Updates

BP expects to deliver around $10 billion of divestment proceeds

CGG delivers advanced 4D images for BP Angola survey in eight weeks

BP has announced that it now expects to deliver divestment proceeds and announced transactions totalling around $10 billion by the end of 2019, comprising the majority of its two-year divestment programme planned to complete by the end of 2020.

Following the $10.25 billion all-cash acquisition of US onshore assets from BHP in 2018, BP announced a $10 billion divestment programme over 2019 and 2020. The strong progress in delivering the programme has been driven by the agreed sale of BP’s interests in Alaska, as well as progress in divesting assets from its existing, nonBHP US Lower 48 legacy gas business.

The $5.6 billion sale to Hilcorp of BP’s Alaskan business – announced in August and subject to regulatory approval – is the largest single agreed transaction and is expected to complete in 2020. BP has also agreed the sale of four packages of legacy gas assets from its US Lower 48 business.

As a result of the agreed divestments, BP expects to take a non-cash, non-operating, after-tax charge of $2-3 billion in its third quarter 2019 results. BP will also continue to review asset valuations as divestments in the US Lower 48 progress over the fourth quarter 2019.

These impairment charges are expected to increase gearing in the short term, as a result of the impact on equity, with gearing remaining above the top end of the 20-30% range through year end. However, in line with the expected growth in free cash flow and the receipt of divestment proceeds, BP continues to expect net debt levels to reduce and gearing to move towards the middle of its target range of 20-30% through 2020.

Across the Upstream, BP continues to make strong progress with the delivery of its programme of major projects. 23 of the 35 projects expected online by the end of 2021 are now in production, with production ramping up from the four projects that have started up so far in 2019.

In the near term, BP’s third quarter 2019 production was impacted by turnarounds in some of the highest-margin regions, and output in the US Gulf of Mexico was significantly disrupted by Hurricane Barry, with facilities shut down for around 14 days. Taken together, these factors impacted BP’s third quarter 2019 production by around 100,000 barrels of oil equivalent per day, with the overall production mix in the third quarter having a higher proportion of barrels produced from higher tax regions.

As a result, BP’s underlying effective tax rate is expected to be around 50% in the third quarter 2019, significantly higher than in the second quarter. The full year 2019 tax guidance of around 40% remains unchanged.n

CGG Subsurface Imaging, part of CGG’s Geoscience division, has delivered state-of-the-art broadband 4D seismic results ahead of schedule from BP Angola’s latest monitor survey offshore Angola. This achievement builds on previous 4D seismic processing projects undertaken for BP Angola.

The enhanced imaging volumes from the Greater Plutonio development in the Lower Congo Basin were delivered four weeks early for this time-critical BP project. Faster than expected completion of this workflow, which included the latest advanced proprietary deghosting and demultiple technology, was made possible by continued investment in CGG’s high-performance computing capacity and the advance of its technology, along with close collaboration with the BP team.

“We were very impressed by the CGG team’s commitment to achieving an early delivery of the data on what was already a challenging schedule,” Radwa El Zidan, geophysicist from the BP-Angola asset team, commented. “The early delivery of results will accelerate our active reservoir management program for this field.” n

Rockwell Automation and Schlumberger announce closing of Sensia joint venture

Rockwell Automation and Schlumberger have announced the closing of their previouslyannounced joint venture, Sensia, the oil and gas industry’s first digitally enabled, integrated automation solutions provider. after a 40-year career with BP and over nine years as group chief executive,

The joint venture leverages Schlumberger’s deep oil and gas domain knowledge and Rockwell Automation’s rich automation and information expertise to address this fastgrowing market. Bob Dudley, 64, has decided to step down as group chief executive and from the BP Board following delivery of the company’s 2019 full year results on 4 February 2020 and will retire on 31 March 2020.

The Board is also pleased to announce that Bernard Looney, 49, currently chief executive, Upstream, will succeed Dudley as group chief executive and join the BP Board on 5 February 2020. Looney will continue in his current role until this date.

