storage
could be attractive to operators (Al‐Hasami et al. (2005) p.2). The Antrim Shale is mature and
due to all of that production, the bottomhole pressure has decreased in the sequence area
(Kreh (2008) p.1). The injection of CO2 in oil reservoirs has been widely explored, but CO2
injection for enhanced gas recovery (EGR) has not been researched as much. The Antrim Shale
could benefit from a hastening of production and lead to a greater overall recovery (Al‐Hasami
et al.(2005) p.2). The Antrim Shale has a natural occurrence of CO2 as a byproduct of production
(Goodman & Maness (2008) p. 57). This means that nearby oil fields to the Antrim Shale like the
Niagaran Brown formation as well as more mature gas fields could benefit from this pipeline
quality CO2 in large quantities and proximity (Toelle et al. (2008) p. 1). Although, there has been
18
concerns that the CO2 could mix with the natural gas, CO2 is denser than natural gas (at reservoir
conditions) and the CO2 is more soluble in water than the natural gas (Al‐Hasami et al. (2005)
p.2). Both of these properties are very favorable to the Antrim Shale as there is a high water
content and low pressure throughout the play.
Conclusion
The Michigan Basin is an interior cratonic basin which through sedimentary processes and
subsidence has a bowl shape. One of the geologic sequences within the basin is an organically
rich shale known as the Antrim Shale. This shale is important because it has economic
concentrations of biogenic natural gas. The two sections with the highest concentration of gas
the Norwood and Lachine members. This type of shale is unique because it was one of the first
reservoirs to produce natural gas through the employment unconventional production known as
hydraulic fracturing. Fractures provide a path for the water and bacteria to form and trap the
natural gas. This shale has been a very productive resource for the production of natural gas.
Although the production has declined since the late 1990’s, the total production of natural gas
out of the Antrim Shale is ~3.0 TCF. While fracing has been used in the sequence, horizontal
drilling has not had much success. The main reasons for this are low vertical well completion
costs, low overall reservoir pressure and large amounts of water co‐production. Recent policies
and regulations within the state of Michigan have made production a little more costly. The
future of the Antrim Shale looks fairly bright with options on the table that could increase the
recovery of the gas. An allowance of vacuum pumps by the state, an adaptation of dip
avoidance technologies, an increase in the practice drilling of “J” shape wells, and CO2
sequestration for enhanced gas recovery are all options that are on the table that could extend
the life of the Antrim Shale gas reservoir.
Figure 1: Development History of Antrim Shale Production AreaSource: Goodman and Maness (2008) p. 11-14
19
Figure 3: Illustration of Sag Basin (Michigan Basin as Case Study)Source: Martini et al. (1998) p.1708
21
Figure 4: Stratigraphic Column of Subsidence Sequences of Michigan BasinSource: Howell and van der Plujm 1(999) p. 977
22
Figure 7: Fracture Orientations of Antrim Shale - Lachine and Norwood MembersSource: Goodman and Maness (2008) p. 23
25
Figure 9: Chemical Reaction to from natural gas (methane)Source: Martini et al. (1998) p. 1701
Figure 10: Map of Michigan Basin Northern Margin Production ZoneSource: Martini et al. (2008) p. 329
27
Figure 11: Antrim Producing Area: Permits, Wells Drilled, Well Connection Permits, Daily ProductionAurora Oil & Gas Corporation RPSEA/GTI Shales Forum 6/4/2009
28
MICHIGAN PUBLIC SERVICE COMMISSION
J U L Y 2 0 1 1MONTHLY GAS PRODUCTION SUMMARY
ANTRIM
REPORTER
TOTALMONTHLY
GASPRODUCTION
AVERAGEDAILYGAS
