Spirit Energy boosts output at two North Sea fields

Following successful offshore drilling campaigns, oil and gas company Spirit Energy has boosted production from two North Sea fields.

Hummingbird Spirit FPSO; Source: Spirit Energy

According to Spirit Energy’s update on Friday, the first gas from the new C6 well at Spirit Energy’s Chiswick field in the Southern North Sea was achieved on March 11, 2020, and has added up to an additional 15 million standard cubic feet of gas per day to the field.

The Chiswick field, around 75 miles off the coast of Norfolk, has been producing gas since 2007. The new well brings overall production from the Greater Markham Area (GMA) to 110 million standard cubic feet of gas per day – enough to heat nearly 950,000 homes.

The development well, completed two months ahead of schedule, is expected to help extend life of the GMA hub to 2028.

The GMA hub spans both the UK and Dutch Continental Shelves, and comprises the Markham, Chiswick, Grove, and Kew fields.

Chestnut field

The Chestnut field is located in block 22/2a of the UK Continental Shelf (UKCS), in 117m water depth.

Spirit said that, together with partner Dana Petroleum, it had completed drilling of a new production well at the Chestnut field, extending the life of that field by as much as three additional years.

Initial expectation when the Chestnut field first came online more than a decade ago was for a little over two years’ production.

First oil from the new Chestnut well was achieved on March 19, 2020. Thanks to the £56 million ($67.32M) investment from Spirit Energy and Dana Petroleum in the new well and a contract extension with Teekay Corporation for the Hummingbird Spirit FPSO, another 2.5 million barrels have been unlocked, Spirit Energy explained.

Neil McCulloch, Executive Vice-President Technical & Operated Assets, said: “The results from the new well at Chiswick exceeded our expectations and will provide us with valuable data to identify further drilling targets in the area.

“At the same time, the work our teams have done alongside our partner Dana Petroleum and our supply chain colleagues, notably Teekay Corporation and Altera Infrastructure, to maximise the potential of the Chestnut field has been exceptional and is making this field a notable success story.

“The industry faces unprecedented challenges but, taken together, the additional gas and oil from Chiswick and Chestnut provide a boost to production from two UK fields at a time when the secure supply of energy is critical.”


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Coronavirus spread pushes Bahamas well drilling to October

London-listed oil company Bahamas Petroleum Company (BPC) has further pushed back the drilling of its first exploration well in The Bahamas, the Perseverance #1.


BPC said on Wednesday that the delay was a result of the “massive, unprecedented, and adverse impact of the spread of the COVID-19 virus.”

According to the company, drilling operations planned for the May/June 2020 timeframe can no longer be assured and are rescheduled to October 2020 onwards.

Cost-effective drilling can best be delivered by ensuring continuous operations throughout the entire period of the 45 – 60 day drill plan uninterrupted.

National and regional shutdowns are impacting the ability of drilling rigs and other mission-critical equipment to get properly prepared and certified for drilling due to travel bans and border closures. Also, The Bahamas declared a state of emergency with a curfew in place on March 17.

This is further compounded given the need to take into account the timing of the traditional hurricane season in The Bahamas which happens between July and mid-October.

“The Board has thus concluded that if the company was to continue to seek to commence drilling in the first half of 2020, there would be an unacceptable level of risk to the company’s ability to operate continuously, responsibly, safely, and within currently established guidelines, timelines and, as a consequence, budgets.

“Accordingly, the company has determined to postpone drilling operations until mid-October 2020 onwards, being after the expected peak in the COVID-19 response, and also after the peak risk period for hurricanes in The Bahamas,” BPC stated.

BPC added that the impact of the response to the spread of the coronavirus, both globally and in The Bahamas, also constituted a force majeure event under the terms of the company’s licenses. Due to that fact, BPC expects to receive a corresponding extension to the current term of the licenses from the Government of The Bahamas.

