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Gazprom Neft improves efficiency in developing the Priobskoye field together with D&M Corp

Junho 1, 2018

Gazprom Neft has entered into an agreement with American corporation DeGolyer and MacNaughton Corp. on the selection and utilisation of innovative enhanced oil recovery (EOR) techniques at its Priobskoye field, in a document signed at this year’s St Petersburg International Economic Forum by Vadim Yakovlev, First Deputy CEO, Gazprom Neft, and Martin Wiewiorowski, Director of D&M’s Russian Branch.

Under this agreement DeGolyer and MacNaughton specialists will, throughout 2018–2020, analyse the history of the Priobskoye field since its discovery, assess the potential for increasing production and increasing the oil recovery factor (ORF), formulate recommendations for realising this potential, and address immediate challenges and problems in developing the Yuzhny (Southern) licence block at the Priobskoye field. On the basis of this data, plans for pilot works and further geological prospecting at the asset will be put in place.

In addition to this, the process of analysing the appropriate cutting-edge technologies to be used will be initiated, and alternative approaches to solving field development problems developed. A programme for the further professional development of Gazprom Neft specialists will also be put in place.

According to Gazprom Neft specialists, the full implementation of programmes developed under the agreement with D&M will allow reserves at the Priobskoye field to be brought into development, will enhance oil recovery through existing well stock, and will increase the ORF by five to six percent.

DeGolyer and MacNaughton plans to open an office in St Petersburg in 2018 in order to undertake implementation of this project.

Vadim Yakovlev, First Deputy CEO, Gazprom Neft, commented: Gazprom Neft has been working with DeGolyer and MacNaughton for more than 10 years. The unique competencies accumulated by the company during annual reserves audits has become a key component in our joint project to study the potential of the Priobskoye field, initiated in 2016. I have every confidence that this new agreement will allow our companies to further strengthen their cooperation and, ultimately, significantly improve efficiency in developing one of our largest production assets.”

http://www.gazprom-neft.com/press-center/news/1646776/

Gazprom Neft improves efficiency in developing the Priobskoye field together with D&M Corp

Junho 1, 2018

As one of the leading independent consulting firm focused on the petroleum industry, DeGolyer and MacNaughton provides unbiased and informed answers to clients worldwide. D&M skilfully blends energy economics, engineering, and the earth sciences to help clients in more than 100 countries make the smartest decisions regarding exploration, recovery, and management of oil and gas resources.

The firm’s services include resources assessments, reserves consulting, reservoir modelling, geologic and petrophysical analyses, development planning, guidance with financial reporting issues, and financial forecasting for petroleum discoveries. DeGolyer and MacNaughton has the largest, most experienced team of professional reservoir consultants in the industry. D&M has built up extensive international experience in independent reserves assessments, the results of which are frequently used in certifying projects for presentation to financial institutions worldwide.

Gazprom Neft is a vertically integrated oil company, primarily involved in oil and gas exploration and production, refining, and the production and sale of oil products. The Gazprom Neft’s corporate structure comprises more than 70 production, refining and sales subsidiaries throughout Russia, the CIS, and abroad.

The company’s proved and probable reserves (SPE-PRMS) are estimated at 2.78 billion tonnes of oil equivalent (btoe), making Gazprom Neft one of the top-20 largest oil and gas companies in the world, and one of Russia’s top three largest companies in terms of production and refining volumes. Total production in 2017 reached 89.75 million tonnes of oil equivalent (mtoe), with refining volumes of 40.1 million tonnes.

Gazprom Neft products are exported to more than 50 countries worldwide, and sold throughout the Russian Federation and abroad. The company’s filling station network totals more than 1,850 outlets throughout Russia, the CIS and Europe.

Gazprom Neft’s net profit in 2017 was RUB253 billion — a 26.5-percent increase year-on-year. The company is an industry market leader in terms of both financial growth and various efficiency metrics, including its internal rate of return (IRR).

The company’s main shareholder is Gazprom PJSC, which has a 95.68-percent interest, with the remaining shares in free circulation.

http://www.einnews.com/pr_news/449447502/gazprom-neft-improves-efficiency-in-developing-the-priobskoye-field-together-with-degolyer-and-macnaughton-corp

DeGolyer & MacNaughton to study Priobskoye EOR

Junho 1, 2018

Gazprom-Neft has entered an agreement with DeGolyer & MacNaughton Corp., Dallas, on the selection and use of enhanced oil recovery methods for giant Priobskoye field in the Khanti-Mansi Autonomous District of West Siberia.

The Russian company said DeGolyer & MacNaughton will “analyze the history of the Priobskoye since its discovery, assess the potential for increasing production and increasing the oil recovery factor, formulate recommendations for realizing this potential, and address the immediate challenges and problems in developing the Yuzhny (Southern) license block” of the field. The work will occur during 2018-20.

In an April 2016 announcement about production of the 100 millionth tonne of oil from Yuzhno-Priobskoye, Gazprom-Neft said the field, known to have complex geology, was producing 32,000 tonnes/day from 2,000 wells.

https://www.ogj.com/articles/2018/05/degolyer-macnaughton-to-study-priobskoye-eor.html

EOG Resources: Reports Fourth Quarter and Full 2017 Results

Abril 13, 2018

“For the 30^th consecutive year, internal reserves estimates were within 5 percent of estimates independently prepared by DeGolyer and MacNaughton.”

EOG Resources, Inc. (NYSE: EOG) (EOG) today reported fourth quarter 2017 net income of $2,430 million, or $4.20 per share. This compares to a fourth quarter 2016 net loss of $142 million, or $0.25 per share.  For the full year 2017, EOG reported net income of $2,583 million, or $4.46 per share, compared to a net loss of $1,097 million, or $1.98 per share, for the full year 2016.

Adjusted non-GAAP net income for the fourth quarter 2017 was $401 million, or $0.69 per share, compared to an adjusted non-GAAP net loss of $7 million, or $0.01 per share, for the same prior year period.  Adjusted non-GAAP net income for the full year 2017 was $648 million, or $1.12 per share, compared to an adjusted non-GAAP net loss of $893 million, or $1.61 per share, for the full year 2016.  Adjusted non-GAAP net income (loss) is calculated by matching hedge realizations to settlement months and making certain other adjustments in order to exclude non-recurring and certain other items.  One of the adjusting items in the fourth quarter and full year 2017 was a non-cash reduction in income tax expense of $2.2 billion, or $3.75 per share, related to the revaluation of EOG’s deferred tax liability and certain other items resulting from the Tax Cuts and Jobs Act.  For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

Higher commodity prices, increased production volumes, well productivity improvements and per-unit cost reductions resulted in significant increases to adjusted non-GAAP net income, discretionary cash flow and EBITDAX for the fourth quarter 2017 compared to the fourth quarter 2016.  For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

Operational Highlights
Crude oil and condensate volumes in the U.S. increased 20 percent in 2017 to 335,000 barrels of oil per day (Bopd).  Increased development activity and well productivity improvements supported the volume increase.  Total company natural gas liquids (NGLs) volumes grew 8 percent while natural gas volumes decreased 6 percent primarily due to the sale of the company’s Barnett and Haynesville Shale dry gas assets in late 2016.  Transportation expenses decreased 11 percent and depreciation, depletion and amortization expenses decreased 12 percent, on a per-unit basis.

Increased development activity drove substantial volume increases in the Eagle Ford and Delaware Basin during the fourth quarter.  Total company crude oil and condensate volumes increased 40,200 Bopd compared to the third quarter 2017.  Natural gas liquids volumes grew 15 percent while natural gas volumes increased 6 percent, compared to the third quarter 2017.

“EOG emerged from the industry downturn in 2017 with unprecedented levels of efficiency and productivity, driving oil production volumes to record levels with capital expenditures approximately one half the prior peak,” said William R. “Bill” Thomas, Chairman and Chief Executive Officer.  “EOG’s integrated teams demonstrated superb operational performance, overcoming a major hurricane and other challenges to deliver record production volumes and cost savings which surpassed original targets set at the beginning of the year.”

2018 Capital Plan
EOG’s disciplined capital plan is designed to achieve strong returns on capital employed and healthy growth while spending within cash flow.  The company expects to grow total company crude oil volumes by 18 percent, generate double-digit ROCE and cover capital investment and dividend payments within discretionary cash flow.  EOG can deliver on its 2018 plan at oil prices below $50 and generates significant free cash flow at a $60 oil price.

EOG’s return-based culture continues to drive cost reductions.  The company targets lower well costs and per-unit operating expenses in 2018 despite a potentially inflationary operating environment.  EOG is also focused on driving continued improvements in well productivity and pursuing exploration efforts in new plays.

Capital expenditures for 2018 are expected to range from $5.4 to $5.8 billion, including production facilities and gathering, processing and other expenditures, and excluding acquisitions.  EOG expects to complete approximately 690 net wells in 2018, compared to 536 net wells in 2017.  Capital will be allocated primarily to EOG’s highest rate-of-return oil assets in the Delaware Basin, Eagle Ford, Rockies, Woodford and the Bakken.

At least 90 percent of the wells completed in 2018 are expected to be premium.  EOG has an inventory of approximately 8,000 such wells, which have a direct after-tax rate of return of at least 30 percent assuming $40 flat crude oil prices and $2.50 flat natural gas prices.

