GENERAL INTEREST — Quick Takes
Pemex outlines restructuring plans
Petroleos Mexicanos said it is establishing affiliates to provide drilling, logistics, and electricity services as part of its corporate restructuring in response to Mexico's sweeping energy reform that ended Pemex's monopoly on oil and gas activities.
In an Aug. 20 statement, Pemex said it plans to keep its exploration and production unit while consolidating its divisions focused on natural gas, refining, and petrochemicals into one unit to be known as the industrial transformation division.
Pemex also plans subsidiaries within the two divisions. One subsidiary will offer drilling services to private and foreign companies entering Mexico's oil and gas businesses. Mexico's government officials have suggested the first private contracts might be announced as early as the 2015 first quarter.
Mexico's energy reform legislation was signed into law in early August (OGJ Online, Aug. 18, 2014).
ExxonMobil unit settles charges from 2012 La. spill
Exxon Pipeline Co. agreed to pay more than $1.4 million to resolve federal charges that a 2012 spill from the company's North Line near Torbert, La., violated the Clean Water Act, the US Department of Justice and Environmental Protection Agency jointly announced.
A federal complaint, which was filed with the proposed settlement on Aug. 26 in US District Court for Louisiana's Middle District, charged that the ExxonMobil Corp. subsidiary broke section 311 of the law when the pipeline ruptured on Apr. 28, 2012, about 20 miles west of Baton Rouge. At least 2,800 bbl of crude leaked into the surrounding area and flowed into an unnamed tributary connected to Bayou Cholpe, the two entities said.
ExxonMobil Pipeline's fine was in addition to costs it incurred to respond to the incident and replace the segment of ruptured pipeline, DOJ and EPA said. It also is continuing cleanup work under a Louisiana Department of Environmental Quality administrative order, and follow-up work under a US Pipeline & Hazardous Materials Safety Administration corrective action order.
The fine will be deposited in the federal Oil Spill Liability Trust Fund. The proposed consent decree is subject to a 30-day public comment period and final court approval.
Parsley Energy adds Permian basin acreage
Parsley Energy Inc., Midland, Tex., has agreed to buy from "multiple sellers" undeveloped and productive acreage in Reagan County, Tex., for a total of about $252 million.
The company described the acquisitions as "bolt-on assets" adjacent to Permian basin land on which it operates, specializing in the stacked-pay fairway of the Spraberry, Wolfberry, and Wolftoka trends.
The new acquisition involves 5,472 net acres, 100% operated with average royalty of 23% and average working interest of 98%. The acreage has 157 net horizontal drilling locations and nine horizontal wells in different stages of development with three wells on one pad.
Estimated net production at closing is 1,800 boe/d.
Parsley said equipment is in place to support current horizontal drilling. Two wells are to be completed by yearend, and the first new horizontal well will be spudded in the first quarter of 2015, it said.
Exploration & Development — Quick Takes
Shell makes deepwater gas discovery off Malaysia
Royal Dutch Shell has made another natural gas discovery on Block SK318 180 km offshore Malaysia with the deepwater Marjoram-1 well, which was drilled in 800 m of water.
Shell earlier this year announced the Rosmari-1 gas discovery, which was also drilled on Block SK218 (OGJ Online, Apr. 17, 2014). That well was drilled to 2,123 m total depth and encountered a 450-m gas column. Shell said at the time that the discovery was "a positive indicator of the gas potential in the area."
Although Shell did not provide an estimate of the size of the Marjoram discovery, a Shell spokesperson told OGJ via an e-mailed statement, "The Rosmari-1 and Marjoram-1 wells combined account for over 200 million boe."
Shell operates Block SK318 with 85% interest. Petronas Carigali Sdn. Bhd. holds the remaining interest.
Mzia DST supports potential hub offshore Tanzania
Results from the second drillstem test (DST) on the Mzia discovery on Block 1 offshore southern Tanzania indicated further support for a hub development to supply a potential onshore LNG project, BG Group PLC said on Aug. 27.