Simon Potter, CEO of BPC, said: “Given the ever-evolving adverse impact of the response to the spread of the Covid-19 virus – which is changing daily and is affecting everyone and all enterprises, around the globe – it has become clear to us that if we continue to push forward with drilling in the first half of 2020, safe and responsible operations would be compromised.

“Shareholders should be encouraged, however, that we are in a strong position to resume drilling activities toward the end of 2020, compared to where we were just a year ago. The company has cash reserves, and financial backers intent on flexibly supporting the company.

“We also have an approved environmental authorization from the Government of The Bahamas, farm-in discussions remain on foot, and the current crisis is presenting a number of interesting alternative opportunities for us.

“The spread of the Covid-19 virus represents a global threat to our collective way of life, and we all have to face reality over the coming months – which in the case of our company means pausing our drilling plans for a time, as hard as that may be. We hope that all of our shareholders, stakeholders, employees, and contractors take care, and stay safe and well in this extremely difficult time for all.”

No change in cost estimate

BPC said that the cost estimate for the Perseverance #1 well was in the range of $25 – $30 million, with potential contingencies for up to an extra $5 million. The company does not anticipate the cost estimate to change due to the rescheduled start of operations.

All previously agreed financial elements would see total funding availability of around $45 million, and issuance of approximately 1.6 to 1.8 billion new shares of BPC.

As a result of the global COVID-19 crisis, a large number of international drilling programs were canceled or postponed, and a large number of rig contractors are revisiting their work programs.

This is expected to have knock-on effects on rig availability and potentially lower rig pricing in the revised drilling window. BPC is already revisiting discussions with a range of contractors for securing a suitable drilling rig for the revised drilling window.

Furthermore, the company will continue to assess options for a farm-out or similar transaction in the coming months, and stated that a number of interested parties, including oil and gas majors and supermajors, have indicated that they would wish for discussions to continue regardless of the coronavirus global crisis and the recent decline in global oil prices.

BPC is also evaluating some potentially value-creating alternative strategic options presented to the company in light of the global COVID-19 crisis.


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EnQuest gives up on production re-start at UK fields

In light of recent developments in the oil market, oil and gas company EnQuest has decided not to re-start production at the Heather and Thistle/Deveron fields located offshore the UK. 

Thistle platform. Source: RMT

EnQuest was in October 2019 forced to evacuate workers from its Thistle platform following an inspection relating to a support element on a redundant subsea storage tank. During the same month, a small fire broke out on the Heather platform and two workers were injured. Production at Heather had been shut down for maintenance prior to the incident.

EnQuest said in November 2019 that single compressor operations had impacted production at Heather.

Production has been shut down at both platforms ever since. EnQuest previously planned to restore production at both platforms in the first half of 2020.

In an update on Thursday EnQuest said it had reviewed each of its assets and related spending plans in light of the current lower oil price environment.

EnQuest’s updated working assumption is not to re-start production at the Heather and Thistle/Deveron fields. Total combined production from these fields in 2019 was c.6,000 Boepd.

Cost-saving measures 

At the same time, the company is implementing a material operating cost and capital expenditure reduction program. This action will significantly lower EnQuest’s cost base, with group free cash flow breakeven targeted at c.$38/Boe in 2020 and $35/Boe in 2021, the company explained.

For 2020, the company is targeting base operating expenditure savings of c.$150 million, which would lower operating costs by c.30% to c.$375 million.

In 2021, the group is targeting unit operating expenditures of c.$15/Boe. These savings are driven primarily by cost savings at Heather and Thistle/Deveron, but also through the removal of non-critical and discretionary operating expenditures and support costs.

The company’s 2020 cash capital expenditure is also expected to be reduced by c.$80 million to c.$150 million. The majority of the group’s 2020 program relates to the recently concluded drilling program at Magnus and the two-well program now underway at Kraken, with approximately $50 million of 2020 cash capital expenditure relating to the phasing of cash payments into 2020.