“EOG enters 2018 better positioned than ever to generate significant shareholder value through the development of its large and diverse inventory of high rate-of-return premium wells,” Thomas said.  “We are determined to maintain the discipline, record-level operational efficiency and performance gained through the downturn.  Our deep inventory of premium wells across the U.S. offers flexibility to adjust to changing conditions.  We also see significant opportunities to increase our premium well inventory through organic exploration and development technology to further extend EOG’s return on capital advantage.”

Dividend Increase
The board of directors increased the cash dividend on the common stock by 10.4 percent.  Effective with the dividend payable April 30, 2018, to stockholders of record as of April 16, 2018, the board declared a quarterly dividend of $0.185 per share on the common stock.  The indicated annual rate is $0.74 per share.

Delaware Basin
2017 was a watershed year for EOG in the Delaware Basin, where it successfully integrated the Yates acquisition, identified 1,240 additional net premium well locations, added the First Bone Spring as its fourth premium play and reduced completed well costs by $800,000 per well.  Delaware Basin crude oil and condensate volumes increased over 80 percent in 2017 and exceeded 100,000 Bopd in the fourth quarter 2017.

EOG continued active development of its 416,000 net acre position in the Delaware Basin in the fourth quarter 2017, completing 65 wells.

In the Delaware Basin Wolfcamp, in Lea County, NM, EOG completed a four-well package, the Calm Breeze 2 Fed Com #701-704H, with an average treated lateral length of 7,100 feet per well and average 30-day initial production rates per well of 2,605 Bopd, 440 barrels per day (Bpd) of NGLs and 3.7 million cubic feet per day (MMcfd) of natural gas.

In the Delaware Basin First Bone Spring, in Lea County, NM, EOG completed the Righteous 6 State Com #301H with a treated lateral length of 7,100 feet and 30-day initial production rate of 1,305 Bopd, 170 Bpd of NGLs and 1.4 MMcfd of natural gas.

In the Delaware Basin Leonard, in Loving County, TX, EOG completed a four-well package, the State Atlas A#3H – D#6H, with an average treated lateral length of 9,800 feet per well and average 30-day initial production rates per well of 1,215 Bopd, 270 Bpd of NGLs and 2.3 MMcfd of natural gas.

South Texas Eagle Ford and Austin Chalk
EOG continues to enhance the productivity of its bellwether asset in the South Texas Eagle Ford.  Eight years after initiating development, EOG further reduced well costs and improved well performance during 2017 in its 520,000 net acre position in the crude oil window of this world class play.  EOG also expanded its enhanced oil recovery program, adding 56 wells last year.  For the full year 2017, crude oil production in the Eagle Ford and Austin Chalk increased one percent year-over-year despite interruption to producing volumes as a result of Hurricane Harvey.

In the fourth quarter, EOG completed 74 wells in the Eagle Ford.  These included 13 wells with lateral lengths of more than 10,000 feet.  In LaSalle County, EOG completed a four-well package, the White 5H-8H, with an average treated lateral length of 12,900 feet per well and average 30-day initial production rates per well of 1,545 Bopd, 80 Bpd of NGLs and 0.5 MMcfd of natural gas.  In DeWitt County, EOG completed a four-well package, the Hendrix 8H-10H and the Hendrix 12H, with an average treated lateral length of 6,700 feet per well and average 30-day initial production rates per well of 2,545 Bopd, 420 Bpd of NGLs and 2.4 MMcfd of natural gas.

EOG continued to test its position in the South Texas Austin Chalk, a geologically complex formation which lies above the South Texas Eagle Ford, completing four net wells in the fourth quarter.

Rockies
EOG’s Wyoming Powder River Basin and DJ Basin activity both contributed to the company’s 2017 crude oil production growth.  In the Powder River Basin, EOG continued exploration activity on its 400,000 net acre position in the core of the play.  The company tested the prospectivity of multiple target zones and also tested the aerial extent of various targets in the Powder River Basin during the year.  In the DJ Basin, EOG achieved significant well cost reductions during 2017 through a focus on efficiency improvements in drilling and completion operations.

In the fourth quarter, EOG completed nine wells in the Powder River Basin.  In Converse County, EOG completed the Mary’s Draw 453-0310H and 455-0310H wells with an average treated lateral length of 7,300 feet per well and average 30-day initial production rates per well of 1,280 Bopd, 610 Bpd of NGLs and 7.6 MMcfd of natural gas.  In the DJ Basin, EOG completed three wells in the fourth quarter.  This included the Big Sandy 522-2536H with a treated lateral length of 8,800 feet and 30-day initial production rate of 1,100 Bopd, 110 Bpd of NGLs and 0.2 MMcfd of natural gas.

Reserves
At year-end 2017, total company net proved reserves were 2,527 million barrels of oil equivalent (MMBoe), an increase of 18 percent compared to year-end 2016.  Net proved reserve additions from all sources, excluding revisions due to price, replaced 201 percent of EOG’s 2017 production at a finding and development cost of $8.71 per barrel of oil equivalent.  Revisions due to price increased net proved reserves by 154 MMBoe and asset divestitures decreased net proved reserves by 21 MMBoe.  (For more reserves detail and a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.)

For the 30^th consecutive year, internal reserves estimates were within 5 percent of estimates independently prepared by DeGolyer and MacNaughton.

Hedging Activity
During the fourth quarter ended December 31, 2017, EOG entered into crude oil financial price swap contracts and differential basis swap contracts.  A comprehensive summary of crude oil and natural gas derivative contracts is provided in the attached tables.

Capital Structure and Asset Sales
At December 31, 2017, EOG’s total debt outstanding was $6.4 billion with a debt-to-total capitalization ratio of 28 percent. Considering cash on the balance sheet at the end of the fourth quarter, EOG’s net debt was $5.6 billion with a net debt-to-total capitalization ratio of 25 percent.  For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

Proceeds from asset sales for the full year 2017 totaled $227 million.

Conference Call February 28, 2018
EOG’s fourth quarter and full year 2017 results conference call will be available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time) on Wednesday, February 28, 2018.  To access the live audio webcast and related presentation materials, log on to the Investors Overview page on the EOG website at http://investors.eogresources.com/overview.

EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China.  EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol “EOG.”  For additional information about EOG, please visit www.eogresources.com.

This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.  All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG’s future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG’s management for future operations, are forward-looking statements.  EOG typically uses words such as “expect,” “anticipate,” “estimate,” “project,” “strategy,” “intend,” “plan,” “target,” “goal,” “may,” “will,” “should” and “believe” or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements.  In particular, statements, express or implied, concerning EOG’s future operating results and returns or EOG’s ability to replace or increase reserves, increase production, reduce or otherwise control operating and capital costs, generate income or cash flows or pay dividends are forward-looking statements.  Forward-looking statements are not guarantees of performance.  Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct.  Moreover, EOG’s forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG’s control.  Furthermore, EOG has presented or referenced herein or in its accompanying disclosures certain forward-looking, non-GAAP financial measures, such as free cash flow and discretionary cash flow, and certain related estimates regarding future performance, results and financial position.  These forward-looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented.  EOG’s actual results may differ materially from the measure and estimates presented or referenced herein.  Important factors that could cause EOG’s actual results to differ materially from the expectations reflected in EOG’s forward-looking statements include, among others:

• the timing, extent and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids, natural gas and related commodities;
• the extent to which EOG is successful in its efforts to acquire or discover additional reserves;
• the extent to which EOG is successful in its efforts to economically develop its acreage in, produce reserves and achieve anticipated production levels from, and maximize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects;
• the extent to which EOG is successful in its efforts to market its crude oil and condensate, natural gas liquids, natural gas and related commodity production;
• the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, transportation and refining facilities;
• the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights-of-way, and EOG’s ability to retain mineral licenses and leases;
• the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations; environmental, health and safety laws and regulations relating to air emissions, disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations imposing conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;
• EOG’s ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties;
• the extent to which EOG’s third-party-operated crude oil and natural gas properties are operated successfully and economically;
• competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties, employees and other personnel, facilities, equipment, materials and services;
• the availability and cost of employees and other personnel, facilities, equipment, materials (such as water) and services;
• the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
• weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, compression and transportation facilities;
• the ability of EOG’s customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
• EOG’s ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;
• the extent to which EOG is successful in its completion of planned asset dispositions;
• the extent and effect of any hedging activities engaged in by EOG;
• the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
• political conditions and developments around the world (such as political instability and armed conflict), including in the areas in which EOG operates;
• the use of competing energy sources and the development of alternative energy sources;
• the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;
• acts of war and terrorism and responses to these acts;
• physical, electronic and cyber security breaches; and
• the other factors described under ITEM 1A, Risk Factors, on pages 14 through 23 of EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017, and any updates to those factors set forth in EOG’s subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

In light of these risks, uncertainties and assumptions, the events anticipated by EOG’s forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration and extent of their impact on our actual results.  Accordingly, you should not place any undue reliance on any of EOG’s forward-looking statements. EOG’s forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.

The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only “proved” reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also “probable” reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as “possible” reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves).  Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include “potential” reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC’s latest reserve reporting guidelines.  Investors are urged to consider closely the disclosure in EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC’s website at www.sec.gov.  In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.

http://investors.eogresources.com/2018-02-27-EOG-Resources-Reports-Fourth-Quarter-and-Full-Year-2017-Results-and-Announces-2018-Capital-Program

80 billion barrels of ‘oil in place’ identified in Bahrain

Abril 4, 2018

Manama, Apr. 4 (BNA): Bahrain’s National Oil and Gas Authority (NOGA), alongside international consultants DeGolyer and MacNaughton, Halliburton, and Schlumberger, today provided new details on the Kingdom’s largest ever discovery of oil and gas, with tight oil amounting to at least 80 billion barrels.
The discovery, made within the 2,000 km2 Khalij Al-Bahrain Basin, is located in shallow waters off the Kingdom’s west coast, close to a fully-operational oil field with ready-to-connect-to facilities, according to Halliburton, who added that this unique factor provides potential for significant cost optimisation.

