The Mississippian Oil play has been a topic of conversation recently in the oil and gas industry. Core areas have been established along counties bordering Kansas and Oklahoma with numerous rigs running. With some of the most inexpensive horizontal well costs in the oil industry, core areas within the play rank as some of the highest rate of return projects in the nation. One the main reasons why the well costs are relatively insignificant is that the Mississippian, unlike other resource plays, has substantial porosity and permeability with relatively shallow drilling depths. Permeability (which is a measurement of the ability of fluids to flow through rocks) in the Mississippian is up to 100,000 times greater than most shale plays. This allows for minimal hydraulic fracturing costs as the rock does not need significant treatment to flow.
Another interesting fact about the Mississippian is that it is a limestone and not a shale, meaning it is not self-sourcing. Almost all of the oil and gas present in the Mississippian was sourced by the Woodford Shale (a world class source rock) which then traveled long distances and was trapped by the stratigraphy in the Mississippian (examples of which are illustrated below).
Schematic diagram of stratigraphic traps
Sandridge map showing horizontal wells drilled along Oklahoma/Kansas border
As a result of this, the Mississippian has a greater variability between wells of whether it produces oil, gas, or oil and gas. This can lead to sometimes surprising well results in areas where there is sparse vertical well control. Often times, these accumulations can change very rapidly in producing phase with areas going back and forth between predominantly oil to predominantly gas. You can even have situations where you intersect an oil reservoir followed by a gas reservoir in the Mississippian due to the nature of how the oil and gas is trapped. Thankfully, due to the thousands of vertical wells, it is possible to map areas in the play where oil accumulations are more prevalent than gas and calculate statistical probabilities. Geologists can also determine which rock types are present allowing for a better understanding of rock properties and depositional environments.
As horizontal drilling continues along the borders of Kansas and Oklahoma, it will be interesting to see how the play continues to grow as companies learn about this play.
The Energy Information Administration (EIA) of the US Department of Energy released revised estimates
of global shale oil and gas resources this week. The new figures represent a significant increase over the EIA's 2011 estimates
. Technically recoverable shale oil (tight oil) grew more than tenfold, due to the inclusion of formations outside the US, while estimated global shale gas resources
rose by 10%. With these revisions, shale formations now constitute 10% of global crude oil resources and nearly a third of global natural gas resources, although the actual impact of these resources on production and markets is still likely to vary greatly from region to region and country to country.
This year's report reflects a greater focus on tight oil, incorporating insights from the significant development of US tight oil resources that has occurred since the previous report was published. Tight oil development is largely responsible for the 19% increase in US crude oil production
from 2010 to 2012. The smaller adjustment to shale gas is the net result of downward revisions for some countries assessed in 2011, such as Poland and Norway, together with the inclusion of resources in additional shale formations and countries, including Russia, Indonesia and Thailand.
The EIA and the consulting firm that prepared the report were careful to differentiate the technically recoverable resources (TRRs) identified in this data from the more restrictive categories of economically recoverable resources and proved reserves
. In other words, these figures represent the quantities of oil and gas that could be recovered if prices justified development and infrastructure was available to carry them to market, not the amounts that producers currently plan to develop. At the same time, these estimates constitute only a small fraction of the oil and gas thought to be present in the assessed shale deposits. Further improvements in technology could substantially increase future TRRs.
It's interesting to note that although the US leads the world in production of both tight oil and shale gas, it ranks second and fourth, respectively, in global resources of these fuels. The report
also indicates that estimated US tight oil resources of 58 billion barrels (bbl) are more than double current proved oil reserves, which represent just under 7 years of current production. That's significant, because a sizable fraction of the 139 billion bbls of US conventional
unproved TRR--non-shale crude oil not currently included in proved reserves--sits in onshore and offshore areas currently off-limits to drilling
. So shale provides a pathway for US oil production to sustain higher output than in the recent past, without having to overcome barriers such as those impeding development offshore California or in the Arctic National Wildlife Refuge.
Or consider Russia, for which the report cites proved reserves equivalent to 21 years of production and slightly exceeding tight oil TRRs. Russia possesses many of the factors conducive to shale development, including a large drilling fleet and an oil industry accustomed to drilling large numbers of wells, along with oil-transportation infrastructure. It remains to be seen whether Rosneft and other producers will choose to develop
the Bazhenov shale
and other deposits rapidly, to increase total output and exports, or more gradually, to offset declines in mature fields and maintain current production rates.
The EIA also reported 32 billion bbls of tight oil TRR in China. Conventional reserves are comparable to those of the US, supporting current production less than half America's. Without tight oil, China's economic expansion and the rapid growth of its vehicle fleet put it on track
to displace the US as the world's largest oil importer within a few years. China-based companies are seeking oil in Africa, South America and North America, so it's hard to envision them leaving their own shale resources undeveloped.
