GLG News by Michael Lynch

Implications: Rob Gilles with the Associated Press in Fort McMurray, Alberta reported in the August 26 issue of the International Herald Tribune that Shell is rapidly expanding oil sand production from Muskeg river open pit mines in the Athabasca region of Alberta. They are joined by ExxonMobil, Chevron, Imperial Oil and others in a development that covers an area the size of New York State. Current daily production of 1.5 million bbl/day will triple by 2020. Alberta, with 175 billion potential barrels has more oil than Venezuela, Russia and Iran. Because of immense water requirements to extract the crude oil, environmentalists are deeply concerned. Oil sand operations produce 4% of Canadian greenhouse gas emissions. Tailing ponds next to rivers threaten fresh water streams with chemical pollution. The oil companies are fully aware of both the criticism and the real dangers involved. Measures are necessary to make operations acceptable to the public. The government cannot ignore the new jobs.

Analysis:  As of right now, any attempt to reduce the expansion of oil sand projects is certain to be defeated. High crude oil prices sustain them and the employment they create. The only way out is to increase extraction budgets to improve the environment. At a minimum, potable water supplies must be projected. The land must remain habitable for wildlife. Extraction costs today are approaching the $50/bbl mark. What will the costs be to satisfy the public and prevent the projects from becoming nuisances? Possibly $5/bbl. Add in another $5/bbl for a publicity campaign to convince the non-believers that, indeed, the projects are beneficial in every way to the economy and the environment. Oil from the mines thus becomes even more than costly than it already is. With a substantially higher extraction cost, oil from sand becomes a primary target for shut in if and when crude oil prices drop below $100/bbl. The world is approaching an energy situation where energy extraction costs collide with consumer’s pocket books. This is no small consideration in an international economy that depends on modestly-priced fuels.

Implications: Clifford Krauss in Houston reported in the August 23-24 issue of the International Herald Tribune that U.S. natural gas production is rising faster than it has in decades. It reverses conventional thinking about the irreversible decline of domestic gas fields. New drilling technology allows commercial production from shale beds. A decade ago, no one thought that possible. Similar shale deposits exist all over the world but few have been explored. If the trend continues, significant implications about prices emerge. Development of liquefied natural gas (LNG) could slow. But not everyone thinks the new supplies could last for decades. Most of the production gain comes from the Barnett shale in the Fort Worth basin. Companies are now shifting their sights to other shales with a promise of even greater production. The Haynesville in northern Louisiana and the Marcellus in Appalachia are shales believed to contain more gas than the Barnett. Real estate speculators are becoming rich.

Analysis:  The alarming factor associated with shale gas production is the extremely high decline rate. A well that comes on line at five million cubic feet/day will fall to half that in six months and down to one million after a year. It is true that the slope of the decline lessens as the curve becomes asymptotic to the time axis. Even after a year, the well is still economic and will remain so for perhaps a decade. One intermediate answer to the long term supply question is performance of the Barnett shale play. The Texas Railroad Commission devotes a special section of its monthly production report to the Barnett. Annual production has increased steadily from 28 bcf in 1997 to 1098 bcf in 2007.Through March of 2008, production was 345 bcf. That would be an annualized rate of 1380 bcf and another record. Should the year end 2008 figure come in less than that, it could be an indicator. The high growth rate is a result of the drilling of new wells whose production outpaces the decline. Drilling today in the Barnett has just about determined the field limits. Once the field is drilled up, production will plateau and then decline rapidly. Producers believe that reduced spacing and increased fracturing stages will forestall the decline even after the field limits have been reached. But this is far from certain. The Barnett shale report issued by the Railroad Commission is a closely watched document. Once a leveling off the Barnett occurs, more accurate assessment of all of the shales can be made. As of today, it appears that unconventional natural gas will be a game-changing event, opening the way for increased commercial activity everywhere. An interesting speculative feature of the play is that many, many oil and gas companies as well as royalty trusts have untested shale deposits under control.

Implications: David Jolly in Paris reported in the August 23-24 issue of the International Herald Tribune that Europe, seeing American exploitation of shale gas, has now begun a similar search. The first chore is to determine how much gas could be available. Many of the same type of North American shale formations exist across Europe. Scientists of the GFZ Research Center are undertaking a six year study to map these resources. Possible commercial production will be based on data for the Barnett shale in Texas. First on the list are deposits in Sweden, the Netherlands and Germany. However known shale deposits exist in Poland, France and elsewhere. European Union officials, nervous about increasing dependency on Gazprom, welcome the effort. Private companies, fearing land speculation, are reticent about discussing their exploration activity. But OMV (Austria) has already announced tests in the Vienna basin, an oil production area since the 1930s. Royal Dutch Shell has licenses in Sweden.

Analysis:  Last April ExxonMobil announced agreements with Falcon Oil and Gas and MOL Hungarian Oil and Gas for exploration in the Mako Trough in southeast Hungary. The projects are aimed at production of unconventional oil and gas. Later, the company announced it was setting up a geological section to look for opportunity across Europe. ExxonMobil is the largest natural gas producer in Europe. It can review exploration records for all of its lease holdings across the continent. Another important producer in the region is Ascent Resources of London which announced this month that it was increasing natural gas production from the Penezlek region in eastern Hungary. The potential is huge. All of the European majors including Shell, BP and Total have large concessions held by production. Other important companies include E.ON, the Wintershall unit of chemical giant BASF. This activity will not be invisible to Gazprom. It is likely that they too, will begin similar regional mapping studies because Russia no doubt has ten times the shale gas resources of Europe. Significant developments in the unconventional oil and gas sector of the business has the potential to completely change the economic landscape for hydrocarbon production and consumption not only in Europe but in the major liquefied natural gas producing nations such as Algeria, Qatar and soon, Iran. In the U.S., production from the Barnett, the Woodford and more recently the Haynesville shales, has already retarded LNG imports. The promise of the Marcellus in Appalachia threatens LNG even further. The international oil and gas industry has an amazing capability of going after natural resources quickly and efficiently. This is a trend to watch carefully. Worldwide natural gas prices could be affected more quickly than anyone thinks possible.  

