IOG52

OGT O I L & G A S T E C H N O L O G Y

Deciphering the performance puzzle in shales

Africa’s rising stars Intelligent computing at the wellhead Cementless future for completions Data is king

ISSUE 52

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AUTUMN 2019

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Going Digital

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OIL & GAS TECHNOLOGY www.oilandgastechnology.net

Editorial Mark Venables – Editor in Chief mark.venables@cavendishgroup.co.uk

own it, not the functions, the functions play a key role in being a partner and enabling that journey.

Ben Avison – Group Editorial Director ben.avison@cavendishgroup.co.uk

But if your business does not own it, it will not

Designers Meng Xiangwei

take off. From then on it is about getting the value

Chairman Koos Tesselaar

because it is fun. You must have the value at the

out of digitalisation, It is not enough to do digital

end that you are trying to achieve. The data is an

CEO Matthew Astill

asset and a a threat as well. Alieh believes that

Managing Director Adam Soroka

of the importance of data and the damage that it

companies that have not understood the concept

can incur are in trouble. It is extremely important

Advertising Director Mike Smith mike.smith@cavendishgroup.co.uk

that we have a grip on how we treat our data in a digital transformation world.

Expert Advisor Trish Meek, Director of Product Strategy Thermo Fisher Scientific

Digital transformation is just another wave that the industry is facing. In the rush to digitise there are two things that must always be borne in mind;

OGT O I L & G A S T E C H N O L O G Y

ISSUE 52 AUTUMN 2019

two constants that will always be there. They were there before the digital wave began and they will

Deciphering the performance puzzle in shales

OIL & GAS TECHNOLOGY

The digital transformation continues to sweep through the industrial sector and the oil and gas industry is no exception. But what is at the heart Africa’s rising stars

of this transition? One opinion I heard at the recent

Intelligent computing at the wellhead Cementless future for completions Data is king

ISSUE 52

|

AUTUMN 2019

Offshore Europe event was integration. This was the

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IOG_Cover_new.indd 1

19/11/2 下午8:05

view of Rami Alieh, GM digitalisation upstream at

be there when digital transformation reduces and something else comes along. It is people and data.

These are the only two things. Data is just going to increase. And the people are the key value.

Combining those two together makes the industry powerful, makes it capable of leading, not just embracing but leading that transformation.

Oil & Gas Technology

Shell, and it is hard to argue with him. Digitisation

Cavendish Group

is about integrating, different disciplines, functions

In the end, digitalization is undertaken for the

Second Floor Front

together. It is about integrating our data together.

sake of generating value. It is for the sake of value.

It is about bringing people together. It is about

Value for customers, value for employees, value for

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bringing down the walls of organisational structures.

society. It is this value that the industry is after.

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efficiently in generating value.

He went on to add the he defines digitalisation as turning data, trusted data into insights, insights into action, but then acting on those actions to generate © copyright 2019 Cavendish Group

value. For it to succeed any digital transformation must be business owned. It is for the business to

Mark Venables Editor Oil & Gas Technology

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CONTENTS

18

Analysis: Deciphering the performance puzzle in shales NEWS AND COMMENTARY 6 Updates

The latest news from around the globe

18 Analysis: Deciphering the performance puzzle in shales

In this first part of a four-part article series, Moving the US shale revolution forward, Scott Sanderson, Tom

Bonny, Scott John, and John England from Deloitte aim to study the learning curves, unearth success

factors, and identify operational well-enhancement

22

opportunities for US shale operators. The analysis is based on Deloitte’s statistical interpretation of reported well-level geological, engineering, and productivity data.

30 Improving performance with intelligent computing at the wellhead

22 In Their Words: Ben van Beurden, CEO of Shell

Speaking to the Oil and Money conference in London,

Production from US oilfields growing the drive to

in November, Ben van Beurden, CEO of Shell, speaks

increase efficiency and boost production from the

climate change and the need for the energy industry

is gaining pace, and one of the most promising

hundreds of thousand wells dotted across the country

about the global evolution underway in response to to embrace it.

solutions is the digital wellhead.

26 Region report Africa: Africa’s rising stars

34 Moving to a cementless future for completions

Oil and Gas Technology looks at the prospects of four of Africa’s rising stars in Republic of Congo, Gabon, Gambia and Namibia

By utilising an innovative cementless technology Total were able to reduce risk and increase operational

efficiency for their Moho North field in The Congo.

34

Moving to a cementless future for completions 38 Data is king

Whether process plant, module or installation,

the refinement of risk and maintenance planning is a constant process and one that involves the management of a vast set of variables.

41 Time for oil and gas to face the music on data

The maxim that data is the new oil had been floated around the oil and gas sector for several years now and while that might be overly simplistic it will play

46

a crucial role going forwards if it can be managed

effectively. To do that the sector could do worse that take a look at how the music industry handles data.

44 Design, digital and detail; saving millions with conductor analysis

50 Working towards a low carbon future

vice president of new equipment sales and customer

The design, maintenance and monitoring of key

operations for Siemens Oil & Gas, about the importance

components such as risers and conductors has

developed significantly as the industry has matured.

of decarbonising the entire oil and gas supply chain

Today, highly developed digital technology is playing

54 Innovation Focus

savings, but also improving the safety of operations.

62 Diary

a huge part, not only in providing efficiency and cost 46 Utilising flare gas to generate power for the oil and gas sector

Oil & Gas Technology spoke to Matthew Chinn, executive

A look at the most innovative new products and services

64 Final Word: Replacement ratios

According to figures from Rystad Energy the so-called

Dynamic expansion of the oil and gas industry

resource replacement ratio for conventional resources now

that tackle the impact of flare gas emissions globally.

every six consumed is being replaced by new sources.

continues to fuel the demand for new technologies

stands around 16%, meaning that only one barrel out of

Updates

BP expects to deliver around $10 billion of divestment proceeds

B

P 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

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Oil & Gas Technology |

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

www.oilandgastechnology.net

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

C

GG 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

Updates

Rockwell Automation and Schlumberger announce closing of Sensia joint venture

R

ockwell 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.