PRODUCTION
TOTALNUMBER OF
WELLSONLINE
DAILYWELL
PRODUCTIONAVERAGES
TOTALNUMBER OFPROJECTS
ONLINE)DFCM()FCM( (MCFD/WELL)
401876,1868,656,1CHEVRON MICHIGAN LLC 3153,44748426,1293,636,1LINN OPERATING, INC. 3252,78625797002,448TERRA 3427,23277087410,808BreitBurn 3326,064741948042,807WARD LAKE ENER 2622,84633206960,607MUSKEGON 3722,77672324438,864TRENDWELL 3515,12342353546,973JORDAN DEVELOPMENT 3412,24642513930,233MERIT ENERGY COMPANY 3410,71062314127,713DELTA 2410,24913343873,362ENERVEST OPERATING LLC 248,49682532366,252OILFIELD 348,15023021585,422HRF 607,24461642951,091SRW 246,13472541713,741PAXTON RESOURCES 324,75251561574,541NORTHSTAR ENERGY LLC 284,6929221756,911YOHE 313,859347890,19NUENERGY OPERATING INC 392,938616846,77J5 412,504744987,35PRESIDIUM ANTRIM WEST, L 391,735347789,93ANTRIM DEVELOP 171,289431213,02SCHMUDE OIL 50655162986,81BABCOCK and BROWN ENER 23602293841,71DEVONIAN ENERGY 14553391709,41JDB ENERGY LLC 2548013534,7SAVOY ENERGY LP 7923911708,2AZTEC PRODUCTION COMPA 909012000,2JAGUAR ENERGY, LLC 326422509OMIMEX 142911571DYNAMIC DEVELOPMENT 55
23197965,9651,845,9SLATOT YLHTNOM 308,005
Report Date: September 30, 2011
Gas volumes are reported at 14.73 psia and 60 degrees F
This report is available on the Internet at this address: http://cis.state.mi.us/mpsc/gas/prodrpts.htm
Figure 13: Production by CompanySource: MSPC Website 2011
30
33
Works Cited Agrawal, A. (2009). A Technical and Economic Study of Completion Techniques In Five Emerging U.S. Gas
Shale Plays. , Texas A&M University p. 1‐137. Al‐Hasami, A., S. Ren, et al. (2005). CO2 Injection for Enhanced Gas Recovery and Geo‐Storage: Reservoir
Simulation and Economics. SPE Europec/EAGE Annual Conference. Madrid, Spain, Society of Petroleum Engineers. P. 1‐7
Catacosinos, P. A., P. A. Daniels, Jr., et al. (1990). "Structure, stratigraphy, and petroleum geology of the
Michigan Basin." AAPG Memoir 51:p. 561‐601. Dellapenna, T. M. (1991). Sedimentological, structural, and organic geochemical controls on natural gas
occurrence in the Antrim Formation in Otsego County, Michigan. p. 1‐147 Dolton, J.C., Quinn, G. L. (1996). "An Initial Resource Assessment of the Upper Devonian Antrim Shale in
the Michigan Basin." United States Department of the Interior: U.S. Geological Survey: p.1‐23. Fink, K. T. (1998). Case History: Cased Hole Horizontal Antrim Well Fractured in Multiple Intervals. SPE
Eastern Regional Meeting. Pittsburgh, Pennsylvania.p.187‐195 Goodman, W. R. and T. R. Maness (2008). "Michigan's Antrim Shale play; a two‐decade template for
successful Devonian gas shale development." Abstracts: Annual Meeting ‐ American Association of Petroleum Geologists 2008.p. 1‐69
Hopkins, C. W., R. L. Rosen, et al. (1998). Characterization of an Induced Hydraulic Fracture Completion
in a Naturally Fractured Antrim Shale Reservoir. SPE Eastern Regional Meeting. Pittsburgh, Pennsylvania, 1998 Copyright 1998, Society of Petroleum Engineers Inc. p. 1‐9
Howell, P. D. and B. A. van der Pluijm (1999). "Structural sequences and styles of subsidence in the
Michigan Basin." Geological Society of America Bulletin 111(7):p. 974‐991. Jenkins, C. D. and C. M. Boyer. II (2008). "Coalbed‐ and Shale‐Gas Reservoirs." SPE Journal of Petroleum
Technology(02). p. 92‐99 Kreh, K. A. (2008). Identifying, Bypassing, and Avoiding Gas Traps in Horizontal Wells. SPE Eastern
Regional/AAPG Eastern Section Joint Meeting. Pittsburgh, Pennsylvania, USA. p. 1‐4 Kuuskraa, V. A., D. E. Wicks, et al. (1992). Geologic and Reservoir Mechanisms Controlling Gas Recovery
From the Antrim Shale. SPE Annual Technical Conference and Exhibition. Washington, D.C., 1992 Copyright 1992, Society of Petroleum Engineers Inc. p. 209‐224
Leighton, M. W. (1990). "Introduction to interior cratonic basins." AAPG Memoir 51:p. 1‐24.
