Production Grows – As Do Areas of Concern

Oil and natural gas production continued to grow in the United States in 2013 even as progress on new federal laws and regulations stalled – but local opposition to shale gas and oil development increased.

Canadian shale gas also ballooned – to 2.8 billion cubic feet per day in May 2013 – but still lagged behind its southern neighbor. Canadian shale gas represented only 15 percent of the country’s 2012 production, but jumped to 20 percent in 2013, as per the Canada National Energy Board and U.S. Energy Information Administration (EIA).

Outside North America, a dozen countries conducted exploratory shale gas drilling – but only China reported commercially viable production, according to EIA. China’s shale gas represented only one percent of the country’s total gas production.

U.S. Production Grew

U.S. oil and natural gas production grew substantially in 2013, but low gas prices continued to shift drilling activities away from natural gas. Below are just a few statistics (EIA data) to document these patterns:

  • In 2012 shale gas was 39 percent of U.S. dry gas production, and Marcellus production was 18 percent of U.S. production. By comparison, shale gas was 28 percent of production in 2011.
  • Natural gas marketed production is projected to have increased from 69.2 Bcf/d in 2012 to 70.4 Bcf/d in 2013.
  • The Henry Hub 2013 average price ($3.69 per thousand cubic feet, mcf, est.) was significantly above 2012 ($2.65/mcf), but nowhere close to the 2008 price of almost $8/mcf.
  • The Bakken Shale produced approximately one million barrels per day in December 2013, and increased oil production from the formation contributed to September 2013 domestic oil production being almost 20 percent over September 2012.
  • Oil well completions increased 18 percent while natural gas completions declined 30 percent, and total well completions increased 6 percent (American Petroleum Institute, third quarter 2013 compared to the third quarter 2012).
Federal Regulations

President Obama stated his intent to reduce greenhouse gas emissions, including reducing methane emissions from oil and gas operations, through executive branch actions because of congressional inaction, and many expected a rush of new regulations.

The early focus of this activity has been on coal-fired power plants, and almost no federal hydraulic fracturing regulations were finalized in 2013. The inaction may reflect longer times for the White House review process, plus the difficulty in dealing with the large number of comments received when draft rules and regulations were released.

The most recent White House regulatory agenda includes:

  • The Bureau of Land Management plans to release its new hydraulic fracturing rules in May 2014.
  • EPA’s draft guidance for hydraulic fracturing using diesel is not yet scheduled for release.
  • The U.S. Coast Guard has sent a draft regulatory proposal on barge transport of flow-back fluids from hydraulic fracturing to the Office of Management and Budget (OMB).

Preliminary ideas evidently include requiring barge operators to have certification of no hazardous materials in wastewater shipments – a potentially expensive and time-consuming requirement given that the fluid comes from multiple well sites.

State, Local Bans and Regulations

Local bans on hydraulic fracturing appeared around the country in 2013; the tally is about 400 state and local bans.

State bans or moratoria have been enacted in Maryland, New Jersey, New York and Vermont.

Most of the numerous local bans have not yet taken effect, and many are currently being fought in the courts. A few examples:

  • In Pennsylvania, the state Supreme Court ruled in December that the Marcellus Shale drilling law, Act 13, which allowed companies to drill anywhere in the state without regard to local zoning laws, is unconstitutional.
  • In Colorado, four municipalities have recently banned or suspended hydraulic fracturing. Governor (and past AAPG member) John Hickenlooper has expressed the position that the municipalities lack the authority to determine the use of the state’s natural resources.

Six states have strengthened their regulation of hydraulic fracturing: California, Colorado, Ohio, Pennsylvania, Utah and Wyoming; simultaneously, the governors of energy-producing states have reiterated their opposition to federal regulation of hydraulic fracturing. In late December the governors of 12 energy-producing states sent an open letter to Washington regulators and policy makers asking that regulation be left to the states.

Federal Legislation

Many Senate and House bills have been introduced on both sides of the safety debate, to either strengthen or weaken federal regulation of hydraulic fracturing – but no legislation that would affect hydraulic fracturing has passed either the House or the Senate, let alone both.

Both last year and this year the proposed bills focused on requiring disclosure of chemicals used in hydraulic fracturing fluid, or giving states the authority to regulate hydraulic fracturing on federal lands. 

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Policy Watch

Policy Watch - Edie Allison
Edie Allison began as the Director of the AAPG Geoscience and Energy Office in Washington D.C. in 2012.

Policy Watch

Policy Watch is a monthly column of the EXPLORER written by the director of AAPG's  Geoscience and Energy Office in Washington, D.C. *The first article appeared in February 2006 under the name "Washington Watch" and the column name was changed to "Policy Watch" in January 2013 to broaden the subject matter to a more global view.

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D.C. Bound: Congressional Visits Days Slated for March 10-12

Want to participate in this year’s AAPG Congressional Visits Days (CVD)?

If so, the deadline to register is looming.

This year’s AAPG CVD event will be held March 10-12, but the registration deadline is Feb. 10.