The group’s 2021 capital expenditure program is expected to reduce further, although production is also likely to be impacted as a result.

The group retains significant liquidity with cash and available facilities of $268.2 million at February 28, 2019.

EnQuest Chief Executive, Amjad Bseisu, said: “Over the last few years, EnQuest has made significant progress in strengthening the business with our three world-class assets in Kraken, Magnus and PM8/Seligi, and a materially reduced debt position.

“Given the prevailing low oil price environment, we are taking decisive action to reduce operating and capital expenditure in 2020 and beyond, with a view to targeting cash flow breakeven of c.$35/Boe in 2021. While these actions have reduced our production expectations, free cash flow has improved and with no senior credit facility amortizations due in 2020 and long-dated bond maturities, we are positioning ourselves to manage through the current low oil price environment.”

It is also worth mentioning that offshore accommodation specialist, Prosafe, has recently been awarded a contract to provide accommodation in support of the redundant subsea tank removal and safe re-habitation of the Thistle Alpha platform in the UK North Sea.

Offshore Energy Today Staff


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Current market challenges not preventing Dorado partners to push for FEED

Australia’s Santos and Carnarvon Petroleum are progressing as planned with the development of the Dorado project, located offshore Australia, despite recent challenges in the market. The partners are focusing on starting the project FEED as planned. 

Dorado field illustration; Source: Santos

The giant Dorado development is located in permit WA-437-P. Santos is the operator and holds an 80% interest and Carnarvon is its partner with the remaining 20% interest.

Carnarvon said on  Monday that its strategy had intentionally targeted projects that have the potential to produce in low-cost environments and thereby absorb extreme economic events such as we’re experiencing at present, namely, a dramatic global response to the spread of the COVID-19 virus and to the fall in oil prices.

The sheer size and nature of the Dorado field means that it is a strong and robust project which is expected to produce at globally competitive capital and operating costs per barrel, Carnarvon said.

Entering FEED

On the Dorado field work, the Carnarvon team is working closely with the operator on a variety of components that are required to formerly enter the Front End Engineering and Design (FEED) phase. At this time there is nothing preventing the beginning of FEED nor its ongoing work throughout this and next year. This is a priority for Carnarvon and the recent global events have not affected this position, the company noted.

The exploration prospects around Dorado, such as Pavo and Apus, are looking attractive on the new Keraduren 3D seismic data. There are also new prospects showing up on the 3D seismic data.

Carnarvon is of the view that the current spot prices for oil do not represent longer term prices expected to be realized in ‘normal’ market conditions.

Carnarvon said: “The company has considered this situation carefully, particularly having regard to when the business expects first production from Dorado, and is confident that it makes sense to proceed with the businesses’ plans unchanged.”

Carnarvon’s Managing Director and Chief Executive Officer, Adrian Cook, said: “We have experienced market volatility in the past, such as with oil prices falling in 2015. During those times we also carefully assessed the situation and felt confident to remain active, working through the uncertainty and volatility that was present at the time.

“Taking this considered approach put the company in an incredibly strong position that resulted in the discovery of the Dorado field in 2018. We have once again taken the time to carefully assess market conditions. Our strong conviction is that the COVID-19 virus issue and low oil prices will be resolved in time. We are of the view that the most appropriate course of action at the current time is to continue to focus on the delivery of our plans, and that includes supporting the operator in advancing the Dorado development.

“Importantly, through careful management, we are in a position to proceed with our plans because of the very strong financial position of the Company. At 31 December 2019 we reported cash of $119 million. Since this time, we have been very prudent with our outlays and we will have more than enough financial resources available to cover our 2020 expenditure. Based on our current forecasts, we will also have more than enough to reach the Final Investment Decision for the Dorado liquids development.”

It is worth mentioning that Santos’ preferred concept for the Dorado project is an FPSO and wellhead platform development. In the initial phase, Santos plans for oil and condensate development followed by future phase of gas export.