“Bob has dedicated his whole career to the service of this industry,” BP Chairman Helge Lund said. “He was appointed chief executive at probably the most challenging time in BP’s history. During his tenure he has led the recovery from the Deepwater Horizon accident, rebuilt BP as a stronger,

“Sensia will make industrial-scale digitalization and seamless automation available to every oil and gas company so their assets can operate more productively and profitably,” Allan Rentcome, chief executive officer of Sensia, said “It will make oil and gas production, transportation and processing simpler, safer, and more secure.”

Headquartered in Houston, Texas, Sensia is projected to generate initial annual revenue of $400 million and employ approximately 1,000 employees. Sensia will operate as an independent entity, with Rockwell Automation owning 53 per cent and Schlumberger owning 47 per cent of the joint venture. Rockwell Automation made a $250 million cash payment to Schlumberger

BP chief executive Bob Dudley to retire, to be succeeded by Bernard Looney

The Board of BP have announced that,

at closing. n safer company and helped it re-earn its position as one of the leaders of the energy sector. This company – and indeed the whole industry – owes him a debt of gratitude.”

On Looney’s appointment, Lund added: “As the company charts its course through the energy transition this is a logical time for a change. Bernard has all the right qualities to lead us through this transformational era. He has deep experience in the energy sector, has risen through the ranks of BP, and has consistently delivered strong safety, operational and financial performance. He is an authentic, progressive leader, with a passion for purpose and people and a clear sense of what BP must do to thrive through the energy transition.” n

Equinor joins third year of TechX accelerator

South America and Europe led oil and gas discoveries in Q3 2019

The Oil & Gas Technology Centre (OGTC) has officially launched the third year of its award-winning accelerator programme, TechX, with the announcement of new industry partner, Equinor.

The TechX Pioneer Programme – a unique technology accelerator and incubator - helps ambitious start-ups take their solutions to the energy market faster. To date, 21 companies have now graduated from the award-winning programme, developing ground-breaking technologies including a Lab-on-a-chip (RAB microfluidics), machine learning seismic imaging software (Optic Earth) and a complete oil field well surveillance technology (Ai Exploration).

In just two years, £2.8 million has been coinvested into these pioneering companies with a further £1 million of additional investment being secured post-graduation from the programme. Collectively, three field trials have been completed with seven planned over the next year and another 10 on the horizon, while 13 new jobs have been created and two new facilities have been opened.

“We’re excited to be partnering with Equinor, to harness their passion, entrepreneurship and technical innovation in mentoring this next cohort of Pioneers,” David Millar, TechX director at the OGTC, said. “While they have already supported the TechX programme during the customer validation stage, this strategic partnership will also allow us to align and broaden our focus on the Norwegian ecosystem, exposing UK-based start-ups and entrepreneurs to an important overseas export market that is leading the way for net zero carbon technologies.

“We look forward to strengthening this year’s programme, working closely alongside our broader partners, BP and KPMG, who have been instrumental in achieving our current success to date.”

BP Ventures, BP UK and KPMG will continue to support the programme, providing unrivalled access to technology specialists, financial experts and test facilities which will accelerate growth within the energy sector. For the third year in a row, BP will award additional funding of £135,000 to two exceptional Pioneers.

Applications for the Pioneer programme are now open for cohort three until 10th January 2020, including a specific focus on technologies that will help deliver digital transformation, low carbon including renewables, subsurface, asset integrity, wells, marginal developments and decommissioning. n South America and Europe led globally with the highest number of oil and gas discoveries during the third quarter (Q3) of 2019, with eight discoveries each during the quarter, according to GlobalData.

GlobalData’s report reveals that a total of 38 oil and gas discoveries were made globally in Q3 2019.

Out of eight discoveries in South America, six are conventional oil discoveries, one is a conventional gas discovery and the remaining is a heavy oil discovery. Europe had five conventional oil discoveries and three conventional gas discoveries in the quarter.