Implications: Drilling Editor Nina M. Rach reported in the August 18 issue of the Oil & Gas Journal that Shell Rocky Mountain Production Company is optimizing Pinedale field wells. Production will be increased and surface disturbances will be reduced. Shell will drill more than 90 wells this year. The 35 mile long Pinedale anticline produces from shales, siltstones and sandstones. The first well, drilled in 1939, had poor permeability and no pipeline connection. Since the 1990s, with multistage fracturing, Pinedale has become the second-largest natural gas field in the U.S. Shell, third-largest leaseholder after Ultra Petroleum and Questar Corporation has drilled more than 280 wells and performed 2,800 fracture jobs. Total investment exceeds $1.5 billion. Well design has evolved with directional drilling and slimmer well bores. Shell focuses on wells of 7,000 to 14,000 feet. Each multistage well has 15 fractures stages filled with 105,000 lb of proppant. Inflationary cost increases run 20% annually.

Analysis:  In this well thought-out, three page presentation, Drilling Editor Rach describes the evolution of Shell’s design and completion technology, always aimed at lower costs and care for the environment. In six years of operations, everything has been streamlined. Unfortunately 20% annual inflation erodes profit even as the company reduces cost further. But the reserves are large and with high gas prices, the company will definitely prosper. With many, many pay sands, the opportunity for continued drilling is substantial. The main uncertainty is variation in natural gas prices in the future. The company’s margins are low and are squeezed even further by higher prices for equipment, services and labor. Essentially, this is the problem faced by all developers of shale gas reservoirs. If costs can be contained, projects of this type can go on indefinitely. Once operating costs equal sales, the game is over.

Implications: Jad Mouawad in New York reported in the August 19 issue of the International Herald Tribune that all seven of the major oil companies were producing less oil than before. Politics plays a part. The terms of foreign concessions in Asia and South America have become more onerous with more oil to the state and less to the companies. Surging fuel prices are blamed on the oil companies. But the primary factor is that oil companies no longer have the international influence of old. Amy Myers Jaffe at Rice University says the industry is in crisis. The production shortfall became evident during the latest quarter. The seven publicly traded major oil companies including ExxonMobil reported that total oil output was down by 650,000 bbl/day. In the 1970s, the oil companies controlled over 50% of production. Today they control 13%. The 10 largest producers now are national oil companies. But the Western companies are far ahead of them in new technology.

Analysis:  One reason for production declines in crude oil is that more and more of the oil company budgets are going into the natural gas side of the business. It is true that much of the landscape where the Western companies operate has been thoroughly explored meaning that whatever resources they find will be far less than what has been found before. Major companies are moving into Canadian oil sands. They are active in Russia with a number of redevelopment projects as well as frontier projects like Sakhalin Island in Russia’s Far East and the Shtokman field in the Barents Sea. As regards ExxonMobil in particular, this second half of 2008 should see an improvement in production as a result of bringing the Kizomba C Saxi/Batuque field offshore Angola on stream in August. At full operation, this field will add 100,000 bbl/day. Kizomba C-Mondo came on line last January and will add another 100,000 bbl/day at peak production. Chevron just announced that oil was flowing from Agbami field offshore Nigeria in July at 100,000 bbl/day. This will increase to 250,000 bbl/day by the end of 2009. So while it is certain that all oil producers will struggle with declining production from older fields, much oil still remains to be found and the Western majors will find it. As a final point, consolidation in the industry is far from over. Some of the second tier producers will ultimately be bought up by the majors. Murphy Oil, Occidental Petroleum, Marathon and Anadarko all fall into this category. Quite some long time will pass before the majors go out of business.

Implications: John Westwood of Douglas-Westwood in Canterbury U.K. reported in the August 4 issue of the Oil & Gas Journal that Europe remains one of the largest offshore producing regions. But declining production and high costs have forced the oil majors to leave. Smaller operators now salvage what oil is left in the big fields and develop the remaining tiny ones. The most recent estimate showed that the UK decline rate in 2007 was 7.5%. Combined capital and operating expenditure off Northwest Europe is the world’s highest, near $51 billion in 2008. The UK is the world’s 13th largest oil and gas producer. UK operating costs rose almost 30% from 2006 to 2007. Capital and operating costs are now $29/bbl for projects coming on stream in 2008-10. Drilling consumes much of the total offshore outlay. With 68 installations, Western Europe has more floating production systems than anywhere else in the world. The environment is harsh and weather is a test for these vessels.

