OGJ Newsletter

March 1, 2010

General InterestQuick Takes

NARUC cites need to retain access to OTC markets

Financial reform legislation should ensure natural gas and electric power utilities have continued access to over-the-counter risk-management products to keep prices more predictable and less volatile, the National Association of Regulatory Utility Commission (NARUC) said during its 2010 winter meeting.

Proposed federal legislation would give the US Commodity Futures Trading Commission oversight of all OTC products, including mandatory centralized clearing and exchange trading for all OTC products, according to the resolution. This would increase hedging costs and, ultimately, consumer prices because margin requirements would be increased, it warned.

Any new legislation addressing OTC risk management products should exempt legitimate gas and electric hedging activity from mandatory clearing requirements, it recommended. The exemption should be narrowly tailored to prevent excessive speculation in gas and electricity markets, the resolution continued.

Independent oil and gas producers have also said that higher margin requirements required by regulated exchanges would severely restrict their ability to manage cash flow and obtain financing. The resolution which NARUC directors approved during the Feb. 14-17 meeting noted that a report by the Joint Association of End-Users found that such requirements would make less money available for utility infrastructure and for exploration and production.

"The laudable goals of reform that ensure market transparency and adequate regulatory oversight can be accomplished by means other than mandatory clearing of OTC risk management contracts and the anticipated extra expense," it continued. Requiring gas and electric market participants using legitimate OTC hedges to report them to the CFTC would make markets sufficiently transparent without additional costs associated with mandatory clearing, for example, NARUC's resolution said.

MMS will increase staff as part of audit strategy

The US Minerals Management Service will add 19 new auditors and continue to target leaseholders that have been identified as high-risk, MMS Director S. Elizabeth Birnbaum said as the US Department of the Interior agency announced its auditing plan for 2010 on Feb. 17.

"MMS auditors will also be taking a closer look at smaller energy producers that may not have been audited as frequently in the past," she said. Audits and other compliance activities which the agency performs can range from limited scope reviews that examine one or more specific areas to full-scale audits that review all aspects of a company's reports and payments over several years, she noted.

The agency, which manages federal land on the US Outer Continental Shelf and is responsible for oil and gas leasing there, collects royalties from mineral and energy producers with onshore leases on federal and American Indian lands as well as operations offshore on the OCS.

MMS said it receives monthly royalty payments from 2,000 companies and individuals covering nearly 30,000 producing leases. It uses specific criteria to identify leaseholders and properties which are more likely not to be in compliance. Properties may range from a single lease to a unit including numerous leases, the agency said.

During fiscal 2008 and 2009, MMS audited or reviewed more than 900 companies and more than 6,300 producing federal properties, it added. In 2009, it collected more than $157 of additional royalties, interest, and civil penalties, including $65 million in audit and other enforcement activities; $34 million through sophisticated automated detection systems, including interest due on late payments, and $54 million through follow-up enforcement actions including civil penalties and negotiated settlements.

"Our goal for 2010 is to cover 86% of high-risk companies and 43% of high-risk mineral producing properties," Birnbaum said. By comparison, the US Internal Revenue Service generally audits 1-5% of individual income tax returns, based on income, and 11-27% of larger companies and corporations, depending on company assets, she noted.

Exploration & DevelopmentQuick Takes

Range Resources plots expansion in Marcellus

Range Resources Corp., Fort Worth, plans to exit 2010 at a net 180-200 MMcfd of gas equivalent from the Marcellus shale and 2011 at 360-400 MMcfed compared with just above 115 MMcfed at present.

The company looks to add three Marcellus rigs in the last quarter of 2010 to the 13 it will keep busy from now until then, drilling and casing 150 horizontal wells this year. The end-2011 rig count will be 24.

Range drilled and completed its first two horizontal wells in the northeast part of the play in Lycoming County, Pa., in the 2009 fourth quarter. Average 7-day test rates were 13.3 MMcfed and 13.6 MMcfed. Hookup will take until late 2010 and early 2011, respectively.

The company is testing its first horizontal Upper Devonian shale well and its first horizontal Utica shale well awaits completion.

