Roberto Aguilera is one of the world’s leading experts on tight gas engineering. Two decades ago, the industry’s ability to extract natural gas from low-porosity formations was nearly non-existent. Now, thanks to new technologies, tight gas has become the industry’s growth engine. I met Aguilera in July of last year in Madrid at the World Petroleum Congress, where he and his son, Roberto F. Aguilera, presented a paper on the future of tight gas. Their prediction was that global tight gas reserves are likely equal to those of conventional gas reserves. (I interviewed the younger Aguilera for Energy Tribune last year. That interview is available here.)

Aguilera’s work in the oil and gas industry has taken him to 50 countries. He has published numerous books and papers on drilling, production and engineering aspects of naturally fractured reservoirs. A native of Colombia, Aguilera was educated at the University of America in Bogota, Colombia in petroleum engineering (1963-1967) and the Colorado School of Mines where he received M.Eng (1971) and Ph.D (1976) degrees in petroleum engineering.

He is now a professor in the Schulich School of Engineering, chemical and petroleum engineering deparment at the University of Calgary, where he holds the ConocoPhillips-NSERC-AERI Chair in Tight Gas Engineering. He is also a Director of Junex in Quebec and Chairman of the editorial review board of the Journal of Canadian Petroleum technology.

ET: We talked over the phone a few weeks ago about the developments in the North American gas business. You said the combination of horizontal wells, and multi-stage slick-water fracturing has created a “revolution in gas.” What do you mean?

RA: I mean that by using creativity the industry is finding keys to unlock the North American unconventional natural gas endowment which is, simply put, gigantic. The first shale well was drilled in 1821 in Chautauqua County, New York, and probably produced gas for local uses through natural fractures. It is significant that the very first shale well already introduces the key element of natural fractures, created by Mother Nature, for successful production of natural gas. The Big Sandy gas field is eastern Kentucky, which started production from Devonian shales in 1921 is a classic example of a naturally fractured reservoir. In my opinion, the same key elements hold true today and are partially responsible for the revolution in gas production. The addition of hydraulic fractures to these already naturally micro-fractured reservoirs leads to the monsters we are pursuing today with horizontal wells that will dominate the North American energy landscape for decades to come. John A. Masters of Canadian Hunter indicated in the foreword of our book “Horizontal wells, Formation Evaluation, Drilling and Production” (1991) that the well design should be approached from the point of view that drilling the target formation is a completion operation as there are many subtleties that can be addressed easily in the preplanning stages that may be virtually impossible to correct once the well is drilled. This drilling-completion vision by a new breed of geologists and engineers working as a team with a common goal in mind has been pursued by many in North America with outstanding results.

ET: Will this revolution mean lower gas prices over the long term?

RA: As long as the gas bubble remains the prices will be low. It is a matter of supply and demand. However, the fact that there is a very large gas endowment could lead to creative means of increasing the utilization of this resource in such a way that will benefit everybody: The US and Canada as a whole, the companies involved in the production and delivery of gas and the consumer.

ET: Speaking of prices, what is a sustainable price for natural gas? I ask because I’ve heard some producers insist that shale gas wouldn’t be profitable when prices are under $8. Now, I’m hearing $5. What’s your take on the relationship between the relatively high cost of drilling for tight gas and the market price which has been so volatile lately?

RA: My take is that $5 to $6 will work in most cases and will make most shale plays competitive. However, there are several factors that have to be taken into account while considering your question. Depth of the reservoir and its relation to the size, lateral extent, thickness, initial productivity and production decline of the prize are key considerations. There are deep and shallow shale gas reservoirs. For example the Haynesville shales can reach more that 13,000 ft. On the other hand the Fayettville shales can be found at less than 4,000 ft. And there are even shallower shales with reasonable potential in Saskatchewan at about 1,000 ft. Availability of drilling, completion and hydraulic fracturing equipment is another key consideration. For example, for the same stimulation; mobilization of hydraulic fracturing equipment, materials and personnel to the Saint Lawrence Lowlands of Quebec to stimulate the Utica shale is very expensive compared with a more mature area where the required equipment might be readily available.

Strategic alliances with service companies would help to mitigate this problem. Proximity to suitable markets, government support and stockholder engagement are other key considerations. Many of these issues can be incorporated in cumulative long run supply curves similar to the ones developed for global conventional gas and other resources by Roberto F. Aguilera and his professors in the Division of Mineral Economics at the Colorado School of Mines. These graphs present cross-plots of total average production cost per unit volume vs. future gas volumes and as such give an idea as to what are reasonable prices to develop each one of the plays under consideration.

ET: We also discussed the Barnett Shale in Texas. You said “There will be many Barnetts around the world.” What did you mean? And where do you expect the future Barnetts to be found?