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.

“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 at closing. n

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

T

he Board of BP have announced that, after a 40-year career with BP and over nine years as group chief executive,

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,

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

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Updates

Equinor joins third year of TechX accelerator

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

S T

he 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,”

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Oil & Gas Technology |

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

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outh 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

Updates

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

T

otal 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

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Updates

Forum’s latest ROV successfully completes sea trials

F

orum 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

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.

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 positioning and flying. n

Chevron sets new greenhouse gas reduction goals

C

hevron 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.

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Oil & Gas Technology |

“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

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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

Updates

Oil industry can save $100 billion on digitalisation

I

n 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

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Updates

FPSO market is booming with Brazil fuelling demand

T

he 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

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 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 be subject to lengthy delays.” n

OPEX Group secures North Sea contract for digital services

A

n Aberdeen-based provider of predictive 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.

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Oil & Gas Technology |

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 maintenance costs. n

www.oilandgastechnology.net

Updates

Upstream sector emerging as the epicentre for Industrial Internet adoption

T

he 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:

‘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

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 Internet implementations. n

Amplus Energy awarded first major contract in Angola

A

berdeen-based floating production 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

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

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

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Updates

New light oil discovery in the Barents Sea

Well-Safe solutions awards two multi-millionpound contracts

W E

quinor 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

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Oil & Gas Technology |

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

www.oilandgastechnology.net

ell-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

Updates

Zohr gas production reaches 2.7 bcfd

P

roduction 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,

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

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 South West fields. n

Production drilling starts on the Dvalin field in Norway

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intershall Dea has begun drilling four 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

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

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

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Updates

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

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orth 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

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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

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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

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Analysis

Deciphering the performance puzzle in shales In this first part of a four-part article series, Moving the US shale revolution forward, Scott Sanderson, Tom Bonny, Scott John, and John England from Deloitte aim to study the learning curves, unearth success factors, and identify operational well-enhancement opportunities for US shale operators. The analysis is based on Deloitte’s statistical interpretation of reported well-level geological, engineering, and productivity data.

I

n mid-2019, US crude oil and natural gas production reached a record high of 12 million barrels per day (MMbbl/d) and 90 billion cubic feet per day (Bcf/d), respectively, mainly due to the high growth of unconventional tight oil and shale gas in recent

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years. In fact, the shale-rich state of Texas is now producing 5 MMbbl/d of oil, more than any OPEC member, barring Saudi Arabia. But, while volumetric growth rates are well known, more specific factors driving this success are far less understood by most stakeholders.

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Isolating shale’s success factors or continually improving productivity in shales is not easy, and that is probably why many shale operators face regular questions on productivity, efficiency, and returns. In the series, Moving the US shale revolution

Analysis

forward, we undertake an integrated statistical analysis of geological, engineering, and productivity data from over 80,000 horizontal shale wells to bring more clarity in understanding this relatively young resource, its performance, and potential.

Although not a substitute for well- or play-specific reservoir and petrophysical interpretations, our work highlights success factors, ongoing challenges, and improvement opportunities for shale operators.

The US oil and gas renaissance For much of the first decade of this century, US energy agencies and policymakers foresaw continuing declines in US oil and gas production, even when taking account of continued investments in deepwater plays in the Gulf of Mexico. However, the advent and commercialisation of hydraulic fracturing and horizontal drilling beginning in the Barnett Shale paved the way for rapid expansion in unconventionals starting 2005. Optimism gained momentum when the US Energy Information Administration (EIA) estimated US shale gas and tight oil reserves at 750 trillion cubic feet (Tcf) and 24 billion barrels, respectively, in 2011, and the confidence soared every time the agency revised its estimates upward. Latest estimates peg reserves at 1,280 Tcf of shale gas and 112 billion barrels of tight oil.

Fast forward a couple of years, shales have outstripped most previous expectations and seem to have altered the entire oil and gas landscape, with the United States now projected to be energy-independent by 2020.

By mid-2019, US tight oil production reached 8.5 million barrels per day (MMbbl/d), or almost 10 per cent of world production. The economic impact of this growth been considerable, as US shales have contributed close to US$1.5 trillion since 2006, close to three times Nigeria’s GDP in 2018, for example.

Understanding shale’s growth drivers Shales are organic mudstones consisting of silt and clay that have a complex and heterogenous mineralogic accumulation/ thickness (formation), require custom

engineering designs and completion stimulations (E&C), and are strongly guided by many above-surface planning and efficiency measures (P&E). Given the intricacy and interdependency among variables, a statistical analysis of all three components (formation, E&C, and P&E), and multiple metrics within each, is necessary to understand its success in the United States.

Certainly, every operator wants to have majority of its acreage and wells in high-quality formations and many have been successful, when measured in absolute terms. But overcrowding and high valuation of acreage in these sweet spots have limited the upside from these areas. The result: an operator’s portfolio ends up comprising many wells in lowerquality formations, reflected in a flat-to-lower formation quality index for all wells spud in the United States since 2009.

Dissecting formation quality, about 85 per cent of wells spudded since 2017 have had a low gamma ray reading, which measures natural radioactivity of a formation. Similarly, petrophysical properties such as deep resistivity logs have been far less encouraging for recently drilled wells.

