Petronas makes new 100 MMboe discovery offshore Malaysia

Petronas has made major oil and gas discoveries through the drilling of NC3 and Spaoh-1 wells in Blocks SK316 and SK306 offshore Sarawak.

In March 2010, successful drilling of the NC3 wildcat well and a subsequent appraisal well brought significant discovery for Petronas in Block SK316 with early estimation of 2.6 trillion standard cubic feet (tscf) of net gas in place. The wells were each drilled to a depth of almost 4,000 meters below sea level. Additionally, production flow test results of the wells demonstrate that the field is technically producible.

The Spaoh-1 well of 3,000m drilling depth, located in Block SK306, shows similar promise. It was drilled in December 2010 and found both oil and gas. The preliminary evaluation indicates around 100 million barrels (mmstb) of oil and 0.2 tscf of gas in place, respectively. Currently, the well is being prepared for production testing.

These discoveries support Petronas' strategy to intensify exploration activities in Malaysia and is expected to further enhance exploration potential offshore Sarawak.

In the next three years, over 50 exploration wells are expected to be drilled offshore Malaysia by Petronas and its production sharing contractors. These activities, especially if they result in discoveries, are expected to spur business opportunities in the oil and gas industry and will promote upstream investment in the country.

Ecopetrol announces discovery in Putumayo

Ecopetrol S.A. informs that it has proven the presence of hydrocarbons at the exploratory well Tinkhana-1, located in the block known as Western Area (Area Occidental) in Putumayo.

The Tinkhana-1 Well produced 140 barrels of oil per day during initial testing - Ecopetrol is the operator and holds a 100% stake in the block - The well is located 4.8 kilometers from Orito. The well is part of exploratory work being carried out pursuant to the Western Area Production Agreement entered into with the National Hydrocarbon Agency, in which Ecopetrol holds a 100% interest.

The well is located within the jurisdiction of the municipality of Orito, 4.8 kilometers northeast of Quriyana field, where on April 6, 2009 Ecopetrol announced the presence of hydrocarbons at another well.

Tinkhana-1 commenced drilling operations on November 17, 2010, reaching a final depth of 6,812 feet, the equivalent of more than two kilometers.

Ecopetrol is currently moving ahead with initial well testing on the Lower Caballos Formation, which, with original discovery pressure at a thickness of 16 feet, is producing an average oil flow of 140 BOPD of 25 degree API gravity.

Ecopetrol's CEO Mr. Javier Gutierrez Pemberthy said, "It is satisfying to have this first find of 2011 recorded in the Putumayo basin, an area of major hydrocarbon potential. In our favor also is the production and transport infrastructure already in place, which could allow Tinkhana-1's production to move at a faster pace, as well as that of other projects which have proven successful in that region of the country."
Ecopetrol will continue running tests on the Caballos formation in the weeks to come. A following evaluation will be used to determine the well's size and production potential.

BP to use mobile drilling facility Polar Pioneer on Skarv Field

BP Norge AS (BP) has received consent to use the mobile drilling facility Polar Pioneer on the Skarv field in the Norwegian Sea.

The consent relates to drilling of production wells on the Skarv field in the period April 2011 to May 2013.

Skarv is located approximately 35 kilometres southwest of the Norne field in the northern part of the Norwegian Sea. The development is a unitisation of the 6507/5-1 Skarv and 6507/3-3 Idun deposits.

BP has previously received consent to use the mobile facility Borgland Dolphin for drilling a total of 17 production wells on the deposits in the Skarv development. Polar Pioneer is taking over the work at Skarv following Borgland Dolphin.

Skarv will be developed with a floating production facility (FPSO), with subsea templates on the seabed. The field is expected to start producing in 2011.

The licensees are BP (operator with an ownership interest of 23.84 per cent), E.ON Ruhrgas Norge AS (28.08 per cent), PGNiG Norway AS (11.92 per cent) and Statoil Petroleum AS (36.16 per cent).
Polar Pioneer (above) is operated by Transocean Offshore and is a semi-submersible drilling facility built at Hitachi Zosen, Ariake, Japan.

The facility received the PSA’s Acknowledgement of Compliance (AoC) in May 2004.