“In South America, Guyana-Suriname Basin and Llanos Orientales Basin had the highest number of discoveries in the quarter with three conventional oil discoveries each,” Adithya Rekha, oil & gas analyst at GlobalData, said. “In Europe, North Sea Basin had the highest number of discoveries with three conventional oil discoveries and a conventional gas discovery.” GlobalData identified Asia and Africa to be the second highest among the regions, in terms of number of discoveries in Q3 2019, with five discoveries each. Asia had three conventional gas discoveries and two conventional oil discoveries in the quarter, while Africa had four conventional oil discoveries and one conventional gas discovery.

Following Asia and Africa, the Caribbean stood third with four discoveries in the quarter. All the discoveries in the Caribbean are conventional gas discoveries. n

Total opens a digital factory to further its ambition of becoming the responsible energy major

Total will open a digital factory in Paris in early 2020 that will bring together up to 300 developers, data scientists and other experts to accelerate the Group’s digital transformation. Total’s goal is to leverage the capabilities of digital tools to create value in all of its businesses.

The Digital Factory will be tasked with developing the digital solutions Total needs to improve its operations, in terms of both availability and cost; offer new services to customers, notably in the area of managing and controlling energy consumption; extend its reach to new distributed energies; and reduce its environmental impact. Total’s ambition is

to generate as much as $1.5 billion in value per year for the company by 2025 through additional revenue and reductions in operating or investment expenses.

“I am convinced that digital technology is a critical driver for achieving our excellence objectives across all of Total’s business segments,” Patrick Pouyanné, chairman and chief executive officer of Total said. “Total’s Digital Factory will serve as an accelerator, allowing the Group to systematically deploy customized digital solutions. Artificial intelligence (AI), the Internet of Things (IoT) and 5G are revolutionizing our industrial practices, and we will have the know-how in Paris to integrate them in our businesses as early as possible. The Digital Factory will also attract the new talent essential to our company’s future.”

Under the direction of Frédéric Gimenez, Chief Digital Officer of Total and Digital Factory project manager, teams comprising top developers, data scientists, architects and specialists in agile methodologies will work with operating personnel from Total’s different businesses in the 5,500-square-meter facility located in the center of Paris. From deep in the city’s innovation ecosystem, they will shape the energy professions of tomorrow, focusing on solutions that can be deployed agilely within the Group. n

Forum’s latest ROV successfully completes sea trials

Forum Subsea Technologies’ latest remotely operated vehicle (ROV), the XLe Spirit, has successfully completed sea trials in Norway. The vehicle is the first of a new generation of electric observation class ROVs. It

Chevron has established new goals to reduce net greenhouse gas (GHG) emission intensity from upstream oil and natural gas. Emission intensity is the emission rate of greenhouse gas per unit of energy produced. The company intends to lower upstream oil net GHG emission intensity by five to ten per cent and upstream natural gas net GHG emission intensity by two to five per cent from 2016 to 2023. The timing is aligned with stocktake milestones set in the Paris Agreement on climate change.

The GHG emission intensity reduction metrics apply to all upstream Chevron oil and natural gas, whether Chevron has operational control or not. is the smallest in the new range, and powerful enough to perform subsea maintenance and repair work. It is ideally suited to the aquaculture market and capable of tasks such as net and tank inspection.

“Global demand for energy continues to grow, and we are committed to delivering more energy with less environmental impact,” Michael Wirth, Chevron’s chairman and CEO, said.

The new reduction goals build on other actions Chevron is taking to address climate change by lowering the company’s carbon intensity, increasing its use of renewable energy and investing in breakthrough technologies. Earlier this year, the company established reduction goals for methane emission intensity and flaring intensity. Chevron is a member of the Oil and Gas Climate Initiative and is helping fund a $1+ billion effort to develop new technologies and

