ROGTEC Magazine - Russian Oil & Gas Technologies - News, Reviews & Articles

ROGTEC Magazine - Russian Oil & Gas Technologies - News, Reviews & Articles

Lukoil 1h 2012 Net Income Reached $4.8 Billion, EBITDA Amounted to $8.8 Billion

Friday, August 31st, 2012

LUKOIL has published consolidated US GAAP financial statements for the first half of 2012.

The Company’s net income was $4,807 million in the first half of 2012, which is a 29.0% decrease y-o-y. EBITDA was $8,808 million, which is a 17.6% decrease y-o-y. Negative effect of foreign exchange differences had a significant impact on net income. Nevertheless, LUKOIL continues to show the best financial efficiency in the industry.

Sales revenues reached $67,658 million (+4.8% y-o-y). Net debt in the first half of 2012 decreased by $893 million or by 14.1% in comparison with the beginning of the year.
Capital expenditures including non-cash transactions in the first half of 2012 were $5.4 billion. Free cash flow in the first half of 2012 was$1,699 million.

In the first half of 2012, lifting costs per boe of production were $4.86, which is a 2.0% decrease y-o-y. Cost inflation was offset by ruble depreciation in the second quarter of 2012 and efficient cost management.
In the first half of 2012, LUKOIL Group total hydrocarbon production available for sale reached 395.1 million boe, which is a 0.2% decrease y-o-y. Crude oil and natural gas liquids production of LUKOIL Group in the first half of 2012 totaled 336.4 million bbl. Production of gas available for sale increased by 10.1% y-o-y, to 9.96 bcm, mainly due to launch of new gas projects in Uzbekistan.

In the first half of 2012 throughputs at the Company’s refineries (including its share in crude oil and petroleum product throughput at the ISAB and Zeeland refining complexes) decreased by 1.3% y-o-y and reached 1.280 million barrels per day. Output at the Company’s refineries in Russia decreased by 3.6% y-o-y mainly due to scheduled maintenance at the Nizhny Novgorod Refinery in the first half of 2012, while output at the Company’s international refineries increased by 6.6% y-o-y mainly due to an increase in shareholding in ISAB refining complex from 49% to 60%.
Measures aimed at higher efficiency and cost control allow the Company to increase net income and operating efficiency.



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Lukoil Board of Directors Sumarizes Company’s Performance in the First Half of 2012

Friday, August 31st, 2012

The OAO LUKOIL Board of Directors has reviewed Group’s preliminary results for the first half of 2012 and investment program realization progress in 2012 in Moscow today.

The geological exploration completed within the reporting period gave LUKOIL an increase in the reserves of oil in the amount of 11.6 million tons, of gas in the amount of 6.9 billion cu. m., and of condensate by 400,000 tons, which in total exceeded the same figure of 2011 by 41%.

The major oil reserves increase was registered at the Vostochno-Lambeyshorskoye field (the Komi Republic), Tevlinsko-Russkinskoye field (West Siberia), and Gagarinskoye field (Perm Region), while the growth in gas reserves was recorded at the Pyakyakhinskoye field (Yamal).

The oil output in the Russian Federation totaled 41.8 million tons, while abroad the figure came to 2.9 million tons, which is cumulatively 2.0% less than in the same period of 2011.

The commercial gas production by the LUKOIL Group organizations came to 9.96 billion cu. m., which exceeded the level of the first half of 2011 by 10%.

The associated petroleum gas utilization rate in Russia came to 87.2%, which is 10.3% higher compared with the same period of 2011. RUR 2.7 billion were allocated to the construction and reconstruction of 53 associated petroleum gas utilization facilities in the first half of 2012.

The Company continued to introduce and test new technologies, specifically, the drilling of horizontal wells by means of multi-scenario completion, including horizontal wells with multi-zone hydrofracturing, as well as testing new polymer solutions for water shut-off.

Oil processing at the Company’s refineries (including mini-refineries and stakes in the ISAB and Zeeland foreign complexes) remained practically unchanged and totaled 31.8 million tons, including 21.7 million tons at Russian refineries (including mini-refineries) and 10.1 million tons abroad.

Within the reporting period, the Russian refineries raised their production of high-octane gasolines by 13.1% as compared to the first half of 2011; their share in the overall production volume of automobile gasolines in Russia reached 99.5%.

The investment costs of LUKOIL Group within the reporting period came to USD 5.4 billion, which is 50% greater than the figure of 2011.

The total amount of tax proceeds and customs fees transferred by the LUKOIL Group organizations to the budget of the Russian Federation in the first half of 2012 was RUR 551 billion, which exceeded last year’s figure in the same period by 17%.