On the other hand, unique engineering designs and intense completions, which have been the hallmark of the shale boom, have compensated for lowerquality formations available or targeted by operators. Over the past ten years, the industry’s completion intensity has increased by 65 per cent due to the increased quantities of proppant and fluids and longer perforated interval. Whether we call them ‘high-intensity completions’ or ‘generation x frac’, these have helped operators to produce more from the same formation and sustain their production even in a period of downturn.

Although above-surface P&E does not impact operators’ productivity directly, time and cost savings and better management of produced resources lower their breakeven.

Operators, with the help of service companies, have made huge strides in reducing their days per foot or lowering the shale cycle time by an average of 100 days.

The P&E index, as a result, has improved by 12 per cent over the past five years, in a lower commodity price environment when there was significant pressure to maintain production growth without increasing capital intensity. And this efficiency has not been limited to a select few; in fact, most operators have gained over the years.

While these three factors have played a role in driving US shale growth, the combination and balance of factors that have made this growth possible remains subject to vigorous debate. The debate is, however, reasonable considering that the development of shales is relatively immature, shale operators are learning by experimenting, and hydrocarbon recovery differs by each basin and even within a basin.

Different basins, different stories Every shale play is different. For instance, among the oil-heavy basins, the Permian’s formation quality seems to be the finest.

Not only does the basin have one of the thickest formations (crossing 800 feet) and many productive layers (nearly a dozen), it also has one of the highest net hydrocarbon potential, reflected in its high resistivity log measurements. Similarly, the gas-heavy Appalachian basin has a strong natural gas crossover of bulk density and neutron porosity logs and the highest gamma ray readings (above 135 API), both of which are indicative of abundant total organic carbon. The large potential of these basins, most probably, explain their high attractiveness and thus the shift of industry’s drilling activity toward these basins in recent years.

Like formations, engineering designs and completion intensity vary significantly by basins. Operators have been experimenting with completion design changes by varying quantities of proppants, fluids, and lateral length, especially in the Permian basin. The basin, despite its high formation quality, has among the least established E&C maturity. Proppant quantity, for example, ranges from few hundred to 2,500 lbs/feet in the basin. The E&C curve of the Eagle Ford basin (on the Gulf Coast), on the

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Analysis

contrary, is normally distributed. Operators in the basin have a maximum number of wells where proppant quantity averages about 1,800 lbs/feet.

Irrespective of the curves, operators have generally been raising the proppant and fluid intensities of their completions. And it has commonly been argued that there is a relationship between completion intensity and well productivity. Certainly, in the initial days of the shale boom, high completion intensity has influenced well productivity.

But has it stayed linear since then? We looked at detailed well data to understand this relationship and decipher which specific completion factors tend to influence productivity the most.

Inversing relationship between completion intensity and higher productivity The relationship between higher completion intensity and additional productivity is generally portrayed as linear— which at least played out as asserted in earlier years of shale development (2013–2015).

During this period, about 23 per cent of wells had both high productivity and high completion intensity as against four per cent during 2009–2012. And probably that is why most operators highlight their record loading of proppants or fluids while presenting quarterly results.

However, that relationship has peaked and started weakening since 2015. In fact, over the past three years (2016–2018), the industry’s productivity was flat despite a 25 per cent increase in proppant and fluid loading. In other words, although operators have experimented with higher intensity designs and stimulations, those led to diminishing or negative results.

During this period, for example, there were more than 3,000 wells (or 23 per cent of the sample set during the period) where proppant quantity was in excess of 1,800 lbs/feet but productivity was below 750 boed per 10,000 feet perforated interval.

The result: lower relative productivity and higher cost of completion—not the desired outcome for any operator. This probably explains why many operators

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underperformed, in terms of their market valuations, even in this period of oil price recovery, and why investors showed far less appreciation for shale companies. Which operator group has attained the best balance of intensity and productivity? What has been their learning trajectory?

The learning curve and opportunity In earlier phases of shale resource development, up to 2014, integrated oil companies had the slowest learning curve and they displayed a significant share of inferior well results due to their late entry into shales.

In fact, in this phase, their experimentation with completions didn’t work out as expected, reflected in their falling productivity per well.

On the other hand, pure-play independents, which also kick-started the shale boom, seemed to have got the most out of their high-intensity completions, especially those in gas-heavy plays, such as Appalachian. Companies such as Cabot O&G were pumping more than 1,500lbs/feet of proppants with average IP-180 productivity of 1,800 boed per 10,000 feet perforated interval as early as 2010.

Inferior well results and the start of the oil price downturn, from mid-2014, forced many integrated oil companies to either shift from production at any cost to productivity with right intensity, or scale back their activity in shales. Both happened, but those who got their learning curve right made a strong comeback by 2016.

One of the leading integrated oil company, for example, increased its productivity by 20 per cent with the same completion intensity level during this period. Pure-play independents, on the other hand, extended their learning curve and protected the linear relationship between intensity and productivity of their wells.

The story, as well as the results, however, changes after 2016. Integrated oil companies registered only a marginal increase in their average well productivity, despite recordhigh completions in 2018. On the other hand, the relationship reversed for pure-play independents, especially for small-and midsized ones. What is leading to this inversing

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of the relationship, for independents now and probably for integrated oil companies later? Although each company has its own reason and not every well is equal, incomplete understanding of the consequences of higher infill drilling and suboptimal completions are among the most probable reasons.

The net result: there exists both a challenge and an opportunity to increase well productivity across the board for this relatively immature resource play – a challenge for every operator to have a portfolio that consists primarily of top-quality wells and a sizeable opportunity for the industry/nation to extend the shale boom further by realising its full potential. Our analysis of ten operators that have pushed technology and engineering limits and registered the highest increase in their completion intensity highlights the prospects of optimizing their portfolio of wells by 10–80 per cent.