San Leon completes 3D seismic program in Poland

San Leon has completed a 60 sq. km 3D seismic program over the Szczecinek block in northern Poland. San Leon (50%) and its partner Gas Plus International B.V. (50%) are currently processing the new data and plan to begin detailed interpretation in March with a view to drilling an exploration well later this year. The survey is targeting the high potential "Sylvia" oil prospect in the Main Dolomite of the Permian Zechstein Formation. "Sylvia" is an analogue to two of the largest oil discoveries in Poland, which were only discovered from the early 1990's through early 2000's with potential reserves in excess of 100 mmbbls of recoverable oil.

Oisín Fanning, Chairman of San Leon commented, "I am delighted that our exploration team will now have the data necessary to evaluate this high potential oil play. The new seismic will enable our in-house team to locate and permit well locations for our planned drilling program."

McMoRan discovers additional hydrocarbons at Davy Jones appraisal well

McMoRan announced results from interim logging operations at the Davy Jones offset appraisal well located on South Marsh Island Block 234 in 20 feet of water.

The Davy Jones offset appraisal well (Davy Jones No. 2) is drilling below a true vertical depth of 27,900 feet. Preliminary data from wireline logs over the interval from 25,400 feet to 27,300 feet, which continue to be evaluated, indicated over 200 feet of gross sand and approximately 100 net feet of sand, based on intermittent porosity data available, in multiple Wilcox zones that appear to be hydrocarbon bearing. Additional data will be required to complete the evaluation.

Paleo and log data indicate the offset well to be approximately 1,300 feet structurally high (up dip) to the Davy Jones discovery well (Davy Jones No. 1) and confirm the major structural features of the Davy Jones prospect. All but one of the sands in the discovery well appear to be present in the offset well, which would confirm sand continuity on the Davy Jones feature. This information also suggests that the Wilcox sands at Davy Jones could be sheet sands (not channel sands) and could be present at other McMoRan prospects on its acreage position within the Davy Jones trend. These results support the wedge effect seen on other large sub-salt structures in the Gulf of Mexico, where sands generally thicken on the flanks of the structure.

The Davy Jones No. 2 well is located two and a half miles southwest of the Davy Jones No. 1 well. Based on analogies with a number of other large sub-surface structures in the Gulf of Mexico, McMoRan believes there is potential for thicker sands on the northern part of the structure, which is closer to the depositional source.

McMoRan is deepening the well to evaluate additional objectives, including possibly the Upper Cretaceous (Tuscaloosa) sections. Paleo data at 27,742 feet indicates the Davy Jones No. 2 well is in the Midway formation, which is a geologic interval below the Wilcox and above the Upper Cretaceous (Tuscaloosa). McMoRan’s interpretation indicates that the Upper Cretaceous (Tuscaloosa) section, if present in deeper horizons on the Shelf at Davy Jones, would be correlative with the prolific Tuscaloosa trend onshore South Louisiana. If confirmed, McMoRan believes the combination of productive Wilcox and Tuscaloosa sands on the same structure could enhance the prospectivity of Davy Jones and the value of McMoRan’s other ultra-deep prospects on its acreage position within the Davy Jones trend.

As previously reported, in January 2010 McMoRan logged 200 net feet of pay in multiple Wilcox sands in the Davy Jones No. 1 well on South Marsh Island Block 230. In March 2010, a production liner was set and the well was temporarily abandoned to prepare for completion. McMoRan has ordered long-lead time and specialty items, including a 25,000 PSI production tree, safety valve and blowout preventer, and expects to complete and flow test the well by year-end 2011.

Davy Jones involves a large ultra-deep structure encompassing four OCS lease blocks (20,000 acres). McMoRan holds a 60.4 percent working interest and 47.9 percent net revenue interest in Davy Jones. Other working interest owners in Davy Jones include: Energy XXI (15.8%), Nippon Oil Exploration USA Limited (12%), W.A. "Tex" Moncrief, Jr. (8.8%) and a private investor (3%).

Chevron makes tenth discovery offshore Australia with Gorgon gas find

Chevron announced a further drilling success in the Carnarvon Basin offshore Western Australia.

The Orthrus-2 well is located in the WA-24-R permit area approximately 60 miles (100 kilometers) northwest of Barrow Island. The well was drilled to a total depth of 14,098 feet (4,297 meters).

Combining both appraisal and exploration objectives, the well encountered 243 feet (74 meters) of net gas pay, of which 102 feet (31 meters) of net gas pay was encountered in a deeper, previously unexplored target interval in the Orthrus field.

