Renewed Interest in U.S. Heavy Oil Resources

Kern Field – The Kern oil field located near Bakersfield California is one of the world’s legendary petroleum discoveries. California became the top oil producer in the United States in 1903 soon after its discovery. In total, 18 giant fields were found with the Midway-Sunset proving to be the largest field discovered in the lower 48 states. Approximately 13 billion barrels of heavy oil (heavy oil is a type of crude oil which is very viscous and does not flow easily) have been recovered from the Kern field. The Kern Field along with others surrounding Bakersfield have been under steam flood for over 50 years. Thermal recovery of heavy oil continues to drive production from Kern and will well into the future.

California – Heavy oil currently represents about half of California’s crude oil production. ChevronTexaco’s chairman and chief executive officer David O’Reilly said last year that he expects continual development and improvements in steam flooding will keep the heavy crude flowing in California well into the new century. He said production is greater than 80,000 bopd and expects to recover up to 80% of the oil from the Kern River field. Another key player in California heavy oil is Berry Petroleum Company. They own and operate working interests in 38 properties in the Midway-Sunset field. According to Berry President and chief executive officer Robert Heinemann, they are developing and testing new concepts to place heat into the remaining oil column to maximize recovery and value. Berry has invested about $91 million on California heavy oil in 2007. In 2008, it plans to invest $173 million to drill over 160 shallow heavy oil wells and construct steam generators and other infrastructure. Approximately 600 wells are planned to be drilled over a 5-year period. Heinemann says the driving force behind development is the current record-high crude oil prices.

Alaska – In Alaska, heavy oil is just beginning to take off. The U.S. Department of Energy puts the heavy oil resource at around 36 billion barrels in the Ugnu, West Sak and Schrader bluff formations on the North Slope. Current production of about 80,000 bopd comes from five fields. Arco Alaska, which has since been integrated into ConocoPhillips, was the pioneer in attempting to develop the North Slope’s heavy oil resource.

Texas – Smaller oil companies are also looking to develop left-behind heavy oil resources in the United States. Calgary-based Pearl Exploration has projects underway in Texas, Montana and Utah. In Texas, Pearl is targeting the San Miguel sandstone heavy oil deposit in the Maverick basin of South Texas, thought to contain two to three billion barrels of heavy oil. Pearl is testing an enhanced oil recovery technology for heavy crude called Steam Assisted Gravity Drainage (SAGD) in the San Miguel. Two parallel horizontal oil wells are drilled in the formation. The upper well injects steam and the lower one collects the water that results from the condensation of the injected steam and the crude oil.

Commentary – Many producers believe that heavy oil will have a much greater role in the world energy market. They are positioning themselves to take advantage of this by trying new technology in areas with left-behind heavy oil resources. Berry Petroleum is making a huge investment in a very mature field and I believe that they will be successful. When I was employed by Mobil Oil in Midland Texas, I reported to Bob Heinemann who at the time was the Manager of the Technical Group. He is now the President and CEO of Berry Petroleum. His technical skills were highly regarded in the oil and gas industry and his expertise was in the area of Enhanced Oil Recovery.