Analysis:  In the early years, Exxon, Royal Dutch Shell, BP, Chevron, Phillips, Total and a few other international majors dominated the activity, drilling and completing the giant oil fields such as Brent, Forties, Ekofisk, Ninian, Beryl and Statfjord. Spot crude oil prices during early production era (1976-78) were in the $12-14/bbl range, about one third of what it now costs to produce a barrel. Only in 1979 did prices jump up over 30/bbl as a result of the Middle East “leapfrog” and by 1983, prices were in steady decline again. The current $29/bbl extraction cost can only persist in a relatively high cost oil regime. The latest estimate of transportation costs as reported by the Oil & Gas journal in the July 21 issue showed that it cost $5.98/bbl to transport North Sea crude to Houston. With refining costs of $5.00/bbl and adding margins for profit and taxes, the wholesale price going into the dealer’s tanks as gasoline, diesel, heating oil or jet fuels comes close to $55/bbl. That gives an indication of the floor price of light, sweet crude oil. As previously reported on a report about Canadian oil sands, products made from heavy crude set a substantially higher floor price. Sadly, these are not floor prices in equilibrium. Each new development, whether it is an oil field in the deep water of the Gulf of Mexico or a redevelopment project in the Middle East, brings a higher cost structure into play. As an example, the super giant oil fields of Saudi Arabia either have already been redeveloped are now being done so. While redevelopment produces more oil, the associated costs are dramatically increased.

Implications: Senior Correspondent Eric Watkins, reported in the August 11 issue of the Oil & Gas Journal that benchmark tanker rates from the Persian Gulf to Japan fell to 7-month lows last week. The cause was ample availability of very large crude carriers. Even so, Japanese leaders are taking no chances on continued low rates. A free-trade agreement with the Sultanate of Brunei, signed in June, took effect on July 31. The part is another attempt by Japan to reduce dependency on Middle Eastern supplies. The agreement will greatly increase Japanese investment in Brunei. Japan is the sultanates largest crude oil importer. Seventy percent of Japan’s liquefied natural gas (LNG) comes from Brunei. Japan’s crude oil imports from the Middle East declined 9.4% from 2007. Saudi Arabia shipped 31.64 million barrels. Next was the UAE at 25.73 followed by Qatar with 13.33 and Iran with 8.24. Russia, fifth, shipped 4.91 million barrels. Japan cancelled a naval drill to conserve fuel.

Analysis:  Slow steaming to conserve fuel is an early symptom that crude oil markets are loosening up. If the trend continues, some high operating cost tankers will be laid up. This has all happened before beginning around 1980 and lasting almost a decade. Once it is clear that consumers are reducing purchases of gasoline and avoiding unnecessary travel, the word quickly spreads across the globe. Fuel riots in Europe and $5/gallon gasoline signs on service stations in the U.S are flashed around the globe on television. Everybody gets the message immediately. Once a genuine conservation effort begins, as has been seen before, the momentum builds and it becomes impossible to predict where the bottom will be for crude oil prices. Nations as well as individuals search high and low for places to save fuel. Airline travel costs go up. People stop flying. Airlines stack aircraft and jet fuel prices begin to fall. Only when oil companies announce project deferments and postponements and the OPEC nations begin to shut in excess capacity will it be possible to make a guess as to where prices will level off. Certainly, right now, they are in free fall. To put even further pressure on crude oil prices, the use of natural gas and liquefied natural gas (LNG) is not going to be affected to any significant degree. In the U.S., more than 80% of the rigs running are drilling for gas.The development of unconventional natural gas is becoming a mad scramble to get pipeline connections. Continued economic concerns related to the housing markets continue to weigh on financial decisions. Quite some time must elapse before balance returns to the world economy.

Implications: Steven Erlanger in Flamanville, France with Maia de la Baume in Paris and Matthew L. Wald in Washington reported in the August 18 issue of the International Herald Tribune that France has begun construction of a new nuclear power plant. The reactor, the first in new construction in 10 years, will cost $5.1 billion and is sited next to two older units. The plant is a third-generation Pressurized Reactor. France obtains 77% of its electricity from nuclear power. Few public doubts arise about reliance on nuclear energy in France. EDF, the French electricity giant is negotiating to buy British Energy with the object of renovating Britain’s nuclear plants. An aide to the Minister of Ecology said that rising cost of fossil fuels push the trend toward nuclear energy. The new closed- fuel cycle plant is much safer and is carbon dioxide free. Electrical power generation in France accounts for 10% of greenhouse gas emissions. France has 58 operating nuclear plants behind the U.S. with 104.

Analysis: All of Europe is rethinking past energy policies. Dependence on Gazprom is worrisome for the European Union. Nuclear along with increased importation of liquefied natural gas (LNG) is seen as an important way to keep costs low and supply relatively secure. From competitive necessity, other European states will have to reexamine their views about nuclear hazards. It is not just France that is focusing on nuclear power. States in Asia and the Middle East are trending toward nuclear power. EDF which is partly owned by the government with shares traded on the Paris Bourse is considered to have a technical edge in the construction of third-generation plants. From being a stodgy French utility, some observers and investors are beginning to see it as a potential growth company. If it is successful in buying British Energy, considerable growth would be assured as it brings their generators up to French standards. One consequence of a generalized worldwide economic slowdown, as the one that now appears to loom over us, is that the pressure to contain costs opens the door for virtually every type of idea, new or old. Another beneficiary of the French National nuclear grid plants is the railroad and mass transportation city rail systems. Inevitably, more and more consumers will park their automobiles, ride the train between cities and then take the Metro or LNG powered busses to get to their final destination. Eventually even highway commercial haulage could be driven to the railroads. Today the European railroads lack the capacity to move the daily freight but, like every thing else, that could change. So the construction of this latest French nuclear reactor is just one of many indicators pointing to a rapidly changing international economy.

