GENERAL INTEREST — Quick Takes
Battelle report questions EPA study process
A Battelle Memorial Institute review of the US Environmental Protection Agency's study of hydraulic fracturing and drinking water concludes EPA did not define important quality requirements in its study process.
Battelle has released a 166-page study outing its analysis, which was done upon the request of the American Petroleum Institute and America's Natural Gas Alliance.
EPA used its discretionary authority to broaden its study significantly beyond what Congress requested in fiscal year 2010. A broader study increases complexity and risk, Battelle said.
Ambitious schedules, driven by various 2012 reporting goals, could make data collection and analysis less robust and scientific conclusions less sound, Battelle warned.
Site data collected during 2006-10 could become obsolete by the time EPA issues its final report in 2014, Battelle said.
Stephanie Meadows, API upstream policy senior advisor, told reporters during a July 10 teleconference that API and ANGA intend for Battelle's report to help EPA produce "the most scientifically sound study possible."
Battelle noted EPA did not designate its study as a "highly influential scientific assessment." Such a formal designation would have triggered higher standards for peer review, study design, data quality, and transparency.
"It is not apparent that systematic planning…was used," Battelle said of EPA's process. "It is conceivable, had a systematic planning process been applied from the outset and in more explicit fashion, the study design would have been more appropriately directed and scientifically robust."
For instance, a more formal study design might have involved a different case study program and different modeling, Battelle said.
Battelle recommended more collaboration between EPA and industry.
Amy Farrell, ANGA's vice-president for regulatory affairs, said API and ANGA member companies have extensive knowledge of geology and water.
"We hope to continue reaching out to EPA and developing a collaborative relationship," she said.
Power generation from coal, gas equal in April
Recently published data from the US Energy Information Administration show that monthly electric power generation from natural gas-fired plants nearly equaled that from coal-fired plants in April, marking the first time this has been so since EIA began compiling these data.
Each type of electric power generation supplied about 32% of total generation during that month, EIA reported using preliminary data.
In April, EIA reported net electric generation from gas-fired plants was 95.9 million Mw-hr, only slightly below the 96 million Mw-hr supplied from coal-fired plants.
The data are subject to change, EIA said, adding that final 2011 data will be released this fall, and 2012 data will be revised at that time.
"Preliminary data are derived from a survey of a sample of large power plants, and final data come from a census of all power plants," EIA reported, adding, "For 2010, the difference between preliminary and final net generation data from all sources was 0.1%."
EIA said, "In April 2012, demand was low due to the mild spring weather. Also in April, natural gas prices as delivered to power plants were at a 10-year low. With warmer summer weather and increased electric demand for air conditioning, demand will increase, requiring increased output from both coal- and natural gas-fired generators."
Unit Petroleum to buy Anadarko assets from Noble
Unit Corp. subsidiary Unit Petroleum Co. has agreed to buy oil and natural gas assets in the Anadarko basin from Noble Energy Inc. for $617 million.
The transaction involves properties in western Oklahoma and the Texas Panhandle. The properties include Noble Energy's interest in about 900 producing wells on 84,000 net acres.
Closing is expected in September, and the acquisition will have an effective date of Apr. 1, Noble Energy said. As of Apr. 1, net production was nearly 60 MMcfd of gas equivalent and net proved reserves were 250 bcf of gas equivalent. Production is 65% gas, 27% NGLs, and 8% oil.
David L. Stover, Noble Energy president and chief operating officer, said the sale is part of the company's previously announced noncore divestiture plan.
Exploration & Development — Quick Takes
Petrobras makes Espirito Santo heavy oil discovery
Brazil's Petrobras has disclosed an offshore heavy oil discovery in the Espirito Santo basin 64 km southwest of Golfinho field.
The Grana Padano well is Block ES-M-661 of the BM-ES-24 concession in 1,208 m of water 58 km off Vitoria. It located 15° gravity oil in reservoirs at 2,008 m.
Petrobras intends to continue exploring the block and will submit a proposed assessment plan to the National Petroleum Agency that describes its plan to delineate the discovery and estimate reservoir volume and productivity.
Petrobras is operator of the concession with 70% interest, and IBV Brasil has 30%.
GeoPark updates Colombia Llanos oil discoveries
GeoPark Holdings Ltd. said it participated in three discoveries in the Llanos basin in Colombia.
The Max-1 well on the Llanos 34 block is testing 1,220 b/d of 15° gravity oil with 18% BS&W from the Guadalupe formation on an electric submersible pump. More tests are needed to determine expected and stabilized production rates. GeoPark operates the block with a 45% working interest.
Max-1 went to a TD of 11,505 ft. The Gacheta formation at 11,054-062 ft and 11,065-080 ft flowed at the rate of 149 b/d of 35.8° gravity oil on a 35-hr test. Guadalupe at 10,600-625 ft flowed 323 b/d of fluid with 6% BS&W for an average of 304 b/d of 14.8° gravity oil.