U.S. Refinery Investments for Oil Sands

Canadian oil sand production will increase by 2 million b/d by 2015, with half of this growth being heavy oil blends. A recent study shows that export pipeline capacity and U.S. refinery capacity will be able to handle the run-up in supplies of Canadian oil. Planned export pipeline expansion of 2.1 million b/d should keep pace with the additional supplies. The expected new pipelines should start up in 2008 and 2009. Refinery projects targeting Canadian heavy oil blends will add 1.1 million b/d if processing capacity. Disclosed projects reveal that pipeline companies and U.S. refiners plan to invest more than $31 billion by 2015 to export and distribute oil sands products as well as process them in the US refining system. In Canada, oil producers have announced production projects that will supply growing volumes of bitumen and Synthetic Crude Oil (SCO). Resulting Canadian heavy blends and SCO supply will grow to 3.7 million b/d in 2015 from 1.7 million b/d in 2007. Most of the Canadian crude is exported to US markets through four major truck-line systems. Enbridge-Lakehead system is the main route for Western Canadian crude exports to the U.S. These four trunk-lines transported about 1.7 million b/d of Canadian crude to the US in 2007. Enbridge is investing the most in pipeline infrastructure, more than $8.5 billion. Refiners that lead the investment in refinery expansions and upgrading to run Canadian heavy blends are BP PLC, ConocoPhillips (by means of its joint venture with Encana) and Marathon Petroleum. These three companies and their partners are planning to invest $13 billion to add about 850,000 b/d processing capacity by 2015. Other refiners will invest $1.7 billion for another 205,000 b/d of capacity.

Commentary – We hear in the news media that no new refineries are being built in the U.S. However, our existing refineries are being expanded and upgraded as needed to process new supplies of crude oil. Although, some sources are indicating that the investment climate is changing. Reductions in refinery margins along with higher project costs and the availability of raw materials and labor could lead to either a delay or cancellation of some of these proposed projects. Regardless, it appears that imports from Canada will continue and perhaps increase primarily due to the “proportionality sharing clause” in the North American Free Trade Agreement (NAFTA) that requires Canada to continue exporting the same proportion of its total supply (production plus imports) that it had exported over the three previous years.

Canadian Oil Sands and U.S. Imports

Description – The Athabasca Oil Sands (also known as the Athabasca Tar Sands) are large deposits of bitumen or extremely heavy crude oil, located in Northeastern Alberta Canada. Bitumen is a sticky, tar-like form of petroleum which is so thick and heavy that it must be heated before it will flow. The Athabasca sands deposit is the largest reservoir of crude bitumen in the world and the largest of the three major oil sands deposits in Alberta along with the nearby Peace River and Cold Lake deposits. The Athabasca deposit is the only large oil sand reservoir in the world suitable for large-scale strip mining although most of it can only be produced using “in-situ” methods. In-situ means “in-place” and refers to recovery techniques which apply heat to bitumen reservoirs beneath the earth.

Development – The world’s first oil sands mine was started by Great Canadian Oil Sands Limited (a predecessor company of Suncor Energy) in 1967. The Syncrude mine (the biggest mine in the world) followed in 1978, and the Albian Sands mine (operated by Shell Canada) in 2003. All three of these mines are associated with bitumen upgraders that convert the unusable bitumen into synthetic crude oil for shipment to refineries in Canada and the United States. Suncor Energy Inc. is the world’s second largest producer of oil sands after Syncrude Canada Ltd.

Potential – Alberta contains the second largest proven concentration of oil in the world, the vast majority of which is found in oil sands deposits. There are 173 billion barrels of oil in the oil sands proven to be recoverable based on a 10% recovery of the bitumen in-place with current technology and today’s oil prices. The Alberta government estimated that the Athabasca oil sands alone contain 35 billion barrels of surface mineable bitumen and 98 billion barrels recoverable by the “in-situ” methods. Alberta’s estimate assumes 20% recovery of the bitumen-in-place. Only 3% of the initial established reserves have been produced since commercial production started in 1967. Oil sands production rates are projected to be 3 million barrels per day by the year 2015..

Commentary -  Approximately 19% of U.S. oil imports are from Canada, about 2.3 million bpd. Canada has become the largest foreign supplier of oil and natural gas to the United States. The strong growth in oil sands production during the past few years has been an important contributor to global supply. This has provided the U.S. a secure source of supply from Canada. Bitumen production from Alberta’s oil sands is projected to increase to 3.1 million bpd by 2015 from 1.2 million bpd in 2007. There is some controversy on the development of the oil sands. Some Canadians are pushing for a moratorium on the expansion of the Alberta Tar Sands due to environmental reasons. Alberta’s Parkland Institute and the Polaris Institute have a released a report that supports the moratorium and claims that the oil sands are the centerpiece of an energy corridor for exports to the U.S. which is increasingly geared to fuel America’s military machine. They might get more converts if they stick to the environmental issues and energy security for their country, instead of fueling anti-American sentiment.