A separate discovery of significant gas reserves in two accumulations below Bahrain’s main gas reservoir has been confirmed.

Extensive work has already been carried out to evaluate in-place volumes. The first well in the drilling programme is planned to produce in August, and over the next two years focus will be given to maximising production and commercial efficiency.

Announcing the size and content of the discovered resources, Bahrain’s Minister of Oil, Shaikh Mohammed bin Khalifa Al Khalifa, said: “DeGolyer and MacNaughton’s and Haliburton’s independent appraisals have confirmed NOGA’s find of highly significant quantities of oil in-place for the Khalij Al Bahrain, with tight oil amounting to at least 80 billion barrels, and deep gas reserves in the region of 10-20 trillion cubic feet.

“Agreement has been reached with Halliburton to commence drilling on two further appraisal wells in 2018, to further evaluate reservoir potential, optimise completions, and initiate long-term production,” the Minister added.

“Oil in place of 80 billion barrels is based on a P50 resource estimate,” said DeGolyer and MacNaughton Senior Vice president, Dr John Hornbrook, speaking at today’s press conference. Dr Hornbrook added that “the discovery breaks new ground for the Bahrain oil and gas industry using established technologies.”

Positive test well results have successfully demonstrated the productivity of the significant resource, with Schlumberger, who performed the first test well drilling, adding that Bapco has already succeeded in flowing high quality oil from the wells during the testing and flow back phases. “Based on the core analysis carried out on several wells the formation could be classified at the edge of the conventional-unconventional type of plays,” a Schlumberger spokesperson noted.

Bapco Chief Exploration Geologist in charge of the discovery, Yahya Al Ansari, added that “the presence of a layer with moderate conventional reservoir properties on top of an organic-rich source rock creates a unique self-sourcing and trapping system, enhancing production and economic viability. The confirmation of this significant resource highlights the vast E&P (exploration and production) potential and opportunities in Bahrain.”

The newly-discovered resource, which officials expect to be ‘on production’ within five years, is expected to provide significant and long-term positive benefits to the Kingdom’s economy – both directly and indirectly through downstream activities in related industries.

NOGA added that the next stage of development will focus on ensuring robust frameworks, data and terms are in place to facilitate further activities and commercial opportunities with international partners.

http://www.bna.bh/portal/en/news/834702

Bahrain’s Biggest Oil Find Since 1932 Dwarfs Reserves

Abril 1, 2018

Bahrain, the smallest energy producer in the Persian Gulf, discovered its biggest oil field since it started producing crude in 1932, according to the country’s official news agency.

Bahrain Field

It is currently bound by the global agreement among major oil producers to limit production to reduce global inventories.

“Initial analysis demonstrates the find is at substantial levels, capable of supporting the long-term extraction of tight oil and deep gas,” Bahrain Oil Minister Shaikh Mohammed bin Khalifa Al Khalifa said in the BNA report.

Bahrain’s revenue from oil and gas dropped 43 percent from 2013 to 2016, according to most recent data available from the Finance Ministry, as crude prices slumped as much as 77 percent. With energy sales accounting for 87 percent of the government’s total income for 2016, Bahrain is trying to diversify its economy and borrow funds to ease pressure on its public finances.

https://www.bloomberg.com/news/articles/2018-04-01/bahrain-says-its-biggest-oil-find-since-1932-dwarfs-reserves

DNO ASA 2017 Annual Statement of Reserves and Resources

Março 16, 2018

DNO ASA, the Norwegian oil and gas operator, today released its 2017 Annual Report and Accounts together with its 2017 Annual Statement of Reserves and Resources, reporting an increase in operating profit and improvements across other key financial and operational metrics.

Founded in 1971 and listed on the Oslo Stock Exchange with the code DNO. OL, the company holds stakes in onshore and offshore licences at various stages of exploration, development and production in the Kurdistan region of Iraq, Yemen, Oman, the United Arab Emirates, Tunisia and Somaliland. Its largest shareholder is UAE-based RAK Petroleum.

Annual 2017 revenues climbed to US$ 347 million, up 72 percent from the 2016 figures, the company said. Operating profit totalled US$ 521 million, up from US$ 6 million in 2016, with the recognition as other income of US$ 556 million under the August 2017 Kurdistan Receivables Settlement Agreement. Excluding the settlement agreement and non-cash impairments, DNO operating profit in 2017 more than doubled to US$ 72 million. Although operational expenditure last year reached US$ 259 million, double the 2016 figure, the company ended 2017 with a cash balance of USD 430 million.

Company Working Interest, CWI, production increased to 73,700 barrels of oil equivalent per day (boepd) from 69,200 boepd in 2016. Total production from DNO-operated fields, including those in which other companies have stakes, rose to 113,500 boepd in 2017, up from 112,600 boepd in 2016. Lifting costs last year averaged US$ 3.6 per barrel of oil equivalent.

DNO’s production continues to be driven by the Tawke field in Kurdistan, where output in 2017 averaged 105,500 barrels of oil per day (bopd). The adjacent Peshkabir field, brought on stream in the middle of 2017, contributed another 3,600 bopd to bring total Tawke licence production to 109,100 bopd for the year. DNO plans to boost production from this licence area in 2018 by drilling ten new wells, the report said.

“We are committed this year (2018) to continue to outdrill, outproduce and outperform all other international companies in Kurdistan – combined,” DNO’s Executive Chairman, Bijan Mossavar-Rahmani, commented.

At year end 2017, DNO’s CWI 1P reserves climbed to 240 million barrels of oil equivalent (MMboe) from 219 MMboe at year end 2016, after adjusting for production during the year, technical revisions and an increase in DNO’s operated stake in the Tawke licence from 55 percent to 75 percent under the terms of the August 2017 agreement. On a 2P basis, DNO’s CWI reserves stood at 384 MMboe (up from 368 MMboe) and on a 3P basis, DNO’s CWI reserves stood at 666 MMboe (up from 521 MMboe). DNO’s yearend 2017 CWI contingent resources (2C) were estimated at 99 MMboe, down from 161 MMboe at yearend 2016, following reclassification of certain contingent resources to reserves.

On a gross basis, at year end 2017, 1P reserves at the Tawke licence, containing the Tawke and Peshkabir fields, totalled 348 MMboe (353 MMboe at yearend 2016) after adjusting for production of 40 MMboe during the year and technical revisions; 2P reserves totalled 513 MMboe (536 MMboe at yearend 2016); 3P reserves totalled 880 MMboe (725 MMboe at yearend 2016) and 2C resources totaled 91 MMboe (211 MMboe at yearend 2016) following reclassification.

International petroleum consultants DeGolyer and MacNaughton carried out The annual independent assessment of the Tawke and Peshkabir fields was carried out by international petroleum consultants DeGolyer and MacNaughton, while DNO internally evaluated the remaining assets.

By Shayne Heffernan on March 16, 2018

http://www.livetradingnews.com/dno-asa-2017-annual-statement-of-reserves-and-resources-78014.html#.Wqu7cXwh3mE

 

The Outdoor Classroom Seminar: Integrated Reservoir Appraisal and Reservoir Modeling

Fevereiro 23, 2018

What you will learn: Through this immersive field-based seminar, students will improve their understanding of modeling and their abilities to model geological features affecting reservoir performance through the collection, observation, interpretation, and modeling of geologic, petrophysical, and engineering data. Seminar instructors will present methods for collecting, analyzing, and interpretating data to most efficiently appraise reservoir size and characteristics. Over the course of the seminar, students will visit outcrops that reveal the complex but interpretable geologic features that influence reservoir development. These outcrop observations, along with wireline log data, petrophysical data collected from nearby boreholes, will be incorporated into the geocellular models that must be developed and simulated during the 5-day course.

Who Should Attend: This course is designed for petroleum engineers, geologists, geophysicists, petrophysicists, and supervisory personnel responsible for executing field-development programs focused on primary, secondary, or tertiary-recovery projects in conventional terrigineous-clastic reservoirs. The geologic and engineering concepts and practices introduced in the seminar are applicable to reservoirs spanning all depositional settings.

See Brochure Link for more details! Integrated Reservoir Appraisal and Development Seminar Final

Costs: TBD per person and includes:

• 5 day seminar
• Field guide and exercise materials
• Transportation during seminar
• Lunch, snacks, and drinks during the seminar

           Additional costs (responsibility of attendees)

• Transportation to and from Salt Lake City, Utah on May 6, returning May 12.
• Meals other than lunch during the five-day course
• Hotel costs

Gazprom Neft: Reserves Replacement at 170%

Fevereiro 22, 2018

Gazprom Neft:  Reserves Replacement at 170%

Gazprom Neft has completed auditing of the company’s hydrocarbon reserves as at 2017. As at 31 December 2017 the company’s total proved and probable hydrocarbon reserves (proved + probable — 2P based on SPE-PRMS international standards,* including proportional shares in production at joint enterprises**) totalled 2.78 billion tonnes of oil equivalent (toe) — a year-on-year increase of 2.3 percent. Production volumes in 2017, at 89.75 mtoe, were compensated by reserves replacement in the order of 170 percent. The audit was undertaken by independent international consulting company DeGolyer and MacNaughton.