Working with its Norwegian partner, Innova AS, Forum tested the XLe Spirit at a fjord with a 500m water depth. The standard equipment function testing was confirmed utilising all ancillary equipment, including cameras, lights, altimeters and sonars. The XLe Spirit benefits from an optional electric or hydraulic five-function manipulator arm. The self-regulating power feature compensates for tether losses ensuring a constant and stable power delivery to the vehicle, regardless of tether length. The trials follow a twelve-week assessment, which took place at Forum’s test tank in Kirbymoorside, Yorkshire, UK. The vehicle is the first observation class ROV to utilise Forum’s Integrated Control Engine (ICE™) to bring greater functionality commonly only found in larger work-class vehicles. The advanced control electronics pod fitted to all Forum XLe observation class vehicles enables superior connectivity and expansion capabilities compared to other ROVs on the market. Ethernet interfacing allows for seamless integration with other industry sensors.

The XLe Spirit incorporates a number of features to maximise its stability for use as a sensor platform, including regulated propulsion power and a wide range of auto-functions for

Chevron sets new greenhouse gas reduction goals

positioning and flying. n

businesses to reduce GHG emissions. Chevron also established a Future Energy venture capital fund to invest in technology to reduce GHG emissions and enable a greater diversity of energy sources. n

Oil industry can save $100 billion on digitalisation

In a new in-depth study, Rystad Energy estimates that as much as $100 billion can be eliminated from E&P upstream budgets through automation and digitalisation initiatives in the 2020s. Service companies are reinventing themselves to help operators unlock these savings.

In 2018, $1 trillion was spent on operational expenditures, wells, facilities and subsea capital expenditures across more than 3,000 companies in the upstream space. There are varying degrees of potential savings within offshore, shale and conventional onshore activity budgets, but in total, around 10% of this spend can be erased through more efficient and productive operations thanks to automation and digitalization.

“Many key industry players are setting optimistic goals, but the realisation of these initiatives largely depends on how freely data is shared amongst companies and how commercial strategies are deployed to drive this development,” Audun Martinsen, head of oilfield services research, said. “Because of this, it could be years before we see full adoption. However, based on our analysis of 2018 capital spend and operational budgets, we believe savings could easily reach $100 billion.”

The amount of savings has the potential to be significant and several operators expect automation and digitalization to reduce drilling costs by 10% to 20%, and facility and subsea costs by 10% to 30%. However, not all field developments or drilling operations have the same capacity to reduce costs. Adoption across the entire value chain of suppliers from national oil companies (NOCs) to majors to smaller E&Ps will vary, so the realistic efficiencies and synergies will be closer to 10% by the end of the next decade.

The painful oil market downturn has given upstream operators and service providers a strong incentive to adapt and become more efficient or be forced to close down shop.

A race among suppliers is currently underway as companies roll-out new digital products; the last three months alone have seen major releases by Schlumberger, Baker Hughes and TechnipFMC. One of the largest digitalization initiatives to date was recently launched on 17 September 2019, the result of a collaboration by Schlumberger, Chevron and Microsoft. This ambitious project aims to visualize, interpret and ultimately obtain meaningful insights from multiple data sources across exploration, development, and production and midstream sectors. n

FPSO market is booming with Brazil fuelling demand

The global market for floating production, storage and offloading vessels (FPSOs) is headed for a major renaissance with as many as 24 FPSO awards expected by 2020, driven to a great degree by Brazil. South America leads the pack with 12 sanctioned FPSO projects planned by the end of next year, followed by Asia with four, Europe and Africa analysis services has secured a new multi-million-pound contract with CNOOC Petroleum Europe for digital services across the company’s UKCS assets.

The three-year contract, with extension options, will see OPEX Group roll out its X-PAS predictive analysis service on the Buzzard, Golden Eagle and Scott platforms, supporting operations across all topside oil, gas, water and power systems. OPEX has delivered digital services for CNOOC Petroleum Europe Limited for the past seven years through its previous contract with the company.

with three each, and two more in Australia, according to Rystad Energy. Brazil – currently witnessing an influx of international E&P companies – is set to award seven more FPSO awards in 2020, thereby bringing the country’s tally to more than onethird of the awards anticipated globally in 2019 and 2020.