The Guadalupe at 10,456-490 ft averaged 299 b/d of fluid with 10% BS&W for an average 276 b/d of 14° gravity oil. The Mirador at 10,300-310 ft and 10,320-336 ft made 637 b/d of fluid, 75% BS&W, on a jet pump on a 26-hr test for an average 159 b/d of 22.8° gravity oil.
The Tua-1 discovery well on Llanos 34 is testing at 1,723 b/d of 18.2° gravity oil with less than 0.5% BS&W from Mirador on ESP. More tests are needed. The Guadalupe formation also tested heavy oil.
Delineation drilling at both discoveries is to start in the third quarter subject to regulatory and partner approval.
On Llanos Block 32 the P1 Energy-operated Maniceno-1 exploratory well went on production in July 2012 at 3,000 b/d of 28° gravity oil. The Samaria-1 exploratory well, drilled in June with potential oil pay in Mirador, Guadalupe, and Gacheta, is to be tested this month. GeoPark has a 10% working interest subject to regulatory approval.
On the Parex Resources Inc.-operated Llanos 17 block, in which GeoPark has 36.8% working interest subject to regulatory approval, the Mapora-1 exploratory well is to be plugged and abandoned and the Celeus-1 exploratory well finished drilling in April with potential oil pay in the C7 and Gacheta formations. Tests are planned for July 2012.
Bossier shale yields oil at Rodessa field
Pegasi Energy Resources Corp., Tyler, Tex., has reported completion of a horizontal oil well in Jurassic Bossier shale in Rodessa field in Cass County, northeast Texas.
The Morse Unit 1H averaged 281 b/d of 40° gravity oil plus associated gas in its first 5 days of continuous production after a five-stage hydraulic frac job in its 2,000-ft lateral. Pegasi Energy has a 56% working interest in the well.
The company said the Morse completion "gives us great confidence in our proposed strategy for the further development of the Cornerstone Project which will involve drilling horizontal wells of 3,000 to 5,000 ft in length."
NCT, Santa Maria test Llanos heavy oil discovery
NCT Energy Group CA Colombia will apply for extended production test authority for the Flami-1 discovery well on the Llanos 27 block in Colombia, said partner Santa Maria Petroleum Inc., Toronto.
Given the Mirador formation's lower productivity and higher water cut, it was decided to terminate tests in the MIrador and produce the Une formation. The well will be shut-in until approval is granted, expected in 4-6 weeks.
Phase 1 tests of the Une formation, perforated at 9,086-9,100 ft, involved producing out the drilling control fluids and cleaning the wellbore. Over a 60-hr period the well produced 1,514 b/d of 15.5° gravity oil with 13% average water cut. Recovery totaled 3,786 bbl of oil in 60 hr.
Following Phase 1 the well was shut in for pressure build-up, and pressure reached 3,850 psi. In Phase 2 the well recovered 5,496 bbl of oil in 73 hr and was produced in stages.
It produced 1,695 bbl in 29 hr with 20% average water cut in Stage 1, 1,527 bbl in 20 hr with 12% water cut in Stage 2, 1,350 bbl in 15 hr with 12% water cut in Stage 3, and 924 bbl in 9 hr with 12% water cut in Stage 4.
Santa Maria is paying 50% of well cost to earn 45.275% of production before payout and 34.25% of production after payout under a private participating interest agreement.
Drilling & Production — Quick Takes
Laricina eyes CSS for Grosmont development
Laricina Energy Ltd., Calgary, is considering cyclic steam stimulation (CSS) for early development of bitumen in the Upper Devonian Grosmont carbonate of Alberta on the basis of results at its Saleski pilot project.
The pilot so far has focused on steam-assisted gravity drainage (SAGD) and a proprietary combination of SAGD with cyclic solvent injection. In Alberta, where bitumen production now comes from sandstone reservoirs, the Grosmont is estimated to hold 406 billion bbl of bitumen in place.
The Saleski project has established production in two Grosmont zones, designated C and D.
"We have determined that early-life start-up oil rates and steam-to-oil ratios are significantly improved when the well pairs were operated under an injection and production cycling process," Laricina said in a press statement. "Our testing and analysis of this to date shows a strong correlation to commercial single horizontal well CSS, similar to existing commercial horizontal well CSS projects."
Laricina and working-interest partner Osum Oil Sands Corp. believe CSS is "a suitable initial development strategy for the Grosmont and may also be an effective start-up method that supports continuous dual-well SAGD."
Laricina is considering amending its application for first-phase development, which targets production of 10,700 b/d of bitumen, to incorporate CSS.
