January 15, 2019

Recognizing the industry's current production challenges, imminent priorities and evolving technology requirements the annual Permian Basin Artificial Lift & Production Optimization conference returns to Houston in January, with an agenda that has been researched and redeveloped to assess production optimization and well reliability techniques and technologies that have been adjusted over the last 12 months to achieve better equipment, wellbore and production efficiencies.

The conference will feature speakers from operating companies, supported by technology providers and equipment suppliers, sharing first-hand technical expertise and strategic visions on the application of cutting-edge techniques and technologies.

Drilling Tools International will be among the exhibitors at this event and will be showcasing its latest technology. On display will be its friction reduction technology and Stinger tools.

The event takes place January 29 through 31 at the DoubleTree by Hilton Greenway Plaza Hotel in Houston, Texas.

More information can be found at www.permian-artificial-lift-production-optimization.com.

US player confirms oil find in Miocene sandstone reservoir and reveals start-up candidates for the year

Llog Exploration is set to bring online its newly-discovered Nearly Headless Nick field in the US Gulf of Mexico later this year, as the operator confirmed earlier reports of an oil find.

The US independent said oil pay was discovered in a high-quality Miocene sandstone reservoir at the field in Mississippi Canyon Block 387.

Block partners Kosmos Energy and BP had already lifted the lid on the discovery, which Llog said was made in 6500 feet of water some 150 miles southeast of New Orleans with the Rowan Resolute rig.

The Covington, Louisiana-based company said the field will be tied back to its operated Delta House facility in Mississippi Canyon Block 254.

Llog operates the field and is partnered by DGE, now acquired by Kosmos, as well as affiliates of Ridgewood, ILX and BP, which has a 10.125% stake.

It added that Nearly Headless Nick is one of three new fields that between them will see five new wells come online this year.

The others are Stonefly – which will be developed as a tie-back to the Ram Powell platform, with first oil seen in December – and Buckskin – a Lower Tertiary play in the Keathley Canyon-area that will tie back to the Anadarko-operated Lucius spar, 10 kilometers away in KC Block 875.

Those five wells are among nine wells that Llog expects to bring online this year, with the four others being development wells, split across its Who Dat, Mandy and Red Zinger schemes.

Llog also said on Monday it has 10 other developments that are in various stages of progression.

The company brought five operated discoveries online in the US Gulf last year: LaFemme in Mississippi Canyon Block 427, Blue Wing Olive in Mississippi Canyon blocks 427-471, Red Singer in Mississippi Canyon Block 257 – all of which are tied back to Delta House.

Completing the five were Claiborne in Mississippi Canyon Block 794 – tied back to the Walter-operated Coelacanth platform – and Crown & Anchor – tied back to Anadarko Petroleum’s Marlin.

Source: Upstream

It was a tumultuous year for oil markets. But as 2018 draws to a close, researchers at Rystad Energy believe global spending in the oil and gas sector will rise in 2019.

The Norwegian consultancy is forecasting an increase of 3%, which amounts to roughly $16 billion more than the investment total for 2018.

"Tight oil and deepwater will see the strongest growth, with an increase of 8% next year," said Espen Erlingsen, partner and head of upstream research at Rystad.

"In terms of the geographical split, 2019 exploration and production (E&P) investments are expected to grow the most in South America, North America, the Middle East and Africa."

Espen’s commentary echoes key findings from the latest edition of the Upstream Trends Report, Rystad’s flagship publication.

The report, which represents the firm’s latest take on the oil market, contains updates that follow the decision by OPEC and its allies to slash crude production by 1.2 million barrels per day (bpd).

Going forward, Rystad is confident that E&P companies are better equipped to live with lower oil prices than they were when the previous price shock hit the market in 2014. If prices fell to $40 per barrel in today’s market, the firm says there’s strong chance that both major global oil companies—and those that focus on tight oil production—could generate positive free cash flow.

Meanwhile, in an $80 per barrel scenario, Rystad believes global investments would increase by roughly 10% on average in 2019 and 2020. At $60 per barrel, it would expect to see a decline of around 2%.

"Investments in the offshore sector are more robust,” Erlingsen adds. “Even with an oil price of $50 per barrel, investments are expected to increase for midwater and deepwater E&P activities. US tight oil is still very sensitive to oil prices and a WTI oil price below $50 will reduce growth.""

Source: Upstream

New seismic techniques identify more barrels of oil potential at deep-water hubs.

BP this week unveiled fresh results from an ongoing advanced seismic campaign around its existing hubs in the deep-water US Gulf.

The company said new techniques have led to the identification of an additional 1 billion barrels of oil potential at the Thunder Horse field.