Moving ahead: Improvements can drive new impetus into shale play performance In a short span of time, the shale revolution has transformed the US oil and gas landscape and led the industry’s global transition to more competitive pricing and efficient production.

But to keep its promise intact, and overcome recent concerns about returns and productivity, shale operators could benefit from: • Bringing specificity through analytics: A statistical integration of geological, engineering, and productivity data can provide clarity to the ongoing debate on which specific factors typically influence productivity and cost most strongly in shales.

• Balancing experimentation and standardization: Move beyond “highly custom” designs and bring a balance between repeatability of manufacturing with benefits of experimentation—that is, realize greater efficiency in some elements while driving meaningful performance improvements in the rest.

• Staying ahead of emerging problems: An orderly and prompt study of its own and competitors’ learning curves, and an early course correction, could keep an operator ahead of emerging questions on well

Analysis

productivity and capital efficiency in shales. • Breaking the syndrome: As against reporting progress of a few best wells only, a comprehensive portfolio assessment and narrative could help operators bridge the gap between their actual performance and the verdict of investors.

Despite shale plays undergoing their early phases of experimentation amid one of the deepest oil downturns in history, what US shale operators have achieved until now

is remarkable. After learning from their and peers’ experiences, shale operators now should embrace a future that is driven by systematic application of science, better analytics, and a deeper proliferation of successful completion design strategies.

In this new world of systemic science and digital innovation, the shale revolution may have all the right elements to continue surprising the industry. n

This is the first article of Deloitte’s Moving the US shale revolution forward research series, which statistically decodes the evolution and progress of the shale boom by analyzing more than 80,000 horizontal shale wells spread across the United States. The three other papers in the series deep dive into two of the primary basins (the Permian and Eagle Ford) and discuss the role of all stakeholders (including oilfield services and midstream companies) in extending the US shale boom.

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Ben van Beurden, CEO of Shell Speaking to the Oil and Money conference in London, in November, Ben van Beurden, CEO of Shell, speaks about the global evolution underway in response to climate change and the need for the energy industry to embrace it.

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he day before he spoke at the conference Ben van Beurden had accepted the award for Energy Executive of the Year. At that event he spoke about evolution. Both his own evolution as a person, his career and, more importantly the evolution of the oil and gas industry. “I believe evolution is to be embraced,” he says. “It is about change for the better, and it is inevitable.

An indication of this evolution is the energy transition that is sweeping through the oil and gas sector, aptly highlighted by the fact that as of next year, the Oil and Money conference itself will have evolved to become the Energy Intelligence Forum.

It is a name that rings true to van Beurden,

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reflecting the current thinking within the sector. “I like the new name,” he says. “It feels in tune with the changing times. And it feels like it should stand the stand the test of the next 40 years. Perhaps the evolution is overdue.

There is so much more to our industry than oil and money. It could have changed to ‘Oil and Gas and Money’ some time ago.

“There is so much that we do, although I have to admit that rebranding the conference to “Oil and Gas and Solar and Wind and Biofuels and Batteries and Hydrogen and Money”, would have been a bit much. But, energy is the right word and Intelligence is the right word too. The world desperately needs intelligence to make a successful energy

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transition to a lower-carbon future. We, as an industry, need intelligence too. And I mean that in more than one sense of the word.

“The need for brain power is obvious enough. The world needs brain power to produce the many different innovations needed to meet the challenge of the energy transition. It needs brain power to take the opportunities those innovations will present.

But we, both our industry and our world, also need intelligence in another sense: knowledge.

And that is why ‘Forum’ is also the right word for the rebrand of this conference. The energy industry needs a forum. A place we can stretch our brains, challenge preconceptions and seek and share knowledge.”

In their words

inevitable, but the world does still need both oil and money. The world needs money because the planet’s energy system has to transform to tackle climate change. That means investment on a vast scale. And, I must emphasise, that the world will only achieve a sustainable future if the investments made are sustainable themselves.

That requires financially sustainable business models – models that lead to attractive returns.

“This is why Shell’s approach is to seek out business value in the energy transition.

The company’s strategic ambitions are clear.

Become a world-class investment case. Thrive in the energy transition. Maintain a strong societal licence to operate. Being a world-class investment is about financial resilience. Thriving in the energy transition is about being a worldclass investment for the decades to come.

Strong societal licence to operate is about having the support of society for what we do. And on that last point. I cannot think of a single company represented here that does not need to take action on its licence to operate.

Society is evolving. We, all of us, must keep up.

Because those who do not, will be left behind.

“So when you read that Shell has bought a utility company, when you hear what we are

doing in electric vehicle charging, in renewables or hydrogen – that is where we are coming from. Shell is seeking to make sustainable investment in a sustainable future.”

Greater collaboration That covers two of Van Beurden’s needs for the oil and gas sector. The third is a strategy that the sector has been trying to achieve over recent years, collaboration. “I am talking about a level of collaboration that goes far beyond what we are used to – and far beyond the energy industry too – because tackling climate change is far bigger than the energy industry,” he explains. “Put it like this. We do not pump oil and gas from the ground and then leave it sitting in storage facilities. People consume it.

They drive. They cook. They run their businesses.

“Tackling the greenhouse gases that come with energy is a question of addressing the consumption of energy as much as it is about the supply of energy. Or to put it another way. Climate change is the biggest challenge facing the energy industry, but the energy industry is not the biggest challenge for a world trying to tackle climate change. That task is far bigger than any one industry, any single country, or even continent.”

Plotting the energy transition But as much as the world needs energy, intelligence and the better understanding that can come from a discussion forum, it also needs three other things if it is to succeed in its energy transition according to van Beurden.