The fourth Saleski well pair, the second targeting the C zone, produced at a rate of more than 1,200 b/d of bitumen during a test cycle. The previous peak rate was 807 b/d (OGJ Online, May 16, 2012).
Laricina holds a 60% working interest in the Saleski project. Osum holds the rest.
Venezuelan group to develop Yucal Placer gas
The Ypergas operating group will begin increasing sour natural gas production at Yucal Placer field in east-central Venezuela and eventually triple present output of 100 MMcfd, said Total Oil & Gas Venezuela.
Yucal Placer, which went on production in 2004 in Guarico state, is a high-pressure reservoir that contains methane and carbon dioxide.
Expansion project sanction and final investment decision took place following the signature of an addendum to the gas sales and purchase agreement between Ypergas and PDVSA Gas.
Ypergas, a combine of Total, Repsol, Inepetrol, and Otepi, operates Yucal Placer field. Total Oil & Gas Venezuela has a 69.5% interest in the Yucal Placer Norte and Yucal Placer Sur licenses, and a 37% interest in Ypergas.
Beach starts gas flow from Encounter well
Flow of 2 MMcfd of natural gas has started from the Encounter-1 wildcat in south Australia's Cooper basin after fracture stimulation, said well operator Beach Energy Ltd., Adelaide. Beach carried out the fracture program in six stages. Beach says the result was a higher flow than last year's shale well Holdfast-1, which was drilled by Beach in the same area. Holdfast flowed as much as 2 MMcfd of gas from seven zones.
Beach intends to continue flow testing Endeavour-1 for a month to better understand zone contributions by the various Permian-age Roseneath shale, Epsilon formation, and Murteree shale sections in the well.
Beach added that Encounter-1 confirmed the lateral continuity of the basin-centred gas play in the Nappamerri Trough with the Patchawarra zone flow testing at 750,000 cfd from the top 5 m.
The company will use the results of Encounter-1 and Holdfast-1 to aid planning for a horizontal well program later this year.
PROCESSING — Quick Takes
NiSource, Hilcorp form JV for Utica shale production
NiSource Inc. unit Midstream & Minerals Group LLC, Merrillville, Ind., has formed a joint venture with affiliates of Hilcorp Energy Co., Houston, a privately owned oil and gas exploration and development company. The JV will build natural gas gathering and NGL processing for production in the Utica shale of northeast Ohio and western Pennsylvania.
Phase 1 of the venture's investment, amounting to about $300 million, is planned for later this year.
As part of the agreement, NiSource will participate in a separate JV with Hilcorp to develop combined acreage in the Utica and Point Pleasant shale formation in northeast Ohio and western Pennsylvania. NiSource will participate in the joint venture as a "nonoperating working interest owner in the total acreage position," it said. Hilcorp will operate and manage development of the combined acreage.
Pennant Midstream LLC, the new midstream JV, will initially invest in construction of 50 miles of 20-in. gathering in northeast Ohio and western Pennsylvania. In addition, Pennant will invest in construction and installation of a cryogenic NGL processing plant in Ohio with initial capacity of 200 MMcfd.
NiSource Midstream Services LLC will operate the system, which initially will provide about 400 MMcfd of both wet and dry gas gathering, with expansion anticipated based on production in the area.
The Hilcorp-NiSource upstream JV will anchor the project with a long-term gathering and processing agreement, while additional capacity will be marketed to other producers in the area, said the NiSource announcement. The project is to be in service by third-quarter 2013.
Pennant is also reviewing multiple downstream NGL options with several parties, including development of its own fractionation, the company said.
Trinidad and Tobago's NGC signs gas supply deal
Trinidad and Tobago's National Gas Co. Ltd. (NGC) reached an agreement with Methanol Holdings Trinidad Ltd. (MHTL) for the supply of 100 MMcfd of natural gas to MHTL's proposed $2 billion ammonia-urea-melamine complex.
MHTL Chief Executive Officer Rampersad Mootilal said the 20-year gas contract was signed after close to a year of negotiations because his company had to evaluate what effect the rise of cheap shale gas in the US would have on the economics of the project.
Mootilal said, "Ordinarily it would not take us this long but we have to be mindful of the changing global environment and in this context we had to be more cautious than before."
He said he expected that site preparation work will begin later this year and construction to start in early 2013.
The project will involve the construction of ammonia, urea, ammonia sulfate plant as well as a number of intermediate plants.
MHTL is the largest exporter of methanol to the US exporting 2.8 of its 4 million tonnes/year of methanol to the US and is the largest exporter of urea ammonium nitrates to the US corn belt.
RIL taps Technip for Jamnagar off-gas cracker
Reliance Industries Ltd. has selected Technip to provide technology and engineering for the refinery off-gas cracker expansion at its 1.24 million b/d Jamnagar refinery and petrochemical complex in Gujarat, India.