The Mzia-3 appraisal well, drilled in 1,800 m of water about 6 km north of the original Mzia-1 discovery, flowed gas at a maximum rate of 101 MMscfd, equal to about 17,000 boe/d.
BG in 2013 tested the Mzia-2 well, the first performed on a Cretaceous discovery in deepwater offshore Tanzania, at 57 MMscfd, or 9,500 boe/d (OGJ Online, May 1, 2013).
"The excellent results from this latest [DST] further reduce reservoir risk, a critical factor as we progress design of the upstream production facilities and infrastructure," said BG COO Sami Iskander. "Also, the Mzia-3 DST, along with previous appraisal activities, supports our efforts to optimize the value of a development across our Block 1 discoveries."
The Deepsea Metro-1 drillship will move north to complete the exploration and appraisal program on the Block 4 discoveries by drilling the Kamba-1 well.
The 2012 Mzia discovery is a multilayered field of Upper Cretaceous age with a gross gas column of more than 300 m (OGJ Online, May 16, 2012).
The Mzia and Jodari discoveries on Block 1 are estimated to hold 9 tcf of total gross recoverable resources (OGJ Online, Mar. 26, 2012). Blocks 1, 3, and 4 offshore Tanzania are estimated to hold 15 tcf of total gross recoverable resources, or 2.5 billion boe.
BG operates Blocks 1, 3, and 4 with 60% interest. Ophir Energy PLC and Pavilion Energy Pte. Ltd. each hold 20% interest in the blocks.
KrisEnergy concludes Gulf of Thailand drilling
KrisEnergy Ltd., Singapore, reported it has concluded drilling an exploration well on Block G10/48 in the Gulf of Thailand, where the company is developing Wassana oil field.
The Mancharee-1 well, which was drilled in 170 ft of water, reached a total 12,205 ft measured depth (10,460 ft true vertical depth subsea). The well encountered gas shows at several levels, KrisEnergy said, but the company couldn't use it to identify any significant pay zones.
Mancharee-1, the final commitment well in the third exploration phase of the license, was drilled using Seadrill Far East Ltd.'s West Cressida jack up rig.
KrisEnergy holds 100% working interest in Block G10/48, which covers 4,696 sq km over the southern section of the Pattani basin in 60 m of water. As well as the Wassana oil development, the block also contains the Niramai and Mayura oil discoveries.
Drilling & Production — Quick Takes
Aasta Hansteen gas development on time for 2017
The Aasta Hansteen gas development in the northern Norwegian Sea is on schedule for production start-up in third quarter 2017, reported operator Statoil ASA.
"We are building the largest Spar platform in the world, and we are setting a new depth record of 1,300 m for a field development and pipeline on the [Norwegian continental shelf]," said Torolf Christensen, Statoil's head of Aasta Hansteen, at a press conference in Stavanger during Offshore Northern Seas 2014.
The project is being developed in several parts of the world, including South Korea where the hull and topside are being constructed. The first offshore work began this summer on the seabed with the laying of a fiber optic cable and installation of rocks for the Polarled pipeline.
As for subsea equipment, Christensen said that 93% is being provided by suppliers with "a Norwegian billing address."
Helge Hagen, project manager for Aasta Hansteen subsea development, said, "The combination of deep waters, harsh weather conditions, and a long distance from existing infrastructure on Aasta Hansteen is unique globally."
The Polarled pipeline is designed to extend from the platform 480 km to the Nyhamna processing plant (OGJ Online, Jan. 8, 2013).
CNRL files application for Grouse oil sands project
Canadian Natural Resources Ltd. has submitted an Oil Sands Conservation Act application with Alberta Energy Regulator for its Grouse steam-assisted gravity drainage (SAGD) project.
CNRL envisions as many as 161 SAGD well pairs from 23 surface pads, a central processing facility, and 50,000 b/d of bitumen from the McMurray formation (OGJ Online, Sept. 19, 2013).