George Kirkland, vice chairman, Chevron, said, "The find at Orthrus-2 represents our tenth offshore discovery in Australia within the past 18 months. Our successful drilling program offshore Western Australia demonstrates Chevron's global exploration capability and our commitment to technical excellence and safe operations."

Jim Blackwell, president, Chevron Asia Pacific Exploration and Production, said, "Our leading Carnarvon Basin leasehold and our accompanying exploration success help underpin further expansion opportunities on the Gorgon Project."

Chevron's Australian subsidiary is the operator of WA-24-R and holds a 50 percent interest, while Mobil Australia Resources Company Pty Limited holds 25 percent. Shell Development (Australia) Pty Ltd and BP Exploration Alpha Ltd each hold a 12.5 percent interest.

Oil demand spurs increasing E&P activity in Texas

The Texas Petro Index (TPI), a composite measure of several economic indicators in the Texas upstream petroleum industry, indicates that the oil and gas business in the state grew at a steady pace in 2010.

The TPI, produced by the Texas Alliance of Energy Partners, showed a 12-month increase of 22.1%, indicating that the energy industry is the number one factor driving job creation in the Lone Star state. This was due primarily to strong oil prices, which averaged $75.96/bbl in 2010, 30.3% higher than in 2009.

Natural gas prices were up, too, averaging $4.32/Mcf last year, a 19% increase over 2009. But abundant supplies overwhelmed the modest demand growth, and acted as a drag on gas prices. After starting off 2010 above $5/Mcf, gas prices sagged to a December average of $4.19/Mcf. In all, the upstream petroleum industry accounted for about 8.5% of the state’s economy.

Heritage Oil discovers major gas field in Iraq’s Kurdistan

Heritage Oil Plc, an independent E&P company, announced a major gas discovery in the Kurdistan Region of Iraq. Following completion of the deepening and testing of the Miran West-2 well, management estimates that the Miran West structure has P90-P50 gross in-place volumes of gas of between 6.8 and 9.1 TCF with 42–71 million bbl of condensate and 53–75 million bbl of oil.

The Miran West-2 well was initially designed as an appraisal well for the Cretaceous section and was subsequently modified to assess the exploration potential of the deeper formations, eventually being drilled to a total depth of 4,426 m. The well results have confirmed three additional pay zones within Lower Cretaceous and Jurassic formations, in addition to the pay zone identified in the Upper Cretaceous in the Miran West-1 well.

Additionally, well results have established that the Miran Field contains two hydrocarbon systems, with oil in the shallower Upper Cretaceous section and wet gas/condensate within the deeper Lower Cretaceous and Jurassic formations. This has resulted in the previously anticipated prospective oil resources in the Lower Cretaceous, identified on the basis of oil shows in the Miran West-1 well, being proven to be wet gas/condensate.

The test rates were constrained by the capacity of the surface equipment and the well test data indicate that individual test intervals could produce at rates of 40 MMscfd with the well capable of producing at a rate of over 100 MMscfd when it is placed on production. The proven hydrocarbons in the Upper Cretaceous can be accessed commercially on the structure as demonstrated by the 8,000-10,000 bopd potential of the Miran West-1. Furthermore, future drilling techniques will maximise the benefit from the fracture networks in order to achieve optimal production rates.

Petrobras makes oil discovery is ultra-deep waters in in Santos Basin

Petrobras has made a discovery of good quality oil in the pre-salt reservoirs of Block BM-S-9 in the ultra-deep waters of the Santos Basin. The discovery was made in well 3-BRSA-861-SPS, informally known as Carioca Nordeste.

The consortium will give continuity to the investments provided in the Discovery Evaluation Plan, presented to the National Petroleum Agency in 2007, to confirm the dimensions and characteristics of the reserve. Carioca Nordeste lies in a water depth of 7,057 ft (2,151 m) about 171 miles (275 km) off the state of Sao Paulo in the evaluation area of the Carioca well.
Petrobras is operator with 45% interest; BG Group owns 30% and Repsol has 25%.