Proved 1P hydrocarbons as at end 2017 are estimated at 1.52 btoe — an increase of 0.6 percent, year-on-year. The reserve replacement ratio for this category of reserves is 110 percent Gazprom Neft’s reserves-to-production ratio in terms of proved hydrocarbon reserves (SPE-PRMS standards) is 17 years. According to SEC standards,*** the company’s total hydrocarbon reserves stand at 1.34 mtoe (an increase of 3.4 percent over 2017).

Drilling of 27 prospecting and exploratory wells was completed in this accounting period, with drilling meterage in 2017 increasing by 41.2 percent (to 94,600 metres). Four new wells and 42 hydrocarbon deposits were discovered last year throughout the group’s licence blocks.

A key positive factor in allowing the company to expand its resources base has been the fine-tuning of technologies in geological prospecting and development drilling, together with the implementation of dynamic ranking for all company options. Gazprom Neft’s new assets — including the Tazovskoye, Severo-Samburgskoye and Kamennomysskoye fields — have all made a major contribution to expanding the company’s resource base.

An assessment of prospective resources at Gazprom Neft’s licence blocks on the Arctic Shelf was undertaken for the first time in 2017, with DeGolyer and MacNaughton estimating these at 1.6 billion tonnes of oil and three trillion cubic metres of gas.

Vadim Yakovlev, First Deputy CEO, Gazprom Neft, commented: «Gazprom Neft last year continued its consistent development of its upstream projects, as well as undertaking work on accessing new licence blocks. Major discoveries were confirmed, which have made the company’s resource base still more balanced and high-quality. The company’s priority development vectors continue to include improving quality in the development of new reserves, active work in studying low-permeability strata, and implementing a programme for improving efficiency in production in those regions in which the company has traditionally operated.»

Abraxas Provides Reserve and Operational Update

Fevereiro 20, 2018

Ecopetrol Group increases its hydrocarbon reserves, proven reserves mount to 1,659 million barrels-equivalent at 2017 close

Fevereiro 19, 2018

Antero Resources (AR) Announces 12% Increase in Estimated Proved Reserves to 17.3 Tcfe

Fevereiro 14, 2018

https://www.streetinsider.com/Corporate+News/Antero+Resources+%28AR%29+Announces+12%25+Increase+in+Estimated+Proved+Reserves+to+17.3+Tcfe/13808873.html

Antero Resources (NYSE: AR) (“Antero” or the “Company”) today announced estimated reserves as of December 31, 2017.

Highlights:

• Proved reserves increased by 12% to 17.3 Tcfe at year-end 2017 (36% liquids), compared to year-end 2016
• Pre-tax PV-10 of proved reserves at year-end 2017 was $10.8 billion at SEC pricing, including hedges
• Proved developed reserves increased by 23% to 8.5 Tcfe at year-end 2017, compared to year-end 2016
• $0.54 per Mcfe proved developed finding and development cost for 2017
• $0.37 per Mcfe future development cost for year-end 2017 proved undeveloped reserves
• 3P reserves increased by 18% to 54.6 Tcfe at year-end 2017 (25% liquids), compared to year-end 2016
• Pre-tax PV-10 of 3P reserves at year-end 2017 was $18.4 billion at SEC pricing, including hedges

Antero’s estimated proved reserves at December 31, 2017 were 17.3 Tcfe, a 12% increase compared to estimated proved reserves at December 31, 2016. Proved, probable and possible (“3P”) reserves at year-end 2017 totaled 54.6 Tcfe, which represents an 18% increase compared to the previous year. For further discussion of 3P reserves, please read “Non-GAAP Disclosure.”

Proved developed finding and development (“F&D”) cost for estimated proved developed reserve additions was $0.54 per Mcfe for 2017. All-in F&D cost for estimated proved reserve additions, including acquisitions, was $0.59 per Mcfe for 2017. Future development costs for proved undeveloped locations are estimated to be $0.37 per Mcfe. The reserve life of the Company’s estimated proved reserves is approximately 21 years based on 2017 production. For further discussion of all-in F&D cost and proved developed F&D cost, please read “Non-GAAP Disclosure.” Antero’s estimated proved and 3P reserves at December 31, 2017 were prepared by its internal reserve engineers and audited by DeGolyer and MacNaughton (“D&M”). D&M’s reserve audit covered properties representing 100% of Antero’s total 3P reserves at December 31, 2017.

Estimated Proved Reserves

As of December 31, 2017, the Company’s 17.3 Tcfe of estimated proved reserves were comprised of 64% natural gas, 35% NGLs and 1% oil. The Marcellus Shale accounted for 90% of estimated proved reserves and the Ohio Utica Shale accounted for 10%. For 2017, Antero added 1.7 Tcfe of estimated proved reserves organically, excluding acquisitions, which is reflective of the continued productivity gains from the use of advanced completion techniques and longer laterals.

All 381 proved undeveloped locations in the Marcellus at year-end 2017 were booked at an approximate 2 Bcf/1,000′ type curve. This compares to year-end 2016 at which time 81 proved undeveloped locations, or 21% of the total proved undeveloped locations in the Marcellus, were booked at the approximate 2 Bcf/1,000′ type curve. The primary driver behind the increase in the number of proved undeveloped locations booked at the higher approximate 2 Bcf/1,000′ type curve type curve is the increased production history observed from the implementation of advanced completions techniques.

Estimated proved developed reserves increased by 23% from year-end 2016 to 8.5 Tcfe at December 31, 2017. The percentage of estimated proved reserves classified as proved developed increased to 49% at December 31, 2017 from 45% at year-end 2016. The average heating content of Antero’s proved undeveloped locations is 1237 BTU, and the average lateral length is approximately 10,500 feet.

Under the Securities and Exchange Commission (“SEC”) reporting rules, proved undeveloped reserves are limited to reserves that are planned to be developed within five years of initial booking. The Company reclassified 2,778 Bcfe of formerly non-proved reserves to proved undeveloped due to their addition to Antero’s five-year development plan. Included in this reclassification was the revision of 286 Bcfe related to an improvement in performance from advanced completions and a 291 Bcfe revision related to a lateral extension of previously booked locations. Additionally, the Company reclassified 2,280 Bcfe of generally lower BTU proved undeveloped reserves to the probable category in 2017 to comply with the SEC five-year development rule. Antero’s 8.8 Tcfe of estimated proved undeveloped reserves will require an estimated $3.3 billion of future development capital over the next five years, resulting in an estimated average future development cost for proved undeveloped reserves of $0.37 per Mcfe.

Antero incurred estimated capital costs of approximately $1.7 billion during 2017, including drilling and completion costs of $1.282 billion, proved property acquisitions of $176 million and leasehold additions of $204 million. Based on the $1.7 billion of capital costs, 2017 all-in F&D cost for proved reserve additions from all sources, including acquisitions and revisions, was $0.59 per Mcfe.

The table below summarizes both SEC and strip pricing as of December 31, 2017 and the associated PV-10 for estimated proved reserves and hedge values:

Valeura Announces Prospective Resources for Unconventional Basin-Centered Gas Prospect

Fevereiro 7, 2018

http://markets.businessinsider.com/news/stocks/valeura-announces-prospective-resources-for-unconventional-basin-centered-gas-prospect-1015019490

CALGARY, Feb. 6, 2018 /CNW/ – Valeura Energy Inc. (“Valeura” or the “Corporation“) (TSX: VLE) is pleased to announce summary results of an independent evaluation of its prospective resources in the Thrace Basin of Turkey prepared by DeGolyer and MacNaughton (“D&M“) of Dallas, Texas in its report dated February 6, 2018 (the “D&M Resources Report“). Highlights of the D&M Resources Report are as follows:

• 10.1 Tcf of estimated working interest unrisked mean prospective resources of natural gas, which includes 236 MMbbl of condensate; and
• 5.2 Tcf of estimated working interest risked mean prospective resources of natural gas, which includes 165 MMbbl of condensate.

Valeura’s CEO, Sean Guest, said “We are pleased to now have an independent evaluation that supports Valeura’s thesis that the Thrace Basin may hold a very large unconventional, basin-centered natural gas-condensate resource. Valeura has been maturing this play for almost five years and these efforts culminated in the drilling of the Yamalik-1 natural gas-condensate discovery in 2017 with our partner Statoil. While Valeura is confident that natural gas is pervasive in these deep formations, we recognise that we are in the early phases of exploration. More drilling and testing will be required to prove that the gas will flow at commercial rates, and to refine the large uncertainty around recoverable gas and condensate. Valeura and Statoil are committed to progressing the work required to further evaluate this unconventional prospect. We are currently working to tie-in the Yamalik-1 discovery well to Valeura’s gas production network to allow for further testing and long-term production and sales. Additionally, Statoil and Valeura are planning a three-well delineation drilling and testing program which is expected to commence in Q3 2018.”

2017 YEAR-END UNCONVENTIONAL PROSPECTIVE RESOURCES SUMMARY

The D&M Resources Report was prepared using the guidelines outlined in the Canadian Oil and Gas Evaluation Handbook (“COGEH“) and in accordance with NI 51-101 and is valid at December 31, 2017. D&M evaluated the unconventional prospective resources attributable to the Teslimkoy/Kesan basin-centered gas prospect on Valeura’s lands in the Thrace Basin of Turkey. The working interest lands included comprise the deep formations (generally below 2,500 m depth) on the Corporation’s Banarli licenses (50% working interest), TBNG JV West Thrace lands (31.5% working interest), and TBNG JV South Thrace lands (81.5% working interest).