Implications: In the August 11, 2008 issue of the Oil & Gas Journal, an unusual 2006 oil well recompletion event was reviewed by Diamond Offshore Drilling Inc. Their semi submersible, the Ocean Vanguard was reequipped to perform recompletion services in the Draugen oil field in the Norwegian North Sea. Although completely unaccustomed to subsea completion work, the drilling crew overcame the many problems and completed the job ahead of Shell’s schedule. Two Christmas trees were pulled, the tubing was replaced and seabed-based water injection and treatment equipment was installed. Included in the project were FMC, Kvaerner, Vestbase, Halliburton, Schlumberger, Seadrill, Oceaneering, Expro, Odfjell, Fugro and Smith Red Baron. A notable success was the repositioning of a turned Christmas tree by FMC working night and day for weeks.  Collum Smyth of Shell Norske noted that the drilling crew demonstrated adaptability to make a safe, successful job. The Vanguard is now a proven completion rig.

Analysis:  Difficult and always complicated offshore operations are routinely accomplished today on schedule. Drilling units like the Diamond Vanguard in the summer of 2006 would have commanded a day rate of around $385,000. The daily cost of the various services required bring that up near the $500,000/day mark. The job, as noted in the review, scheduled for 73 days, was completed in 60. Thirty million dollars just to change out two Christmas trees, install new tubing and reequip the wells for water injection. All of that just to restore a mere 22,000 bbl/day of crude oil production. In the summer of 2006, the price of crude oil would have been about $70/bbl so the recompletion resulted in a cash flow of $1.5 million/day. That is a payout of the recompletion in 20 days. Clearly it was well worth the planning, coordination and effort required. Most of the time, complex offshore operations go smoothly and the job is a success. The work is dangerous. Once in a while, something goes wrong and when this happens, the cost can be in the millions. If it is a blowout or a fire, the cost can be in the hundred of millions. Fortunately the crews are extremely well-trained to cope with emergencies when coping with high pressure wells. And today’s blowout prevention equipment is, to all extents and purposes, foolproof. But the summary of the operation reveals one of the reasons for today’s expensive crude oil.  

Implications: Reuters reported in the august 16 issue of the International Herald Tribune that OPEC cut its forecast of global crude oil demand for the fifth month. Production is more than adequate. Supply and demand are in balance. The 13 members of OPEC produce 40% of the world supply. Higher OPEC production and a strengthening dollar indicated a weaker outlook for the oil market. The softening world economic situation has led to further slow demand growth. Oil has fallen from $147/bbl in July to $113 today. For 2008, demand will increase by 1.0 million bbl/day, 30,000 bbl/day less than the previous forecast. OPEC’s office in Vienna is staffed by economists who prepare the monthly report. The next meeting of the group is set for September 9. OPEC’s prediction for demand growth in 2009 was unchanged at 900,000 bbl/day. Supply growth from non-OPEC sources will be 950,000 bbl/day. With current OPEC production above demand, a sharp inventory buildup is possible. Hurricanes could upset the balance.

Analysis:  Nothing takes the place of a prolonged international economic slowdown when it comes to taking pressure off the crude oil markets and with them, the major oil companies. This is a positive development for consumers because it will inevitably lead to further consolidation in the industry. Consolidation leads to greater operating efficiency, less demand for expensive capital, reduced inflationary pressure and in short, a return to more or less normal business practices which means lower gasoline prices. Putting more crude oil on the line at any price gives way to putting the least expensive crude oil on line. The immediate impact will be on the high cost developments which include the deep waters of the Gulf of Mexico, the Arctic, Canadian shale oil and the Orinoco Tar Belt. Majors and independents alike will reconsider smaller projects with lower rates of return but which do not require high-risk capital. It is to be remembered that the OPEC producers, like the majors, have had to cope with inflationary pressures as well as shortage-induced delays. A slowdown will give the entire international oil and gas industry time to rethink strategy. The steel industry will get a breather. The furious competition for rare technical talent will become subdued. Oil company management will no longer be distracted by prolonged appearances before the U.S. Congress and the various European commissions. Closer attention to business by oil company managers will be rewarded by more accurate decisions. Life will be simpler.

Implications: Senior Associate Editor Judy R. Clark reported in the August 11 issue of the Oil & Gas Journal that technological advances in the use of high temperature heat to produce heavy crude oil may resolve major problems. Both dependence on politically unstable sources of foreign oil and generation of greenhouse emissions could be drastically reduced by using the heat from a nuclear reactor to refine heavy crude oil in the reservoir. Charles W. Forsberg, nuclear engineer at MIT, has proposed pumping heat from the reactor down to the oil zone. Volatile hydrocarbons vaporize and move toward recovery in cooler places. Away from the heat source, they condense and can be pumped to the surface. The distillation leaves most impurities behind. As the temperature continues to rise, heavier hydrocarbons will crack thermally to produce lighter oils. Heating the reservoir duplicates standard refining processes. Most of the theoretical progress has been made with recovery of shale oil. 