RA: As indicated in our World Petroleum Congress (WPC) paper you mention in the introduction of this interview, tight gas reservoirs are present in almost all petroleum provinces around the world. The same holds true for shales -- more so because shales are a very important source rock. So my vision of several Barnetts around the world stems from the pervasive presence of shales. Black shales of South America and Africa are similar to those of North America in their association with sandstone and siltstone. Black shales of central Europe and the western part of the former Soviet Union are associated with carbonate reefs, an association that as far as I know is not present in North America. But in the same way that all naturally fractured reservoirs are different, all shale gas reservoirs are also different. I like to consider each one as a research problem by itself. Repeating the same successful drilling and completion approach carried out in one shale reservoir, without the necessary research and careful evaluation, may lead to major fiascos, headaches and financial losses in another shale reservoir. As to where the future Barnetts can be found, I anticipate that it will occur primarily in regions which previously have shown significant discoveries of oil and gas. But because of the supply and demand issues mentioned above, it will take several years (maybe decades in some areas) before shales outside the US and Canada are developed.

ET: You and your son, Roberto F. Aguilera, have written about gas as a bridge fuel toward the future. It seems to me that policymakers been slow to understand the revolution in gas and how it might play a positive role in future energy policy in the US and Canada. Do you agree? If so, why are they so slow on the uptake?

RA: We have written about natural gas as a bridge toward a possible hydrogen economy. I agree that policymakers have been slow. But I do not blame them. I suspect that we, in industry and academia, have not done a good job in promoting the benefits of natural gas as compared with other fossil fuels. We are talking in here about the cleanest fossil fuel that can be burned; four atoms of hydrogen for one atom of carbon. An H/C ratio of 4:1. By way of comparison the average H/C ratio for oil is 2:1, for coal 0.5:1 and for wood and other agricultural residues 0.1:1. Thus the ratio provides a reasonable proxy to environmental quality, and shows that natural gas is more benign to the environment as compared with other fossil fuels and at the same time more convenient to the user. And the gas endowment in both countries is gigantic and will lapse for several decades. So we have to try hard to sell the benefits of natural gas to policymakers and the public at large. There is an initiative to develop unconventional gas in the western energy corridor of the Rocky Mountain region of the northern US and Canada. I think this joint approach could become a very effective tool to accelerate the understanding of policy makers on the key role that natural gas will play in the energy future of both countries.

ET: I’ve noticed that the paper you did last year for the World Petroleum Congress differentiates between shale gas and gas from tight sands. Will tight sands be a bigger play than shale? And how will those compare with coal-bed methane?

RA: Our WPC paper last year focused on tight gas formations – not shale gas. The difference is important. In the case of shales the gas is generated in the shale and remains in the shale. So the shale plays the role of source rock and reservoir rock. In this case, part of the gas is adsorbed in kerogen within the shale, part is stored in inter-particle porosity and part is in natural microfractures. Typically, production of formation water is not an issue in shale gas. In coalbed methane, the coal is also source and reservoir, the gas is adsorbed in the coal but water production from natural fractures (cleats) might pose an environmental hazard. On the other hand, in the case of tight formations the gas has been generated somewhere else (most likely in a shale) and has migrated to the tight formation where it is trapped and stored in inter-particle, slot and microfracture porosity. When gas is trapped in continuous tight accumulations there is not a water leg and water production is not an issue. When gas is trapped in regular structural and stratigraphic traps with very low permeability (tight formations) water production can become a very important operational, environmental and economic issue.

The tight gas endowment we presented at the WPC, which did not include shale gas, was over 15,000 Tcf for the 937 recognized petroleum provinces throughout the world. Following the same procedure of our WPC presentation, which included proxy support from geologic sources, discovery process using a variable shape distribution (VSD) model, data from the United States and Canada; and a global gas resource pyramid, we estimate preliminarily the global shale gas and coalbed methane endowments at approximately 10,000 tcf and 5,000 tcf, respectively. So our total conventional (15,000 Tcf) and unconventional gas (30,000+ Tcf) endowment is over 45,000 Tcf without including reserve growth. In our view, the future is brilliant because of the significant gas endowment throughout the world that will last for several decades. And the bonus is that, as indicated in my reply to your previous question, natural gas is the cleanest fossil fuel available, providing comfort, cleanliness and convenience to the user. Definitely a win-win combination for all parts involved.

ET: EnCana has a big position in shale gas. But generally speaking, are Canadian producers lagging US companies in their embrace and use of horizontal drilling and multi-stage fracturing? Has shale gas production in Canada (as a percentage of overall production) kept up with shale gas production in the US?

RA: Canada has not kept up with shale gas production in the US. In fact, Canada shale gas production is, relatively speaking, in its infancy. However, Canada’s shale gas potential is gigantic in the Western Canadian sedimentary basin (WCSB), the Saint Lawrence Lowlands of Quebec and the Maritimes. At present, we are seeing action that I anticipate will continue to grow with time in the Montney and Horn Valley (WCSB) and the Utica shales of Quebec. Also in shallow Colorado group shales of Saskatchewan and elsewhere. However, when it comes to unconventional gas exploitation, we are following the lead of the US. In my opinion, the vision shown by the US in the research and development of Devonian shales, followed by research on drilling and hydraulic fracturing with the sponsorship of the DOE and under the careful eye of the Gas Research Institute (GRI) led to the big success history we see today in the US. The research my Chair is conducting as part of the GFREE program at the University of Calgary uses many analogs from the work done by the GRI. Our GFREE is a multi-disciplinary target-oriented research program integrated by geoscience (G), formation evaluation (F), reservoir drilling, completion and stimulation (R), reservoir engineering, and economics and externalities (EE).