The D&M evaluation benefited from the Yamalik-1 natural gas-condensate discovery, which was recently drilled and tested on the Banarli licenses. Yamalik-1 discovered an approximate 1,300 m column of natural gas and condensate in over-pressured reservoirs below 2,900 m in the Teslimkoy and Kesan formations. The well was drilled to 4,196 m, fracture stimulated and production tested in Q4 2017. As announced on December 27, 2017, four production tests from eight frac stages in the Kesan formation yielded a 24-hour aggregate test rate of 2.9 MMcf/d. Extensive coring and wireline logging information was also captured in the well.

Yamalik-1 was the first well to be extensively facture stimulated in the basin-centered gas prospect in the Thrace Basin. However, well data from seven other legacy wells drilled in the prospective area to depths up to 4,050 m also indicate over-pressured natural gas below approximately 2,500 m and were available for D&M’s evaluation. Only one of these legacy wells (Yayli-1) was fracture stimulated with a small two-stage frac at a depth of approximately 2,800 m.

Table 1 below summarizes D&M’s estimates of Valeura’s working interest prospective natural gas resources (defined as “conventional natural gas” under NI 51-101). These numbers as reported by D&M are for the complete gas stream and explicitly include condensate resources (defined as “natural gas liquids” under NI 51-101) which are entrained in the natural gas. Sales gas volumes would be nominally lower than those presented in Table 1. Table 2 shows the amount of condensate that would be recovered associated with the production of the natural gas volumes shown in Table 1.

Table 1 Valeura Working Interest Natural Gas Prospective Resources at December 31, 2017^{(6)(7)(8)(9)(10)}

Valeura Working Interest Lands (1)	Unrisked				Chance of Commerciality % (11)	Risked Mean Estimate (12)
	Low Estimate (2)	Best Estimate (3)	High Estimate (4)	Mean Estimate (5)
Conventional Natural Gas (13) – Bcf
Total	3,229	7,652	20,077	10,137	51.1	5,182

 

The broad range of recoverable gas from 3.2 to more than 20 Tcf  is a function of the uncertainty in the various components of the assessment including recovery factor. There has been very limited stimulation and production testing from the over-pressured Teslimkoy and Kesan formations in the Thrace Basin, and as yet there is no production data. To determine potential recovery factors, D&M have utilized their experience in analogous basins. The prospective resources in Table 1 and 2 assume a low recovery factor estimate of approximately 25%, a best and mean estimate of 40% and high estimate of 55%. Significantly more delineation drilling, stimulation, and testing will be required to confirm that gas can be commercially recovered from the prospect, and to generate type curves that can be used in a predictive sense. All of Valeura’s prospective resources were sub-classified into the project maturity subclass of ‘prospect’.

Table 2 Valeura Working Interest Natural Gas Liquids Prospective Resources at December 31, 2017^{(6)(7)(8)(9)(10)}

Valeura Working Interest Lands (1)	Unrisked
	Low Estimate (2)	Best Estimate (3)	High Estimate (4)	Mean Estimate (5)
Condensate (Natural Gas Liquids) (14) – MMbbl
Total	45	155	504	236

 

D&M has assigned a chance of discovery of 70%. This high chance is driven by: (1) the hundreds of legacy wells drilled in the Thrace Basin which support the geological model for the Teslimkoy and Kesan formations; (2) the over-pressured natural gas which was encountered and tested at Yamalik-1, and (3) the seven legacy wells surrounding the basin which all encountered over-pressured gas below 2,500 m.

D&M has assigned a chance of development of the natural gas prospective resources of approximately 74%, which is a product of the probability of threshold economic field size and probability of development. This high chance of development reflects that existing hydraulic fracturing technology is being applied, well depths and costs are not expected to be excessive, sales pipeline infrastructure already exists in the area and there are ready domestic markets in Turkey for domestic natural gas and condensate sales. This results in an overall chance of commerciality of 51.1% which is the product of chance of discovery and chance of development. The resulting risked mean estimates of conventional natural gas prospective resources are shown in Table 1, as risked for chance of commerciality.

Understanding of the extent of this basin-centered gas prospect in the Thrace Basin and its potential commerciality is in the early stages of exploration and appraisal. There are a number of positive and negative factors which are driving large uncertainty. The key positive factors include:

• Design work is underway for the production facilities and gathering pipeline to tie-in the Yamalik-1 well to Valeura’s existing gathering sales pipeline infrastructure to enable a long-term production test and natural gas and condensate sales from the well at an anticipated cost of approximately US$3 MM (gross). First sales from Yamalik-1 are targeted for Q2 2018.
• Valeura and Statoil are planning a delineation drilling program comprising three wells expected to commence in Q3 2018 and extend into 2019. The first well in this program will be the second and final earning well under Phase 3 of the Banarli Farm-in to be fully funded by Statoil.
• The follow-up delineation drilling program will benefit from the new Karaca 3D seismic in terms of finalizing drilling locations, correlating the seismic to the Yamalik-1 well results and targeting sweet-spots in the basin-centered gas prospect.
• It is expected that the follow-up delineation wells will be drilled to approximately 5,000 m given good potential to extend the column of hydrocarbon-bearing sands. The Yamalik-1 well was drilled to 4,196 m, the limit of the rig capability and well completion, but the base of the well was still in gas-bearing sands that were successfully flow tested.
• Valeura’s existing infrastructure and customer base is expected to be capable of handling sales of more than 35 MMcf/d compared to current sales through the system of less than 10 MMcf/d, thereby providing the opportunity for early production from any future delineation wells.
• Turkey is a captive natural gas market given that 99% of its natural gas demand is served by imports. This provides an attractive marketing opportunity for a domestic natural gas producer. As Valeura’s natural gas production volumes potentially grow beyond the limit of its owned infrastructure, there are multiple take-away opportunities. These include: a potential to tie-in to a pipeline owned by Bori Hatlari ile Petrol Tasima Anonim Sirketi (“BOTAS“) just north of the Banarli lands; a tie-in to another BOTAS interconnector pipeline traversing Banarli and connected to an export line to Greece; and sales to the local gas distributor who currently offtakes gas from the BOTAS pipeline to the north.
• Natural gas prices in Turkey are strong. Valeura’s average natural gas price realization in Q4 2017 was approximately CAD$6.61/Mcf. On January 1, 2018, the reference natural gas price set by BOTAS was increased by 14%.

Negative factors with respect to the estimate of prospective resources include:

• The basin-centered gas prospect is in the early exploration and delineation cycle with very sparse well control and very limited fracture stimulation and testing data.
• There is no long-term well production performance from the basin-centered prospect to establish a production type curve specific to the prospect, thereby requiring use of analogue information at this time to establish development plans and to confirm the chance of commerciality.
• Recovery efficiencies are uncertain given the absence of site specific long-term well production performance data in the basin-centered gas prospect.
• The limited deep drilling carried out in the Thrace Basin provides poor visibility on future costs to drill, frac and complete deep development wells to exploit the basin-centered gas prospect and the associated impact on the chance of commerciality.
• Although oil and gas activity has been underway for many decades in the Thrace Basin area, as activity levels increase, timelines may increase to achieve government and local landowner approvals.

RESERVES UPDATE

For completeness, the Corporation also announces an update on its proved plus probable (2P) gross reserves attributed to its properties in the Thrace Basin of Turkey. The Corporation has completed an internal assessment (non-independent) which estimates 2P gross reserves of 7.8 MMboe effective December 31, 2017. This represents a significant increase in reserves relative to the reported year-end 2016 and is attributed to the TBNG acquisition which occurred after the year-end 2016 report.  The Corporation expects that the related 2P net present value of future net revenue before-tax for year-end 2017 will be similar to year-end 2016 as the increase in reserves from the TBNG acquisition is expected to be mostly offset by a reduction in the forecast gas price.

D&M are currently preparing their independent evaluation of the Corporation’s reserves at December 31, 2017. This information will be released in the normal course in March 2018 in conjunction with the release of the 2017 Annual Information Form.

ABOUT THE CORPORATION

Valeura Energy Inc. is a Canada-based public company currently engaged in the exploration, development and production of petroleum and natural gas in Turkey.

OIL AND GAS ADVISORIES

When used herein, the term “boe” means barrels of oil equivalent on the basis of one boe being equal to one barrel of oil or natural gas liquids, or 6.0 Mcf of natural gas. Barrel of oil equivalent may be misleading, particularly if used in isolation. A boe conversion ratio of 6.0 Mcf to 1.0 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

The prospective resources and reserves estimates provided herein are estimates only and there is no guarantee that the estimated reserves and prospective resources will be recovered.

RESERVES AND RESOURCES DEFINITIONS

“Chance of Discovery” is the estimated probability that exploration activities will confirm the existence of a significant accumulation of potentially recoverable petroleum.

“Chance of Development” is the estimated probability that, once discovered, a known accumulation will be commercially developed.

“Company gross reserves” are the Company’s working interest (operating or non-operating) share before deducting royalties and without including any royalty interests of the Company.

”Condensate” is defined as Natural Gas Liquids product type as per NI 51-101.