Analysis:  The average crude oil recovery from oil fields all over the world is less than 35%. Primary recovery can be as low as 5% for extremely heavy crudes but on average is in the 15-25% range. Primary water drive recovery can be 75-85% but only a handful of fields (including East Texas) fall into that category. Secondary recovery can often double recovery from primary and “enhanced” recovery can squeeze out another 10-20% over many, many years of injection of gases or chemicals. In the final analysis, huge quantities of oil remain bound to the pores of the pay zone because of capillary pressure. Oil fields today are studied in advance of development with the idea of maximizing recovery from beginning to end. Primary recovery and secondary recovery, once in common usage, are terms which if not obsolete are certainly obsolescent. The term “nuclear reactor” is dated from 1940-1945 and the the nuclear power era began some years later. Since that time oil producers have speculated about what would happen if extremely high temperatures from such reactors could be introduced into crude oil reservoirs. But not much happened in the way of research because of governmental fears about accidents and unintended consequences. As a result, no oil company has ever tried to repressure an old field in this manner (the Soviets considered it). Today, with an accurate understanding of nuclear processes, reliable safeguards and more importantly, new drilling technology, the feasibility is no longer in question. Another technological advance is the design and construction of high-quality insulation materials and their use in both pipelines and subsea systems. Superheated steam has always been considered as the most likely fluid for this application but now nitrogen and other inert gases are equal candidates. Pemex proved the ability of compressed nitrogen to improve oil recovery in the Cantarell complex. Imagine what would happen if nitrogen at 700° Celsius were injected into a Green River shale zone. The basic chemistry is thermal cracking of heavy hydrocarbons which refiners do all the time as a matter of routine. Crude oil recovery by nuclear processes is an idea whose time has arrived. All it takes is a relaxation of governmental regulations and the crude oil supply problem can be solved for decades to come.

Implications: Christopher Swann (Bloomberg) in Washington reported in the August 12 issue of the International Herald Tribune that the World Bank has provided funding for the Tata Ultra Mega power plant in western India. This comes one year after Robert Zoellick, president of the bank, pledged to assist in fighting climate change. But the bank is not slowing its investments in fossil-fuel projects that emit greenhouse gases. Concerns about social deprivation outweigh environmental worries. Critics of the bank say that financing energy projects sacrifice air and water quality for revenue. Last year 10 percent of the bank’s financing went for power generation. In response to criticism, the bank said it was investing in energy conservation projects as well as renewable energy. A shortage of electricity is a major constraint to growth in developing countries. About 400 million people live without electricity in India and the situation is worse in Africa. 

Analysis:  The World Bank Group includes the International Bank for Reconstruction and Development (IBRD). This organization provides loans and technical assistance for projects in member countries. Further, it encourages and helps to arrange co-financing. The International Finance Corporation (IFC) has several functions with regard to improving the local economy of member countries and it attempts to bring private financing when possible. The International Development Association (IDA) provides funds for projects in the poorer of the member countries. The Multilateral Investment Guarantee Agency (MIGA), among other things, guarantees investments to protect investors from risks such as nationalization. It has the further function of advising governments. The International Center for Settlement of Investment Disputes (ICSID) provides arbitration services with regard to disputes between private investors and host governments. While it has suffered many scars and stings since it was formed in 1944 as a consequence of the Bretton Woods (New Hampshire) Conference, countless energy projects in remote corners of Asia and Africa were possible only through its good offices. It is fair to say that, in general, it has alleviated poverty many times over. Like all companies and institutions engaged in energy projects, it is mindful of air quality. Climate change is not one of its prerogatives. Indeed, the arguments about climate change are manifold. Some scientists say it is not happening. Some say it is happening as a consequence of the whims of Mother Nature. Geologists know that it has existed repeatedly in the several eras of the stratigraphic column from the Cenozoic to the Pre-Cambrian. Ice ages have come and gone. Continents have collided and then drifted apart. The seas rise when the polar ice caps melt during periods of warming. The seas fall when ice accumulates at the poles during ice age conditions. None of this is covered in the mandate of the World Bank. As long as projects are carefully managed to maximize utility, bring prosperity to poorer regions of the world and control unwanted plant discharges with modern technology, the World Bank is on course.

Implications: The Oil & Gas Journal reported in the issue of August 11 that Southwestern Energy Company of Houston was running 500 million cubic feet/day from its Fayetteville shale in north-central Arkansas. The company, with 857,000 net acres, estimated that ultimate recovery could be improved by up to 20% from horizontal wells with closer perforation spacing. The technique was tested in 38 wells during the first half of 2008 and will continue for the rest of the year. Today, 22 rigs are drilling longer laterals. Average length has increased from 2104 feet in 2007 to 3,562 feet now. Later this year the company plans to reduce the spacing of wells to 80 acres. Completion knowledge consistently improves. During the first quarter, 83 wells averaged 2.54 MMCF/D. Seventy-five wells averaged 2.15 MMCF/D after 30 days and 72 averaged 1.93 after 60 days. As of June 30, the company has completed 619 wells. Realized price was $8.17/MCF. Wells are located in 8 Arkansas counties.

Analysis:  Decline rates for shale gas wells follow a similar pattern whether they be in the Barnett, the Woodford, the Fayetteville, the Haynesville or any other shale formation where production characteristics are similar. But there are differences. For example,as near as can be determined, the Barnett shale in the Fort Worth basin has only free gas in the reservoir. But the Woodford shale in the Arkoma basin appears to have both free gas and adsorbed gas. Adsorbed gas is bound to the surface of the shale in a thin layer which only turns into free gas after the pressure has been lowered to some threshold level. Newfield Exploration Company has published type curves for the Woodford shale which include an example for an extended lateral (>3,000 feet) and a standard lateral (2,000-3,000 feet). Both curves show adsorbed gas coming into the flow stream after about 75 days of production. The Southwestern data do not tell if the Fayetteville shale contains adsorbed gas but the three points of data plot almost as a straight line on semi-log paper. Comparing the 60 day Fayetteville curve with Newfield’s 450 day Woodford curve allows an approximation of ultimate recovery. For the data presented, it appears the wells that Southwestern Energy is completing today will recover around 2.5 billion cubic feet over the life of the well. If they can extend that by 20%, then ultimate recovery could be about 3 billion, perhaps more. The question is whether gas production comes only from the fractured zones. If it does, and many think that is the case, then by reducing the spacing, the ultimate recovery could be significantly increased from the acreage under lease. Natural gas production from shale zones is a constantly evolving technology. Nobody really knows how much the ultimate recovery can be until all of the various techniques are tested.