The situation is more complicated for shale-rich OPEC members like Libya and Venezuela. For example, aside from its current political instability, Libya has nearly 90 years of conventional oil reserves at its current OPEC quota
of around 1.5 million bbl/day, before considering the 26 billion bbls of tight oil identified by the EIA.
On balance, the latest EIA shale resource assessment presents a wider and more realistic view of shale outside the US than in 2011. That includes tempering some of the previous report's enthusiasm for shale gas prospects in places like Poland, where few wells had been drilled until recently. The new element is the report's portrayal of the tight oil resource base as broad and deep, centered mainly on countries likely to be motivated to develop it. The shale gas revolution may be slow to spread globally, due to much-discussed differences in the conditions for development, compared to those in the US. By contrast the development of shale oil, or tight oil, faces fewer obstacles and an eager market.
by Saudi Arabia's oil minister, Ali Al-Naimi
, indicated that Saudi Aramco would soon begin exploring the country's shale gas resources. As another means
of reducing oil consumption in the Kingdom's electricity sector
, in order to preserve oil exports, this appears to make both practical and economic sense. However, as noted by the Wall St. Journal, compared to the US Saudi Arabia has much less water available for the hydraulic fracturing of shale and tight gas reservoirs. Absent a reallocation of its substantial conventional gas production, Saudi shale gas could become a key factor in global energy security. However, the techniques employed to extract it might be different from those that currently dominate the US shale gas scene.
It must seem odd that Saudi Arabia would even be interested in shale gas, a resource that wasn't exploited in the US until conventional gas production was declining steadily. Saudi Arabia might still be the world's largest oil producer, at least for now
, but it is not the "Saudi Arabia of natural gas". Although the country has proved gas reserves
comparable to those of the US, it apparently didn't win nature's gas lottery on the Arabian Peninsula. Saudi gas reserves and production amount to only about 10% and 19%
, respectively, of the Middle East's gas totals. Iran and Qatar are far ahead. And while Saudi gas production has doubled since 2000, output in neighboring Qatar has expanded by a factor of six in the same interval.
Much of the Kingdom's conventional gas reserves are associated with oil production
and are often required to be reinjected to maintain reservoir pressure and oil output. Available Saudi gas has been preferentially allocated
to industrial projects, such as petrochemicals expansion. As a result, little new gas was supplied for power generation, so the Saudi electricity sector has been burning large and increasing quantities of oil that could otherwise be exported. The need for additional gas has become acute, but exploration in the vast Empty Quarter has not yielded the expected gas bonanza, while the internal price of natural gas has been constrained
at levels well below even recent low US natural gas prices--too low to make most new production attractive on its own merits.
As if the economics of shale gas development weren't challenging enough in such an environment, the key ingredient that has fueled the US shale revolution, water, is in short supply in Saudi Arabia. The needs of cities and industry in this arid country exceed the water supply from aquifers to such an extent as to require 27 desalination facilities
, delivering nearly 300 billion gallons annually. At several million gallons of water per hydraulically fractured shale gas well, the logic of burning oil to desalinate water to produce gas looks questionable. Fortunately, there are multiple emerging pathways for reducing or eliminating net water consumption in "fracking".
For starters, many US producers now routinely recycle the 10-30% of injected water that typically flows back from the well after hydraulic fracturing, for use in subsequent wells. Recycling has become the standard
in places like Pennsylvania's portion of the Marcellus shale, reducing the call on fresh water for fracking. The oil services industry
offers various techniques for cleaning "flowback" water, and new ones are under development, including the use of algae
Drillers can further reduce freshwater consumption through the use of nitrogen in foam or other forms
. ERDA, a precursor of the US Department of Energy, conducted research on that technique
in the 1970s, and it has been refined since then. Nitrogen is readily available from air separation plants and does not depend on water, though it does require energy.
Another approach for waterless fracking
has been field-tested in Canada
, using gelled propane
. A blog post
in Scientific American described some of the pros and cons of this method, which is more expensive where water is cheap but might fit the bill in dry regions where LPG is readily available. For that matter, it might make sense in New Mexico if the Mancos Shale
of the San Juan Basin turns out to be another viable tight oil play.
The upshot is that a shortage of fresh water shouldn't constitute an insurmountable obstacle to exploiting Saudi Arabia's unconventional gas resources, which Mr. Al-Naimi cited at 600 trillion cubic feet. However, it remains to be seen whether shale gas development is the best answer to a problem that has been created by selling natural gas to industry for as little as $0.75 per million BTUs, while burning $100 oil
($17 per million BTU) to generate electricity. Whether the ultimate solution is shale gas or something else, resolving this gap in Saudi industrial policy could have a significant impact on future oil prices.
