IGENERAL INTEREST — Quick Takes
Jonah Energy completes purchase of Jonah field assets
Jonah Energy LLC, a Denver-based TPG Capital affiliate, has completed the acquisition of Jonah field operations in Sublette County, Wyo., from Encana Oil & Gas Inc., a wholly owned subsidiary of Encana Corp., for $1.8 billion, effective Dec. 1, 2013.
The Jonah field acquisition, first reported on Mar. 31, encompasses a total productive area of 24,000 acres and more than 1,500 active wells in Jonah field, along with more than 100,000 undeveloped acres in the normally pressured lance area adjacent to Jonah (OGJ Online, Mar. 31, 2014).
Yearend 2013 proved reserves totaled 1.5 tcf of gas equivalent with first-quarter 2014 net production of 311 MMcfed.
This is the first acquisition by Jonah Energy, which was formed by TPG this year to acquire and operate the Jonah field operations. The company said it plans to own and operate additional producing onshore oil and gas properties in North America.
Jonah Energy is led by Tom Hart, chief executive officer, and Craig Manaugh, president and chief operating officer. The company plans to retain the employees currently working in connection with Jonah field and continue investment in the field and adjacent acreage.
Statoil farms out more interest offshore Angola
Statoil ASA has farmed out 5% participating interest in the Eni SPA-operated Block 15/06 offshore Angola to Sonangol EP for $200 million.
"This transaction is part of Statoil's continued optimization process to maximize value and focus financial and organizational capabilities to core assets," said Tove Stuhr Sjoblom, Statoil sub-Saharan Africa senior vice-president. "The transaction will allow Statoil to unlock capital and contribute to improved financial flexibility going forward."
Statoil said the Angolan continental shelf is the largest contributor to its oil production outside Norway and is a key building block for the company's international production growth.
Statoil's equity production from Angola totaled 200,000 b/d in 2013. In addition to the ownership in four producing assets, Statoil also holds participating interests in several other licenses including exploration blocks in the Kwanza basin offshore Angola.
RIL, partners press India over gas price
Reliance Industries Ltd. and partners have issued a notice of arbitration seeking action by the government of India on the price of natural gas produced from the deepwater KG-D6 block in the Bay of Bengal (OGJ Online, Feb. 19, 2013).
Under a formula set by the government in 2013 that was to have provided a transition to arms-length pricing provided by the production-sharing contract, the group has been selling gas at a price of $4.20/MMbtu. The price was to have doubled on Apr. 1 (OGJ Online, July 1, 2013).
Delay of the price increase has created doubts about the ability of the group to sanction investments of nearly $4 billion this year, according to statements by RIL and Niko Resources Ltd., one of the partners with a 10% working interest.
"In addition, this will also delay the ability of the parties to appraise and develop other significant discoveries made last year," the Niko statement said. "Overall, the parties were planning to invest $8-10 billion in the next few years to significantly increase production from the D6 block."
RIL became subject to government pressure to accelerate drilling on the block when production failed to meet expectations.
BP PLC, the other partner, acquired its KG D6 stake in a 2011 purchase of 30% interests in 21 Indian blocks from RIL.
Exploration & Development — Quick Takes
Encana improves Montney shale IP rates
Encana Corp. has increased initial production rates by about 75% in its Montney shale drilling program.
The company is using a revised well design in the Cutback Ridge area in northeast British Columbia that involves longer laterals and more intense stimulation.
Michael McAllister, Encana chief operating officer, said the company significantly increased fracture intensity, cut inner frac spacing to 25 m from 50 m, and kept the sand concentration the same.
"It's somewhat of a game changer for us in the Montney," McAllister told analysts during a May 13 call to discuss first-quarter results.
Encana is partnered with a subsidiary of Japan's Mitsubishi Corp. in certain parts of the Cutback Ridge area.
Encana holds nearly 600,000 net acres in the Montney shale, which spans northeast British Columbia and northwest Alberta. This year's plans call for accelerating development of the oil and liquids-rich portions of the formation. Eight rigs are expected to drill 80-85 net wells.
Encana sold its gas-rich Jonah field operations in Wyoming for $1.8 billion in March and divested East Texas properties for $530 million in April (OGJ Online, Mar. 31, 2014; Apr. 29, 2014). Earlier this month, it established a foothold in the Eagle Ford shale in South Texas, agreeing to pay $1.3 billion to Freeport-McMoRan Oil & Gas for 45,500 net acres in the play's oil window (OGJ Online, May 8, 2014).
KMG EP makes oil, gas discovery in Rozhkovskoye field
KazMunaiGas Exploration Production Joint Stock Co. (KMG EP) reported making an oil and gas discovery in the Bashkirian tier's sediments of the Carboniferous period in Rozhkovskoye field.