Cadogan Petroleum plc: Half Yearly Report for the Six Months ended 30 June 2012

Friday, August 31st, 2012

Cadogan Petroleum plc (“Cadogan” or the “Company”), an independent oil and gas exploration, development and production company with onshore gas, condensate and oil assets in Ukraine, announces its unaudited results for the six months ended 30 June 2012.

·     Continued production from the Zagoryanska, Debeslavetska and Cheremkivska licences at a combined rate of about 51 mcm/day of gas and 5.1 tons/day of condensate

·     Joint venture established to develop unconventional shale gas in Lviv western Ukraine announced

·     New well at Zagoryanska 11 drilled

·     Total capital expenditure of $16.2 million during the first half of 2012 (30 June 2011: $3.0 million)

·     Decreased operating costs to $4.9 million (H1 2011: $5.4 million) despite significant increase in activity

·     Net cash and cash equivalents at 30 June 2012 of $51.3 million (31 December 2011: $65.0 million)

Commenting on the results, Bertrand des Pallieres Chief Executive Officer said:

“As predicted in 2011 the Company has made significant progress in its strategic alliances with both state companies and major oil companies and is developing exciting opportunities for the business. Although the results of the shale gas initiative will take time to be realised, Cadogan is able to participate in this type of venture without the usual significant levels of capital. A further initiative is being considered in the shallow Black Sea area. These activities continue to demonstrate our aim to become a key player in accelerating the transformation of the energy sector in Ukraine.”

Board Statement


During the first half of 2012 the Group continued to focus on developing its assets in Ukraine, with continuing production from one major asset in eastern Ukraine and from three minor assets in western Ukraine. Although significant increases in production from new assets have yet to be achieved,  management has in 2012 run a significantly larger capital investment programme than in previous years, with no corresponding increase in operating costs due to a significant management focus on productivity initiatives.

In June 2012 Cadogan with its joint venture partner, Ukrainian state-owned National Joint Stock Company Nak Nadra Ukrayny (“Nadra”), entered into a Share Purchase Agreement with Eni S.p.A (“Eni”), the Italian integrated energy company, whereby Eni will acquire a stake in the  joint venture established by Nadra and Cadogan, Ukrainian company LLC Westgasinvest. LLC Westgasinvest currently holds subsoil rights to nine unconventional (shale) gas license areas in the Lviv Basin of Ukraine, totalling approximately 3,800 square kilometres of acreage. The Lviv Basin is considered to be one of the most attractive basins in Europe for the exploration of unconventional gas, being a continuation of the Lublin Basin in Poland which has already attracted substantial interest from the hydrocarbon industry.

Under the transaction, Eni will acquire 50.01% of LLC Westgasinvest from the joint venture parties and will fund an initial exploration program. Cadogan had transferred ownership of its two west Ukraine licences, Debeslavetska and Cheremkhivska to the joint venture. Following the conclusion of the transaction Cadogan will retain ownership of 15% of LLC Westgasinvest. The transaction remains conditional on achieving certain conditions precedent including Ukraine anti monopoly clearance and this is on target to occur by the end of September. Cadogan remains the operator for its existing conventional activities at Debeslavetska and Cheremkhivska and will keep the economic benefit from the conventional activities on these two licenses.


During the period to 30 June 2012 the Group continued to operate safely and efficiently.

Since the end of the half year the Group has concluded the drilling activity on its Zagoryanska 11 well and the data acquisition programme is underway. The results will be announced once the full programme and validation has been concluded. Results of the various Zagoryanska workovers of the wells acquired in 2010 that were initially drilled in the Soviet era have not been in accordance with expectations, but the information gathered is being compiled into a further analysis of the Zagoryanska fields and the adjacent Pirkroskvoe field to identify reservoir structures. The rig used on the Zagoryanska 11 drilling project has been moved to another major oil company project in eastern Ukraine, but will remain available to Cadogan for further projects in 2013.

Operations at Pokrovskoe remain temporarily suspended. The Pokrovskoe 2a well was drilled to 4,783 metres into the V22 level of the Upper  Visean. The Logs acquired  indicated the presence of hydrocarbons in the lower part of the well and a decision was taken to deepen the well by approximately 350 metres. Whilst pulling out of the hole the running string became stuck and subsequent fishing operations with the limited equipment available in country has not allowed the running tool to be recovered. Management will evaluate the most effective option, amongst those available, to re-enter the well. After analysis of the results for the Pokroskvoe 1 well, deepened in 2011, and the Pokroskvoe 2a wells, Eni advised Cadogan that it did not intend to exercise its option to acquire a further 30% of the share capital of Pokroskvoe Petroleum BV. The option formed part of the transaction entered into with Eni in July 2011.