Implications: Chris Borowski (Reuters) in Warsaw reported in the August 8 issue of the International Herald Tribune that OMV, the Austrian oil and gas company, still holds 20.2% of MOL’s stock. MOL is the Hungarian national oil company which successfully resisted the merger attempt. OMV had expected a merger with MOL would make it a European giant oil company. Does it hold on for another chance or sell its stake? Now each of the two companies is trying to buy out the Croatian oil company, INA. The failed merger attempt comes at a sensitive time for Russia’s role in Europe’s energy business. European politicians worry that Gazprom could solidify its near monopoly. Fund manager Mark Mobius sees the impasse as an opportunity for MOL to combine with a Russian firm to create a force in Eastern Europe. Observers note that MOL’s successful defense resulted in a fall of the value of its stock which at its peak traded at a 43% premium. Some investors may flee the stock.

Analysis:  Not only Gazprom is involved in the quest for market share in Eastern Europe. Exxon Mobil’s recent formation of an exploration program in the Mako Trough in southeast Hungary is a signal that the fight is just beginning. Royal Dutch Shell and Total (France) are waking up to the opportunities for the extraction of unconventional natural gas all across Europe. In recent years both OMV and MOL have sought exploration opportunites everywhere in the world in the hopes of finding major reserves which could be transported back to Europe. MOL is a key company because of its location and long-standing ties to Gazprom. The two companies, even merged, would not really present much of a challenge to the big dogs. OMV has 13 oil fields, 905 wells and produces about 17,400 bbl/day. MOL has 54 oil fields, 875 wells and produces 16,400 bbl/day. OMV proved reserves are 50 million barrels as compared to 20 million for MOL. These are small amounts compared with those of Exxon Mobil, Royal Dutch Shell, BP and Total. But considering the flux of the market in Europe, the inability of the European Commission to install a unified energy policy and the possibility that both OMV and MOL could control large volumes of unconventional shale gas reserves give them a romantic niche in the world of international investors. Thus the stock values of both companies will fluctuate with each new hint that a consolidation could occur. As oil company speculations go, these two will remain interesting for some time.

Implications: The Oil & Gas Journal reported in the issue of August 4 that U.S. crude oil demand dropped 3% during the first half to 20.08 million bbl/day. It was the first large drop since 1991. The report was published July 18 by the American Petroleum Institute. Gasoline deliveries fell 1.7%. Remarkably it was the largest decline in 17 years. But demand for ultralow-sulfur diesel (ULSD) jumped 16%. Refiners are supplying the market with record diesel supplies. Gasoline has a greater share at the more discretionary consumer level. The high gasoline prices have caused the U.S. fall off in demand. It is not yet clear what higher prices are having internationally. Petroleum imports fell below 13 million bbl/day, the lowest level since 2003. Crude oil production in the Lower 48 U.S. states fell 2.1% during the first six months. Alaskan crude oil production was lower too. Exploratory drilling is up 53% this year and development drilling increased 15%. Industry is trying hard.

Analysis:  For the first quarter of 2008, the Oil & Gas Journal reported that total world demand was 85.43 million bbl/day while supply was 85.64 million. U.S. demand was 20.15 million bbl/day. Source of the data was the U.S. Department of energy International Petroleum Monthly. There was a positive addition to world inventories of 210,000 bbl/day. This latest API report shows that U.S. demand fell further in the second quarter to 20.01 million bbl/day. The unknown quantity is what will be the demand for the second half of the year. Given the general economic climate, a good guess is that increases in diesel demand will approximate additional declines in gasoline consumption. Even that could be wrong. If gasoline prices continue their downward slide, greater use of low mileage vehicles would occur. It is well established that existing world oil production of about 73.3 million bbl/day will continue to decline at a rate of about 300,000 bbl/day. Offsetting this will be about 250,000 bbl/day of new supply (using estimates based on an Oil & Gas Journal report of June 9).With what is known right now, inventories will stay level or rise further, ever so slightly. Speculators, who follow inventory adjustments closely, are likely to continue shorting the futures market until at least the end of the third quarter. Crude oil prices could slip further. But when third quarter inventory data become available in the October report, the yearly trend should be well established. By then, the Olympic Games in China will be history and the effect of some subsidy reductions in the Far East will be evident. With that data in hand, it should be possible to predict, more or less, what the demand/supply situation for 2009 will be (and by extension, price trends). Right now, it is anybody’s guess.

Implications: Washington Editor Nick Snow reported in the August 4 issue of the Oil & Gas Journal that experts say a basic force behind higher oil and gas prices is more expensive exploration and production. Policy focus is on crude oil price but Cambridge Energy Research Associates Chairman Daniel Yergin said the problem relates to costs of facilities as well as access to drilling locations. The industry’s problems are tied to the plunging prices of 20 years ago. Companies became smaller because they expected prices to remain low. Less equipment was manufactured. Fewer petroleum engineers and geologists were educated. The latest capital cost index shows that an item that cost $100 in 2005 now costs $210. The price of steel is up 60% since the beginning of 2008. Horizontal wells are more expensive. Independents are drilling half of the new oil and gas wells. Still, wells are drilled. The industry is breaking drilling records all across the country.