On test in reservoirs of the Bashkirian period, the U-24 well flowed at maximum rates of 1,900 b/d of light, dry crude oil and 6 MMcfd of gas through a 9½-mm choke. U-24 was drilled in 2013 in the northeast wing of the field. Previous exploration at this part of the field targeted hydrocarbons in the Bobrikovskiy and Tournaisian horizons, KMG EP said.
"The discovery of Bashkirian deposit on Fyodorovskiy block confirms the high potential of this asset," said Abat Nurseitov, KMG EP chief executive officer.
According to technical audits carried out in accordance with international standards, KMG EP's 2P liquid hydrocarbon reserves in Rozhkovskoye field to 7.9 million tonnes in 2013 from 5.4 million tonnes in 2012. Production at Rozhkovskoye field is due to start in 2017.
Ural Group Ltd. (UGL) is exploring Rozhkovskoye field, and holds a 100% stake in Ural Oil & Gas LLP (UOG), which owns the exploration license for Fyodorovskiy block in the Zelenovsk district of western Kazakhstan, 70 km east of Uralsk. KMG EP acquired a 50% stake in UGL from Exploration Venture Ltd. in 2011.
Central Petroleum starts development of Dingo gas field
Central Petroleum Ltd., Brisbane, has started development of its Dingo gas field in Amadeus basin in Northern Territory 65 km south of Alice Springs.
The company has also been offered a conversion of the field retention license into a 25-year production licence by the Northern Territory government.
The development comprises a field gathering system that will connect two production wells to a central processing plant and a 45-km pipeline to the Northern Territory government-owned Owens Spring electric power station.
Start of gas production is slated for first-quarter 2015.
Earlier this year Central acquired Dingo field, along with producing Palm Valley gas field to the west, from Magellan Petroleum Australia in a deal worth $35 million (Aus.) (OGJ Online, Feb. 19, 2014).
When added to the Palm valley gas flow, Central will supply 3.3 petajoules of gas a year under contract from 2015.
The two fields have a total of 53 bcf of gas in the 2P reserves category and Central says there are more leads and exploration opportunities within its Amadeus basin permits.
Nova Scotia seeks bids in active eastern Canada offshore
Exploration and development remain brisk offshore eastern Canada, provincial officials reported May 6 at the Offshore Technology Conference in Houston.
Nova Scotia on May 5 issued a call for bids covering four blocks on the Scotian Slope east of its offshore gas-producing area.
The area covered by the offering is near current exploration and north and east of areas where BP PLC and Royal Dutch Shell PLC each plans investments totaling $1 billion over the next several years, according to Andrew Younger, the provincial energy minister.
In a press conference at OTC, Younger said Shell is preparing to drill as many as seven wells starting next year in the area covered by its six contiguous blocks. He said company geoscientists are reviewing 10,000 sq km of data acquired in the first 3D wide-azimuth seismic survey ever conducted off Canada, which it completed last year.
On four blocks between Shell's acreage and the producing area, BP soon will begin a 3D seismic survey over a 14,000-sq-km area in 100-3,000 m of water.
Water depths in the parcels newly offered for bid are 100-4,100 m. The two eastern-most blocks lie along the maritime boundary with Labrador and Newfoundland.
A well drilled on the western-most block in 1986 identified a large structure on the upper slope in 1,540 m of water, according to a press statement. The blocks are considered prospective for oil and gas in Cretaceous and Jurassic formations.
The Canada-Nova Scotia Offshore Petroleum Board will accept bids through Oct. 30.
Also at the press conference, Premier Tom Marshall of Newfoundland and Labrador said a combine of Statoil and Husky Energy have two rigs active in the area of their offshore Bay du Nord, Mizzen, and Harpoon discoveries, in the Flemish Pass basin northeast of the province's producing fields in the Jeanne d'Arc basin (OGJ Online, Oct. 8, 2013). In that area, ExxonMobil Corp. is developing Hebron heavy oil field with a concrete gravity platform.
Drilling & Production — Quick Takes
Petrobras starts oil production from Lula field
Petroleo Brasileiro SA has started oil production from well 7-LL-22D-RJS in the Santos basin's presalt Lula field.
This well, which the company says has a production potential of 26,000 b/d, is connected to the Cidade de Paraty floating production, storage, and offloading vessel via a platform-connection system deployed for the first time in the field. The wellhead lies in 2,130 m of water.
Six additional wells will be connected to the platform during the year, of which four will be production wells and two injection wells, ramping up Cidade de Paraty to full production capacity of 120,000 b/d in the third quarter.