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Equinor cleared to drill wildcat well in North Sea

The Norwegian Petroleum Directorate (NPD) has given Equinor a drilling permit related to the drilling of a wildcat well in the North Sea off Norway. 

Transocean Norge, formerly known as West Rigel; Source: Equinor

The NPD said on Friday that the 34/7-E-4 AH wellbore would be drilled from the Transocean Norge drilling rig.

The drilling program for wellbore relates to the drilling of a wildcat well in production license 089 where Equinor is the operator with an ownership interest of 41.5 percent.

Other licensees are Petoro, Vår Energi, Idemitsu Petroleum, and Wintershall Dea with 30, 16.1, 9.6, and 2.8 percent stakes respectively.

The area in this license consists of parts of block 34/7. The well will be drilled just southwest of the Snorre field.

Production license 089 was awarded on March 9, 1984, in the 8th licensing round on the Norwegian shelf. This well is the 41st exploration well to be drilled in the license.


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Rystad: With OPEC+ ready to unleash extra barrels, oil prices could fall into low $20s

Oil prices could fall into the low $20s for the global market to rebalance, as Rystad Energy expects an increase in global supplies in the next three months. OPEC+ countries are locked and loaded to add between 1.5 million and 2.5 million barrels per day (bpd), which Rystad estimates is their realistic short-term capability.

Illustration. Author: SP Mac

After the breakdown in OPEC+ negotiations and subsequent oil price free-fall, Saudi Arabia and the UAE have both signaled their intention to flood the market with additional oil production starting next month, Rystad said in a report released on Wednesday.

“Without OPEC+, the global oil market has lost its regulator and now only market mechanisms can dictate the balance between supply and demand,” said Espen Erlingsen, Rystad Energy’s Head of Upstream Research.

Rystad Energy estimates that global liquids demand was reduced by around 4 million bpd in February, primarily driven by the coronavirus. Over the next months, demand might be weakened by between 2 million to 4 million bpd due to the virus, Rystad said.

The cost of supply curves can be a good barometer to gauge how the market will react to various scenarios, says Erlingsen. Rystad Energy has updated its estimates of the short-run marginal (SRM) cost for the global liquids market.

For conventional fields, the SRM only includes transportation costs, effects of gross taxes and price differentials to Brent. All other costs, such as production cost and investments, are excluded, as Rystad Energy believes that these costs will not affect production levels from producing fields in the short term.

For tight oil assets, producing wells include the same costs as conventional fields, while the drilled uncompleted wells (DUC wells) also include the costs for completing the wells. For not yet drilled tight oil wells, both drilling and completion costs are included.

The shape of this curve is rather flat, as the SRM for the majority of the oil fields is below $5 per barrel. In fact, around 92 million bpd of production has an SRM below $5 per barrel. Total production with an SRM cost above $15 per barrel is around 4 million bpd.

Rystad Energy estimates that the total demand for liquids will be around 100 million bpd in June 2020, assuming no coronavirus impact.

The cost of supply curve moves to the right if OPEC+ increases production. The equilibrium price moves from around $25 per barrel (no additional OPEC+ supply) to $19 per barrel in the modest 1.5 million bpd increase scenario and $14 per barrel in the large 2 million bpd increase scenario.

If demand weakens by 2 million bpd in June (total demand of 98 million bpd), the equilibrium oil price moves from around $19 per barrel to around $11 per barrel in the modest OPEC+ increase scenario. If demand weakens by 4 million bpd in June (total demand of 96 million bpd), the equilibrium oil price moves down to around $9 per barrel in the modest OPEC+ increase scenario.


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UAE’s ADNOC pledges to increase oil supply amid price war

UAE’s oil giant ADNOC has decided to step up its efforts and produce more oil, pledging to increase supply to over 4 million barrels per day in April 2020 following the collapse of the OPEC+ agreement and the oil price war between Saudi Arabia and Russia.