The project will increase ethylene capacity to 3.248 million tonnes/year from 1.883 million tpy and boost capacities of related products (OGJ Online, May 3, 2012).
TRANSPORTATION — Quick Takes
Gas Atacama awards Chilean FSRU to Golar LNG
Chilean energy company Gas Atacama has awarded a contract to Golar LNG Ltd. for Gas Atacama Mejillones seaport's floating storage and regasification unit (FSRU).
The initial term of the contract, in Gas Atacama's option, is for 15-20 years and is to generate an average $48 million/year for the 15-year charter or $47 million/year for the 20-year charter, according to the Golar announcement. Gas Atacama has three 5-year contract extension options, representing a potential 15 years more of commitments.
The FSRU will be moored 1.6 km offshore in 50 m of water in the Bay of Mejillones. The newbuild FSRU will be able to store 170,000 cu m of LNG and deliver about 180 MMcfd of vaporized natural gas. It will be delivered in fourth-quarter 2015.
The regasified LNG will be delivered via Gas Atacama's subsea pipeline and is primarily to supply the onshore 780-Mw Central Termica Atacama thermal power plant.
Regasified LNG could additionally be used to the meet the demands of some of Gas Atacama's mining customers, said the announcement, as well as those of other power generators. Parties have agreed to the possibility for further expansion of the FSRU regasification capacity of up 360 MMcfd.
Final detailed contracts were executed in a signing ceremony by Gas Atacama and Golar on July 5 in Santiago, but full commitment by the parties to the transaction is subject to certain contractual conditions related to Gas Atacama's achieving a threshold of new power sales agreements before Dec. 31.
Gas Atacama owns a natural gas pipeline and power station. Current shareholders include Endesa (Chile, 50%), the largest electrical energy generating company in Latin America, subsidiary of the Spanish Endesa Group, and controlled by ENEL of Italy; and the Southern Cross Group (50%), a private investment group with interests in Chile and other Latin American countries.
Australian Pacific group reach FID for Train 2
Australian Pacific LNG—a group comprising Origin Energy Ltd., ConocoPhillips, and Sinopec—has reached a final investment decision (FID) to build a second train at the coal seam gas-LNG plant on Curtis Island, near Gladstone in Queensland.
Additionally, Sinopec has formally taken another 10% interest in the project for $1.4 billion, bringing to 25% its stake in the project.
Origin and ConocoPhillips both are looking to further dilute their respective 37.5% interests in the project. Origin has said it would like to reduce its share to 30%.
First LNG from Train 1 is on schedule for 2015. First LNG from Train 2 is eyeing 2016.
The FID was reached a week after Origin signed a 20-year, 1 million tonne/year of LNG offtake deal with Kansai Electric Power.
Meanwhile, Sinopec's total offtake has grown to 7.6 million tpy following agreement on Train 2.
The APLNG group's financing arrangement for the downstream part of the project—an $8.6 billion (Aus.) facility from a syndicate of banks including the import-export banks of China and the US—was subject to reaching FID on Train 2.
Origin says the cost of the project is unchanged, aside from foreign exchange movements.
The project will be supplied by CSG fields in the Surat-Bowen basins of southeast Queensland. It now comprises two LNG trains, each with a capacity output of 4.5 million tpy. The first train reached FID in mid-2011 and construction at the Curtis Island plant site is well under way.
Turkey, Azerbaijan sign Trans-Anatolian agreement
Turkey and Azerbaijan have agreed to build the 16-billion cu m/year Trans-Anatolian natural gas pipeline, transporting Azeri gas through Turkey to Europe. Turkey will have access to as much as 10 bcm/year of the gas.
The pipeline would extend 2,400 miles at an estimated cost of $5 billion. Gas would be sourced from the BP PLC-operated Shah Deniz II field in the Caspian Sea roughly 70 km southeast of Baku. The field has a target start-up date of yearend 2017.
The Trans-Anatolian pipeline was originally proposed in November 2011 as the non-European Union segment of a Southern Corridor natural gas pipeline to supplant the OMV-led Nabucco pipeline project (OGJ, Feb. 6, 2012, p. 108).
Nabucco has since scaled back to run from the Turkish-Bulgarian border to Austria. Other options to transport gas to Europe include the Trans-Adriatic Pipeline to Italy and the South East Europe Pipeline through Hungary, Bulgaria, and Romania.
BP has said a final transportation selection will be made in 2013 (OGJ Online, Apr. 18, 2012). BP's partners in Shah Deniz II are Statoil 25.5%, State Oil Co. of Azerbaijan Republic 10%, Lukoil 10%, Total 10%, Naftiran Intertrade Co. 10%, and Turkish Petroleum AO 9%. BP's share is 25.5%.
More Oil & Gas Journal Current Issue Articles
More Oil & Gas Journal Archives Issue Articles
View Oil and Gas Articles on PennEnergy.com