Fall 2013 finds the Permian Basin acknowledging yet more peaks and possibilities.
Two locations in New Mexico, including Otero Mesa, 12 million acres of wild grasslands in southern New Mexico primarily controlled by the Bureau of Land Management, are included on a list of 12 places in the U.S. deemed “too wild to drill” by the Wilderness Society. Also in the new report is Chaco Canyon in northwestern New Mexico.
“Energy sources like oil and gas are needed to keep cars on the road and electricity flowing to our homes,” Jennifer Dickson of the Wilderness Society said, “but there also must be a balance between extracting these resources and protecting places in America that are simply too unique and special to be opened to oil and gas drilling.”
Centurion Pipeline, a subsidiary of Occidental Petroleum, said Aug. 6 it is proceeding with construction of the previously announced Cline Shale pipeline system to transport crude oil from Irion, Sterling, Coke, Tom Green, and Mitchell counties to its existing Colorado City station in Scurry County.
The system is supported by long-term commitments received during Centurion’s recent successful open season. Originating near Barnhart, the pipeline will be capable of transporting about 75,000 barrels per day of crude oil to Centurion’s Colorado City station and to the proposed BridgeTex pipeline, which is expected to provide access to the Texas Gulf Coast by July 2014. The 100-mile Cline Shale pipeline will include several origination stations designed to receive crude oil via truck and pipeline. The system is expected to be completed in 2014 second quarter.
Texas Railroad Commissioner Christi Craddick urged the federal Bureau of Land Management to exempt Texas and other states that are already effectively regulating hydraulic fracturing from the bureau’s proposed rules for federal and Indian lands.
“States are much more effective in encouraging oil and gas exploration, development and production, while still protecting the environment and human health,” Craddick said Aug. 22. “It is clear that federal law and regulations detract operators from investments on federal lands, driving them towards production on non-federal land that is governed by greater regulatory certainty.”
A report in March 2013 by the Congressional Research Service shows that, since 2007, production of natural gas on federal lands fell by 33 percent while production on state and private lands grew by 40 percent.
“The minimal amount of federal land [1.8 percent] in Texas provides further cause to the impractical nature of the proposed rule for Texas,” Craddick said. Craddick said BLM has failed to note any state with insufficient hydraulic fracturing regulations in place.
Mining sand for the oil and gas industry has become an economic boom in McCulloch County. The Abilene Reporter-News said supplying proppants for hydraulic fracturing of oil and gas wells supports hundreds of jobs in McCulloch and brings thousands of rail cars through San Angelo each year.
“Sixty percent of what we move on the railroad today is frac sand,” Elizabeth Grindstaff of Texas-Pacifico Transportation (the railroad that runs through San Angelo) said. “We will move about 30,000 rail cars this year. We’ve tripled the volume for two years in a row.” McCulloch is enjoying the growth from the proppant industry thanks to the sand produced from the Hickory sandstone formation. Texas, Illinois, and Wisconsin are the top three producers of frack sand in the U.S., according to 2011 figures from USGS.
Howard Hamm, CEO of Oklahoma City-based Continental Resources, says horizontal drilling—more so than hydraulic fracturing—is responsible for the current American energy renaissance.
“America has a long history of achieving the impossible,” Hamm told Matt DiLallo of The Motley Fool. “We defeated the British. We landed on the moon. We invented the Internet. And now we can add horizontal drilling to the list of American innovations that have changed the world forever… Some may say this new abundance in oil and gas is due to hydraulic fracturing. However, fracking technology has been consistently in use for more than 60 years. What is new is horizontal drilling.”
Hamm said in 2000 there were fewer than 50 horizontal drilling rigs in the U.S., but there now are more than 1,200, “which is why we’ve gone from talking about peak oil to now pondering American energy independence within a decade.”
Scott Sheffield, CEO of Irving-based Pioneer Natural Resources, said horizontal drilling is revitalizing legacy oil and gas fields in the Permian Basin. Talking about a well that recently was drilled horizontally, he said, “What’s interesting, in six months, it’s reached 140,000 barrels of oil equivalent… Our typical vertical well takes 30 to 35 years to produce 140,000. So we did that in six months.”
Allen Howard, president and CEO of NuTech Energy Alliance, told the Oil and Gas Financial Journal that the Permian Basin is “the most exciting play on the horizon.” The liquids-rich area, comprised of the Midland Basin, the Delaware Basin, and the Marfa Basin, has experienced a revival of activity from unconventional resources, new technology, and increasing oil prices.
“From my personal perspective from the tremendous amount of work we have analyzed,” Howard said, “there are about three or four plays in the Permian Basin that are not quite there technically. When the strategies are properly understood and implemented, you will see some of the best reserves per well in the world.”
Pioneer Natural Resources CEO Scott Sheffield said the Spraberry Wolfcamp in the Permian Basin could possibly become the largest oil and gas discovery in the world. “We believe this field will reach 100 billion BOE recoverable reserves,” he told the Oil and Gas Journal Aug. 12 during a conference in Denver on unconventional resources technology.
Sheffield said Pioneer will test 13 zones over the next three years. Pioneer is the largest acreage holder in Spraberry, with 900,000 acres (730,000 net acres)—the majority of which could be prospective for the horizontal Wolfcamp Shale. Based on Pioneer’s extensive geologic database, petrophysical analysis, and successful drilling results to date, there is significant horizontal Wolfcamp Shale resource potential in this acreage.