AER said clearing and lease construction is scheduled for fourth-quarter 2015, with major facility construction beginning in fourth-quarter 2017 and steaming in fourth-quarter 2019. Expected life of the project is 20 years.
The site is about 75 km northeast of Lac La Biche and 47 km southwest of the hamlet of Conklin.
Petrobras eyes Lapa field pipeline-heating
Petroleo Brasileiro SA (Petrobras) will evaluate pipeline-heating systems for use in development of deepwater Lapa oil field in the Santos basin offshore Brazil.
Wood Group Kenny has begun a conceptual engineering study for the state-owned company of two options: water-heated pipe-in-pipe and electrically trace-heated pipe-in-pipe. Wood Group Kenny said use of either option would represent the first application of active heating pipeline technology in a presalt environment.
Its project will give Petrobras and partners in Block BM-S-9 a basis for evaluation of technical feasibility of a southwest area tieback on the field and determination of the most cost-effective technology. Lapa field, formerly known as Carioca, is in 7,021 ft of water about 170 miles offshore (OGJ Online, Oct. 30, 2013). When it declared Carioca commercial last December, Petrobras estimated reserves at 459 MMboe and production start in third-quarter 2016. Oil is 26° gravity.
Petrobras operates the block with a 45% interest. Partners are BG E&P Brasil 30% and Repsol Sinopec Brasil 25%.
PROCESSING — Quick Takes
MRPL commissions FCC at Mangalore refinery
Mangalore Refinery & Petrochemicals Ltd. (MRPL), a subsidiary of Oil & Natural Gas Corp. Ltd., has commissioned a fluidized catalytic cracking (FCC) unit that comprises part of the long-delayed Phase 3 expansion project at its 194,000-b/d refinery in Mangalore, India (OGJ Online, June 8, 2010).
The FCC unit was commissioned on Aug. 27, and products from the unit already are being routed to their respective destinations, MRPL said in a notice to India's BSE Ltd. (formerly Bombay Stock Exchange).
Commissioning of the FCC will increase the refinery's production of LPG, light distillates, and propylene to be used as feedstock for an integrated 440,000-tonne/year polypropylene (PP) unit, MRPL said.
The company previously said it expects to reach manual completion on the PP unit, also a part of the Phase 3 expansion, by October (OGJ Online, Aug. 14, 2014).
No details were disclosed regarding the third train of a three-train sulfur recovery unit, which MRPL earlier said was due to be commissioned by the end of August.
Announced in February 2010, the Phase 3 expansion project was designed to increase the refinery's complexity and profitability by increasing refining capacity to 300,000 b/d as well as equip the plant to process lower-cost heavy, sour, and high-TAN crudes, according to MRPL.
Earlier in the year, MRPL commissioned other units in the Phase 3 expansion, including a 650,000-tpy coker heavy gas oil hydrotreating unit (OGJ Online, May 15, 2014) as well as a 3 million-tpy delayed coking unit (OGJ Online, Apr. 4, 2014).
MarkWest to expand processing in Pennsylvania
MarkWest Energy Partners LP, Denver, will expand midstream infrastructure at its Keystone complex in Butler County, Pa., the company said, to handle growing rich-gas production from the Marcellus shale and Upper Devonian formations.
New processing agreements with Rex Energy Corp. and EdgeMarc Energy will underwrite the expansion. As part of these agreements, MarkWest will build Bluestone III and IV, each of which to handle 200 MMcfd and to begin operations in fourth-quarter 2015 and second-quarter 2016, respectively.
In addition, MarkWest will build 40,000 b/d of additional de-ethanization capacity and more than 20,000 b/d of additional propane and heavier NGL fractionation capacity.
The Keystone complex currently consists of Bluestone processing and fractionation and Sarsen processing, which combined provide 210 MMcfd of processing capacity and 26,500 b/d of fractionation capacity (OGJ, June 9, 2014, Newsletter).