The X-PAS service has been developed by OPEX to support oil and gas operators improve the predictability of offshore operations. Combining oil and gas and data science expertise with a range of predictive technologies, the service helps operators to maximise the value of operational data.

OPEX collaborates closely with oil and gas facilities’ support teams to capitalise on this existing data and expertise in a way that enables them to act proactively in order to improve production uptime, solve complex problem areas and help reduce The seven projects already confirmed this year collectively represent production capacities of over 700,000 barrels per day of oil and around 60 million cubic meters per day of gas.

“The ongoing upswing in newly sanctioned FPSO projects points to a brighter future for the FPSO market. Offshore operators are finding their footing again after the downturn of 2014, as a robust rise in free cash flow has fueled a significant uptick in deepwater investments,” says Audun Martinsen, head of oilfield services research at Rystad Energy.

The FPSO boom in South America is mainly the result of large investments in deepwater exploration and field development. Another important factor has been Brazil’s recent relaxation of local content regulations, which has attracted new international players to the table.

“Brazil’s greater competitiveness on a global scale is a driver behind such huge FPSO awards, along with the region’s recovery from the Car Wash corruption scandal, Petrobras’ debt reduction, substantial pre-salt discoveries and healthier oil prices,” Martinsen noted. “These positive factors also add greater certainty to project timelines, and we no longer believe Petrobras’ developments will

OPEX Group secures North Sea contract for digital services

An Aberdeen-based provider of predictive

be subject to lengthy delays.” n maintenance costs. n

Upstream sector emerging as the epicentre for Industrial Internet adoption

The upstream sector is witnessing considerably more implementations of the Industrial Internet compared to other oil and gas sectors. This is driven by the need to reduce operational risks and maximizing returns from their assets through digitialisation, according to GlobalData.

The company’s latest thematic report: solutions specialist Amplus Energy Services has been awarded a multimillion-dollar contract to re-evaluate the development of marginal fields in Angola. The aim of the contract is to develop economically viable field development solutions for a major operator in Angola.

The six-month project will be managed by Amplus Energy Services from its Aberdeen headquarters.

Amplus will work in partnership with TechnipFMC and Halliburton to support the work on the project, while local support in

‘Industrial Internet in Oil & Gas’ reveals that the adoption of the Industrial Internet would enable companies in digitalizing oilfield operations and creating digital twins to reduce risks and optimize performance.

Industrial Internet has the potential to transform traditional processes and workflows and boost the technological capabilities of oil Angola will be provided by Amplus Energy Services’ partner in country – Prodiaman Oil Services.

The Amplus Versatile Production Unit (VPU) is the key to offering clients, safe, fit for purpose and extremely cost-effective production facilities. The VPU can support a wide range of production capacities.

The vessel operates on dynamic positioning (DP) and is fitted with a disconnectable turret buoy, which gives the VPU unrivalled safety performance, operational efficiency and mobility to move field to field, if required. The VPU’s ability to sit directly and gas firms. This could help them achieve two primary objectives: firstly, companies would be able to overcome operational challenges while venturing into new frontiers in search of hydrocarbon resources; and secondly, Industrial Internet adoption will improve productivity and efficiency, thereby strengthening market competitiveness in a challenging environment.

“In general, adoption of the Industrial Internet would make organizations more dynamic and adaptable to external factors,” Ravindra Puranik, oil & gas analyst at GlobalData, said. “This concept is expected to play a central role in simulation and modelling of projects against different market scenarios, optimizing inventory levels, demand forecasting, decision support, and logistics optimization, and setting up long-term objectives for an organization.”

Adoption of digital technologies has surged of late, largely as a reaction to the crash in crude oil prices. However, companies have been quite methodical in their approach to enable this transformation and ensuring maximum possible value can be derived through Industrial

Amplus Energy awarded first major contract in Angola

Aberdeen-based floating production

Internet implementations. n

above the subsea production facilities reduces cost in every aspect of a marginal field development. n

New light oil discovery in the Barents Sea

Well-Safe solutions awards two multi-millionpound contracts

Equinor and partners OMV and Petoro have made an oil discovery in the Sputnik exploration well in the Barents Sea. Recoverable resources are preliminarily estimated at 20-65 million barrels of oil.