Two independent organizations, Standard and Poor's and ITG Investment Research, recently issued reports suggesting that current government estimates of the natural gas resources in the Marcellus shale are significantly understated
. The differences among estimates are startling, with ITG assigning resources of 330 trillion cubic feet
(TCF) of natural gas equivalent to the Marcellus, in contrast to the latest estimate of just 141 TCF from the Energy Information Agency (EIA) of the US Department of Energy. Standard & Poor's reportedly
concluded that the Marcellus could provide "almost half of the current proved natural gas reserves
in the U.S."--which I take to imply up to 300 TCF of dry gas. It's important to understand why these figures could vary so much, and it's equally important to consider what they might mean for other shale basins and for the future development of the US natural gas market.
Two factors stand out when comparing the Marcellus to other gas fields: its relative youth and its enormous extent. The first Marcellus well was only drilled in 2003
, into a formation underlying roughly 95,000 square miles
of the Appalachian Basin of the eastern US. That is more than 10 times larger than the Hugoton gas area
of Kansas, Oklahoma and Texas. Discovered in 1922, the Hugoton fields were long considered the largest gas accumulation in the country, with an estimated ultimate recovery of 75 TCF
. They are still producing, though at declining rates. Hugoton, which is also the source of most of the world's supply
of helium gas, has 12,000 wells
, versus around half that figure
for the Pennsylvania portion of the Marcellus, as of May 2012. Because so much of the Marcellus remains essentially untouched, with most of its producing wells still early in their lives, anyone estimating its recoverable resources must make numerous assumptions about well productivity, productive life, and how the resources will be developed over time. Changes in the actual results from a relatively small number of wells can have a big impact on such estimates at this stage of development.
This can be seen in the progression of Marcellus estimates. In 2002 the US Geological Survey projected
mean resources of just 2 TCF, which they revised in 2011 to 84 TCF and 3.4 billion barrels of gas liquids, yielding an effective total of just over 100 TCF of gas equivalent. Meanwhile, EIA included an estimate of 410 TCF
in its 2011 Annual Energy Outlook, but then revised that to 141 TCF in its 2012 Energy Outlook
. That decline of 66% made headlines
and was viewed by many critics of shale gas development as signaling that shale resources were not as significant as previously thought, and perhaps indicative of a "bubble."
Following the bouncing ball of Marcellus resource estimates no doubt creates uncertainty about the scale of this and other shale deposits. However, no matter which Marcellus number one chooses among the recent estimates, the resource looks enormous. Even the USGS figure of 84 TCF is equivalent to over 14 billion barrels of oil, or half-again the original estimate for Alaska's Prudhoe Bay field
, which was a game-changer in global oil markets in the 1980s. That means there's enough gas to sustain higher production volumes than today's for decades--up to 5 billion cubic feet per day (22% of US dry gas production
in 2011) for perhaps 40 years or more. And those resources are likely to grow over time, as more of the Marcellus is accessed and evaluated. That's been typical of large oil and gas fields such as the Hugoton, and I would expect to see a similar trend with the big gas and liquids shale plays, including the Eagle Ford and Niobrara, after the initial volatility of estimates settles down.
If the production from the Marcellus and other shale gas deposits were just a case of a big straw draining a small glass, the US would soon be back in the same situation as it was in the first half of the last decade, relying on imported liquefied natural gas
(LNG) for a growing share of its gas supply. Under such a scenario, it would make little sense to build new infrastructure to transport this gas to distant markets. It also wouldn't make sense to invest in new, gas-intensive manufacturing in petrochemicals and other industries. And it certainly wouldn't be prudent to undertake the even more complex transformation of part of our transportation system to use natural gas instead of petroleum products. Yet we're starting to see all of these things, including a new ethylene complex in the former rust belt
of Pennsylvania, the conversion
of a Gulf Coast LNG import terminal to a liquefaction and export plant, and the beginnings of a compressed natural gas (CNG) refueling network
for heavy trucks. Together with estimates of the low cost of Marcellus production from the Standard & Poor's and ITG reports, these developments validate the potential of a resource that energy economist Philip Verleger suggests could make the US "the low-cost industrialized country for energy
The epicenter of the global shale energy revolution is in the US, where shale gas now supplies roughly 30%
of the country's natural gas demand and more than 7%
of its total energy needs, while shale oil--also called "tight oil"--has helped reduce US oil imports. However, this US lead mainly reflects the head start provided by the early application of key innovations to large deposits like the Barnett and Marcellus shales, which are becoming household names. These factors don't guarantee the US a permanent edge in either shale reserves or output, because the geological distribution of shale gas and oil is very much global, as indicated in this 2011 Energy Information Agency map
, which covered less than half the world's countries. China's offer this week of 20 shale gas exploration blocks
for lease comes on the heels of earlier estimates
that China holds 25 trillion cubic meters (TCM) of shale gas, or 883 trillion cubic feet (TCF), and potentially as much as 36 TCM
(1,271 TCF). Either figure puts China at the top of the global shale resource league table
In some respects, shale energy could be even more transformational in China than in the US. Consider that shale gas emerged in America just as the economy was entering a recession. GDP and demand for energy in all its forms have remained weak, forcing shale developers to capture market share from other suppliers. Many of the gains made against coal and other sources of electricity came as a result of slumping natural gas prices, as supply exceeded demand and gas imports were squeezed out of the market. Moreover, pipeline natural gas, whether from shale or conventional wells, is no novelty in the US, having accounted for one-fifth to one-fourth of total energy consumption
for six decades. It is a major energy source for the residential, commercial, industrial and utility sectors
, though it occupies only a tiny niche
in transportation. US shale gas is likely to continue to displace other fuels at the margin, but it remains to be seen to what extent it will fuel growth outside gas's long-established roles.