First of all, the world needs oil and gas. “The world needs oil and gas because it is what the world relies on for so much including, often, its most basic needs of heat and food and shelter,” he says. “And that will not change overnight.

This is why Shell will continue to invest in oil and gas, even as we work to help speed progress to a lower-carbon future.

“Secondly, the world needs money.

Yes, that’s right. Evolution is both good and

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In their words

Big impact That does not, however, mean energy companies cannot have a big impact. “We can, for a start, change the mix of the energy products we sell,” van Beurden continues.

“We can offer different, lower-carbon, energy products. And selling a mix of energy products with a progressively lower carbon intensity is exactly what Shell aims to do. That will mean more low-carbon biofuels in the mix of things we sell, more renewable electricity and products like hydrogen too. It also means addressing our operational emissions, including methane leaks.

“We are already working towards our ambition – and the fact Shell has won another award this year, the Energy Intelligence award for Leadership in New Energy, is a sign to me that this work is beginning to be noticed. But there is

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a long way to go. In fact, achieving our ambitions in this area would mean Shell becoming a radically different company to the one you know today. But to achieve those ambitions in the way I described earlier – by making sustainable investments that make sound business sense – means demand must transform too. We can choose to sell lower-carbon products, but we cannot make people buy them.”

Choices Transforming demand means everybody making better choices: from individuals, to companies, to governments. Van Beurden points to a study by the European Environmental Bureau recently that found that extending the lifespan of smartphones and other common electronics by just one year would cut the EU’s carbon emissions by

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the same amount as taking two million cars off the roads.

“This need for better choices is why I believe greater international efforts are needed,” van Beurden says. “These better choices must be made easier for people to make.

“Some of the answer comes down to governments. Governments can provide regulation and consumer signals – like welldesigned, well-balanced taxes – as well as incentives, like grants to help buy electric cars. The world also needs government-led carbon-pricing mechanisms to encourage lowcarbon choices. I cannot overstate the need for immediate action on this. A global emissions trading system, as described by Article 6 of the Paris Agreement, is essential.

“But government-led carbon-pricing

In their words

will not be enough on its own to shift large parts of the energy system. What we need is co-ordinated action to drive an international industrial transformation on an unprecedented scale. This is not just down to governments.”

But van Beurden is clear that it is not all about government intervention, alongside governments, businesses have a significant role to play. Businesses which supply energy, alongside businesses in sectors that use energy: from shipping to finance, aviation to chemicals, steel to cement. The urgency is such that he believes they must all come together, sector by sector, to work out how to decarbonise each sector’s energy use.

“Each sector that uses energy is different, and some are highly fragmented, so the actual action needed in a sector will vary,” van Beurden explains. £All sectors, however, share the same three ways to make progress. First,

improve energy efficiency. Second, turn to lower-carbon energy products. Third, offset or store away emissions that cannot be avoided.”

Time to take action One example of governments and business working together is the Getting to Zero coalition announced at the UN Climate Summit in New York last month. It brings together Maersk, Citigroup, Shell and the Danish government in a joint push. The coalition is seeking to find a way to put a commercial ship to sea that does not add greenhouse gas emissions to the stock in the atmosphere by 2030. In other words, a net-zero emissions ship. The coalition will also need to work with other governments, ship builders, port operators and more.

“It is a good start,” van Beurden agress.

“And we will need another coalition to do the same for the next sector, and the next. That is

not to say any of this will be easy. But I believe that if this type of sector-by-sector action does not happen, the world will fail to meet the goal of the Paris Agreement.

And I also believe that energy companies which do not play a full role in such collaborations – and that do not evolve – will fall behind society. They will fall by the wayside.

“Because even though the world still needs oil and money and will always need energy.

And even though we, in our industry, have both the brains and the knowledge to successfully navigate the energy transition.

Despite all of this. If we do not have intelligence enough to share our knowledge, to embrace collaboration and move with the change happening all around us, we risk forfeiting our place in society. And if a company has no place in society, it has no place being a company at all.

We can, and must, evolve.” n

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Africa’s rising stars Oil and Gas Technology looks at the prospects of four of Africa’s rising stars in Republic of Congo, Gabon, Gambia and Namibia

A

frica continues to offer abundant opportunities to explore for hydrocarbons in a frontier market.

New hydrocarbon provinces are popping up regularly; Mauritania and Senegal are good examples of countries where hydrocarbons have recently been discovered. But they are not alone in providing bright hope for the hydrocarbon future of the continent.

Republic of Congo stakes its claim as gas exporter The Republic of Congo is the fourth largest Sub-Saharan producer of oil, with an output of 277,000 bopd in 2015. Its proven oil reserves amounted to 1.6 billion barrels in 2015, with a reserves-to-production ratio of 15.8 per cent.

The prospects for the nation are improving largely thanks to Total E&P Congo’s Moho Nord project. The USD 10-billion Moho Nord project,

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the largest oil project in the country’s history, was launched in 2013 and has the potential to increase Congo’s production by 50 per cent to a total of 140,000 bopd. Targeted reservoirs amount to 700 million boe.

After becoming a significant oil producer in the mid-1970s, Congo (Brazzaville) is now the fourth largest in sub-Saharan Africa. Most of the fields in current production are in coastal waters. The average quality of oil output has improved over the years, aided by the coming on-stream of Elf’s deep-water Nkossa field. The bulk of oil production is exported.

Total started up production from the Moho Nord deep offshore project, located 75 kilometres offshore Pointe-Noire in the Republic of the Congo, early last year. Operated by the group, the project has a production capacity of 100,000 barrels of oil equivalent per day.