The Sputnik well was drilled in licence PL855, approximately 30 kilometres North East of the Wisting discovery. The well encountered a 15 metre oil column in a Triassic sandstone reservoir. Fluid samples contain light oil and water.

“We are encouraged by this result as it confirms the presence of oil north of the Wisting discovery, where Equinor has acquired a strong acreage position,” says Nick Ashton, Equinor’s senior vice president for exploration in Norway and the UK. “The geology in the Barents Sea is complex, and more work lies ahead to determine commerciality. But this discovery shows that persistence and our ability to learn from previous well results does pay off,” says Ashton.

In 2017, Equinor’s Gemini Nord well resulted in a very small, uncommercial oil discovery in a reservoir channel system within the PL855 licence. In 2018, a larger channel complex was targeted in the neighboring PL615 licence, with the Intrepid Eagle well. This well proved a 200 metre gas column, but no oil. The Sputnik well, which is the second well in PL855, has proven oil in a large channel system. “Detailed fluid analysis combined with geological and geophysical mapping will be carried out to fully understand the commercial potential of the Sputnik discovery,” Ashton added. “If confirmed that the structure comprises volumes that can be recovered in a commercially viable way, the partnership will assess possible development solutions.”

The Sputnik well (7324/6-1) was drilled to a vertical depth of 1569 metres below the seabed by semi-submersible drilling rig West Hercules, which has now moved on to drill the Equinor operated Lanterna well in PL796 in the Norwegian Sea.

Equinor is operator and holds 55% of the PL855 licence. Partners are OMV (25%) and Petoro (20%). n Well-Safe Solutions has announced the award of two multi-millionpound contracts to continue the transformation of the Well-Safe Guardian, the decommissioning company’s first asset, into a bespoke plug and abandonment unit. Global Energy Group and Rigfit7seas have been appointed to deliver the ambitious refurbishment of the semi-submersible drilling rig. Global Energy Group will provide quayside services and the paintwork scope while Rigfit7seas will provide accommodation upgrade services.

Well-Safe is progressing in a timely manner with the refurbishment work on the asset which it acquired earlier this summer. As part of the upgrade, Well-Safe will be installing a dive system and the capability to deploy a SIL (subsea intervention lubricator). Phil Milton, Chief Executive Officer of Well-Safe Solutions, said: “The award of these contracts, within the timeframes we committed to, will ensure that this bespoke plug and abandonment asset will be available to the industry in 2020.”

Global Energy Group, who have been supporting Well-Safe with marine operations and quayside services since April this year have secured the contract to support the upgrades and life extension works at the Port of Nigg. n

Zohr gas production reaches 2.7 bcfd

Production from ENI’s Zohr field has now reached more than 2.7 billion cubic feet per day (bcfd), about 5 months ahead of the Plan of Development (PoD). This result has been achieved following the completion of all eight onshore treatment production units – the last one commissioned in April 2019 – and all Sulphur production units in August, the production start-up of two wells in the southern culmination of the field (in addition to the ten wells already drilled in the northern culmination) as well as the start-up on August 18th 2019 of the second 216 km long 30” pipeline connecting the offshore subsea production facilities to the onshore treatment plant.

The new pipeline, in conjunction with the completion and optimization of the plant treatment capacity, paves the way to increase, production wells on the Dvalin gas field in the Norwegian Sea, getting ready for the start of production in 2020. The Dvalin field will strengthen Wintershall Dea’s position as one of the largest gas exporters from Norway. Drilling of the production wells from the Transocean Arctic rig is expected to last approximately one year and follows by the year end, the field potential production rate up to 3.2 bcfd against the POD’s plateau rate of 2.7 bcfd. The Zohr field, the largest gas discovery ever made in Egypt and in the Mediterranean Sea, is located within the offshore Shorouk Block. In the Block, Eni holds a 50% stake, Rosneft 30%, BP 10% and Mubadala Petroleum 10% of the Contractor’s Share.