In the northeast part of the play, the company has drilled 31 horizontal wells, of which 26 await completion and five await hookup.

Most of the company's wells are in the play's southwest portion, where Range has been accumulating data for 2.5 years. The company said estimated ultimate recovery for a Marcellus horizontal well there averages 4.4 bcfe.

Before August 2009, a typical Range Marcellus well had a 2,200-2,800-ft lateral and eight frac stages. Since then laterals are 2,900-5,000 ft with 9-17 fracs, the company said.

"As has been demonstrated in other shale plays, it appears that the longer laterals result in higher initial production rates, higher EURs and improved economics," Range said.

Range has aggregated 900,000 net acres in the high-quality part of the Marcellus play, and a considerable share of the company's $190 million leasehold budget for 2010 will go to block up its Marcellus acreage position.

As of yearend 2009, for each of its proved developed wells in the Marcellus shale play, Range recorded on average 1.2 offset drilling locations as proved undeveloped reserves under new federal rules.

ExxonMobil, MOL to quit Hungary's Mako area

ExxonMobil Corp. and MOL Hungarian Oil & Gas PLC sent written notices to Falcon Oil & Gas Ltd., Denver, that neither will proceed to the appraisal stage of the joint production and development project in Hungary's Mako Trough.

In accordance with the production and development agreement, ExxonMobil's and MOL's respective participating interests in the contract lands, the Foldeak-1 well, and all other interests will revert to Falcon.

The two exiting companies obtained disappointing gas flow rates from alternating shales and sands in the Tertiary Szolnok formation in a basin centered gas accumulation (OGJ Online, Oct. 8, 2009).

Falcon, which becomes operator of the contract area, is seeking alternative strategic partners and is in active discussions with multiple parties to continue evaluation of its 247,000 acres under the long-term production license.

McCully propane frac wells decline, AVO tried

Gas production at two wells in McCully field in southern New Brunswick have declined after encouraging initial rates, and separately the operator is evaluating the amplitude variation with offset technique to identify areas for infill drilling.

The $28.6 million 2010 capital budget of Corridor Resources Inc., Halifax, NS, includes funds for drilling two McCully Hiram Brook wells and is based in part on field output averaging 19.5 MMscfd versus the 23 MMscfd previously estimated. This is because the McCully L-38 and P-47 wells appear to be on hyperbolic decline trajectories and have fallen to 1 MMscfd/well from test rates of 5 MMscfd in the fall of 2009.

Corridor theorizes that the reservoirs may be smaller than indicated by formation thickness, that abundant pyrobitumen reduces reservoir size, or that wax found on wellheads and downhole tools may indicate that rapid pressure drawdown during initial high-rate testing may have led to wax deposition near the well bore.

Early results of a xylene soak-squeeze in the L-38 well indicate the treatment may not be effective, and Corridor is considering restricting flow rates to stem wax deposition in this part of the field.

Corridor also plans to drill the L-37 horizontal well using an oil base mud to minimize formation damage. The company expects that a horizontal well in this part of the reservoir may be free of bitumen and productive without hydraulic fracs. It also may not experience decline rates similar to those at L-38 and P-47. The company will defer the second 2010 McCully well fracs are necessary.

Corridor is building a detailed reservoir model using data from the field's 30 wells to assess fluid drainage patterns and select infill locations.

The 2010 budget includes funds to drill the Sally's Brook Hiram Brook prospect 17 km north of McCully field, Corridor's share of four wells to be drilled on Anticosti Island in the Gulf of St. Lawrence, and performing a site survey for a proposed drilling location on the Newfoundland side of the giant Old Harry structure in the gulf east of Prince Edward Island (see seismic section, OGJ, Sept. 28, 1998, p. 108).

Corridor is seeking a floating rig to drill within 2 years to 4,000-6,000 ft in 1,400 ft of water at Old Harry, where it estimates the potential at 2 billion bbl of oil or 5 tcf of gas recoverable.

Quebec Utica shale gas flow rates encouraging

A horizontal exploration well in Ordovician Utica shale in Quebec's St. Lawrence Lowlands is flowing gas at 5 MMcfd of gas about 3 weeks after its initial rate of more than 12 MMcfd.