The Keystone complex is anchored by Rex Energy. MarkWest in May began operations of the 120-MMcfd Bluestone II plant and 10,000 b/d each of ethane and C3+ fractionation capacity to continue handling Rex Energy's growing rich-gas production. In addition to the Bluestone processing and fractionation plants, MarkWest completed a 32-mile purity ethane pipeline connecting Bluestone to Sunoco Logistics Partners LP's Mariner West pipeline.
RWE Dea starts up Egypt's Disouq gas plant
RWE Dea AG has started gas production from the central treatment plant (CTP) of the Disouq development project in Egypt.
Production started at 45 MMscfd and has reached about 90 MMscfd. With the North West Khilala gas plant, producing since September 2013, the Disouq rate is about 150 MMscfd.
The CTP is "a significant milestone in advancing production growth from our Egyptian assets," said Dirk Warzecha, chief operating officer of RWE Dea AG. "We started the project during difficult times in the country, which required special measures for security and logistics."
The company expects increases in the CTP and North West Khilala to result in production of about 200 MMscfd in 2015.
Maximilian Fellner, general manager of RWE Dea Egypt, said the company plans to connect seven additional wells to the CTP and bring them on stream in 2015.
The CTP produces gas from five wells three fields: North Sidi Ghazy, South Sidi Ghazy, and North West Sidi Ghazy. Gas produced from the North West Khilala field is processed in the North West Khilala gas plant (OGJ Online, Apr. 30, 2014).
The Disouq project encompasses development of seven gas fields in the Nile Delta.
RWE Dea's partner in the project is Egyptian Natural Gas Holding Co. Production is operated by the joint venture Suez Oil Company.
RWE Dea has 10 onshore and offshore concessions in Egypt.
With the launch of the CTP, RWE Dea will boost its oil and gas production in Egypt by 50% to 44,000 boe/d.
SOCAR builds gas-cleaning plant at Baku refinery
State Oil Co. of Azerbaijan Republic (SOCAR) is building a dry gas-cleaning unit at its Heydar Aliyev (formerly New Baku) refinery at Baku in Azerbaijan.
The unit is designed to remove sulfur compounds and carbon dioxide from dry gas produced at the refinery before it is transported via pipeline to an associated ethylene and polyethylene plant operated by SOCAR subsidiary Azerikimya Production Union, SOCAR said.
The project also will contribute to lower sulfur levels in the refinery's diesel production, the company said.
Construction of the unit, which has occurred concurrently with the reconstruction of the refinery's fluid catalytic cracking (FCC) unit No. 55, is scheduled to be commissioned on Sept. 20, SOCAR said.
SOCAR recently completed maintenance work on the atmospheric and vacuum distillation units at the Heydar Aliyev refinery, but the completion of major repair and reconstruction work on the plant's FCC unit has been ongoing (OGJ Online, July 18, 2014).
Turkmen plant to yield gasoline from gas
Construction has begun at Ovadan-Depe near Ashgabad, Turkmenistan, on a 15,500-b/d plant that will make gasoline from natural gas.
The plant will be the first full-scale, commercial facility based on proprietary technology of Haldor Topsoe of Denmark.
Called Topsoe Improved Gasoline Synthesis (Tigas), the catalytic process can use synthesis gas from other feedstocks, including coal, petroleum coke, and biomass.
State-owned Turkmengas owns the facility. Kawasaki Heavy Industries Ltd. and Ronesans Turkmen are handling engineering and construction.
TRANSPORTATION — Quick Takes
NEB hears Aboriginal viewpoint on Trans Mountain
Canada's National Energy Board will hear the viewpoint of Aboriginal groups on the Trans Mountain expansion project on Aug. 25 in Edmonton, the first of four scheduled hearings through Nov. 28.
The hearings were originally scheduled to run throughout August, but after receiving input from several Aboriginal groups, the board amended its hearing schedule to avoid interfering with salmon harvest.
Edmonton hearings are scheduled through Sept. 5. Hearings are also scheduled for Chilliwack, BC, in October; and Kamloops, and Victoria, BC, in November.