By contrast gas accounted for just 4% of China's total energy consumption in 2010, according to BP's annual Statistical Review
, compared to 70% for coal, 18% for oil, and 8% for hydropower, other renewables and nuclear power combined. China's official GDP growth target for 2012
is 7.5%, slower than in recent years, yet still robust compared to the OECD countries. Even with China's commitments to improve the energy intensity
of its economy, that economic growth will translate into substantial energy demand growth. Shale gas stands to capture large portions of that growth, if developers can achieve well productivity comparable to US shales and attract the infrastructure investments required to deliver the gas to market. And with the environmental drawbacks of China's coal dependence becoming increasingly apparent, shale gas could materially improve both air pollution and greenhouse gas emissions in the world's largest energy consuming country.
China won't be the only country seeking to apply the shale extraction techniques perfected in the US to their own enormous, untapped resources. South Africa, with technically recoverable shale gas resources estimated
to exceed Canada's, just lifted its moratorium
on shale exploration. Meanwhile, Ukraine, with Europe's third-largest shale gas resources, earlier this year chose
Royal Dutch Shell and Chevron to explore two large shale prospects and was reportedly considering
another tender for this month.
Developing China's shale resources won't be easy, as the Financial Times noted on Tuesday
. China-based companies have invested in shale plays outside China partly to gain expertise, while also inviting foreign companies to participate in China. The combination of horizontal drilling and hydraulic fracturing that has been so successful elsewhere must be adapted to the different geology of China's shale deposits. Just as importantly, drillers must adapt the shale business model to an environment with regulations, legal system and property rights quite different from the unique mix of state-level rules and privately held mineral rights that prevail in most of the US "shale patch." None of this looks insurmountable, and the potential prize is large enough to keep all parties focused on making progress.
For my first blog post, I thought it would be useful to introduce some basic geology. Hopefully, this will be helpful in increasing readers’ general understanding of the modern oil industry.
The energy industry has had a great deal of change in the past twenty years with the introduction of the concept of shale plays. Resource plays (which include shale plays) are defined as oil and gas projects where there is low geologic risk in not finding hydrocarbon and are generally statistically repeatable for a large number of wells. Often times, the word is used for all forms of resource plays which is not accurate.
Shale is a sedimentary rock which is composed of clay and silt sized particles. Shales and other mudstones actually are the most common sedimentary rocks present in the geologic record. One would expect that since shale is found in almost every single well ever drilled there would be a huge number of successful shale plays in the U.S. The reason why that is not the case is twofold. The first reason is that most shales do not have a large kerogen (organic) content which is necessary to make oil and gas. The second reason is that shale is ductile. Due to the large amount of clay in the rock, it does not frac well. Even if you are capable of fracing the formation, your fracture ends up closing due to the rock being so plastic.
So what is one of the main factors that differentiates a successful shale play from a failure? The rock is not a true shale! If you look at the most recent successful shale plays in the U.S. (such as the Eagle Ford, Barnett, Niobrara, Bakken), they have almost all been either carbonates (often marly) or very silica rich mudstones. Many times these rocks were misnamed shales due to their black coloration (due to organic content) and higher gamma ray measurements. Due to their extremely low clay content and large mature organic content, these rocks previously thought of as shales are now some of the biggest and most prolific reservoirs in the U.S. Unfortunately, the original names have stuck through time and the rest is history. So in the future, when you hear about a new shale play, be sure to ask the deeper question as to what the actual play is.
Michael Rozenfeld, P.E.
Mr. Rozenfeld is a licensed professional engineer in the State of Texas