Production from the Zagoryanska, Debeslavetska and Cheremkivska licences continued at a combined rate of approximately 51 mcm/day of gas and 5.1 tons/day of condensate.


Under the October 2009 settlement with Global Process Systems Inc (GPS), the Group is entitled to a payment of $37.5 million. To date $7.5 million has been received but the remaining $30 million due to the Group in 2011 has not been received. As a consequence of this non-payment the Group rescinded GPS’s exclusive right to sell the plants contained within the settlement agreement and started legal proceedings to recover the amounts due. The Group retains legal title to both plants and management continues to expect to recover value of at least $30 million due to the Group through a sale of the plants and recovery through litigation.

Financial position

At the date of this report, the Group had cash and cash equivalents of approximately $46.9 million. The Directors believe that the capital available at the date of this report is sufficient for the Company and the Group to continue operations for the foreseeable future.

Changes to the board

On 26 January 2012 Adelmo Schenato was appointed a director of the Company and became the Group’s Chief Operating Officer. On 19 June 2012 Ian Baron resigned as a director of the Company. Mr Alessandro Benedetti resigned as a director of the Company on 27 June 2012.


Cadogan continues to aggressively develop and manage its portfolio of assets in Ukraine in order to fully exploit substantial industry changes taking place there. The Board believes that this strategy will allow the Company to develop into a significant player in the potential rich Ukraine energy sector.


Operations review

Reserves and resources

As at 30 June 2012 the Group held working interests in nine (2011: nine) gas, condensate and oil exploration and production licences in the east and west of Ukraine. All these assets are operated by the Group and are located in either the Carpathian basin or the Dnieper-Donets basin, in close proximity to the Ukrainian gas distribution infrastructure. The Group’s primary focus is on the four licences where the main reserve and resource potential is located, Zagoryanska, Pokrovskoe, and Pirkovskoe in the Dnieper-Donets basin of east Ukraine and Bitlyanska, in the Carpathian Basin of west Ukraine.

Summary of the Group’s licences held at 30 June 2012
Working interest (%) Licence Expiry Licence type(1)
Major licences      
40.0 Zagoryanska April 2014 E&D
70.0 Pokrovskoe August 2016 E&D
100.0 Pirkovskoe October 2015 E&D
96.5 Bitlyanska(2) December 2014 E&D
Minor licences      
October 2026
September 2016
49.8 Cheremkhivska(3) May 2018 Production
100.0 Slobodo-Rungerska April 2016 E&D
95.0 Monastyretska November 2014 E&D

(1)    E&D = Exploration and Development.

(2)    The working interest on the Bitlyanska licence declines on a stepped basis, every five years after the commencement of production on each well. The Joint Activity Agreement (‘JAA’) also distinguishes working interests on new wells and work over wells with the former offering a higher share to the Group. Effective working interests are shown above.

(3)    The working interest on Debeslavetske and Cheremkhivske licences did not change for the conventional gas as the result of the transaction described in the Board Statement above.


The following are updates to the full Operations Review contained in the Annual Financial Report for 2011:

Zagoryanska licence

In 2009 the Zagoryanska 3 well was perforated and commercial flow rates were achieved. Production from the well  commenced in August 2010 at a flow rate of 55 mcm/day (2 million scf/day) of gas and 15 t/day (120 bpd) of condensate and the well was tied into the Group’s Zagoryanska gas treatment plant. Average monthly gross production rates during the first half of 2012 were 30 mcm/day gas (H1 2011: 35 mcm/day) and 5.1 t/day condensate (H1 2011: 8 t/day).

As required by the work programme on the licence, a new well has been drilled to 5,180 metres at Zagoryanska 11. The well has been completed and a data acquisition programme is being carried out, and the results will be available by the end of Q3 2012.  The rig used on the Zagoryanska 11 drilling project has been moved to another major oil company project in eastern Ukraine. As required by the licence, further geological and economic estimation of hydrocarbon reserves, seismic interpretation, modelling and geological studies of the field are on-going.

Following the purchase of the Zagoryanska 3 well in 2010, (which it was previously renting), together with four additional wells on the field a work over plan was prepared for three of the four additional wells (Zagoryanska 1, 2 and 8). Zagoryanska 1 and 2 wells have been worked over, and work over operations are concluded and both wells are presently being  monitored; the work over of Zagoryanska 8 identified issues within the old well that could not be resolved with the fishing equipment available in country and is temporarily abandoned.