34
Leighton, M. W. and D. R. Kolata (1990). "Selected interior cratonic basins and their place in the scheme
of global tectonics; a synthesis." AAPG Memoir 51:p. 729‐797. Manger, K. C., S. J. P. Oliver, et al. (1991). Geologic Influences on the Location and Production of Antrim
Shale Gas, Michigan Basin. Low Permeability Reservoirs Symposium. Denver, Colorado. p. 1‐10 Martini, A. M., L. M. Walter, et al. (1998). "Genetic and temporal relations between formation waters
and biogenic methane; Upper Devonian Antrim Shale, Michigan Basin, USA." Geochimica et Cosmochimica Acta 62(10):p.1699‐1720.
Martini, A. M., L. M. Walter, et al. (2003). "Microbial production and modification of gases in
sedimentary basins; a geochemical case study from a Devonian shale gas play, Michigan Basin." AAPG Bulletin 87(8): p. 1355‐1375.
Martini, A. M., L. M. Walter, et al. (2008). "Identification of microbial and thermogenic gas components
from Upper Devonian black shale cores, Illinois and Michigan Basins." AAPG Bulletin 92(3): P. 327‐339.
Matson, M. M. (2011). "The Origin of Natural Fractures in the Antrim Shale, Michigan." P. 1‐51. Michigan Department of Environmental Quality (MDEQ). (2011). High Volume Hydraulic Fracturing Well
Completions. M. D. o. E. Quality: p.1‐3. (MSPC) Michigan Public Service Commission (2010). MICHIGAN ANTRIM SHALE PRODUCTION: HISTORY
AND PHYSICAL ATTRIBUTES AS IT RELATES TO U‐16230: p. 1‐45. (MSPC), Michigan Public Service Commission (2011). "About Michigan's Natural Gas Industry:
Exploration and Production." http://www.dleg.state.mi.us/mpsc/gas/about1.htm (last revised Oct. 14 2011)
(MSPC‐1), Michigan Public Service Commission (2011). "MPSC Gas Well Connection Permits Issued.
http://www.dleg.state.mi.us/mpsc/gas/pesec1.htm (last revised March 02 2011) Reeves, S. R., D. G. Hill, et al. (1993). Production Optimization in the Antrim Shale. SPE Production
Operations Symposium. Oklahoma City, Oklahoma. p. 495‐505 Shurr, G. W. and J. L. Ridgley (2002). "Unconventional shallow biogenic gas systems." AAPG Bulletin
86(11): p. 1939‐1969. Toelle, B., L. J. Pekot, et al. (2008). EOR Potential of the Michigan Silurian Reefs Using CO2. SPE/DOE
Symposium on Improved Oil Recovery. Tulsa, Oklahoma, USA, Society of Petroleum Engineers. p. 1‐7
Wood, J. R., Quinlan. W. C. (2009). "An Approach to Recover Hydrocarbons from Currently Off‐Limit
Areas of the Antrim Formation, MI Using Low‐Impact Technologies: Final Report." p. 1‐60.