Source: ADNOC

In a statement on Wednesday ADNOC Group CEO, Dr. Sultan Ahmed Al Jaber, said: “In line with our production capacity growth strategy announced by the Supreme Petroleum Council, we are in a position to supply the market with over 4 MMBPD in April. In addition, we will accelerate our planned 5 MMBPD capacity target.”

ADNOC also said it would provide better forward visibility to its customers and that it would shortly announce forward prices for the months of March and April 2020.

“This decision has been made to ensure that our customers have visibility of the price so they can plan accordingly,” ADNOC CEO said.

“As announced in November 2019, ADNOC remains firmly committed to moving from its current retroactive pricing mechanism to a new forward pricing mechanism for its flagship Murban crude oil. This will be traded on a new independent exchange, ICE Futures Abu Dhabi (IFAD), which is expected to launch after the necessary regulatory approvals are obtained.”

ADNOC’s decision to boost oil output comes after OPEC and Russia last week failed to agree on further production cuts in order to cope with falling global oil demand as a result of coronavirus outbreak.

OPEC suggested the extension of oil production cuts until the end of the year and further cuts until June 2020, but Russia refused to support this plan pushing OPEC to remove all limits on its own production, Reuters reported last Friday.

As a result, oil prices suffered a historic collapse last Monday after Saudi Arabia shocked the market by launching a price war against onetime ally Russia.

With the decision to increase output, UAE’s ADNOC has joined the state-run Saudi Aramco which, according to Reuters, plans to raise capacity to 13 million bpd from 12 million bpd.

Offshore Energy Today Staff


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Tailwind files environmental statement for North Sea project

Oil and gas company Tailwind Energy has filed an environmental statement for its Evelyn development, located in the UK North Sea, to the UK authorities. A final investment decision for the project is expected to be made this year. 

Triton FPSO
Triton FPSO; Source: Tailwind

Tailwind is working towards committing to development of the Evelyn field located in the Central North Sea.

Ensuring that environmental matters have been fully considered for the Evelyn Development, before the full field development decision is taken, Tailwind has prepared an Environmental Statement presenting the findings of the Environmental Impact Assessment and has been submitted to the UK’S Secretary of State for Business, Energy and Industrial Strategy (BEIS), the company informed on Tuesday, March 10.

A public consultation on the plans is underway. Tailwind will make a final investment decision on the Evelyn field in 2020, conditional upon the approval of the Environmental Statement.

Tie-back to Triton FPSO

The first phase of development will consist of a single well, subsea tie-back to the Triton FPSO. The subsea tieback will include a new 10ʺ production line, 4ʺ gas lift line and umbilical for control services. The first oil is expected by the end of 2022.

There is also a possible phase 2 development consisting of a second well also covered by the field development plan. A decision whether to proceed with Phase 2 will be taken following review of the success of the first phase of production to decide if it is necessary to maximise hydrocarbon recovery. The development of a second well (EV2) will include the installation of a new 10ʺ pipeline, 4ʺ gas lift pipeline and umbilical between EV2 and the Evelyn valve skid (EVVS).

No significant topside processing system modifications are required to process the Evelyn fluids over the Triton FPSO. The tie-in point for Evelyn will be via the new Triton P1 riser, which is already being replaced as part of a Dana maintenance subsea scope during the major 2022 shutdown, and is outwith the scope of this ES.

The Evelyn development is located in the Triton cluster. Tailwind in September 2018 completed the purchase of Shell UK Limited, Shell EP Offshore Ventures Limited, and Esso Exploration and Production UK Limited interests in the Triton Cluster.

The Triton area consists of six producing oil fields developed via common infrastructure in the UK Central North Sea, located approximately 190km east of Aberdeen in water depths of 90m. The six fields currently producing oil and gas via the Triton FPSO, are Bittern, Guillemot West, Guillemot Northwest, Clapham, Pict and Saxon.