Pokrovskoe licence

At Pokrovskoe 2a the well was drilled to a casing point at 4,783 metres in 2012 where the logs acquired indicated the presence of hydrocarbons in the lower part of the well and a decision was taken to deepen the well by approximately 250 metres. Whilst pulling out of the hole the running string became stuck and the limited fishing equipment available in country prevented the running tool from being recovered. The well has therefore been suspended while future options are considered for the well. After analysis of the results for the Pokroskvoe 1 well, deepened in 2011, and the Pokroskvoe 2a wells, Eni advised Cadogan that it did not intend to exercise its option to acquire a further 30% of the share capital of Pokroskvoe Petroleum BV. The option formed part of the transaction entered into with Eni in July 2011.

Pirkovskoe licence

No activity to report up to the date of this report.

Bitlyanska licence area

No activity to report up to the date of this report.

Minor fields

The Group has a number of minor licence areas located in western Ukraine. These include the following:

·      Debeslavetska Production licence area

The field is currently producing 101.4 boepd (full year 2011 was 84.0 boepd). The planned compressor maintenance is under schedule.

·      Cheremkhivska Production licence area

This licence is currently producing 23.0 boepd (full year 2011 was 32.8 boepd).

·      Monastyretska licence area

After re-entry of the Blazhiv 1 well in 2011, minor oil production was re-established at the rate of 16 bopd. A basic hydraulic formation cleaning on the well was conducted; and present production is averaging 20 – 25 bopd. Well behaviour is being monitored and further actions are being considered.


Financial Review


In the six months ended 30 June 2012 the Group mainly focused on exploration activity at Pokrovskoe and appraisal activity at Zagoryanska fields together with its joint venture partner Eni. In total $16.2 million was spent on capital expenditure, which was a primary reason for the cash position to decrease to $51.3 million as at 30 June 2012 from $65.0 million as at 31 December 2011.

Income statement

Loss before tax was $7.1 million (30 June 2011: $6.2 million, 31 December 2011: profit – $152.6 million). Revenues of $2.7 million (30 June 2011: $4.4 million, 31 December 2011: $7.0 million) comprised sales of gas from the Debeslavetska, Cheremkhivska fields and Zagoryanska 3 well. Cost of sales, which represents production royalties and taxes, depreciation and depletion of producing wells and direct staff costs amounted to $1.9 million (30 June 2011: $3.5 million, 31 December 2011: $6.3 million) to give a gross profit of $0.8 million (30 June 2011: $0.8 million, 31 December 2011: $0.7 million). In addition, an increase in the gas price in Ukraine enabled gross margin to increase to 30% from 19% for the comparative period in 2011.

·   Other administrative expenses of $4.9 million (30 June 2011: $5.4 million, 31 December 2011: $11.6 million) comprise staff costs, professional fees, Directors’ remuneration, depreciation charges on non-producing property, plant and equipment.

·   Net impairment charges of $2.0 million (30 June 2011: $0.3 million reversal of impairment, 31 December 2011: $2.8 million) relates to Ukrainian VAT impairment.

·   Other operating loss of $1.1 million (30 June 2011: $2.0 million, 31 December 2011: income – $4.6 million) relates to net foreign exchange losses (30 June 2011: $2.0 million, 31 December 2011: gain – $2.4 million) mainly on the translation of the USD denominated monetary assets held by the UK companies whose functional currency is GBP.

Profit on disposal of subsidiaries and other losses for the year ended 31 December 2011 relate to the Eni transaction completed in July 2011 (refer to note 39 to the Consolidated Financial Statements for year ended 31 December 2011).

Cash flow statement

The Condensed Consolidated Cash Flow Statement on page 13 shows expenditure of $6.1 million (30 June 2011: $2.0 million, 31 December 2011: $16.9 million) on intangible Exploration and evaluation assets (E&E) and $10.0 million (30 June 2011: $0.9 million, 31 December 2011: $4.4 million) on Property, plant and equipment (PP&E). In addition, the Group received $4.1 million (30 June 2011: $nil, 31 December 2011: $58.0 million) as a part of deferred consideration from disposal of subsidiaries in 2011.

Net cash outflow from operations has decreased to $2.2 million during six months ended 2012 from $3.5 million in the same period of 2011 mainly due to changes in the working capital.