In recent months, the UK supermajor has also added at least six major new tie-back projects to its US Gulf line-up, with potential for more. The company said it has added at least a pair of opportunities at each of the Atlantis, Thunder Horse, Mad Dog and Na Kika hubs.

Seismic efforts include the application of proprietary algorithms to full waveform inversion seismic techniques — allowing data previously processed in a year-long timeframe to be crunched in just a few weeks — as well as specialized 4D ocean bottom nodes and BP’s Wolfspar seismic acquisition tool focused on low-frequency data.

BP has before spoken about the new resources uncovered via new seismic techniques and reservoir characterization, but the numbers involved have continued to increase.

At Atlantis, the company now believes it has identified an additional 400 million barrels of oil equivalent, up from the 200 million boe initially cited in 2017.

Overall, the UK supermajor aims to grow its net US Gulf production to 400,000 barrels of oil equivalent per day over the next decade, up from 300,000 boepd now and less than 200,000 boepd in 2013.

“BP’s Gulf of Mexico business is key to our strategy of growing production of advantaged high-margin oil. We are building on our world-class position, upgrading the resources at our fields through technology, productivity and exploration success,” said BP’s upstream chief executive Bernard Looney.

"And these fields are still young, only 12% of the hydrocarbons in place across our Gulf portfolio have been produced so far. We can see many opportunities for further development."

Next on the agenda for BP is development of two discoveries near the Na Kika hub, where there is optimism that new resources could lead to an estimated doubling of oil production.

The company identified Manuel, a recent infill drilling prospect on Mississippi Canyon 520, as one of them, with an eye to a 2021 start-up.

Subsea 7 and OneSubsea Schlumberger recently announced a contract to provide subsea services for this two-well development, with offshore operations to start in the fourth quarter.

BP also confirmed the Llog Exploration-operated Nearly Headless Nick find in Mississippi Canyon 387, where the supermajor has a 20.25% working interest. That discovery will be tied back to Llog's nearby Delta House production facility.

BP operates Na Kika on 50%, with Shell holding the remainder.

The company estimates the field contains 700 million boe of initial hydrocarbons in place net to BP.

In the case of Thunder Horse, following application of the new methods the company is planning a second south expansion, as well as a project called Thunder Horse Shallow. BP did not provide a timeline for any new plans at the hub, where expansion projects have been ongoing in recent years.

The company is targeting output close to 125,000 boepd by 2020 or thereabouts, according to a December investor day presentation made by BP executives in Oman.

The massive semi-submersible in Mississippi Canyon has plenty of space as it is the US Gulf’s largest platform, with capacity for throughput of 250,000 barrels per day of oil.

BP’s projects do not include exploration efforts by Thunder Horse partner ExxonMobil on its wholly-owned block immediately east of the platform, where the US supermajor has been drilling a well on Mississippi Canyon Block 779.

The UK supermajor is estimating net hydrocarbons initially in place resource for Thunder Horse at 2.9 billion boe.

BP operates Thunder Horse on 75% with ExxonMobil holding the rest.

And in addition to its new Argos semi-submersible platform at the Mad Dog field due to come on stream in late 2021, the company is also planning a Mad Dog north-west water injection project and a Mad Dog south-west expansion.

With the new platform having capacity of 140,000 gross bpd of oil, coupled with infill projects, BP is targeting a tripling of current production by 2025.

The company estimates its net in-place hydrocarbons at this greater field to be 2.7 billion boe.

Source: Upstream

Chevron has been greenlighted by regulators to drill what would appear to be its next Norphlet target in the Mississippi Canyon area of the deep-water US Gulf, a prospect called Yarrow.

The US supermajor’s objective lies in Mississippi Canyon 434 just south-west of Shell’s Appomattox discovery, the region’s first Norphlet development, which is due to begin production via a massive semi-submersible this year.

Chevron will use the drillship Pacific Sharav to tackle the prospect, which lies in 6940 feet of water about 66 miles offshore, according to data from the US Bureau of Safety & Environmental Enforcement. The drilling permit was granted on 10 January.

The US supermajor sketched out up to nine well and re-spud locations on the block, with each expected to take no more than 125 days to drill.

Chevron picked up the block at a 2016 lease sale on a 100% share.

The company still operates the block but was joined by French major Total on a 25% share. In July 2018 Total upped its stake to 40%.

Chevron and Total have teamed up for an exploratory campaign in the Norphlet that has already yielded a discovery at Ballymore.

Source: Upstream

BP is pressing on with its study of the Tigris project in the deep-water US Gulf of Mexico, despite partner Chevron’s decision earlier this autumn not to pursue the potential development any further.