“Moho Nord is the biggest oil development to

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date in the Republic of the Congo,” Arnaud Breuillac, president, exploration and production at Total, said. “A showcase for Total’s deep offshore operational excellence, it consolidates our leading position in Africa. Moho Nord will contribute to the reinforcement of the cash flow of the group and to its production growth.”

The Moho Nord field is developed through 34 wells tied back to a new tension leg platform, the first for Total in Africa, and to Likouf, a new floating production unit. The oil is processed on Likouf and then exported by pipeline to the Djeno onshore terminal, also operated by Total.

The facilities are designed to minimise their environmental footprint. There will be no routine flaring and the all-electric design improves energy efficiency by optimising the amount of power needed to run the installations. All the produced water will

Region report: Africa

of gulf that runs all the way up the coast of Cote’d Ivoire and, Nigeria.”

Jerreh Barrow, Commissioner for Petroleum, Ministry of Petroleum and Energy, The Gambia

be reinjected into the reservoir. Total is the operator of the project with a 53.5 per cent interest. Its partners are Chevron Overseas (Congo) Limited (31.5 per cent) and Société Nationale des Pétroles du Congo (15 per cent).

But exploration and production in the nation is not only the domain of the oil and gas majors, the independents play a key role in developing the resources. One such company is Anglo African Oil & Gas (AAOG) who made a significant step in its exploration in the Republic of Congo when it spudded the TLP103 well on the Tilapia oil field in mid-August.

David Sefton, executive chairman at AAOG explained that unlike the larger Democratic of Congo to the south, the Republic of Congo is a good place to work. “It is the old French Congo, now the Republic of Congo, is just to the north of the Democratic Republic of Congo,” Sefton, commented. “It’s only about five million people in a country the size of France. It is stable, decent croissants in the mornings, very French.

Sometimes it’s called Congo B, Brazzaville where Congo K, Kinshasa, the south side of the river is a little more challenging place.

“It’s the oldest producing country in West Africa, so they have been going for a long time there. Currently dominated by, as you might expect, the French oil companies. Total is the biggest in that country. It has huge investments there. ENI, number two. It’s the same kind

Gabon sets the agenda for growth Gabon is among the top ten oil producers in Sub-Saharan Africa and has been an oil producer for more than 50 years. It reached its peak 12 years ago when oil production reached 370,000 barrels per day to its current level of 200,000 barrels a day. To combat the natural decline of mature fields, the government has focused its attention on offshore resources which account for more than 70 per cent of the reserves.

“Let me first say that Gabon is one of the safest oil producing countries in Africa and has been for a long time,” Pascal Houangni Ambouroue, the Gabonese Minister of Petroleum said at last year’s Africa Oil Week conference.

“At the moment most of the oil wells that are producing are mature, which is why the Gabonese Government has put in place a set of measures such as the revisions to the Hydrocarbon Code to improve production from these mature wells and also encourage exploration and discovery of new oil in deepwater offshore.

“This will also stimulate the entry of new players with the major companies are now focussed on deep waters for production of oil and gas. Ongoing prospecting shows that Gabon has very good resources in terms of oil

and gas for the future. To combat the natural decline of mature fields, the government has focused its attention on offshore resources which account for more than 70 per cent of the reserves.”

There are currently in the region of 30 oilfields in production, making Gabon is currently the fifth largest oil producer in Africa, but production is declining. The Gabonese Government launched its tenth bidding round in late 2013 that generated eight new production sharing contracts with Marathon, Petronas, Repsol, Noble and Woodside, Impact Oil & Gas and Ophir which are all working on their exploration programmes. A further round was launched just over two years ago but the government was forced to suspend it as the low oil price and proposed economic terms failed to attract the desired interest, hence the recent amendments to the code.

The Gambia looks to oil for economic growth According to Jerreh Barrow, Commissioner for Petroleum, Ministry of Petroleum and Energy, The Gambia, oil revenue has the potential to significantly change the economic situation of the Gambia and hence the wellbeing of Gambian.

Key to that success is the MSGBC Basin.

It has been the shining light of African

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Region report: Africa

exploration through the recent darkness the industry has endured. That light, or rather floodlight, was cast upon the region through the recent world-class discoveries in Senegal and Mauritania.

“The MSGBC as you know is one of the largest sedimentary basins in Africa and is also becoming one of the most prospective ones for petroleum exploration with different play types being investigated,” Barrow says. “I used investigated because the MSGBC is also one of the least explored regions and hence potentially holds many play types. Specifically speaking about The Gambia, laying in the central of the MSGBC, with discoveries to both the North and South the prospectivity is predictably high.

There have been many prospects identified on trend with, and just few kilometres away from the SNE and FAN discoveries in Senegal.

“MSGBC is turning out to be beyond what was every expected in that, since the 2014 discoveries 11 successive and successful wells have been drilled in the North of the Gambia and this has caught the attention of the Petroleum industry as evidenced in the skyrocketing interest.”

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The Gambia has over ten thousand square kilometres of offshore acreage and preliminary resource estimates in this is over three billion barrels of oil. It is worth mentioning that the Gambia and Senegal has long standing inextricable socio-cultural relations and bonds. In addition, there is an excellent political relationships and very well defined maritime boundaries.

“Geologically speaking, the Gambia is still at the early exploration stages of exploration with a deep offshore exploration well expected to be drilled during the later part of the year, but geologically speaking we are in a proven province,” Barrow adds. “Currently two blocks are licensed to FAR and Erin with Petronas seeking to farm into these licenses. All of this is a testimony to the prospect and conduciveness of the investment environment in The Gambia.