Analysis:  While consumers in the U.S. and Europe are struggling with the consequences of an almost unprecedented economic crisis, inflation continues to push exploration and production costs up. Consider a barrel of heavy crude oil. Extraction costs are running between $30 and $40/bbl. Transportation can add $5/bbl and refining, another $5. Add profit margin of 25% and taxes at 35% of profit and wholesale prices range from $65-70/bbl. If crude prices continue their slide toward $100/bbl, as many observers predict, producers will see a flashing orange signal. If prices fall below that, some high-cost projects will be suspended or cancelled. When projects are suspended, it means that the volume of new oil going into the international stream is reduced. With annual decline rates of the total black oil stream running at 3.5 million bbl/day, it will not take too many months until crude oil will once again seek market equilibrium at higher prices. The question then is how severe is this downturn and will consumption continue to decline below the zero demand growth line. If so, prices will remain at the lower levels. But at some point, with retail gasoline prices falling from over $4/gallon, to around $3/gallon, consumers will again fill the tanks of their low mileage vehicles. Today is a period of uncertainty. Until inflation in the cost of oil and gas field development stabilizes, producers will not know how to act and operations will slow down across the board. Some of the unconventional natural gas producers are already seeing distress as natural gas prices come down into the $8.5/million Btu range. Oil companies have budgeted hundreds of billions of dollars in capital and exploratory expenditure based on the thinking that crude oil prices will remain high. Should it become clear that this is a long-term recession, the rosy scenario for drilling contractors and oil service companies will go a glimmering. In 1980, worldwide oil consumption was already in decline under the impact of $34/bbl crude. When oil reached $40/bbl in 1981, consumption began falling rapidly finally leveling out into a trading range between $31-27/bbl during 1982-1985. Producers were breathing easier. Consumption had flattened out. But then in February of 1986, the price of crude oil plummeted from $26/bbl all the way down to $10/bbl by mid-year. That was the year of the collapse. Could the world be reliving that scenario? Hard to say but producers are nervous and looking over their shoulders.

Implications: Washington Editor Nick Snow reported in the August 4 issue of the Oil & Gas Journal that the United States has 2,247 trillion cubic feet of natural reserves, a 118 year supply at 2007 demand levels. A study released by the American Clean Skies Foundation (ACSF) and Navigant Consulting Inc., explains that existing forecasts underestimate unconventional reserves. The study covered tight sands, coalbed methane and gas shale reservoirs. Aubrey McClendon, ACSF chairman pointed out that new technologies have resulted in the rapid development of gas shales. Growth in proved U.S. reserves has come almost exclusively from unconventional resources. Two members of the U.S. Congress, Rahm Emanuel and Dan Boren have cosponsored a bill to increase use of natural gas as a transportation fuel for automobiles. Navigant Consulting talked to 114 producers which supply 90% of the total North American natural gas supply. Sixty-six provided information about the resource base and production levels.

Analysis:  An entirely new category of natural gas company has emerged in North America as engineers capitalize on new drilling and completion technology to unlock the natural gas in shale. This has been made possible by the development of Top Drive which enables drillers to bore horizontally once the level of the shale has been reached. Equally important is logging-while-drilling (LWD) and measurement-while-drilling (MWD) which first appeared in the 1990s and is an accepted tool now. Another, even newer device which has made commercial exploitation of gas shales possible is the rotary steering assembly. This device allows the driller to point or push the bit in the direction of good quality pay as indicated by the LWD tool. High pressure formation fracturing has been around for over fifty years but only in the last decade has it been important as a means to improve production rates in horizontal laterals. The fractures are propped open with Ottawa sand or high strength glass beads to assure high flow rates. Today multiple stages of fracturing are performed in most shale gas completions. Each stage improves production performance. The technical laboratory for much of this new technology has been the Barnett shale of the Fort Worth basin. The Texas Railroad Commission publishes on its website a monthly update on the Barnett. As of June 3, 2008, there were 7,766 gas wells in the 19 counties where the Barnett shale is found. Just since the year 2000, over 3.8 trillion cubic feet have been produced from this source alone which now makes up 15% of Texas natural gas production. Today exploration is active in the Woodford of Oklahoma, the Marcellus of Appalachia, the Haynesville of north Louisiana and the Fayetteville in Arkansas. Many other yet to be tested deposits exist and await the drill. This niche industry is in its infancy.

Implications: Felicity Barringer reported in the August 4 issue of the International Herald Tribune that the U.S. Congress is debating whether to intensify drilling efforts on government land. Consumers want lower gasoline prices but most new onshore drilling during the last seven years found natural gas. Oil production from Western lands has declined by 12% compared to the Clinton era. Drilling in the West is more likely to find gas. The wellhead price of natural gas is five times higher than it was in the 1990s. Increased production from government land puts downward pressure on natural gas prices because the North American gas market is largely isolated from the world market. More of the nation’s oil reserves are in Texas, offshore, Alaska and California while ninety percent of the drilling permits in 2007 were in Colorado, New Mexico, Utah and Wyoming. Environmental effects of drilling have taken a toll. Pinedale, Wyoming had its first ozone alert last winter. High prices encourage oil drilling.