The Talisman Energy Inc. St. Edouard-1A well has a 1,000-m lateral with eight frac stages in Middle Utica. Clean-up and flow back began Jan. 29 at more than 12 MMcfd, and the well averaged more than 6 MMcfd during the test, said partner Questerre Energy Corp., Calgary.

The 5 MMcfd rate is at 640 psi flowing tubing pressure on a 5/8-in. choke. The extended production test continues.

During completion, microseismic data were recorded using the St. Edouard-1 vertical hole as a monitoring well. Preliminary analysis indicates the fracs were successful in stimulating sufficient rock volume in the entire Utica sequence, Questerre said.

The initial rates from St. Edouard exceed Questerre's internal threshold for commercial production on a per well basis based on targeted development costs, the company said. Talisman and Questerre are evaluating pipeline options to tie in the well.

Egypt Western Desert concessions extended

Egypt's Ministry of Petroleum extended Apache Corp.'s Khalda Offset and East Bahariya concessions in the Western Desert through July 2016 and July 2012, respectively.

Apache committed to drill at least 10 wells on Khalda Offset with a minimum $45 million capital outlay and $35 million signature bonus. The concession covers 908,900 acres. It committed to drill at least 3 wells on East Bahariya with a minimum $10 million in spending and $4 million signature bonus. The concession covers 673,800 acres.

Based on 2009 exploration success in and around the newly extended concessions, Apache has accelerated 3D seismic surveying and planned a full slate of exploratory drilling.

The most recent discovery, West Kanayes E-1X in the Matruh basin on a concession adjacent to Khalda Offset, tested a combined 17 MMcfd of gas and 1,960 b/d of condensate from 80 ft of net pay in three zones in the Jurassic Alam el Buieb (AEB-6) formation.

The discovery extends AEB production eastward about 4 miles from production in Khalda Offset and into the sparsely drilled West Kanayes concession, said Tom Voytovich, vice-president of Apache's Egypt region.

"With the high oil rate encountered in the upper zone, this well will be produced to maximize liquids production during the time when our gas-handling capacity is facilities-constrained," Voytovich said.

Apache, operator of West Kanayes with 100% contractor interest, plans two more exploratory wells in 2010.

Khalda Offset and East Bahariya are among 22 concessions operated by Apache in joint ventures with Egyptian General Petroleum Corp. Apache, the largest producer and most active explorer in the Western Desert, had gross production of 175,000 b/d of oil and 752 MMcfd of gas in the last quarter of 2009. Net production was 96,000 b/d and 383 MMcfd.

Industry Scoreboard

Drilling & Production Quick Takes

ADCO lets contract to boost Bab oil flow

Abu Dhabi Co. for Onshore Operations (ADCO) has let contract to National Petroleum Construction Co. (NPCC) of Abu Dhabi for work that will increase oil production from onshore Northeast Bab field by 80,000 b/d.

The $683 million engineering, procurement, and construction contract covers development of Lower Cretaceous Habshan-2 and Thamama G zones. Bab field, on production since the 1960s and an important source of natural gas, is 150 km southwest of Abu Dhabi city (see map, OGJ, Aug. 3, 2009, p. 32).

Expansion of Bab oil production is part of an effort by ADCO to raise its output to 1.8 million b/d of oil from 1.4 million b/d. Abu Dhabi accounts for nearly all production by the United Arab Emirates of about 2.27 million b/d.

ADCO also plans to start production from Bida Al Qemzan and Qusahwira fields and from elsewhere in Bab.

NPCC's work will include well tie-ins and flowlines connecting production wells to four new remote degassing stations, tie-ins of 54 water injection wells, pipelines totaling about 950 km, and associated equipment.

Repsol to develop satellite fields off Spain

Repsol Investigaciones Petroliferas SA has let a lump-sum contract to Technip for subsea work to develop two Casablanca satellite oil fields 50 km off the eastern coast of Spain in the Mediterranean Sea, Technip reported.