Are Gasoline Prices Going Higher?

A Primer on Gasoline Prices – Gasoline is one of the major fuels consumed in the United States and the main product refined from crude oil. Consumption in 2007 was about 142 billion gallons, an average about 390 million gallons per day and the equivalent of about 61% of all the energy used for transportation, 44% of all petroleum consumption, and 17% of total U.S. energy consumption. About 47 barrels of gasoline are produced in U.S. refineries from every 100 barrels of oil refined to make numerous petroleum products. While gasoline is produced year-round, extra volumes are made and imported to meet higher demand in the summer. Gasoline is delivered from oil refineries mainly through pipelines to an extensive distribution chain serving about 167,500 retail gasoline stations in the United States. (Source: National Petroleum News, 2007 Industry Scorecard)

Breakdown of Gasoline Cost – The EIA says gasoline retailers and wholesalers account for about 8% of the total cost of gasoline. Refiners get another 8% and taxes eat up 12%. The remaining 72% is crude oil. Based on a price of $4.00 per gallon the breakdown is as follows: Crude oil – $2.88, Taxes – 48 cents, Refining – 32 cents and Distribution/Marketing – 32 cents.

Price Increases with Crude Oil Price – From January 2003 to June 2008, oil prices have increased 306% while gasoline prices have risen 177% (Based on data from the Energy Information Administration). For the most part, the price increases for both crude oil and gasoline tracked reasonably well. But since September 2007, they have been deviating with crude oil price increases accelerating faster than gasoline prices.

Commentary – Gasoline and the refining business is not my expertise, but the issue is on everyone’s mind. One explanation for the deviation in price increases is lower refining margins and/or lower margins at the retail level. It was recently announced by Exxon that they are getting out of the U.S. retail gasoline business. You’ll still see the Exxon-Mobil signs and logo, but they will sell 2,200 or so gas stations they still own. In June of this year the Cambridge Energy Research Associates (CERA) reported that U.S. gasoline demand likely peaked in 2007 due to the U.S. economic slowdown and changes in consumer behavior. This reduced demand in the U.S. could be impacting gasoline prices. If the relationship between gasoline prices and crude oil price holds that we are either going to see crude prices decline which doesn’t appear to be very likely or gasoline prices are going higher.

Potential of the Outer Continental Shelf (OCS)

Primer on the OCS – The Outer Continental Shelf Potential (OCS) consists of the submerged lands, subsoil and seabed, lying between the seaward extent of the State’s jurisdiction and the seaward extent of Federal jurisdiction. The Continental Shelf is the gently sloping undersea plain between a continent and the deep ocean. The U.S. OCS has been divided into four leasing regions. They are: Gulf of Mexico OCS region, Atlantic OCS Region, Pacific OCS Region and the Alaska OCS region. The Department of Interior’s Minerals Management Services (MMS) oversees our offshore energy program which accounts for about 27% of America’s domestic oil production and about 15% of our domestic natural gas production.

Potential of the OCS – The Minerals Management Services (MMS) made a new assessment of the potential of the OCS in 2006. This assessment provides estimates of the undiscovered technically and economically recoverable oil and natural gas located outside of known oil and gas fields on the OCS. It considers recent geophysical, geological, technological and economic information and utilizes a probabilistic oil or gas play-based approach to estimating the undiscovered resources of oil and gas for individual plays. Due to the inherent uncertainties associated with an assessment of undiscovered resources, probabilistic techniques were used and results reported as a range of values corresponding to different probabilities. The estimates from the 2006 assessment for the total U.S. OCS can be summarized as a range with a minimum, most likely and maximum. For oil, the range is from 67 billion barrels to 115 billion with a most likely estimate of 86 billion barrels. For natural gas, the range is from 326 trillion cubic feet to 565 trillion with a most likely estimate of 420 trillion cubic feet.