Balance sheet

As at 30 June 2012, the Group had net cash and cash equivalents of $51.3 million (30 June 2011: $30.9 million, 31 December 2011: $65.0 million). Intangible E&E assets of $71.7 million (30 June 2011: $8.4 million, 31 December 2011: $66.0 million) represent the carrying value of the Group’s investment in exploration and appraisal assets, mainly at Pokrovskoe licence. It also includes $40.3 million of fair value uplift recognised in 2011 from the valuation of the 70% jointly-controlled interest in the former subsidiary which holds the licence. The PP&E balance of $107.9 million (30 June 2011: $53.2 million, 31 December 2011: $99.4 million), comprised of the cost of developing fields with commercial reserves and bringing them into production. It includes $40.0 million of fair value uplift recognised in 2011 from the valuation of the 40% jointly-controlled interest in the former subsidiary which holds Zagoryanska licence. Trade and other receivables of $58.5 million (30 June 2011: $35.8 million, 31 December 2011: $66.3 million) include $30.0 million (30 June 2011: $30.0 million, 31 December 2011: $30.0 million) receivables in respect of the settlement with GPS, $24.7 million (30 June 2011: $nil, 31 December 2011: $29.1 million) represent deferred and contingent consideration for the disposal of two of Group’s subsidiaries to Eni in July 2011 and $1.1 million prepayments (30 June 2011: $3.3 million, 31 December 2011: $4.3 million) mostly relate to prepayments made to contractors in Ukraine for the drilling and work over campaign.

Related party transactions

No material transactions have taken place with related parties during the six months to 30 June 2012.


There has not been any change to the commitments and contingencies reported as at 31 December 2011 (refer to page 64 of the Annual Report).


The Group continually monitors its exposure to currency risk. It maintains a portfolio of cash and cash equivalent balances mainly in US dollars (‘USD’) held primarily in the UK and holds these mostly in term deposits depending on the Group’s operational requirements. Production revenues from the sale of hydrocarbons are received in the local currency in Ukrainian hryvnia (‘UAH’) and to date funds from such revenues have been held in Ukraine for further use in operations rather than being remitted to the UK. Funds are transferred to the Company’s subsidiaries in USD to fund operations at which time the funds are converted to UAH. Some payments are made on behalf of the subsidiaries from the UK.

Key performance indicators

The Group monitors its performance in implementing its strategy with reference to clear targets set out for five key financial and one key non-financial performance indicators (‘KPIs’):

·      to increase oil, gas and condensate production measured on number of barrels of oil equivalent produced per day (‘boepd’);

·      to increase the Group’s oil and gas reserves by de-risking possible resources and contingent reserves into 2P Reserves. This is measured in million barrels of oil equivalent (‘mmboe’);

·      to increase the realised price per 1,000 cubic metres;

·      to decrease the cost per barrel for exploration and acquisition related expenditure;

·      to increase the Group’s basic and diluted earnings per share; and

·      to reduce the number of lost time incidents.

The Group’s performance during the six months 2012 against these targets is set out in the table below, together with the prior year performance data. No changes have been made to the source of data or calculation used in the period/year.

  Unit 30 June 2012 30 June 2011 31 December 2011
Financial KPIs        
Average production (working interest basis) (1) boepd 210 424 297
2P reserves (2) mmboe 2.6 2.6 2.6
Realised price per 1,000 cubic metres (3) $ 489.9 345.2 395.1
Basic and diluted (loss)/profit per share (4) cent (3.1) (2.5) 65.6
Non-financial KPIs        
Lost time incidents (5) incidents - - 2

(1)  Average production is calculated as the average daily production during the period.

(2)  Quantities of 2P reserves as at 30 June 2012 and 31 December 2011  are based on Gaffney, Cline & Associates’ independent reserves report on 2P Reserves as at 31 December 2009, dated 16 March 2010, as adjusted for the actual production until 30 June 2012, 30 June 2011 and 31 December 2011 respectively.

(3)  This represents the average price received for gas sold during the period (including VAT).

(4)  Basic and diluted (loss)/profit per Ordinary share is calculated by dividing the net (loss)/profit for the period attributable to Ordinary equity holder of the parent by the weighted average number of Ordinary shares during the period.

(5)  Lost time incidents relate to injuries where an employee/contractor is injured and has time off work.

Risk and Uncertainties

There are a number of potential risks and uncertainties inherent in the oil and gas sector which could have a material impact on the long-term performance of the Group and which could cause the actual results to differ materially from expected and historical results. The Company has taken reasonable steps to mitigate these where possible. Full details are disclosed on pages 12 to 13 of the 2011 Annual Financial Report. There have been no changes to the risk profile during the first half of the year. These are summarised below:

Operational risks

·     Health, safety, and environment

·     Drilling operations

·     Production and maintenance

·     Work over and abandonment

·     Subsurface risks

Financial risks

·     Recoverability of the Group’s assets

·     Liquidity risk, management and going concern assumption

·     Regulatory and tax compliance risk

·     Fraud risk

·     Foreign exchange risk

·     Inflation risk

·     Credit risk

·     Commodity price risk

Corporate risks

·     Regulatory and licence issues

·     Emerging market risk

·     Insurance risk


Directors’ Responsibility Statement

We confirm that to the best of our knowledge:

(a)          the Condensed set of Financial Statements has been prepared in accordance with IAS 34 ‘Interim Financial Reporting';

(b)          the interim management report includes a fair review of the information required by DTR 4.2.7R (indication of important events during the first six months and description of principal risks and uncertainties for the remaining six months of the year);

(c)           the interim management report includes a fair review of the information required by DTR 4.2.8R  (disclosure of related parties’ transactions and changes therein); and

(d)          the condensed set of financial statements, which has been prepared in accordance with the applicable set of accounting standards, gives a true and fair view of the assets, liabilities, financial position and profit or loss of the issuer, or the undertakings included in the consolidation as a whole as required by DTR 4.2.4R.


Rosneft and Statoil Sign Shareholder Agreements for Russian Offshore Exploration Joint Ventures

Thursday, August 30th, 2012

Rosneft and Statoil today signed Shareholder and Operating Agreements that will establish joint ventures for the four offshore Russian license areas included in the Cooperation Agreement signed by the two companies on May 5, 2012. The license areas in question are Perseevsky in the Barents Sea and Kashevarovsky, Lisyansky and Magadan 1 in the Sea of Okhotsk.

The agreements were signed in Stavanger (Norway) by Rosneft Chairman and President Igor Sechin and Statoil CEO Helge Lund. Their signing represents a significant step towards full implementation of the Rosneft – Statoil Cooperation Agreement.

The Shareholder and Operating Agreements are identical for the four license areas. Rosneft will have an equity share of 66.67% in each of the operating joint ventures and Statoil´s share will be 33.33%. Statoil will fund 100% of costs in the exploration phase, which includes an obligatory work program of six wildcat wells to be drilled during the period 2016-2021.

A fiscal reform package providing incentives for the development of Russian offshore, including through geological survey, was outlined in a Russian government decree of April 2012. Enactment and implementation of these measures will facilitate the conduct of more capital intensive exploration work.

The agreements also foresee exchange of management and technical personnel between the companies and building of competence in core E&P disciplines.

Igor Sechin, Chairman of the Management Board and President at Rosneft, said: “The agreements signed today are another important step in implementing the May 2012 strategic agreement on cooperation. The pace at which this agreement with Statoil is being implemented instills us with confidence and means we can say that all of the companies’ obligations within the joint venture will be fulfilled on time and in strict compliance with environmental regulations.”

“It is important to see Statoil and Rosneft reach this milestone in the implementation of the May 5 cooperation agreement,” says Statoil CEO Helge Lund. “At Statoil, we look forward to exploring these offshore Russian licenses together with Rosneft. The agreements that we signed today give me confidence in our joint strategic venture. We are working well together and proceeding rapidly. I congratulate the Statoil and Rosneft project teams for their efforts and look forward to taking the next step in our partnership with Rosneft.”


Integra Group appoints Steven Dashevsky as Non-executive Director

Thursday, August 30th, 2012

Integra Group (LSE:INTE) announces that Steven Dashevsky has been elected a member of the Group’s Board of Directors. He will fill the vacancy created after Robert Maguire resigns from the Board. Mr. Dashevsky, 38, has been in investment and brokerage business for the past fourteen years and is currently a founding partner in his own investment boutique Dashevsky and Partners.

Mr. Dashevsky has been also appointed to the Company’s Audit and Compliance Committee. The Board’s appointment of Mr. Dashevsky to the Board of Directors will be subject to re election at the next shareholders’ meeting to occur later in 2012.

Commenting on Mr. Dashevsky’s election, Integra’s Board Chairman John Fitzgibbons said:

“We are pleased to welcome Steven to the Board. Steven’s extensive knowledge of the Russian oil industry, combined with his capital markets experience, will add value to Integra’s Board. We are grateful to Bob Maguire for his contribution to the Board over the past five years and wish him success in his future endeavors.”


GE Oil & Gas Launches CHA Hydraulic Actuator Series at ONS 2012

Thursday, August 30th, 2012

  • Offers New Features for Increased Drilling Safety
  • Operates at Supply Pressures up to 6,000 psi

Expanding its portfolio of hydraulic actuators for the surface drilling sector, GE Oil & Gas is launching the CHA Hydraulic Actuator Series at the Offshore Northern Seas (ONS) 2012 Conference and Exhibition being held August 28-31 in Stavanger.

Since its acquisition of the John Wood Group PLC Well Support division in 2011, GE has been supplying customers with the RA Series of actuators product line, a reliable, cost-effective solution capable of managing supply pressures up to 3,500 psi. GE’s new CHA Series exceeds the RA Series by accepting supply pressures up to a maximum of 6,000 psi.