Analysis:  Until the beginning of the 21st Century little if any thought was given to environmental damage of domestic oil and gas development and the costs associated with it. Most of the invective was aimed at the coal and nuclear power industry. That has now changed. All types of energy are now under scrutiny which explains why wind and solar energy have become the new darlings of the environmentalists. Unfortunately neither of these sources can be readily converted to transportation fuels. To make matters worse, the price of imported oil has risen to the point where consumers must curtail their driving. Inevitably, this slows down an economy already in the doldrums from other causes. In fact a U.S. domestic energy policy aimed at more crude oil production is doomed to failure because the crude oil still in the ground is difficult to extract and will be produced at such low rates that U.S. crude oil production will continue its relentless decline. Most of the drilling is for natural gas because that is what the drillers can easily find. The solution to the dilemma is beginning to emerge in the ranks of policy makers and that is to use natural gas as transportation fuel. This will require transformation of the coast to coast, north to south highway system so that natural gas refueling stations are conveniently located. To a large extent, Europe and parts of Asia are well along that path. How quickly it develops in the U.S. will depend in part on the willingness of the major oil companies to make the required investments. The nation has the natural gas. It has all of the technology required to convert it to one or another form of transportation fuel. Unhappily much futile debate remains on crude oil policy. Only when the reality of the true situation is accepted, will significant progress begin. Meanwhile get a lock top for your gas tank.  

Implications: Kate Galbraith in Dallas reported in the August 6 issue of the International Herald Tribune that Americans are thinking about using natural gas to power automobiles. T. Boone Pickens, the oilman in Texas is pushing for it. His fear of reliance on foreign oil is behind his belief that natural gas is the solution to the transportation fuel problem. His advertisements on TV and in print are generating discussion. Today such vehicles account for less than one percent of the U.S. Highway fleet. Industrial users of natural gas do not look forward to a new market in natural gas. The problem now is a shortage of fuel pumps. Without them service stations cannot offer compressed natural gas. People buying such cars often use expensive home refueling kits. Natural gas powered vehicles have a range of 250 miles which is half that of those powered by gasoline. If natural gas becomes a major transportation fuel, prices for it could go up.

Analysis:  The use of natural gas as a transportation fuel looks to be an idea whose time has nearly arrived. Even if demand for gasoline slows markedly because of its high price, worldwide usage of all liquid transportation fuels will remain at much higher levels than in years past. The reason is that in Asia, the automotive market is booming. And in the U.S. and Europe, it is not going away. Even Russia is having an auto construction boom. In the U.S., extraction costs of natural gas from marginal reservoirs are relatively low. Figures of $2/million btus are often reported by the several producers. New technology such as multiple reservoir fracturing holds the promise of keeping costs in this range despite higher steel costs. Contrariwise, extraction costs for crude oil continue to climb at the rate of 15%/year. Transportation costs by tanker continue to rise at the same rate. Refining costs are also influenced by inflation. With costs for liquid fuels steadily rising and costs for natural gas remaining about the same, the long term prospects for natural gas are excellent. Converting the entire highway service station system to include natural gas outlets would put pressure on the downstream budgets of the major oil companies but all of them are gas producers from conventional reservoirs and some of them, notably ExxonMobil are rapidly moving into the unconventional side of the business both in the U.S. and in Europe. All of this activity suggests that much strategic thinking about natural gas is taking place throughout the world.

Implications: Senior Editor Steven Poruban reported in the July 28 issue of the Oil & Gas Journal that production of bitumen from Canadian oil sands will rise in the coming decades. But advances in technology will be required to reduce extraction emissions. At a July 15 meeting at the Oil Sands & Heavy oil Technology conference & Exhibition in Calgary, these and other controversial topics were heatedly discussed. Focus was on the potential economic environmental drawbacks of oil sands. Last month the U.S. Conference of Mayors passed a resolution calling for a ban on purchases of fuels for city vehicles that required excessive greenhouse emissions during extraction. Canadian producers are concerned that the resolution could gain political momentum during the coming U.S. presidential election. More than one billion barrels of conventional oil has been produced. This compares to 1.7 trillion barrels of bitumen in place in Canadian oil sands. Oil sand bitumens need emission controls.

Analysis:  The Oil & Gas Journal reported over 100 Canadian oil sand projects authorized or underway in its June 9 survey of international oil and gas projects. New supply will steadily come on each year through 2021. The projects are relatively small. Most are in the 30,000-100, 000 bbl/day range. These projects will hardly affect the overall world decline rate that is currently estimated to be 3.5 million bbl/day/year. Still they are important because they represent security of supply and transportation cannot be threatened by international political crises. That American major oil companies are represented shows that they understand the value of safe supplies. The technology of extraction is evolving constantly. The steam assisted gravity drainage (SAGD) projects are far less polluting than the mining projects. But even the SAGD projects require fuel for boilers. Often petroleum coke, with heavy greenhouse gas emissions, is the cheapest fuel available. Ideally, natural gas as fuel would greatly improve the “political correctness” of the extraction process but it is in short supply. That may change over the next few years as natural gas from the apparently prolific Muskwa shale in northern British Columbia becomes available. In any event, all fuels today are challenged to some degree. Coal is considered to be even worse than bitumen from oil sands. Even light crude oil has some sulphur which must be removed. If fuel for commerce and industry is not cheap and readily available, business slows and people suffer. The trick is to reach a compromise that allows some measure of prosperity even while the atmosphere is kept clean. The primary question facing society is how to accomplish this.