“Natural Gas” is defined as Conventional Natural Gas product type as per NI 51-101

“Proved” or “1P” reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

“Probable” reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable (“2P“) reserves.

“Prospective Resources” are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development.

”Reserves” are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on: (a) analysis of drilling, geological, geophysical, and engineering data; (b) the use of established technology; and (c) specified economic conditions, which are generally accepted as being reasonable and shall be disclosed. Reserves are classified according to the degree of certainty associated with the estimates.

FOOTNOTES TO TABLES

(1)	Valeura’s working interest in the lands (exploration licences and production leases) that are encompassed (all or a portion thereof) in the basin-centered gas prospect in the Teslimkoy/Kesan formation is as follows: Banarli 50%, West Thrace 31.5% and South Thrace 81.5%.
(2)	The low estimate is the P90 quantity. P90 means there is a 90% chance that the estimated quantity will be equaled or exceeded.
(3)	The best estimate is the P50 quantity. P50 means there is a 50% chance that the estimated quantity will be equaled or exceeded.
(4)	The high estimate is the P10 quantity. P10 means there is a 1 % chance that the estimated quantity will be equaled or exceeded.
(5)	The mean estimate is the probability-weighted average (expected value).
(6)	The totals are the arithmetic summation of probabilistic estimates. Arithmetic summation may produce invalid results except for the mean.
(7)	Unconventional prospective resources, as prepared by D&M, are those quantities of petroleum that are estimated, at a given date, to be potentially recoverable from undiscovered unconventional accumulations by application of future development projects. Unconventional prospective resources may exist in petroleum accumulations that are pervasive throughout a large potential production area and would not be significantly affected by hydrodynamic influences (also called continuous-type deposits). Typically such accumulations (once discovered) require specialized extraction technology (e.g. massive fracturing programs for tight gas). Tight gas occurs within low permeability reservoir rocks, which are rocks with matrix porosity of 10 percent or less and permeability of 0.1 millidarcies or less, exclusive of fractures. Tight gas can be regionally distributed (e.g. the basin-centered gas prospect in the Thrace Basin evaluated herein), rather than accumulated in a readily producible reservoir in a discrete structural closure as in a conventional gas field.
(8)	Prospective resources have both an associated chance of discovery and a chance of development. There is no certainty that any portion of the unconventional prospective resources estimated herein will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the unconventional prospective resources evaluated. Estimates of the unconventional prospective resources should be regarded only as estimates that may change as additional information becomes available. Not only are such unconventional prospective resources estimates based on that information which is currently available, but such estimates are also subject to uncertainties inherent in the application of judgmental factors in interpreting such information. Unconventional prospective resources should not be confused with those quantities that are associated with contingent resources or reserves due to the additional risks involved. Because of the uncertainty of commerciality and the lack of sufficient exploration drilling, the unconventional prospective resources estimated herein cannot be classified as contingent resources or reserves. The quantities that might actually be recovered, should they be discovered and developed, may differ significantly from the estimates herein.
(9)	The unconventional prospective resources estimates contained in the D&M Resources Report are expressed as gross and working interest unconventional prospective resources. Table 1 and 2 summarizes Valeura’s working interest unconventional prospective resources, which incorporate the fraction of potential hydrocarbon pore volume owned or partially owned by Valeura and Valeura’s working interest ownership, before deduction of any associated royalty burdens. Recovery efficiency is applied to unconventional prospective resources in Table 1 and 2.
(10)	The estimation of resources quantities for a prospect is subject to both technical and commercial uncertainties and, in general, may be quoted as a range. The range of uncertainty reflects a reasonable range of estimated potentially recoverable quantities. Estimates of petroleum resources herein are expressed using the terms low estimate, best estimate, high estimate and mean estimate (unrisked and risked) to reflect the range of uncertainty.
(11)	The chance of commerciality is defined as the product of the chance of discovery and the chance of development. Chance of discovery is defined in COGEH as the estimated probability that exploration activities will confirm the existence of a significant accumulation of potentially recoverable petroleum. Chance of development is the estimated probability that, once discovered, a known accumulation will be commercially developed.
	Chance of discovery in the D&M Resources Report is referred to as the probability of geologic success (Pg), which is defined as the probability of discovering reservoirs that flow hydrocarbons at a measureable rate. The Pg is estimated by quantifying with a probability, each of the following geologic chance factors: trap, source, reservoir and migration. The product of the probabilities of these four chance factors is Pg. Pg is predicated and correlated to the minimum case prospective resources gross recoverable volume(s). Consequently, the Pg is not linked to economically viable volumes, economic flow rates or economic field size distributions.
	In the D&M Resources Report, two factors have been considered in determining the chance of development as follows:
	Chance of development = Ptefs (probability of threshold economic field size) x Pd (probability of development)
	D&M defines Ptefs as the probability of discovering an accumulation that is large enough to be economically viable. Ptefs is estimated by using the prospective resources potential recoverable quantities distribution in conjunction with the threshold economic field size (TEFS). TEFS is the minimum amount of the producible petroleum required to recover the total capital and operating expenditure used to establish the potential accumulation as having a potential present worth at 10% equal to zero using the most likely price scenario.
	D&M defines Pd as the probability that a given discovery will be a viable development project. It takes into account the chance that the discovered target zone will flow the predicted hydrocarbon phase(s) at a commercial rate. It also considers the chance that the target zone can be mechanically completed and appraised in a reasonable time and in compliance with the projected cost schedule. The Pd is estimated by the quantification and product of these two chance factors.
(12)	The risked mean estimate of conventional natural gas prospective resources = the unrisked mean estimate x chance of discovery x chance of development.
(13)	The risked mean estimate of natural gas liquids prospective resources = the Unrisked mean estimate x chance of discovery.
(14)	The natural gas liquids prospective resources are included in the conventional natural gas prospective resources.

 

ABBREVIATIONS

Bcf	billion cubic feet
bbl	barrels
boe	barrels of oil equivalent
m	metres
M	thousand
MM	million
MMcf/d	million cubic feet per day
Tcf	trillion cubic feet

 

ADVISORY AND CAUTION REGARDING FORWARD-LOOKING INFORMATION

This news release contains certain forward-looking statements and information (collectively referred to herein as “forward-looking information“) including, but not limited to: the anticipated delineation drilling and development program to exploit the basin-centered gas prospect on Valeura’s working interest lands; the plans, timelines and cost to tie-in the Yamalik-1 well to conduct a long term production test, establish production type curves and achieve gas sales; completion of Phase 3 of the Banarli Farm-in and drilling of the second earning well to be funded by Statoil; the ability to target sweet spots in the basin-centered gas prospect; the plans to drill to 5,000m in the basin-centered gas prospect delineation program and the cost and timeline impacts; the capacity of Valeura’s existing infrastructure in the Thrace Basin and ability to handle up to 35 MMcf/d; the ability to access other pipeline systems in the Thrace Basin should future production volumes exceed the capacity of Valeura’s existing infrastructure; the anticipated conventional tight gas development program in the Tekirdag field that underpins the Corporation’s current probable and possible reserves; the preparation and timing of the 2017 D&M Reserves Report; and the ability to finance future developments. Forward-looking information typically contains statements with words such as “anticipate”, estimate”, “expect”, “target”, “potential”, “could”, “should”, “would” or similar words suggesting future outcomes. The Corporation cautions readers and prospective investors in the Corporation’s securities to not place undue reliance on forward-looking information, as by its nature, it is based on current expectations regarding future events that involve a number of assumptions, inherent risks and uncertainties, which could cause actual results to differ materially from those anticipated by the Corporation.

Statements related to “reserves” or “prospective resources” are deemed forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and prospective resources can be profitably produced in the future. Specifically, forward-looking information contained herein regarding “reserves” and “prospective resources” may include: estimated volumes and value of Valeura’s oil and gas reserves; estimated volumes of prospective resources and the ability to finance future development; and, the conversion of a portion of prospective resources into reserves.

Forward-looking information is based on management’s current expectations and assumptions regarding, among other things: political stability of the areas in which the Corporation is operating and completing transactions, and in particular the aftermath of the July 2016 failed coup attempt in Turkey and April 2017 constitutional referendum; continued safety of operations and ability to proceed in a timely manner; continued operations of and approvals forthcoming from the Turkish government in a manner consistent with past conduct; future seismic and drilling activity on the expected timelines; the prospectivity of the TBNG JV lands and Banarli licences, including the deep basin-centered gas potential; the continued favourable pricing and operating netbacks in Turkey; future production rates and associated operating netbacks and cash flow; future sources of funding; future economic conditions; future currency exchange rates; the ability to meet drilling deadlines and other requirements under licences and leases; and the Corporation’s continued ability to obtain and retain qualified staff and equipment in a timely and cost efficient manner. In addition, the Corporation’s work programs and budgets are in part based upon expected agreement among joint venture partners and associated exploration, development and marketing plans and anticipated costs and sales prices, which are subject to change based on, among other things, the actual results of drilling and related activity, availability of drilling, fracing and other specialized oilfield equipment and service providers, changes in partners’ plans and unexpected delays and changes in market conditions. Although the Corporation believes the expectations and assumptions reflected in such forward-looking information are reasonable, they may prove to be incorrect.