ET: The Obama administration has said it plans to eliminate the tax break for intangible drilling costs. If that happens, what will it mean for the US gas market?

RA: At this stage, I do not think the elimination of any tax breaks will be beneficial to anybody.

ET: What is the smartest course of action for natural gas-focused companies both in the US and Canada? That is, how should they be seeking a strategic advantage in shale?

RA: Try to join forces with government to pursue collaborative research and development to the best of our abilities. This works. A clear example is provided by joint efforts of industry and government in the US in the 1980s that led to a dramatic upward slope change of the unconventional gas production curve. This clearly benefited everybody. Work with stakeholders. Respect the environment. Carry out campaigns to educate the general public about the cleanliness of natural gas. In a nutshell, integrate natural gas from shales and other reservoirs with the certainty that this will lead us to live in a cleaner environment with less pollution and less smog.

ET: There have been a number of reports that talk about the potential for shale gas at Montney and Horn River. What will be the constraints on production from those fields?

RA: The potential of shale gas at Montney and Horn River is very large. In my view, there are not geological or technical constrains viz-a-viz other successful shales in the US. The pay thickness, total organic content and gas in place volumes are comparable and sometime superior to some of the US reservoirs. However, there are economic constraints associated mainly with low gas prices and large distances to markets. From the point of view of the environment it will be important to reduce the footprint to a maximum by optimizing development and drilling of as many wells as possible from a single pad location.

ET: The gas business has long been bifurcated between “conventional” and “unconventional.” But now, the trends are obviously showing that the unconventional is conventional. Should we change our vocabulary on these terms? And if so, do you have any suggestions?

RA: At this time, I do no think it is wise to change our vocabulary. Although these are misnomers, there are important differences between what we have called historically conventional vs. unconventional gas. In conventional gas, the fluid is stored in interparticle porosity with generally medium to high permeability. In this case, gas is trapped above water due to buoyancy forces and fluid flow can be handled by Darcy’s law with suitable modifications to account for turbulent flow. On the other hand, there are some common threads that are generally observed in the case of unconventional gas. For example, tight gas, shale gas, coalbed methane and natural gas hydrates contain very large volumes of original gas in place but very low recovery factors; natural fractures are generally found in these types of reservoirs, something that does not happen necessarily in the case of conventional gas; and because of the special drilling, completion and stimulations required to establish commercial production, these reservoirs can receive fiscal incentives that would make their exploitation more attractive to operating companies. There are also the issues related to gas adsorption in shales and coalbed methane reservoirs discussed previously.

ET: Given that the US and Canada could have a glut of gas for years, perhaps decades to come, what policies should the federal governments in the two countries be adopting? Should they, for instance, be encouraging more use of natural gas vehicles?

RA: Most definitely. Massive efforts to produce natural gas vehicles and retrofit older vehicles would be beneficial in different fronts. From an environmental point of view, there would be significant reductions in CO2 emissions and less smog and pollution in the US and Canada, particularly in large cities. If successful, and I do not see any reasons why this would fail, this would be most likely imitated by other countries around the world. From an economic point of view, there would be important savings particularly for the US as the massive use of natural gas in all types of vehicles would lead to a reduction in oil import volumes. So this would benefit also the country as a whole.

ET: You’ve been in this business for a long time. Which energy analysts/journalists/writers do you admire? In that same vein, what energy-focused publications do you view as "must reads"?

RA: I have learnt a lot from technical energy publications by the International Institute for Applied Systems Analysis (IIASA). Individuals like Cesare Marchetti, Nebojsa Nakicenovic, Arnulf Grubler and Hans Holger Rogner have done, in my opinion, outstanding work on energy related issues during the past 30+ years. I admire the work of Robert Hefner III, one of the original leaders in drilling deep, high pressure-high temperature gas reservoirs; probably an individual with ideas ahead of his time. In my view, his book “The GET: Grand Energy Transition” (2008) is a “must read” document for policymakers and people actively involved with natural gas, the environment and energy transitions. Some of the ideas presented in his book are very thought provoking. I enjoy the works of Vijay Vaitheeswaran and his ideas of how a transition to a hydrogen economy might save the planet; and J. L Simon’s book and his thoughts on the ultimate resource. I go periodically to the website of Energy Tribune and enjoy articles particularly by Michael Economides and Robert Bryce. I also follow the energy writings by Gordon Jaremko in Alberta. For those who are concerned about peak oil and peak gas I recommend as a “must read” the book “The Availability of Global Fossil Energy – How Long will it Last?” by Roberto F. Aguilera (2008).

ET: Thank you.