Dana Petroleum and Endeavour Energy are Tailwind’s partners in the Triton cluster. Dana currently operates the Triton FPSO along with the Clapham, Saxon, Pict and Guillemot West fields. Following the recent Tailwind transaction with Shell/Esso, Dana now also operates the Bittern field. Tailwind is operator of the Gannet E Field, with Dana as pipeline operator and Petrofac as well operator. Tailwind also operates the Belinda/Evelyn discoveries with Petrofac as well operator.


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GulfSlope files for permit to drill Gulf of Mexico prospect

GulfSlope Energy has filed an application for permit to drill and submitted the exploration plan (EP) for the drilling of the Tau prospect on the outer continental shelf of the U.S. Gulf of Mexico.

Valaris 102 jack-up rig; Source: Valaris

The application for permit was filed with the Bureau of Safety and Environmental Enforcement and the EP was submitted to the Bureau of Ocean Energy Management. The company anticipates receiving approvals in late March.

Tau is a subsalt Miocene prospect located on Ship Shoal Area, South Addition Blocks 336/351 in approximately 305 feet of water. The Tau No. 2 well is designed to be drilled to 20,000′ TVD (21,543′ MD) to test multiple intervals that correlate to productive zones in the nearby Mahogany Field, located approximately five miles to the southwest.

GulfSlope is the operator with a 25 percent working interest and Delek GOM Investments LLC, a subsidiary of Delek Group, owns a 75 percent working interest.

John Seitz, Chairman and CEO of GulfSlope, said: “GulfSlope was encouraged by what we saw in the geologic section penetrated below salt in the Tau No. 1 well. The new surface location avoids issues encountered in the first well and optimizes below salt targeting of the prospective intervals. We are looking forward to drilling deeper and testing the large and very exciting exploration potential in the Tau Prospect.”

“We are conducting pre-drill activities and are actively working with our insurance underwriters to finalize the previously announced claim. The insurance proceeds should provide the majority of the funds required to drill Tau No. 2.”

GulfSlope has previosuly hired the Valaris 102 jack-up drilling rig. The company said last year that, in addition to a subsalt test well at Vermilion 375 (Corvette Prospect), the rig is also suitable for drilling the second well at Tau.


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Masirah flows first Yumna oil into tanker

Exploration and production company Masirah Oil has completed the Yumna 1 well and flowed first oil into an Aframax tanker. The well is located in Block 50, 30km offshore east Oman. 

Bull Papua tanker; Source: PT. Buana Lintas Lautan, Tbk

Masirah awarded a contract to Foresight Offshore Drilling to use the Foresight Driller IX drilling rig for the appraisal well on Block 50 in early November 2019.

Later that month, Masirah also awarded a contract to Wings Offshore for the floating storage and offloading (FSO) vessel, Mt Bull Papua, to be used on the Yumna field. The Mt Bull Papua is an Aframax tanker with a storage capacity of 750,000 barrels.

The well was spud on December 26, 2019.

In an update released earlier this week, Masirah said that the well came in as expected and confirmed the updated reservoir model.

The Yumna 1 well has tested at a production rate of 11,843 stock tank barrels of oil per day through a 1-inch choke, with a crude oil gravity of 42 degrees API. The Yumna field is being further appraised with an extended early production test.

The company also stated that further data evaluation and testing would be done and its findings would be released when completed.

Masirah is an 86.37 percent owned subsidiary of Singapore’s Rex International.

Commenting on Masirah’s update, Dan Broström, Executive Chairman of Rex International, said: “We are very happy with the successful results from the Yumna 1 well and are pleased to play a part in opening up a new frontier offshore, east of Oman. We expect the high level of activity to continue as we move forward in the block. We thank the Ministry of Oil & Gas in Oman for their support and help in this endeavor.”

Offshore Energy Today Staff


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