Connection of well 7-LL-22D-RJS to the FPSO was completed on May 5, when flexible pipelines were deployed. Cidade de Paraty began operations in June 2013. Well 7-LL-11-RJS was connected directly to the platform and produces 30,000 b/d (OGJ Online, June 10, 2013).
Lula field, where oil was discovered in 2012, is operated by Petrobras with 65% interest (OGJ Online, Apr. 13, 2012). Partners are BG E&P Brasil Ltda. 25% and Petrogal Brasil SA 10%.
QP to invest $10 billion in Bul Hanine redevelopment
Qatar Petroleum (QP) plans to invest more than $10 billion in the redevelopment of Bul Hanine oil field about 120 km offshore Qatar. The project, which is currently at the pre-FEED stage, is designed to prolong the field's life by countering its production decline and doubling its current oil production rate.
QP said the magnitude of its investment reflects the extent of project scope, which includes new offshore central production facilities and a new onshore gas liquids processing facility at Mesaieed, marked by a 150-well drilling campaign between this year and 2028.
New wells will be drilled from the modified wellhead jackets, as well as from 14 new wellhead jackets. Both new and modified wellhead jackets, in addition to associated production and injection flowlines, will form parts of the project works.
All wellheads stream fluids will be processed in the new offshore central complex, comprised of production, compression, utility, and living quarter platforms, with topsides weight ranging from 4,000-14,000 tonnes, the company said.
Produced oil will be sent to Halul Island for export. The produced sour rich gas of about 900 million cu ft/d will travel via a new 150-km subsea pipeline to a new gas treatment facility in Mesaieed for products recovery, where lean sweet gas will be sent via a new subsea pipeline back to the new off-shore facilities for compression and injection.
The redevelopment is part of QP's plan to raise the efficiency of producing fields that were originally developed with older technology, as well as the implementation of various well drilling programs to increase crude oil reserves in fields such as Bul Hanine and Dukhan.
Major reservoir and field-wide studies have been undertaken—including seismic surveys—to reassess the reserves and the long-term production prospects for each field. This has been carried out using improved oil recovery techniques and full-field redevelopment plans, as well as computer modeling and processing, the company said.
LGO to log first Goudron redevelopment well
Leni Gas & Oil PLC (LGO), London, will run electric logs to total depth of 4,212 ft in its first well of a 30-well redevelopment program for Goudron oil field in Trinidad and Tobago.
The well, GY-664, encountered oil-bearing Miocene-Pliocene sandstones with thicknesses totaling an estimated 1,300 ft: more than 350 ft in the Goudron formation, about 720 ft in the Gros Morne formation, and 100 ft in the Lower Cruse formation.
LGO will set 7-in. casing after logging.
It's doing the work under an incremental production service contract it acquired for reactivation of the field in October 2012, when production was less than 40 b/d. LGO has produced more than 100,000 bbl from the field since then.
The license, in which LGO holds a 100% interest, covers 2,875 acres near a wildlife sanctuary in southeastern Trinidad. The field was discovered in 1927 and developed by Texaco during 1956-86. It has direct access to a pipeline to state-owned Petrotrin's 168,000-b/d Point-a-Pierre refinery.
LGO has reactivated 70 old wells, and raised Goudron field output to about 300 b/d.
The company said in April that in addition to reactivating wells, it had refurbished storage facilities and doubled sales-tank capacity, repaired bridges and roads, installed a camp, extended and restored electrical power, and built water-treatment facilities. It its budget LGO assumes output of 65 b/d/well from Goudron redevelopment drilling. The company says some wells might produce as much as 160 b/d each.
On pump, the field has produced a total of less than 4 million bbl from primary production.
LGO said 2P reserves in currently productive zones are estimated at 7.2 million bbl. Meanwhile, 3P reserves are 30 million bbl. Contingent resources, based on enhanced recovery, might be as high as 60 million bbl, LGO said.
PROCESSING — Quick Takes
Aramco lets more contracts for Jazan IGCC plant
Saudi Aramco has let two engineering and construction contract packages to Italy's Saipem SPA for work related to the Jazan IGCC (integrated gasification combined-cycle) power plant project to built adjacent to the 400,000-b/d refinery under development at Jazan Economic City, Saudi Arabia.
The first package includes engineering and construction of a gasification unit, soot-ash removal unit, acid gas removal unit, and hydrogen recovery units, according to Saipem.
Under the second package, Saipem will provide engineering and construction for six sulfur recovery unit trains as well as associated storage installations, the company said.
In addition to engineering and construction activities, Saipem's scope of work under both packages will include procurement, precommissioning, assistance to commissioning, and performance tests of the units and installations, according to the company.