A Repsol group made the Montanazo D-5 and Lubina-1 discoveries northeast of Casablanca and off Tarragona in mid-2009.

Montanazo, drilled to 2,354 m in 736 m of water, tested at 3,800 b/d of 32° gravity oil. Lubina, drilled to 2,439 m in 663 m of water 4 km north of Montanazo, made 3,700 b/d of 31.5° gravity oil. Repsol said each could produce 5-7 years, quadrupling Spain's then-existing 2,000 b/d of oil production.

Technip's scope includes engineering, supply, installation, and precommissioning of an 11-km flexible pipeline system to connect two production wells to the Casablanca platform, installed in 1981, which already handles oil from Boqueron, Rodaballo, Chipiron, and Casablanca fields.

Offshore installation is scheduled for first-half 2011 using the Deep Constructor, a Technip deepwater construction vessels.

This pipeline system will include a riser, a flowline, and two short sections of pipe to connect subsea structures.

In addition, Technip will install a pumping manifold and umbilicals. The flexible pipelines and umbilicals will be trenched to protect fishing lines, Technip said.

All flexible pipelines will be fabricated at Technip's plant in Le Trait, France.

BPZ updates Peru Corvina, Albacora operations

BPZ Resources Inc., Houston, placed on long-term test its seventh oil well in Corvina field on Block Z-1 off Peru as it worked toward a transition to commercial production around May 31.

The company also received approval to restart long-term tests at the A-14XD well in Albacora field, in Peru near the marine boundary with Ecuador 16 miles north of Corvina field, and resumed drilling the A-15D well, expected on line by the end of April.

The CX11-17D well in Corvina was making an initial 2,000 b/d of oil with normal gas-oil ratio and no formation water.

BPZ perforated 80 ft in two sets of sands within the well's 225 ft of estimated net oil pay. It first opened lower sands that had not been tested before in prior wells before adding the second set of sands, thus allowing the company to gather data to update its geologic and reservoir models.

The company is collecting data to determine the field's drive mechanism and has ordered equipment to reinject produced gas and water.

BPZ has spud the CX11-22D, projected to 10,000 ft measured depth, and expects to place it on line near the end of April.

The clearance to resume tests at A-14XD, BPZ's first well in Albacora, came as it positioned extended well test equipment at the Albacora platform. BPZ hasn't determined what production declines may occur at Albacora.

ERCB reports on Joslyn Creek steam release

The Energy Resources Conservation Board of Alberta (ERCB) released an incident report on the May 18, 2006, steam release at Total E&P Canada Ltd.'s Joslyn Creek steam-assisted gravity drainage (SAGD) oil sands project as well as Total's report on the incident to ERCB.

ERCB's report notes that the Joslyn Creek project, 60 km north of Fort McMurray, was the shallowest SAGD development in Alberta, with horizontal steam injection wells at less than a 100-m depth.

The report said the steam release breached the caprock and affected a 125 m by 75 m surface area. The release caused rock projectiles to travel up to 300 m from the main crater and produced a 1-km dust plume. The report notes that there was no loss of life or injury and the incident did not emit any harmful gas.

After the incident, ERCB imposed pressure restrictions on steam injection for the project and in June 12, 2009, approved the suspension of the project. Recently Total has submitted an application for abandoning the project.

ERCB concluded that Total was noncompliant with its approved development scheme by operating at bottomhole pressures higher than the 1,400 kPa (absolute) proposed in its application and by failing to shut-in wells that exceeded a 1,800 kPa (absolute) bottomhole pressure.

The Joslyn Creek incident is the only time that a SAGD operation in Alberta has had a caprock breach that released steam to surface, ERCB said.

ERCB also said it began to implement changes in March 2007 in its application processes. The changes require thermal project applications to provide more detailed geological information for determining the caprock competency as wells as provide an outline for monitoring caprock integrity during steam injection.

Processing Quick Takes

ExxonMobil to use NRU in Texas field work

ExxonMobil Corp. will employ nitrogen recovery and cryogenic gas processing equipment from Air Products, Lehigh Valley, Pa., for work to extend the producing life of Hawkins field in northeast Texas.