The project is executed by Petrobel, the Operating Company jointly held by Eni and the state corporation Egyptian General Petroleum Corporation (EGPC), on behalf of Petroshorouk, jointly held by Contractor (Eni and its partners) and the state company Egyptian Natural Gas holding Company (EGAS).

Eni has been present in Egypt since 1954, where it is the main producer with approximately 360,000 barrels of oil equivalent an intense summer of activity around the Wintershall Dea operated Dvalin development.

Since April there has been high activity at the Dvalin field with installation of pipe-lines and the manifold at 400 meters water depth. In August, a 3,500 tonne processing module was completed and lifted on to the nearby Heidrun platform in preparation for receiving gas from the Dvalin field. The field is located 259 kilometers north of Kristiansund in mid Norway.

“A summer of activity topped off with the start of drilling on the key Dvalin project is a potent sign of the belief we have in Norway, and the resources we are prepared to invest to reach our ambitions,” Hugo Dijkgraaf, Wintershall Dea chief technology officer, said. “The Dvalin team has worked tirelessly from day one to deliver a smooth, timely, and most of all safe project to date.” Dvalin is being developed as a subsea

per day equity. Such production is expected to further grow within the year, thanks to the ramp-up of Zohr and the start-up of Baltim

Production drilling starts on the Dvalin field in Norway

Wintershall Dea has begun drilling four

South West fields. n field tied back to Heidrun, which lies some 15 kilometers to the northwest. The four wells will be drilled to a depth of around 4,500 meters. The design philosophy for the wells has focused strongly on HSEQ, in line with the whole Dvalin project to date. The drilling team aims to maintain the project record of having no serious incidents. The Dvalin gas field in the Norwegian Sea is being developed with four subsea wells, tied back to the

Equinor operated Heidrun host platform. The gas from Dvalin will be transported to the Heidrun platform via a 15-kilometre pipeline. From there, it will be sent to the Polarled gas transportation system via a 7.5-kilometre pipeline, before it will be further processed to dry gas at the Nyhamna onshore gas terminal. Finally, the gas will be transported via Gassled to the market. n

North Sea oilfields cut downtime by 32 per cent in four years

North Sea oilfield operators have successfully reduced the frequency of offshore downtime by 32 per cent in the past four years, according to the Glacier Production Index

The index charts the frequency with which oilfields in the North Sea report zero production compared to those exporting oil into pipelines in any given month.

The launch report reveals a substantial decline in downtime in the past four years. In 2014, North Sea oilfields recorded 726 individual months of no production; by 2018, this had reduced to 497. Overall production remained steady in that timeframe, meaning the reduction in downtime converted directly into uptime.

The trend coincides with an industry-wide push to improve efficiency, which according to the Oil & Gas Authority has improved for five consecutive years to 2018. “North Sea oilfield operators have made a concerted effort to tackle downtime and maintain high levels of production efficiency,” Scott Martin, executive chairman of Glacier Energy Services, said. “These findings are testament to those efforts and should be seen as a boost to the industry’s supply chain.

“Downtime as a proportion of total production is at its lowest ebb since 2011. As overall production volume declines and the process of decommissioning intensifies, preventing unplanned downtime is becoming a constant preoccupation of operators.”

Despite the industry’s success in combatting downtime, levels of zero production remain twice as high as they were 10 years ago. According to the Glacier Production Index, downtime months hit an all-time low of just 203 in 2007 – less than half what they are today.

A more recent analysis of production in the North Sea over the past 12 months reveals an uptime peak in January 2019 (84 per cent), with a steady rise in uptime since June 2018. Uptime has now been above 80 per cent for five consecutive months.

“With more than half of North Sea platforms having gone beyond their original life expectancy, maintenance programmes can take them out of operation for extended periods of time,” Martin added. “Rising costs, coupled with lower levels of investment and available liquidity, means downtime is continuing to have a wider impact on production.” n