These two packages are part of Aramco's development of the largest gasifier-based power plant in the world, which will use vacuum residue produced by the nearby Jazan refinery as well as high-sulfur fuel oil to produce power for both the refinery and the national grid, Saipem said (OGJ Online, Nov. 13, 2012).
Turkmenistan lets contract for petrochemical complex
State-owned TurkmenGaz has let an $800 million contract to a consortium of engineering firms led by Toyo Engineering Corp. for the construction of a gas chemical complex in the Turkmenbashi district of Balkan Province in western Turkmenistan.
In partnership with Hyundai Engineering Co. Ltd., Hyundai Engineering & Construction Co. Ltd., and LG International Corp., Toyo will be responsible for the engineering, procurement, and commissioning of the gas separation unit as well as ethylene and polypropylene production units, according to Toyo.
The complex—which will use gas sourced from shelf of the Caspian Sea to produce 400,000 tonnes/year of ethylene, high-density polyethylene, and 80,000 tpy of polypropylene—is slated for completion in 2018, Toyo said.
A planned 5 billion cu m/year gas separation unit at the complex will use Toyo's Coreflux technology to enhance recovery of ethane and LPG, while BASF's Oase technology will be used for acid gas removal, according to Toyo.
Additionally, the complex will employ technology from Lummus Technology and W.R. Grace & Co. for ethylene and polypropylene production, respectively, Toyo said.
Turkmengaz plans to export and sell polymer products manufactured at the complex to markets mainly in Asia Pacific, the EU, and Turkey, according to Toyo.
TRANSPORTATION — Quick Takes
South Stream expects first gas from Russia in late 2015
Pipelay for South Stream Line 2 will begin in mid-2015, with first natural gas flow from Line 1 following later that year. Trond Gjedrem, materials manager for South Stream Transport BV, made these remarks May 12 at the Pipeline Technology Conference in Berlin, despite the European Parliament having voted last month that South Stream should not be built.
Also since this vote, OAO Gazprom and Austria-based OMV AG agreed to construction terms allowing South Stream gas to reach Austria by 2017 (OGJ Online, Apr. 30, 2014).
The subsea portion of South Stream will cover 911 km across the Black Sea from Russia to Bulgaria, with four parallel 15.75 billion cu m (bcm)/year lines planned for a total finished operating capacity of 66 bcm/year. New strings would be brought on in staggered succession following Line 1, Gjedrem continued, with Line 2 starting in 2016, Line 3 in early 2017, and Line 4 in late 2017.
Line 1 will use S-lay installation for the landfall segments in both Russia and Bulgaris, with the Saipem 7000 preforming J-lay for the 800-km section of 2,200-m water depth. Multiple 32-in. OD lines were chosen for the project instead of a single larger line due to pressures in water that deep. South Stream expects to lay 2-3 km/day. Each line will use 75,000 joints of pipe.
Trans Adriatic Pipeline takes onshore step
Trans Adriatic Pipeline (TAP) has issued a prequalification notice with the European Union for an engineering, procurement, and construction contract covering onshore work in Greece and Albania (OGJ Online, Dec. 18, 2013). The contract encompasses 760 km of 48-in. gas pipeline and 32 block-valve stations.
The 870-km TAP will be part of the system that will carry gas from Shah Deniz II field in the Caspian Sea to Europe. It will connect with the Trans-Anatolian Pipeline near the Turkish-Greek border at Kipoi and include a section crossing the Adriatic Sea with landfall in southern Italy.
TAP, based in Baar, Switzerland, expects onshore pipeline construction to begin in 2016, with three segments in Greece and two in Albania. The highest elevation is 1,800 m in Albania. The group issued a prequalification notice in April for a contract covering construction of roads and bridges in Albania.
Santos Gladstone LNG project reaches another milestone
The Santos Ltd.-operated Gladstone LNG project has passed another milestone with the final section of the coal seam gas supply transmission pipeline now laid through a tunnel underneath Gladstone harbor to the LNG plant site on Curtis Island.
One hundred and twenty pipe segments, each 36 m long, were welded and gradually pushed through the 4.3-km tunnel using a large hydraulic jack.
The tunnel was first filled with seawater to give buoyance to the 42-in. line as it was pushed through.
The operation brings the 420-km supply pipeline from fields in the Surat and Bowen basins of central-eastern Queensland to its final stages of construction.
The marine crossing pipe will now be connected to the buried mainland and island sections of the line.
Saipem Australia was the pipeline contractor while Theiss was responsible for the tunnel construction.
Pipeline precommissioning works are under way with 50% of the required hydrotesting completed.