“With our new CHA Series, GE now provides a more robust line of actuators,” said Ian Milne, president of the GE Oil & Gas Pressure Control business. “This introduction increases our market competitiveness, as we continue to provide a full array of products with added-value services. We believe the CHA Series offers key features that will appeal to operators who are concerned with increased safety.

Improved safety features offered by the CHA Series include:


  • Quick-disconnect design enables removal of the actuator from the bonnet within the valve operating stroke, without depressurizing the valve and releasing hydrocarbons.
  • Powerful dual-coil spring package is capable of shearing standard 7/32” braided cable, allowing valve closure.
  • A captured spring design prevents release of the preloaded spring during repair or actuator removal.
  • Top access rising stem provides both a visual confirmation of the valve’s position and an interface for the use of safety-related accessories.


The CHA Series offers two large-diameter (1/2”) LP actuator ports: one for easy alignment to supply lines, minimizing debris buildup and one with an optional safety head designed to protect the actuator from over-pressurization and costly repairs. Operating at a maximum supply pressure of 6,000 psi allows use of a smaller actuator and greater control system flexibility. Fewer housing penetrations prevent the ingress of dust or water for easy maintenance.


Final joint of Nord Stream’s second string welded

Thursday, August 30th, 2012

The final joint at the second string of the Nord Stream gas pipeline was welded in the Portovaya Bay.

Final joint of Nord Stream’s second string weldedConstruction of Nord Stream gas pipeline

The final joint connected the offshore section of the pipeline’s second string to its onshore section as well as to the onshore infrastructure on the Russian coast in the Portovaya Bay near Vyborg.

The second string will be filled with process (buffer) gas in coming days, which is the necessary final stage before its commissioning.

It is projected to start gas supplies to Europe via Nord Stream’s second string in the fourth quarter of 2012.


Schlumberger Introduces Next-Generation On-Demand Reamer that Saves Rig Time

Thursday, August 30th, 2012

Schlumberger announced today the release of the Rhino XC* on-demand reamer. This next-generation reaming tool provides unlimited activation of the flow actuation system to reliably enlarge boreholes.

Building on Rhino XS* hydraulically expandable reamer technology, the Rhino XC reamer actuation system, with ream-on-demand capabilities, provides complete control of reamer cutter-block deployment, regardless of well-inclination angle. Its flow activation system eliminates the need for time-consuming pumpdown device activation, allowing the reamer to be placed below inner diameter-restricted bottomhole assembly components resulting in a reduced pilot-hole interval at total depth.

“With its on-demand capabilities and unlimited activations and deactivations of the cutter blocks, customers can optimize their underreaming program in real time,” said Dean Watson, president, Drilling Tools & Remedial, Schlumberger. “In deepwater environments, this provides huge savings for our customers by enabling faster and reliable activation.”

The Rhino XC reamer is effective in a variety of formations where simultaneous drilling and reliable hole enlargement are essential. The reamer’s one-piece, balanced design increases torque and load-carrying capacity while reducing drilling-generated vibrations that produce undergauge and irregular boreholes. Once activated, the reamer effectively enlarges wellbores for improved casing running, cement clearance and equivalent circulating density control.

In offshore Norway, one North Sea customer undertook a long and challenging 9½-in x 10¼-in section with the potential for several hole-related issues. For flexibility in handling borehole instability, the operator required on-demand capability to close reamer flow to the annulus. The Rhino XC was run, allowing cycling of the reamer multiple times during the course of the run, simply by changing the pump flow rate in a predetermined sequence. The resulting 9,283-ft run was completed in just over 300 circulating hours, a new run-length record for the client.


Arnlea launches new ATEX certified RFID tags at ONS 2012

Wednesday, August 29th, 2012

Arnlea Systems Limited, who provide Frequency Identification (RFID) solutions to the oil and gas industry, has announced the launch of a new range of ATEX-certified RFID tags designed specifically for use in hazardous areas at ONS.

The company, based in Inverurie, near Aberdeen, has designed the tags for use on FPSOs, drilling rigs and offshore platforms to allow fast and easy attachment to a wide range of equipment. This enables users to uniquely identify the item by simply scanning the tag in a similar manner to the scanning of a barcode in a supermarket.

Extremely robust and designed for a wide range of environmental conditions, the product is expected to survive for the life of the equipment it is attached to.

The tags are also compatible with Arnlea’s existing range of paperless software solutions for operator data gathering, inspection of safety critical equipment and hoses, paperless maintenance, and equipment/material movement tracking.