ExxonMobil and Rosneft to explore for Black Sea oil

ExxonMobil the Russian state oil company Rosneft have entered into an agreement for joint development of oil and gas resources in the Black Sea, which includes an initial focus on oil exploration and production in the Tuapse Trough in the Russian Black Sea basin. The Tuapse Trough is an 11,200-sq-km deepwater offshore area along the Black Sea coast of the Krasnodar region.
The agreement allows Rosneft and ExxonMobil to pursue additional opportunities to expand Black Sea energy sector cooperation in areas such as additional exploration and production, crude oil sales to Rosneft's Tuapse refinery and other Black Sea markets, development of regional transportation infrastructure, and deepwater offshore technology research and development.
Igor Sechin, deputy Prime Minister of the Russian Federation, said "Cooperation with ExxonMobil once again underscores our commitment to the principles of transparency and vision of the Russian energy industry as a part of an integrated global marketplace. ExxonMobil technologies will effectively complement Rosneft's experience and resources. Development of this area will become the springboard for full-scale Black Sea basin development, and this challenge will require coordinated efforts of many nations and companies in the region."
The companies plan to apply their experience and expertise to implement this project through application of new technologies and the highest standards of environmental safety.
Rex Tillerson, chairman and CEO of ExxonMobil, said that he welcomed the opportunity to expand ExxonMobil’s activities with Rosneft. "ExxonMobil will bring its technology, project execution capabilities and innovation to complement Rosneft's strengths and experience in the region. We will build on the successful relationship we have with Rosneft through the Sakhalin 1 project to help meet energy needs in Russia and the wider Black Sea area,” Tillerson said.
Rosneft President Eduard Khudainatov said, "Commencement of implementation of the second major contract with a leading international partner this year demonstrates Rosneft's capabilities and its management's focus on creating a global energy company capable of undertaking the most complex offshore projects."

Total reports discoveries offshore Congo

Total reported discoveries in the Moho-Bilondo License offshore the Republic of the Congo. The discoveries, Bilondo Marine 2 and 3 wells (BILDM-2, BILDM-3), were drilled to a total depth of 5,906 ft in the Tertiary series and flowed successfully. Both wells encountered a gross reservoir of 253 and 144 feet, respectively, and they did not encounter water.

Total commented that these discoveries suggest a potential extension of phase 1, which is already producing in the southern part of the license. This first phase, brought on stream in 2008, was the first ultra-deepwater field developed in the Republic of the Congo. The field is currently producing nearly 90,000 bopd from 13 subsea wells tied into a floating production unit. The oil is exported to the onshore Djeno terminal. Total operates the license, holding a 53.5% interest; Chevron holds 31.5%; and Societe Nationale des Petroles du Congo holds 15%.

GAC and TransAtlantic sign agreement to support Arctic exploration

GAC Norway has welcomed the TransAtlantic ice-breaking Anchor Handling Tug Supply (AHTS) ‘Tor Viking II’ to Hammerfest after its transit of the ice-bound North East Passage, under a new agency agreement that brings together two companies with plans for Arctic expansion.

Berthing at the northern Norwegian port marked the end of the vessel’s voyage from Alaska to Europe through frozen seas, shaving three weeks off the sailing time needed to take the traditional route through the Panama Canal. It was the first time a commercial vessel had used the Northern Sea Route so late in the year.

Arctic expertise
“The ice situation became more and more difficult as we proceeded to the north-west from the Bering Strait,” says Capt Almkvist. “With ice over 60cm thick and with ridges several metres thick, the passage was more difficult this time compared to our voyage in November 2007.

“When we arrived at Hammerfest, GAC had arranged all necessary clearances and requirements for our stay. Their pre-arrival information and service was very professional and helpful.”

Oil & gas exploration
Significant future oil and gas extraction is expected to take place in new fields in the Arctic waters, promoting demand for specialist ice-going offshore vessels with specially-trained crews.

GAC’s local expertise and global experience in the energy sector, coupled with TransAtlantic’s proven capabilities in executing operations in ice and harsh weather conditions, look set to play an important part as oil and gas exploration gathers momentum.

Supporting expansion
Göran Eriksson, TransAtlantic’s Manager Commercial Operations, says: “2010 was a busy year for us in Arctic waters. To succeed in remote areas and harsh environments, it is essential to have a strong and competent port agent like GAC on which to rely.”

GAC Norway’s Managing Director, Ahmet Özsoy, adds: “We have expanded our operations in the Arctic with branches in Spitsbergen as well as Hammerfest, as part of our strategic plan to grow further in the region.

“We are proud and happy to have been appointed to handle TransAtlantic’s agency and logistics needs in northern Norway and look forward to helping both companies achieve their Arctic ambitions.”