Forward-looking information involves significant known and unknown risks and uncertainties. Exploration, appraisal, and development of oil and natural gas reserves are speculative activities and involve a significant degree of risk. A number of factors could cause actual results to differ materially from those anticipated by the Corporation including, but not limited to: the risks of currency fluctuations; changes in gas prices and netbacks in Turkey; uncertainty regarding the contemplated timelines for the Yamalik-1 tie-in program; completion of the Banarli Farm-in program and the basin-centered gas delineation drilling program; the risks of disruption to operations and access to worksites, threats to security and safety of personnel and potential property damage related to political issues, terrorist attacks, insurgencies or civil unrest in Turkey; political stability in Turkey, including potential changes in Turkey’s constitution, political leaders or parties or a resurgence of a coup or other political turmoil; the uncertainty regarding government and other approvals; counterparty risk; potential changes in laws and regulations; and risks associated with weather delays and natural disasters; the risk associated with international activity; and, the uncertainty regarding the ability to fulfill the drilling commitment on the West Thrace lands. The forward-looking information included in this news release is expressly qualified in its entirety by this cautionary statement. The forward-looking information included herein is made as of the date hereof and Valeura assumes no obligation to update or revise any forward-looking information to reflect new events or circumstances, except as required by law. See Valeura’s 2016 AIF for a detailed discussion of the risk factors.

Additional information relating to Valeura is also available on SEDAR at www.sedar.com

Neither the Toronto Stock Exchange nor its Regulation Services Provider (as that term is defined in the policies of the Toronto Stock Exchange) accepts responsibility for the adequacy or accuracy of this news release.

SOURCE Valeura Energy Inc.

Maurel & Prom: -2017 sales: $400m (up 14%)

Fevereiro 6, 2018

Paris, 5 February 2018
 No. 02-18

2017 sales: $400m (up 14%)

• Group sales up 14% to $400m for 2017
  • Increase in the average sale price of oil: up 24% compared to 2016
  • Higher demand for gas in Tanzania: annual production up 13%
• Group reserves at 31 December 2017 in M&P share :
  • Gross P1+P2 reserves: 215 MMboe
  • P1+P2 reserves net of royalties: 195 MMboe

 

2017 Sales

The Group’s consolidated sales for 2017 amounted to $400 million (€355 million), up 14% compared to 2016.

This increase was due to the sharp rise in oil prices in 2017, despite a drop in oil production in Gabon during the period.
The average sale price of oil in fiscal year 2017 rose by 24% to $53/bbl versus $42.7/bbl in 2016.

To meet the higher demand for gas in Tanzania, gas production significantly increased starting in the second half of 2017. For the full year, average production stood at 49.1 MMcf/d at 100%, up 14% over the previous year.

Hydrocarbon production in 2017

Operated oil production in Gabon in the fourth quarter of 2017 amounted to 24,144 bopd, down 8% compared to the previous quarter. This was primarily due to the installation of an autonomous power generation system designed to reduce operating costs. Production was halted during its commissioning, resulting in an estimated loss of 860 bopd in Q4 2017.

To mitigate the Ezanga permit field depletion resulting, among other things, from its development programme being halted for close to three years on account of the drop in oil prices, Maurel & Prom Gabon will resume all of its drilling activities. This programme, set to begin in the first half of 2018, involves drilling 11 development wells and three sidetracks.
In addition, drilling of the first exploration wells on the Kari and Nyanga-Mayomnbé permits will start in the second half of 2018.

In Tanzania, demand for gas from the national company, TPDC, rose steadily in 2017 to reach average production of 62.2 MMcf/d at 100% in Q4 2017.
This demand, which is linked to industrial gas consumption in Dar Es Salam, is expected to increase further in 2018.
Group reserves in M&P share at 31 December 2017 (WI M&P)

The Group’s reserves correspond to the volumes of recoverable hydrocarbons currently in production plus those revealed by discovery and delineation wells that can be operated commercially. These reserves were certified by DeGolyer and MacNaughton in Gabon and RPS Energy in Tanzania as at 31 December 2017.

At 31 December 2017, gross P1+P2 (2P) reserves amounted to 215 MMboe, the equivalent of 195 MMboe in M&P share net of royalties.

In Gabon, 2P reserves net of royalties and restated for 2017 production amounted to 151.1 MMbbls at 31 December 2017, with P1 reserves accounting for 79% of that total. This level of certified reserves reflects the value and success of the work undertaken to optimise the Ezanga field following the drop in oil prices.

At 31 December 2017, the Group also had gas reserves of 265 Bcf.

These gas assets give the Group access to fixed, stable revenues over the long term. The sale price is $3.0441 per thousand cubic feet and rises with inflation. Maurel & Prom thus has cash flow unaffected by oil price fluctuations.

https://globenewswire.com/news-release/2018/02/05/1332573/0/en/Maurel-Prom-2017-sales-400m-up-14.html

 

KMG EP reserves update as at 31 December 2017

Fevereiro 1, 2018

http://www.lse.co.uk/regulatory-news-article.asp?ArticleCode=wrsgv56r&ArticleHeadline=KMG_EP_reserves_update_as_at_31_December_2017

RNS Number : 4570D
JSC KazMunaiGas Exploration Prod
31 January 2018
�
PRESS-RELEASE

Astana, 31�January 2018. JSC KazMunaiGas Exploration Production (“KMG EP” or the “Company”) announces the results of an independent audit of liquid hydrocarbon reserves at the Ozenmunaigas JSC, Embamunaigas JSC and the Ural Oil and Gas LLP (KMG EP’s share – 50%) fields as at 31 December 2017. The audit was performed by independent consultant DeGolyer and MacNaughton (“D&M”).

According to the D&M report, proved plus probable (2P) reserves of liquid hydrocarbons as at 31 December 2017 were 145 million tonnes (1,065 million barrels), equal to the level at the end of 2016. The reserve replacement ratio (the ratio of increase in reserves to annual production) was 100%.

Proved (1P) reserves of liquid hydrocarbons at 31 December 2017 were 102 million tonnes (754 million barrels), and proved, probable and possible (3P) reserves amounted to 193 million tonnes (1,418 million barrels).

Liquid hydrocarbon reserves as of 31 December 2017

(See Article link for tables)

The report does not include KMG EP’s share in reserves of JV Kazgermunai LLP, CCEL (Karazhanbasmunai) and PetroKazakhstan Inc.

NOTES TO EDITORS

KMG EP is among the top three Kazakh oil producers based on the 2017 results. The overall production in 2017 was 11.9 million tonnes (240 kbopd) of crude oil, including the Company’s share in Kazgermunai, CCEL and PKI. The Company’s volume of proved and probable reserves excluding shares in the associates, at the end of 2016 was 182 million tonnes (1,327 mmbbl). The Company’s shares are listed on the Kazakhstan Stock Exchange and the GDRs are listed on the London Stock Exchange and Kazakhstan Stock Exchange. The Company raised over US$2bn at its IPO in September 2006.

For further details please contact us at:
KMG EP. Investor Relations (+7 7172 97 5433)
Saken Shoshanov
e-mail: ir@kmgep.kz�

KMG EP. Public Relations (+7 7172 97 7887)

Bakdaulet Tolegen

e-mail: pr@kmgep.kz�

�

Finsbury (+44 (0)20 7251 3801)

Dorothy Burwell

e-mail: KMGEP@finsbury.com��

Forward-looking statements

This document includes statements that are, or may be deemed to be, ”forward-looking statements”. These forward-looking statements can be identified by the use of forward-looking terminology including, but not limited to, the terms ”believes”, ”estimates”, ”anticipates”, ”expects”, ”intends”, ”may”, ”target”, ”will”, or ”should” or, in each case, their negative or other variations or comparable terminology, or by discussions of strategy, plans, objectives, goals, future events or intentions. These forward-looking statements include all matters that are not historical facts. They include, but are not limited to, statements regarding the Company’s intentions, beliefs and statements of current expectations concerning, amongst other things, the Company’s results of operations, financial condition, liquidity, prospects, growth, potential acquisitions, strategies and as to the industries in which the Company operates. By their nature, forward-looking statements involve risk and uncertainty because they relate to future events and circumstances that may or may not occur. Forward-looking statements are not guarantees of future performance and the actual results of the Company’s operations, financial condition and liquidity and the development of the country and the industries in which the Company operates may differ materially from those described in, or suggested by, the forward-looking statements contained in this document. The Company does not intend, and does not assume any obligation, to update or revise any forward-looking statements or industry information set out in this document, whether as a result of new information, future events or otherwise. The Company does not make any representation, warranty or prediction that the results anticipated by such forward-looking statements will be achieved.

This information is provided by RNS, The company news service from the London Stock Exchange

NOVATEK Announces Year-End 2017 Reserves

Janeiro 25, 2018

Moscow, 23 January 2018. PAO NOVATEK (“NOVATEK” and/or the “Company”) announced that independent petroleum engineers, DeGolyer & MacNaughton, have completed their comprehensive reserve appraisal of the Company’s hydrocarbon reserves as of 31 December 2017.

Total SEC proved reserves, including the Company’s proportionate share in joint ventures, aggregated 15,120 million barrels of oil equivalent (boe), including 2,098 billion cubic meters (bcm) of natural gas and 164 million metric tons (mmt) of liquid hydrocarbons. Total proved reserves increased by 12.8% compared to the year-end 2016, representing a reserve replacement rate of 435% for the year.

The Company’s reserves were positively impacted by successful exploration works at the Utrennee, Kharbeyskoye, West-Yurkharovskoye and Urengoyskoye (Samburgskiy license area) fields, production drilling at the South-Tambeyskoye field, as well as the new licenses obtained through tender auctions (Gydanskoye, Verhnetiuteyskoye and West-Seyakhinskoye fields) and recent asset acquisitions (South-Khadyryakhinskoye, Syskonsynyinskoye fields and West-Yaroyakhinskiy license area). Excluding the effect of obtaining new licenses, our total proved reserves increased by 1.3%, representing an organic reserve replacement rate of 134%.