Arnlea’s solutions eliminate human error and verify user competence, leading to foolproof data integrity and substantial efficiency improvements. By distributing knowledge of equipment and processes to the fingertips of multi-skilled field personnel, operations are streamlined and bring increased productivity and return on existing assets.

“The oil and gas industry has been looking for simple, cost-effective solutions to easily identify, monitor, and track the wide range of equipment and materials in use in the industry today”, said Arnlea Managing Director Kevin Boyd. “Now, with the release of these new RFID tags, the key to such a solution exists.”


International oil and gas leaders to speak at ADIPEC’s world-renowned conference

Wednesday, August 29th, 2012

Under the theme “Sustainable Energy Growth: People, Responsibility, and Innovation”, the conference will feature industry figures from NOCs and IOCs
Abu Dhabi, UAE, August 29, 2012: The 2012 edition of the Abu Dhabi International Petroleum Exhibition and Conference (ADIPEC), organised in conjunction with Society of Petroleum Engineers (SPE), will examine a range of best practices as well as cutting-edge technology solutions aimed at meeting present and future challenges in the oil and gas industry, according to the event’s latest Conference Preview.

ADIPEC, the largest oil and gas event in the Middle East, will be held at the Abu Dhabi National Exhibition Centre (ADNEC) from November 11-14.

The first day of the conference will consist of two Executive Plenary Sessions, with senior oil company executives discussing the vital elements of sustainable industry growth and sharing insights on new strategies.

Moderated by Conference Chairman–Ali Al Jarwan, CEO, ADMA-OPCO, the first Executive Plenary Session, “Growth and Sustainability,” features Andrew P. Swiger, Senior Vice President, ExxonMobil Corporation; Antonio Costa Silva, Chairman of the Management Commission, Partex Oil and Gas; Christophe de Margerie, CEO, Total; Robert Dudley, Group Chief Executive, BP; and Sami F. Al-Rushaid, Chairman and Managing Director of Kuwait Oil Company.

The second Executive Plenary session: “Technology Deployment”, will be moderated by Programme Co-Chairs–Qasem Al-Kayoumi, Manager, Offshore Division, ADNOC, and Ray Mitro, Vice President, ZADCO.

The session will invite contributions from Ashok Belani, Executive Vice President Technology, Schlumberger; Bernard J. Duroc-Danner, President, CEO and Chairman, Weatherford; Hirobumi Kawano, President, JOGMEC; Matthias Bischel, Executive Director Projects and Technology, Shell; and Mohammad Husain, President and CEO, Equate.

Following the Executive Plenary Sessions, five Panel Sessions will take place, debating key topics such as ‘Meeting the world’s needs for energy’, ‘Human capital preparations key to future industry success’, ‘Unconventional oil and gas development’, ‘Can gas resources alone respond to growth aspirations?,’ and ‘Sustainability, environmental improvements and CSR’.

John Barry, Vice President Technical (Middle East and North Africa) & Country Chair for Shell Abu Dhabi B.V, said: “The combination of the SPE’s rigorous approach to pulling together a top quality technical programme, together with a great exhibition pulling together top IOCs, NOCs and suppliers, make ADIPEC a truly impactful event in this region. Shell has been a keen supporter from the inception, and looks forward to another record breaking ADIPEC.”

Taking place alongside the conference are a number of activities organised by the Society of Petroleum Engineers (SPE), including an educational workshop, a science teachers workshop, and an education day, which is an initiative to introduce students to the discipline of petroleum engineering and the industry in general, plus the first Middle East conference for the Petroleum and Chemical Industry Committee (PCIC), organised by the PCIC

“I always find ADIPEC an outstanding opportunity to expand my technical and executive network with the best companies in the world,” said Ms. Hosnia S. Hashim, Deputy Managing Director of North Kuwait Asset, Kuwait Oil Company (KOC).

“ADIPEC provides the framework where the world’s and Middle East’s Oil and Gas gather, to exchange technical progress, and gain a fresh perspective on the industry progress, recent results, and challenges ahead. It’s one event I would not want to miss,” Ms. Hashim concluded.

Organised by dmg::events, the 15th edition of ADIPEC is supported by ADNOC, the UAE’s Ministry of Energy and the Abu Dhabi Chamber of Commerce, with Platinum sponsors ExxonMobil, JOGMEC, OilSERV, TOTAL; Gold sponsors Dolphin Energy, JODCO, INPEX, OMV, OXY, Partex Oil and Gas, Saudi Aramco, Shell, Statoil; Silver Sponsor Wintershall; Strategic Partner Arab Development; Official Fire and Safety Partner NAFFCO, and the official publication Pipeline Magazine.



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