“Though we at an early stage in the exploration cycle, a conscious policy is being aggressively pursued to lay the foundation for creating linkages with the local economy to leverage the opportunities created by the Petroleum industry. We have included forward looking provisions in the licence agreements in anticipation of the development of the sector. The

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strategy in the Gambia is a realistic and futuristic in that we are developing the local content regime in cognizant of our current realities and the state the industry should be in the future.

“Many things need to happen to optimize benefits of these potential resources. Broadly speaking good governance, strong management institutions, capacity building, robust legislative and regulatory frameworks are all critical for the optimal benefiting from the project.”

Namibia: The Last Great Frontier “Namibia is oil and gas’s last great frontier,” Gil Holzman, president and CEO of ECO Atlantic Oil & Gas confidently proclaims. “There are other frontiers out there, but they are in more exotic areas such as the Arctic, which is very complicated. Namibia, on the other hand is much simpler, the infrastructure is already in the area.”

Interest has been mounting around the possibility of significant finds off the shore of Namibia in recent years even though only small volumes of hydrocarbon have been produced. According to the National Petroleum Corporation of Namibia (NAMCOR) on the 50 licences that have been awarded there have been

Region report: Africa

11 exploratory wells and seven appraisal wells drilled. The one success has been Brazil’s HRT who discovered oil at Wingat-1 well in the Walvis basin, but not at commercially-viable volumes.

Part of the confidence in Namibia stems from its location; surrounded by resource rich states in South Africa, Angola and Botswana. “The characteristics are quite well known,” Holzman adds. “There is oil in South Africa and Angola, there is oil the other side of the Atlantic in the Campos and Santos Basins in Brazil.”

Holzman calls Namibia Africa for beginners and a perfect place to start understanding the region. “When I go to Windhoek I feel like I am back in Zurich; it’s so clean and organised,” he adds. “It is also very stable; there have never been any problem there, it is peaceful, democratic, and stable.

It’s English speaking and they have a rule of law. It’s the second rated country in Africa, after Botswana; they are neck and neck as the

best countries in Africa to do business.

“I have operated in many other regions and the Namibian Government is one of the most supportive governments for the oil and gas industry, mainly because they leave the international players to come and explore for oil. They understand the challenges, they are very supportive and very patient. To an extent they are real partners to the industry.”

Eco Atlantic’s interests in the region are contained within the Walvis basin, a highly active but underexplored oil and gas region.

In 2013 a proven offshore petroleum system was discovered by HRT and since then there has been increased activities in the region by major oil companies. Eco Atlantic has acquired four offshore licence blocks covering 23,000 km2 in the Walvis asin. The four licences are strategically positioned.

Today there are a host of major players in the basin, but that was not always the case.

“When we started together with Tower, Chariot

and HRT back in 2010 we proved that there are at least two active petroleum systems in offshore Namibia,” Holzman continues. “Gradually we gained more traction and came onto the radar of more of the industry players. Today in 2018 you see ExxonMobil, Total, Shell, ONGC and Tullow in the basin. The bigger names came in after the smaller companies have proved the play, and this is exactly how it should work.”

As for Eco Atlantic’s future, Holzman is adamant that there is a petroleum system in place. “The oil is there, but you must understand that it is a huge area of water; each block is between 5,000 and 10,000 square kilometres,” he explains. “Oil exploration is risky and expensive, so it takes time to de-risk the basin and understand where the oil might have been trapped and where it has migrated to. But the prize is big, we know that because of the huge structures underneath the ocean. Once someone hits oil we are talking hundreds of millions or even billions of barrels.” n

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English Eyebrow

Improving performance with intelligent computing at the wellhead Production from US oilfields growing the drive to increase efficiency and boost production from the hundreds of thousand wells dotted across the country is gaining pace, and one of the most promising solutions is the digital wellhead.

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ake any flight from Texas to California, and you will fly over West Texas and New Mexico. With a quick glance out of the window, you will see the land pockmarked with a seemingly boundless patchwork of square sandy areas as far as the eye can see.

What your eyes won’t be able to tell you from that height is that each one of those squares contains an oil wellhead. Welcome to the Permian Basin that supplies almost a third of the US domestic crude oil.

The case for digital wellheads The oil fields in the basin contain tens of

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thousands of wells, growing every year. Over the past five years, more than 5,000 wells have been added to the inventory. What you will also notice is that aside from the wells there is very little else in the region as far as infrastructure goes. Each of these wells is unmanned and, more often than not, located in areas with poor access. Despite these challenges, the wells need to be inspected to check for gas leaks and any structural damage, which can be a costly and time-consuming operation.

Aside from the need to avoid falling foul of compliance or health and safety issues, there is the matter of data. In modern oil

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production, data is vital for planning and assessment, and wellheads are a significant and abundant source of data that at present, is mostly untapped. Although some of the newer wellheads may have smart digital sensors with built-in wireless communications, the vast majority are legacy installations with analog gauges. Even the new smart sensors require a technician to be in close proximity to download the data to a handheld device.

What is a digital wellhead? “Operators are trying to digitize these fields and wells so that they can detect all

Edge

the important production parameters from a remote location,” Jane Ren, founder, and CEO of San Jose, California-based industrial software company, Atomiton, says. The answer is a digital wellhead that provides integrated functionality at the edge. This will allow real-time and predictive analytics of wellhead integrity, well performance and environmental risk.

The idea of the digital wellhead is to give it a brain, or more accurately, an edge computing device. “The plan is to bring everything onto a level playing field,” Ren adds. “Whether the well instrumentation is analog or digital, we would like all the wellhead information to be available on the same platform even though it comes from different devices and vendors.”

That is the ultimate vision, but the most important thing is to achieve a digital wellhead, regardless of whether or not it has

remote connectivity, in that there must be multipurpose computer intelligence on site. This will have a positive impact on three particular areas. The first is automation, the second is precision, and the third is prediction. “These are the three big advantages that were not able to be achieved before we added edge intelligence,” Ren says.