Air Products will deliver the NRU plant equipment later this year.

ExxonMobil will operate the new NRU plant to process about 140 MMscfd of natural gas, said the company in an announcement last month (OGJ, Jan. 18, 2010, p. 10). Recovered nitrogen will be reinjected into the field for reservoir stimulation. The company expects to recover an additional 40 million boe at Hawkins field.

Construction was to begin this quarter with project start-up expected in late 2011, said an ExxonMobil statement in January. The project will extend by 25 years the life of the field, which was discovered in 1940.

Hawkins field lies in Wood County, Tex., about 100 miles east of Dallas. The company said that over 70 years it has produced more than 800 million bbl and is one of the largest ever discovered in the state.

Transportation Quick Takes

RasGas 3 starts up LNG Train 7

Ras Laffan LNG Co. Ltd. 3 (RasGas 3) has started up its 7.8-million-tonnes/year Train 7 at Ras Laffan Industrial City, Qatar.

Plant capacity matches that of RasGas Train 6, inaugurated last year (OGJ Online, Aug. 12, 2009), and expands total LNG production from the site to more than 60 million tpy, according to OGJ figures. Qatar's North field, estimated to hold more than 900 tcf, supplies all trains.

The announcement from ExxonMobil Corp. said RasGas 3 Train 7 is the fourth 7.8-million-tpy LNG plant brought online in the past 12 months by its joint venture with Qatar Petroleum. "These mega facilities have sufficient scale to competitively reach markets around the globe," it said.

RasGas 3 is part of an investment in natural gas production and liquefaction by affiliates of QP and ExxonMobil that includes 12 new, 210,000-cu m Q-Flex LNG vessels and one 260,000-cu m Q-Max LNG vessel, said ExxonMobil. The final component of the investment is the Golden Pass LNG terminal, under construction near Sabine Pass, Tex. It will be able to regasify 15.6 million tpy when it starts up later this year.

El Paso to sell Mexican pipeline assets to Sempra

El Paso Corp. agreed to sell its interest in Mexican pipeline and compression assets to Sempra Pipelines & Storage, a unit of Sempra Energy. The sale includes El Paso's 50% interest in a joint venture with Mexico's state owned Petroleos Mexicanos consisting of the 15,000-hp Gloria a Dios compression station, the 23.4-mile Samalayuca pipeline, the 70.8-mile San Fernando pipeline (and 75,000 hp of accompanying compression), and the 117.4-mile Burgos LPG pipeline (with 1,200 hp of pumping), all near the Mexico-Texas border. The 12.75-in. OD, 30,000 b/d Burgos LPG pipeline extends from Pemex's Burgos gas processing center to Monterrey, Nuevo Leon, Mexico.

The sale also includes El Paso's wholly owned 14,000-hp Naco compression station and 7.8-mile Agua Prieta pipeline, originating at the Arizona border. El Paso expects the $300 million transaction to close in the second quarter.

The sale did not include El Paso's interest in the proposed 1.3-bcfd Sonora LNG terminal, covered by a separate joint venture with Houston's DKRW Energy LLC. Sonora Terminal and Pipeline would deliver natural gas to northern Mexico and the southwestern US from the terminal site in Puerto Libertad, Sonora, Mexico.

El Paso says the project has received permits to develop the terminal and associated pipelines but is still in the process of securing Pacific Rim LNG supplies. It anticipates commercial operations by 2014-15, pending supplier agreements.

Correction

The headline "NARUC study lists adverse impacts for ongoing OCS ban" (OGJ, Feb. 22, 2010, p. 26) incorrectly suggests that the National Association of Regulatory Utility Commissioners conducted the study. NARUC authorized the study and hired Science Applications International Corp. to conduct it. The same article also erroneously identified O'Neal Hamilton as a former NARUC chairman. He formerly chaired South Carolina's Public Service Commission and currently chairs NARUC's committee on gas.

More Oil & Gas Journal Current Issue Articles
More Oil & Gas Journal Archives Issue Articles
View Oil and Gas Articles on PennEnergy.com