At year-end 2017, the Company’s reserve to production ratio (or R/P ratio) was 29 years.

Under the PRMS reserves reporting methodology, the Company’s total proved plus probable reserves, including the Company’s proportionate share in joint ventures, aggregated 28,471 million boe, including 3,879 bcm of natural gas and 366 mmt of liquid hydrocarbons.

NOVATEK reserves according to international standards
Proved reserves under the SEC methodology

***

Information provided in this press release represents expected results of PAO NOVATEK operations in 2017. The information represents preliminary assessment only, which can be adjusted after statistical, financial, fiscal and business reporting becomes available. The information on PAO NOVATEK’s operational results in this press release depends on many external factors and therefore, provided all permanent obligations imposed by the London Stock Exchange listing rules are unconditionally observed, cannot qualify for accuracy and completeness and should not be regarded as an invitation for investment. Therefore, the results and indicators actually achieved may significantly differ from any declared or forecasted results in 2017. PAO NOVATEK assumes no obligation (and expressly declares that it has no such obligation) to update or change any declarations concerning any future results, due to new information obtained, any future events or for any other reasons.

NOVATEK Announces Year-End 2017 Reserves

Algerian Sonatrach and Libyan NOC to jointly operate oilfields on mutual borders

Janeiro 17, 2018

Photo Source: NOC Facebook page. Left to right, NOC Chairman, Mr. Mustafa A. Sanalla; Sonatrach Chairman & CEO, Mr. Abdelmoumen Ould-Kaddour; and D&M Chairman & CEO, Mr. John W. Wallace

Algerian Sonatrach signed Monday an agreement with the Libyan National Oil Corporation (NOC) to run a number of oilfields located on the borders between the two countries, according to a statement on the NOC website.

According to the agreement was a further step on the ground after a study that was carried out on 2006 concerning Al-Rar and Al-Wafaa oilfields that are located on the borders between Algeria and Libya. Al-Rar gas field is located on the Algerian side of the border, while Al-Wafa oilfield is located on the Libyan side of the border.

“If it was proved that the two fields are in fact one field, they will be run and managed jointly by the two countries,” A source from Sonatrach told Anadolu Agency.

“Through the agreement, the two companies decided to update the old study using the technical data collected from January 2008 to present,” the source clarified, adding that the two companies are also seeking to achieve the optimal utilization for the two fields through the agreement.

Sonatrach have been halting all its projects and investments in Libya since 2011.
Source: http://www.libyanexpress.com/algerian-sonatrach-and-libyan-noc-to-jointly-operate-oilfields-on-mutual-borders/

Algeria, Libya agree to jointly manage oil fields on shared border

Janeiro 17, 2018

Algeria’s state-run oil company Sonatrach signed an agreement, Monday, with the Libyan National Oil Corporation (NOC) to run a number of crude oil fields located on the borders between the two countries.

The agreement included updating a study that was carried out on 2006 concerning Al-Rar and Al-Wafa oilfields, which located on the shared borders between Algeria and Libya, according to a statement by Sonatrach.

Al-Rar gas field is located on the Algerian side of the border, while Al-Wafa oilfield is located on the Libyan side of the border.

An official at Sonatrach, who preferred anonymity, told Anadolu Agency, said the study would “clarify the hypothesis of the connection between the Algerian Al-Rar gas field and the Libyan Al-Wafa oil field.”

Read More: Foreign intervention in Libya ‘frustrating progress’

“If it was proved that the two fields are in fact one field, they will be run and managed jointly by the two countries,” the source noted.

In September 2006, DeGolyer & MacNaughton (D&M) conducted a study, which aimed at confirming the existence of a connection between the two fields. The study depended on a data that was provided by Sonatrach and NOC.

“Through the agreement, the two companies decided to update the old study using the technical data collected from January 2008 to present,” the source pointed out, adding that the two companies are also seeking to achieve the optimal utilization for the two fields through the agreement.

Sonatrach have been halting all its projects and investments in Libya since the 2011 Arab Spring.

The oil extraction industry in Libya has been experiencing security hurdles, a fact that has led to a reduction in the country’s daily oil production by 30 per cent.
Source: https://www.middleeastmonitor.com/20180116-algeria-libya-agree-to-jointly-manage-oil-fields-on-shared-border/

DeGolyer and MacNaughton Signs Cooperative Agreement with SOCAR

Novembro 9, 2017

DeGolyer and MacNaughton Signs Cooperative Agreement to help SOCAR Improve Performance and Development of Azerbaijani Oil and Gas Fields

D&M’s John Wallace and Martin Wiewiorowski met this week with Rovnag Abdullayev, the President of SOCAR, to sign an agreement to help SOCAR, the state-owned oil and gas company, improve the efficiency of field development efforts in the country’s oil and gas fields.

According to a statement issued by the Azerbaijani Government, D&M will review the development plans for 20 fields and prepare recommendations for increasing oil production and recovery, reducing oil production costs, and defining short-term strategic goals. D&M will also participate in the implementation of those recommendations.

SOCAR announces Cooperative Agreement

D&M Hosts Seminars and Executive Briefings

Agosto 9, 2017

D&M Hosts Seminars and Executive Briefings on Unconventional Reservoirs
Presentations Focused on Reservoir Management and Well Performance Analysis

Due to their unique nature, unconventional assets present challenges in estimating reserves and resources. Over the past ten years in North America, petroleum companies, operators, and financiers have funded and developed unconventional resources at a remarkable pace, yet key questions related to the accurate projection and forecast of cash flow and production remain, even as the industry advances ever longer lateral wells in stacked plays. Production from these resources is, by its nature, a combined function of reservoir/fluid properties, geology, and completions, and consequently, production forecasting is not a simple curve-fitting exercise.

In its 2017 Executive Briefing and companion Unconventional Short Course series, DeGolyer and MacNaughton (D&M) reviewed its approach to answering these questions as well as associated issues with reserves and resources estimation as raised by recent SEC letters and practice. The combined audience of over 150 executives was drawn from D&M’s clients as well as non-clients and represented over 60% of the market value of all listed upstream oil and gas companies in North America. In addition, numerous privately held companies, investment banking entities, and North American and international sovereign wealth and private-equity firms, as well as the super-majors, were present. During the Executive Briefings, numerous insights were shared from D&M’s independent annual examinations of over 40% of North American unconventional resources wells. D&M’s methodology for evaluating unconventional reservoirs was shared in detail, including D&M’s combination of production diagnostics, analytics, model-based analysis, and static reservoir and completion data.

“D&M’s approach is unique, correct and very timely”-attendees at D&M’s 2017 Unconventional Resources Executive Briefing

The general feedback from the executives present at these briefings has been that “D&M’s [unconventional resources] approach is unique [among its peers], correct [technically], and very timely.” Indeed, the use of D&M’s approach was seen by these executives as applicable on a daily basis as opposed to purely during the reserves estimation cycle.

D&M’s diagnostic-based approach is already used by D&M engineers to examine and more accurately estimate performance from unconventional resources wells. D&M engineers bring a unique body of knowledge to bear through the use of this consistent approach. It is anticipated that additional insights will be drawn from the continuing examination of such wells, especially as completion designs are further refined, evolve, and are projected to set new economic benchmarks for particular formations.

The companion Unconventional Short Course: “Well Performance Analysis and Forecasting in Unconventional Reservoirs” was delivered by Dr. Dilhan Ilk, who leads D&M’s unconventional resources consulting activities. In this course, Dr. Ilk reviewed the theoretical foundations of the methodology used to analyze and forecast production. Examples of its application from major plays were reviewed in detail, and insights drawn from D&M’s work were presented to enhance attendees’ own ongoing work in unconventional resources. ​

One of the technologies D&M deploys to support its approach to unconventional resources is Kappa Engineering’s Citrine Field Production Analysis Module (Citrine). This new module has been developed by Kappa Engineering in collaboration with D&M and enables the rapid loading of mass public, client, or simulation sources for the processing of multi-well data. Particularly suited to unconventional plays, Citrine uses visualization trend identification and multi-well comparison to enable users to fully understand and interpret field performance using diagnostics and decline-curve analysis. Click here to learn more .

if you are interested in having Dr. Ilk lead a private version of the Unconventional Short Course: “Well Performance Analysis and Forecasting in Unconventional Reservoirs” for your organization.

In addition to a 2017 Executive Briefing event on August 28 in Denver, D&M will conduct further executive briefings in future.

if you wish to be included in future events.

Dr. Dilhan Ilk, Vice President at D&M, is a leading authority on well performance analysis for unconventional reservoirs.   The primary presenter for each of the meetings, Dr. Ilk says many companies are overestimating the potential of unconventional wells or at least not looking realistically about the production lifecycle.

Dr. Dilhan Ilk

 

Citrine Field Production Analysis

Kappa Engineering - Agosto 7, 2017

Kappa Engineering, in collaboration with DeGolyer and MacNaughton, has released a new module that enables the rapid loading of mass public, client, or simulation sources for the processing of multi-well data. Particularly suited to unconventional plays, Citrine uses visualization trend identification and multi-well comparison to enable users to fully understand and interpret field performance using diagnostics and decline curve analysis. Learn more.