The UK supermajor has been a 50% partner with Chevron in the venture, which originally aimed to develop the discoveries of Tiber, Guadalupe and Gibson via a centralized production hub.

The US supermajor told Upstream in September that it would no longer pursue the development and would seek to relinquish its stake in two of the discoveries.

BP, however, has confirmed to Upstream that it still sees potential in the Lower Tertiary fields that lie in a remote western part of the Keathley Canyon area of the Gulf.

"BP will continue to assess development for the Tigris project and we are evaluating our options," the company said.

"Tigris has been in the pre-front end engineering and design phase and is conceptualized as a multi-field hub development for the area."

Chevron had been progressing Tigris and Anchor in lockstep for the past year and a half via a lengthy joint pre-FEED process.

The idea was to develop designs and technology that could be used not just for Tigris but also the Anchor discovery.

Tigris had long been seen as coming later in the development queue due to a range of factors.

Those included challenging ultra-high pressure, high-temperature technology to cope with tricky Lower Tertiary geology, the spread of multiple discoveries across various blocks, and a remote location well removed from existing infrastructure.

However, Chevron has now decided the project could not be made to work despite the long period of study — a decision that came after a year in which the company also found two new promising discoveries in Ballymore and the Shell-operated Whale.

It's chief financial officer Pat Yarrington told investors on a call in recent weeks the move should not be read as a referendum on deep-water, but as chasing the highest-return projects.

BP, however, has also been part of the very small club of offshore players that has continued to demonstrate an appetite for new operated developments in the US Gulf, having sanctioned the Mad Dog 2 production semi-submersible currently under construction in Korea.

Lately, however, it has also focused on new resource opportunities around its existing hubs of Atlantis, Thunder Horse, Na Kika and Mad Dog to keep those facilities producing as close to full capacity as possible.

"The deep-water Gulf of Mexico is one of BP’s core areas globally, and BP believes it has significant opportunities for future growth based around four major producing hubs, four non-operated hubs and a highly prospective acreage position," BP said.

Source: Upstream

Louisiana’s Haynesville shale is poised to push gas production in the southern US play past a 2011 record as the Gulf coast gears up for an increase in liquefied natural gas exports, according to a new report from Norwegian consultancy Rystad Energy.

Between the fourth quarter 2016 and the same period in 2017, the play added 1.85 billion cubic feet per day of gross gas production. Last year, the Haynesville, housed partly in east Texas but mostly in north-western Louisiana, produced an additional 1.3 bcfd.

"We conclude that Haynesville shale’s revival, for the second year in a row, looks sustainable. Supported by its proximity to a new LNG export terminal, gas production will continue to grow, and achieving new all-time high gas production levels should happen within a matter of months," Rystad Energy partner Artem Abramov said.

For the play to reach all-time highs, it must produce an additional 700 million cubic feet per day, the report said. The play’s production peak was at 7.5 bcfd in the fourth quarter of 2011.

The play had 63 rigs operating this past week, up seven from 2017, according to a weekly tally by energy services firm Baker Hughes.

Added capacity at LNG projects such as Freeport, Cameron, Corpus Christi and Elba Island is expected to tip production over 40 million tonnes per annum in 2019, Rystad said, driven especially by Cheniere Energy’s Sabine Pass terminal in Louisiana.

The Sabine Pass facility currently operates four liquefaction trains and was the first big LNG export facility to enter service in the Lower 48 US states in February 2016. A fifth train is expected to enter commercial service in the first quarter of 2019.

In February 2017, pipeline operator Williams provided 1.2 billion cubic feet to Sabine Pass when it brought the Gulf Trace project online.

Source: Upstream

BP is evaluating whether to drill another well at its consolidated license off Nova Scotia where it drilled its unsuccessful Aspy probe last year.

The UK supermajor has agreed to surrender half the lands and pay a C$1 million drilling deposit to regulators in order to extend the license by one year.

The first phase of BP's consolidated exploration license (EL) 2434R expired on Monday after a term of six years, according to the Canada-Nova Scotia Offshore Petroleum Board. In order to move into a second, three-year phase BP would have had to have drilled four wells during the first phase. Since it only drilled the Aspy well, the company exercised its option to give up 50% of the license and to pay the deposit.

"We reviewed our very large acreage, and this is routine license management activity," BP said in a statement. "We are currently evaluating the data from the Aspy well and that data will help determine our plans going forward."

If BP decides to drill another well during the one-year extension, it will need to apply to the CNSOPB for authorization. If it does not, it will have the option to either forfeit the drilling deposit and pay another $1 million to extend the license for another year, or to forfeit the deposit and surrender 50% of the remaining lands. The latter choice would move the license into the second phase, the CNSOPB said.

Source: Upstream