AAPG Congressional Visits Days event annually provides an opportunity for AAPG members to discuss petroleum science and energy issues with decision makers in the legislative and executive branches of the federal government.

It also is an exciting introduction to the world of politics that will provide the tools to use at the local and state levels once you return home. AAPG staff will provide training and briefing materials, and schedule the meetings.

This year’s CVD:

  • Starts with an afternoon briefing on how Congress works; the legislative process; ways to make your visits successful; and issues that are of concern to Washington.
  • On the second day, gives participants the chance to visit the executive branch and congressional committee offices.
  • The third day is devoted to small-group visits to senators’ and representatives’ offices.

To register or get additional information contact Edith Allison, 
GEO-DC’s Energy and Geoscience policy director, at eallison@aapg.org
or (202) 643-6533.

To reserve lodging, contact the 
Army and Navy Club by Feb. 10, at (202) 628-8400; or email toFrontDeskPOS1@armynavyclub.org.

– Edith Allison

See Also: Book

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See Also: Bulletin Article

This study documents that Danian-aged sand remobilization of deep-water slope-channel complexes and intrusion of fluidized sand into hydraulically fractured slope mudstones of the Great Valley sequence, California, generated 400-m (1312 ft)–thick reservoir units: unit 1, parent unit channel complexes for shallower sandstone intrusions; unit 2, a moderate net-to-gross interval (0.19 sand) of sills with staggered, stepped, and multilayer geometries with well-developed lateral sandstone-body connectivity; unit 3, a low net-to-gross interval (0.08 sand) of exclusively high-angle dikes with good vertical connectivity; and unit 4, an interval of extrusive sandstone. Unit 2 was formed during a phase of fluidization that emplaced on an average 0.19 km3 (0.046 mi3) of sand per cubic kilometer of host sediment. Probe permeametry data reveal a positive relationship between sill thickness and permeability. Reservoir quality is reduced by the presence of fragments of host strata, such as the incorporation of large rafts of mudstone, which are formed by in-situ hydraulic fracturing during sand injection. Mudstone clasts and clay- and silt-size particles generated by intrusion-induced abrasion of the host strata reduce sandstone permeability in multilayer sills (70 md) when compared to that in staggered and stepped sills (586 and 1225 md, respectively). Post-injection cementation greatly reduces permeability in high-angle dikes (81 md). This architecturally based reservoir zonation and trends in reservoir characteristics in dikes and sills form a basis for quantitative reservoir modeling and can be used to support conceptual interpretations that infer injectite architecture in situations where sands in low net-to-gross intervals are anticipated to have well-developed lateral and vertical connectivity.
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A three-dimensional seismic data set and published data from exploration wells were used to reconstruct the tectonostratigraphic evolution of the Mandal High area, southern North Sea, Norway. The Mandal High is an elongated southeast-northwest–trending horst. Three fault families in the Lower Permian sequence, inherited from the basement structural grain of Caledonian origin, are interpreted: (1) a north-northwest–south-southeast–striking fault family, (2) a northeast-southwest–striking fault family, and (3) a near east-west–striking fault family. In addition, an east-southeast–west-northwest–striking fault family (4) that formed during Late Jurassic rifting and was reverse reactivated in the Late Cretaceous is interpreted. We suggest that inversion occurred because of small dextral motion along fault family 1. A final fault family (5) displays various strike orientations and is associated with salt movements.

Seven chronostratigraphic sequences defined by well data and recognized on three-dimensional seismic data are interpreted and mapped: Early Permian rifting in a continental environment; Late Permian deposition of the Zechstein salt and flooding; Triassic continental rifting; uplift and erosion in the Middle Jurassic with deposition of shallow-marine and deltaic sediments; rifting and transgression in a deep-marine environment during the Late Jurassic; a post-rift phase in a marine environment during the Early Cretaceous; and flooding and deposition of the Chalk Group in the Late Cretaceous. An eighth sequence was interpreted—Paleogene–Neogene—but has not been studied in detail. This sequence is dominated by progradation from the east and basin subsidence. Well and seismic data over the Mandal High reveal that large parts of the high were subaerially exposed from Late Permian to Late Jurassic or Early Cretaceous, providing a local source of sediments for adjacent basins.

Similar to the Utsira High, where several large hydrocarbon discoveries have been recently seen, the Mandal High might consist of a set of petroleum plays, including fractured crystalline basement and shallow-marine systems along the flanks of the high, thereby opening up future exploration opportunities.

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See Also: Environmental Geosciences Article

Shales are becoming the most important source of natural gas in North America, and replacement of coal by natural gas is reducing CO2 emissions and improving air quality. Nevertheless, shale gas is facing strong opposition from environmental nongovernmental organizations. Although these organizations have greatly exaggerated the potential negative environmental impacts of shale gas and shale oil, methane leakage and contamination of groundwater and surface water by flowback and produced waters are serious concerns. These contamination pathways are not unique to shale gas and shale oil, and they are manageable.
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See Also: Online e Symposium

The presentation describes a well established fracture modeling workflow that uses a standard 3D seismic, conventional logs, image logs and data from one core to build predictive 3D fracture models that are validated with blind wells.

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