A general comparison of the 2001 and 2006 assessments made by the MMS indicates that at the mean level the 2006 estimates for the entire OCS area represent an increase of 11 billion barrels of oil and 58 trillion cubic feet of natural gas or about 15% for oil and gas. The vast majority of this increase occurred in the Gulf of Mexico. Significant increases for the deepwater areas were the major contributor to the overall growth in the estimates for oil. The majority of the increase in natural gas was related to deep gas plays located beneath the shallow water shelf of the Gulf of Mexico.

Commentary – The estimates made are termed undiscovered technically recoverable resources. At the current high prices for oil and natural gas, these estimates could also be economically recoverable. The minimum estimate for oil is more than three times the current U.S. proved oil reserves and the minimum natural gas estimate is one and one-half times the current proved natural gas reserves in the U.S. Finally, the MMS should secure funds to do an updated study and conduct new seismic surveys using the latest 3-Dimensional seismic surveying technology. According to the Senate’s Energy and Natural Resources Committee Chairman Jeff Bingham (D-New Mexico), the 2006 assessment did not use the latest technology available i.e. 3D seismic Mapping. Neither the Administration nor Congress tried to get another seismic survey done with the modern more accurate technology.

Imports: What countries do we import from and how much?

Crude Oil Imports Top 15 Countries – Preliminary monthly data on the origins of crude oil imports in May 2008 has been released by the Energy Information Administration (EIA). The report shows that two countries exported more than 1.5 million barrels per day to the United States. The top five exporting countries accounted for 66 % of United States crude oil imports in May while the top ten sources accounted for approximately 88 % of all U.S. crude oil imports. The top five sources of US crude oil imports for May were Canada (1.8 million barrels per day), Saudi Arabia (1.6 million barrels per day), Mexico (1.1), Venezuela (1.0) and Nigeria (0.9). Total crude oil imports averaged 9.7 million barrels per day in May, which is a decrease of 0.3 million barrels per day from April 2008.

Commentary – It is a common misconception that the United States imports most of its foreign oil from the Middle East. It is not even close. Our dependence on oil from the Persian Gulf represents barely 10 percent of total domestic oil consumption, and most of that oil comes from Saudi Arabia and Iraq. This picture could change if Mexico’s crude oil production continues to decline.

Chevron’s Deepwater Jack Field Discovery Update

On September 5, 2006, the media reported an oil discovery (the Jack 2 well) by Chevron, Statoil and Devon Energy in the Deepwater area of the Gulf of Mexico. It was reported to be the largest oil discovery since the Alaskan oil fields and that it could boost U.S. oil reserves by 50%. The discovery was 175 miles off the Louisiana coast and its potential was estimated to be in the range of 3-15 billion barrels of oil. The oil was discovered at 28,000 ft or approximately 4 miles beneath the ocean floor. The well flow tested at a sustained rate of 6,000 bopd. The article also said that it would take 4-5 years to fully develop the field.

Update – According to Chevron’s 2007 Annual Report, the Jack 2 well discovery was actually in 2004 at the Walker Ridge Blk 758. Chevron has a 50% working interest in the well and is the operator. The Annual Report also said a second well for appraisal was planned for 2008. According to Devon Energy’s 2007 Annual Report, Devon has a 25 % working interest in the Jack Field and the target has been the Lower Tertiary oil sands. The report said that the discovery well encountered 350 ft of net oil sand and that a 2nd appraisal well was initiated in 2007 and currently drilling. Devon indicated that if the Jack Field is sanctioned in 2009, first production could occur as early as 2013.

Commentary – I am cautiously optimistic about the potential reported. The numbers are highly speculative. However, the U.S. Oil reserves according to EIA are about 29 billion barrels of oil equivalent and if this field’s potential is proven it could boost U.S. oil reserves significantly.