The board said evidence from Aboriginals will "make up an important component of the evidence the panel will consider as it decides whether or not to recommend approving the project."
NEB said Trans Mountain submitted its application on Dec. 16, 2013 (OGJ Online, Dec. 17, 2013). The project would expand the existing Trans Mountain pipeline system in Alberta and British Columbia and include 990 km of new line, new and modified facilities such as pump stations and tanks, the reactivation of 193 km of existing pipeline between Edmonton and Burnaby, BC, and expansion of the Westridge marine terminal.
Separately, Kevin Sorenson, Canada's minister of state (finance), participated in an Aug. 20 panel discussion at the 64th Oilmen's Business Forum in Banff, emphasizing the importance of collaborating with Aboriginal communities on resource projects and increasing their participation in pipeline safety operations.
"The best way to achieve our goals is through partnerships, meaningful engagement, and ongoing dialogue among key partners including industry, Aboriginal communities, and governments," Sorenson said.
Dakota Gold to develop Bakken-Three Forks terminal
Dakota Gold Transfer-Plaza LLC plans to develop a crude oil transload terminal in Mountrail County, ND. Sited on 350 acres in the eastern section of the Bakken and Three Forks shale oil producing areas and served by Canadian Pacific Railway (CP), the Plaza Terminal will allow shipment to multiple markets via rail and pipeline.
Dakota Gold is a joint venture between its president and chief executive officer, Cody Moe, and the TrailStone Group, majority-owned by Riverstone Holdings LLC. The Mountrail County Commission approved Dakota Gold's application for a conditional use permit and its request to have the site rezoned for industrial use.
Dakota Gold plans to break ground on Plaza Terminal later this year and expects storage and high-speed rail loading service to be available second-half 2015. The company plans beginning direct truck-to-train transload service roughly 90 days after construction starts.
The terminal, with an initial 70,000-b/d train loading capacity, will aggregate crude oil produced in Mountrail and neighboring counties via gathering pipelines and trucks, providing storage on-site. Initial storage capacity will be 309,000 bbl, with second-phase expansion to more than 600,000 bbl planned. Terminal design includes two loop tracks with storage for one to two additional trains on the leased private rail spur connecting to CP, a covered loading barn, a 14-arm system capable of loading a unit train in about 14 hr, 15 truck unloading bays, and three 103,000-bbl tanks.
Dakota Gold is working with various midstream companies to develop gathering connections to the Plaza Terminal. The company is also talking with pipeline companies to develop outbound pipeline service from the Plaza Terminal.
Dakota Plains Holdings Inc. and Hiland Partners LP last week reported signing an interconnection agreement linking Dakota Plains' Pioneer Rail terminal in New Town, ND, with Hiland's Market Center gathering system crude oil pipeline network. The companies expect to commission the interconnection Oct. 31 (OGJ Online, Aug. 19, 2014).
PAA to build Cushing-to-Memphis pipeline
Plains All American Pipeline LP (PAA) plans to construct a 440-mile, 20-in. crude oil pipeline that will carry as much as 200,000 b/d of sweet crude from the Plains Cushing, Okla., terminal to Valero's Memphis Refinery. The project is expected to cost $900 million and be completed in late 2016.
PAA says the pipeline, to be called Diamond, also will provide access to Valero Energy Partner's Collierville line and is underpinned by a long-term shipping agreement with Valero and a related contract for storage and terminalling services at the Plains Cushing terminal.
Valero holds an option until January 2016 to become a partner in Diamond and purchase 50% interest. PAA says construction of the pipeline will expand upon the refinery's long-term ability to produce gasoline, diesel, and jet fuel for the greater Memphis and eastern Arkansas area.
In addition to Diamond, PAA is currently building the 310-mile, 20-in. Cactus crude oil pipeline from McCamey, Tex., to Gardendale, Tex. The company expects it to cost $350-375 million and enter service first-quarter 2015 (OGJ Online, Apr. 16, 2013).