President Enrique Pena Nieto of Mexico recently proposed opening his country’s historically closed energy industry to foreign investment. His plan would rewrite two constitutional amendments and invite private companies to partner with national oil company Petroleos Mexicanos (Pemex) in sharing profits from exploration. Foreign companies would receive a share of revenues from oil and gas fields rather than the hydrocarbon volumes themselves to sell. The New York Times said the sweeping reforms have “the potential not only to return the country to its early 1980s heyday of energetic oil drilling, when it was one of the world’s most promising producers, but also to reduce further the United States’ dependence on OPEC producers.”
The Wall Street Journal said it potentially opens some of the world’s biggest remaining untapped oil reserves to private companies and sets the stage for “a new energy boom on the U.S. doorstep.” The Journal said in 1938 Mexico became the first big oil producer to nationalize its oil industry.
“If Mexico passes this bill, and we have peace in the streets, then the country will make an important leap forward,” prominent Mexican historian Enrique Krause told the Journal.
Kurt Glaubitz of Chevron told the New York Times, “This is a good start. We’re optimistic about the reforms that are taking place and the opportunities that Mexico is presenting to international oil companies.”
Mexico ranks ninth among the world’s leading oil producers and third among sources of foreign oil to the U.S. and has the world’s fourth biggest reserves of shale gas. But production has plunged in recent years, and it has been forced to import increasing amounts of gasoline and natural gas from U.S. refineries. In his announcement Aug. 12, Pena Nieto said Pemex has drilled only three shale gas wells. The Times said Pemex does not have the capital or expertise to extensively explore deep-water prospects in the Gulf of Mexico or technically challenging shale fields requiring modern techniques. Additional production from Mexico could provide an additional cushion to ease oil price spikes during periods of instability in the Middle East and North Africa.
The Oil and Gas Journal said Mexico’s two leading political parties “apparently have enough votes to make the necessary constitutional changes in the 35 state legislatures which must ratify any such move, as well as the national congress when it reconvenes in September.”
FROM THE RAILROAD COMMISSION OF TEXAS
[issued 28 August 2013]
The Texas average rig count as of Aug. 16, 2013, was 837, representing about 49 percent of all active land rigs in the U.S. In the last 12 months, total Texas reported production was 583 million barrels of oil and 7.4 trillion cubic feet of natural gas. The commission’s estimated final production for June 2013 is 61,223,793 barrels of crude oil and 550,781,218 Mcf (thousand cubic feet) of gas well gas.
The commission derives final production numbers by multiplying the preliminary June 2013 production totals of 50,340,234 barrels of crude oil and 448,921,035 Mcf of gas well gas by a production adjustment factor of 1.2162 for crude oil and 1.2269 for gas well gas. (These production totals do not include casinghead gas or condensate.)
Texas natural gas storage reported to the RRC for July 2013 was 386,691,560 Mcf compared to 387,606,074 Mcf in July 2012. The August 2013 gas storage estimate is 384,693,645 Mcf.
The RRC Oil and Gas Division set initial September 2013 natural gas production allowables for prorated fields in the state to meet market demand of 8,071,578 Mcf (thousand cubic feet). In setting the initial September 2013 allowables, the commission used historical production figures from previous months and producers’ demand forecasts for the coming month, then adjusted the figures based on well capability. These initial allowables will be adjusted after actual production for September 2013 is reported.
FROM THE U.S. ENERGY INFORMATION ADMINISTRATION
[issued 06 August 2013]
Crude oil prices increased during the first three weeks of July 2013 as world oil markets tightened during seasonal increases in world consumption, unexpected supply disruptions, and heightened uncertainty over the security of supply with renewed unrest in Egypt. The U.S. Energy Information Administration (EIA) expects that the Brent crude oil spot price, which averaged $108 per barrel over the first half of 2013, will average $104 per barrel over the second half of 2013, and $100 per barrel
The discount of West Texas Intermediate (WTI) crude oil to Brent crude oil, which averaged $18 per barrel in 2012 and increased to a monthly average of $21 per barrel in February 2013, closed below $1.50 per barrel July 19, 2013, and averaged $3 per barrel for the month. The strong demand for light, sweet crude oil in the Midwest and new pipeline capacity to deliver production from the West Texas Permian Basin directly to the Gulf Coast contributed to the price of WTI rising relative to Brent crude oil.
EIA expects the WTI discount to widen to $6 per barrel by the end of 2013 as crude oil production in Alberta, Canada, recovers following the heavy June flooding and as midcontinent production continues to grow.
Rising crude oil prices and seasonal demand increases contributed to U.S. regular gasoline retail prices increasing from an average of $3.50 per gallon July 1, 2013, to $3.63 per gallon Aug. 5, 2013. EIA expects the regular gasoline retail price to average $3.59 per gallon in the third quarter of 2013, and the annual average price to decline from an average of $3.63 per gallon in 2012 to $3.52 per gallon in 2013 and to $3.37 per gallon in 2014.
U.S. crude oil production increased to an average of 7.5 million barrels per day (bbl/d) in July 2013, the highest monthly level of production since 1991. EIA forecasts U.S. total crude oil production will average 7.4 million bbl/d in 2013 and 8.2 million bbl/d in 2014, both about 0.1 million bbl/d higher than forecast last month.
Natural gas working inventories ended July 2013 at an estimated 2.88 trillion cubic feet (Tcf), about 0.37 Tcf below the level at the same time a year ago and 0.04 Tcf below the five-year average (2008-12). EIA expects the Henry Hub natural gas spot price, which averaged $2.75 per million British thermal units (MMBtu) in 2012, will average $3.71 per MMBtu in 2013 and $3.95 per MMBtu in 2014.
—compiled by Garner Roberts