Arctic National Wildlife Refuge (ANWR)

Background – ANWR lies in the top NE corner of Alaska and comprises about 20 million acres. There is a special area in ANWR of 1.5 million acres on the Arctic Coastal Plain called the “10-02″ area. This area was set aside by Congress specifically for oil and gas exploration. The 10-02 area is classified legally as neither “refuge” nor “wilderness”. There is geological evidence of potential large hydrocarbon deposits in this area. It is completely flat and barren with no trees, hills or mountains. Nine months of the year it is covered with snow and ice. Congress has limited any future development of the “10-02″ to only 2,000 acres. This is 1/2 to 1% of the total area of ANWR. The “10-02″ area cannot be explored without Congressional approval. Proponents of opening up the area to oil and gas exploration want the entire 1.5 million acres open.

Potential – The most recent petroleum assessment of the “10-02″ area was completed in 1998 by the U.S. Geological Survey (USGS). Based on this study, the total quantity of technically recoverable resources was estimated to be between 5.7 and 16 billion barrels of oil with a most likely estimate of 10.4 billion barrels. Commercial viability of a discovery depends on oil price, size of the fields discovered, technology and how close to existing pipelines. For comparison purposes, Alaska’s Prudhoe Bay Oil Field which is the largest oil field in North America has an estimated 25 billion barrels of oil but, only 13 billion is expected to be recovered.

Production – There is considerable uncertainty regarding future ANWR oil production. A March 2008 Study by the Energy Information Agency (EIA) projected a peak oil rate of approximately 900,000 Bopd using the most likely resource number above. If the moratorium on drilling was lifted in 2008, the EIA projected oil production to start up in 10 years. Production from ANWR is actually limited to the excess capacity of the Trans-Alaska Pipeline System (TAPS). This pipeline has a throughput capacity of 2.1 million bopd and the current flow in the line from the Alaskan North Slope is around 0.7 million leaving an excess capacity of 1.4 million for ANWR and other sources.

Commentary – In my opinion as an engineer, both the estimates of recoverable oil and predictions of production schedules have a high degree of uncertainty. The only way to get a true assessment of the potential of the ANWR “10-02″ area is to lease it to the oil companies and allow them to drill with no pre-conditions. Some 75% of the Alaskans support the opening up of ANWR to drilling. This area is not going to make the U.S. energy independent, but it can help the U.S.reduce its dependency on foreign imported oil. Because the Alaska North Slope production is in decline, ANWR production could extend the economic life of TAPS.

Brazil – The Real Story About Energy Independence

Brazil’s Ethanol Program – Brazil’s ethanol program started in 1975, when soaring oil prices put a chokehold on the economy. In response, the country’s military rulers launched an effort to free themselves from foreign oil – which then accounted for almost 90% of oil consumption – by developing innovative fuels. Ethanol made from sugar cane was the obvious candidate, given Brazil’s favorable climate and endless amount of arable land. Years of work and billions of dollars in subsidies later, Brazil is the world leader in ethanol production. Brazil produces 4.8 bil. gals. of ethanol per year.  Some reports indicate that they have replaced has much as 40 % of the gasoline use in the country.

Brazil’s Exploration and Production Plan – After the 1980’s ethanol shortages in Brazil, the country began to recognize that ethanol production alone would not lead to energy independence and started promoting policies to boost domestic oil production. Petrobras, the state-owned oil company maintained a monopoly on oil activities until 1997 when the government opened up the oil industry to competition. The majority of brazil’s oil reserves are located in the Campos and Santos Basins, which are offshore areas near the southeast coast. The Brazilian government resolutely supports its goal of making Brazil a net exporter of oil in years to come. According to the Oil and “Gas Journal, Brazil had 11.7 billion barrels of proven oil reserves in 2007. In 2006 Brazil produced 2.2 million bbls per day of which 77% was crude oil or 1.7 mil. bopd. This compares to 750,000 bopd back in 1986. According to Reuters UK, in the first six months of 2008 Brazil’s oil and natural gas output averaged 1.84 million bbls per day of oil equivalent (oil and natural gas). Average output may have fallen recently due to a five-day strike by oil workers in the Campos Basin which accounts for 80 percent of the total Brazil oil output.

Commentary – Headline news in recent weeks has been that Brazil has achieved energy independence, or at least come very close to achieving it. This milestone has been attributed to Brazil’s increased use of ethanol in particular the increased use of E85. Statistics from the Brazilian government tell a different story. Brazil has achieved energy independence, for the most part, through increased domestic crude oil production, not through its domestic ethanol program. Brazil is set to significantly expand its crude oil production over the next five years. Its national production goal is 2.3 million bpd by 2010. To achieve this, 15 major oil production projects are planned to be implemented in 2008. In the U.S. we have politicians and some governors saying that we don’t need to drill and boost our own domestic production because we can develop a biofuels program like Brazil and achieve energy independence. Last week on CNBC, Joe Kernen was interviewing the Governor of Pennsylvania Edward Rendell and he was asked if he supported lifting the ban on offshore drilling in the Outer Continental Shelf (OCS). The governor said that it is too far down the road and wouldn’t have any major impact on oil prices. He also said that it wouldn’t produce enough and that we need to develop new energy sources that are environmentally friendly. He also said that in less than three decades, Brazil has achieved energy independence from its ethanol program and that we should model ourselves after them and do the same. The facts about Brazil are often misrepresented and some of our leaders ignore the most significant reason for Brazil’s energy independence, that being governmental policies favorable to boosting domestic oil production.

Strategic Petroleum Reserve (SPR) – Is $4.00 a gallon an emergency?

Background – The Strategic Petroleum Reserve (SPR) is an emergency petroleum storage field maintained by the Department of Energy. The crude oil reserves are stored at four sites on the coastline of the Gulf of Mexico. Each site contains a number of artificial caverns created in salt domes below the surface. According to the U.S. Department of Energy (DOE) the inventory in storage as of 7/11/08, is 706 million barrels. The maximum capacity of the storage field is 727 mil. barrels. The maximum total withdrawal capability from the SPR is 4.4 million bbls per day.There have been two emergency drawdowns of the inventory. In early 1991, 34 mil. bbls was authorized to be withdrawn during the Iraq invasion of Kuwait. Actually only 17 mil. bbls were withdrawn. The 2nd drawdown was during Hurricane Katrina when oil production facilities, terminals, pipelines and refineries were damaged along the Gulf regions of Mississippi and Louisiana in August 2005. A sale of 30 mil bbls was authorized and five companies submitted offers for 11 mil. bbls. In 2005, Congress directed SPR to take actions to expand its authorized size to 1.0 Billion barrels of oil capacity. In June 2007, DOE issued a plan to expand SPR to 1.0 Bil. bbls with a maximum withdrawal rate of 5.9 mil. bopd. No information is available as to what progress they have made. President Bush wants the SPR expanded to 1.5 Bil. bbls.

Commentary – The DOE claims on their website that they have 58 days of import protection. The fact is that we cannot protect the nation from loss of all our imports. We are currently importing approximately 11 Mil. Bopd. Since the maximum withdrawal rate from SPR is 4.4 Mil. bopd, we are going to be short 6.6 Mil. bopd.  We can protect 4.4 Mil. bopd of imports for a period of 160 days based on the current inventory of the SPR. Hopefully, if there was a war or emergency not all of our imports would be cutoff. It appears to me that the SPR needs to be safeguarded for emergencies and expanded as planned and quickly. However, we have politicians like the Speaker of the House Nancy Pelosi recently urging President Bush to authorize withdrawals from the SPR to help with relief of gasoline prices. Hopefully, common sense will prevail.