Delivering wellhead automation A typical example of automation is gas leak detection. This is a significant concern at wellheads, some of which could even be abandoned wells but where the operator is still liable for any leak from the structures.

The challenge around gas detection without automation is that it always requires people to visit the site. These inspection teams will attend to the wellhead site with infrared sensors or cameras, move around the area

and try and detect any possible gas leaks.

These wellheads are remote, so there is travel involved, the inspections are infrequent, so when they do visit the wellheads there is the added risk that they may be exposed to health and safety risks.

“The idea behind having automation and intelligence at the wellhead is to be able to put gas sensors at the wellhead that can constantly monitor for any gas in the area,” Ren explains. “With an automated drive and the sensor located on a rotating mount, it can turn in various directions controlled by the edge computer. This reduces the need for people to visit the site.”

There are several philosophies when it comes to digitizing the wellhead, either through a device strategy or an edge strategy. One option would be to replace the dumb, analog sensor with a smart

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Edge

sensor that has embedded computing and communications capabilities. This can be expensive and often only delivers a point to point solution with the individual device providing its information in isolation. Aside from that lack of integration, this method can also be challenging to scale “Edge-based digitization is about being open to the low-level sensors,” Ren explains.

“The sensor can be dumb, but it is given intelligence by the edge computing device.

You are adding intelligence to sensors inside one computing device that can include gas detection, pressure or flow monitoring and even structural monitoring.”

Adding precision and prediction Precision is another benefit of edge computing capabilities. There are two ways you can detect any issues such as leaks or corrosion.

One is to use a threshold-based anomaly such as pressure changes. With edge computing, these detections can be much more precise.

On the market now are relatively low-cost gas detection sensors that can be attached to seams or seals between the flanges. These can detect even small leaks; however, it requires data processing at a high level to filter out the noise of the baseline fluctuation. The software needs to be able to look at trends and continuously compare the anomalies before it can confirm a leak. It is not a single point detection, and that makes it much more feasible to do at the wellhead when you have computing resources there.

The third area is prediction, which encompasses two separate things. The first is incidents, whether there are a leak or pressure issues in the well. The second type is called risk factors. “Having a risk factor does not mean there will be an incident, for example, there may be some structural changes at the flanges that is not bad enough to create an incident yet, or there may be heavy corrosion around the wellhead structure that could lead to a future leak,” Ren says. “The prediction is to use the risk factor monitoring to be able to derive the probability of a wellhead incident so the maintenance and inspection visits can be targeted, and condition based.”

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So why would prediction require edge processing? “One of the newer ways of monitoring corrosion or erosion of the wellhead is by using advanced, AI-based image analytics,” Ren says. “It will continuously monitor the patches of color changing on the pipes in a well structure to be able to detect the color and pattern changing as the corrosion and erosion have been advancing.

Then it will need to be able to integrate the risk factors of humidity and temperature in that particular well.

“All those risk factors need to be monitored, now combined with the prediction, the algorithm must be able to tell better which well could be more exposed to incidents or quality issues. All that sort of prediction requires computing and is not something that can be done by a single sensor or device. And that’s what we mean by putting the multipurpose compute on the well. It’s also called digital wellheads.”

Additional benefits There are two types of resources that cost money at the wellhead. The first is people, the wellhead maintenance crews that visit the site number in their hundreds, then there is the cost of any regulatory infractions. By using intelligence at the wellhead these visits can be dramatically reduced, not down to zero, but

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they would become condition based as opposed to schedule based. Every well is different and can be exposed to various risk factors, so when they visit each well at which time for which inspection will be different, and that will reduce the cost.

There is also an additional, secondary effect of the digital wellhead, and that is the increased data capturing and integrated processing. “The reality is that there is more data generated at a wellhead than there is data processed,” Ren explains. “Wellhead data is very valuable in monitoring and diagnosing the health of the well, the productivity of the well in addition to the quality of the well. You would have to aggregate multiple wellhead data together to be able to make better conclusions about the reservoir.”

Most of the digitization efforts at wellheads are currently centered on creating digital data without being able to integrate this information to undertake analytics. By putting computing power at the wellhead, you are not only putting it at the edge but aggregating multiple edge devices into a center that can create more valuable information on the reservoir and its long-term health and productivity. “That is why we selected the wellhead as a crucial strategic point because it is a data-rich point,” Ren concludes. n

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Completions

Moving to a cementless future for completions By utilising an innovative cementless technology Total were able to reduce risk and increase operational efficiency for their Moho North field in The Congo.

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he cementing process that isolates the various down hole formation zones as well as firmly fixing the casing in place has been core to the completion process since it was first used over a century ago. Despite its maturation as a completing technology is still presents a myriad of challenges to operators which has led them to seek new and better ways for zonal isolations.

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During the drilling process, you will have to do several tests to make sure that you have correct pressure and a nonleaking well.

Cementing is central to the discussion of zonal isolation and well integrity because cement typically provides at least one barrier in a well and is a component of the barrier envelope or barrier system during well construction and the operational phases of the well.

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Three cementing challenges in deepwater Part of the process of preparing a well for further drilling, production or abandonment, cementing a well is the procedure of developing and pumping cement into place in a wellbore. Most commonly, cementing is used to permanently shut off water penetration into the well. Part of the completion process of a prospective production well, cementing can be

Completions

used to seal the annulus after a casing string has been run in a wellbore.

Additionally, cementing is used to seal a lost circulation zone, or an area where there is a reduction or absence of flow within the well.

In directional drilling, cementing is used to plug an existing well, in order to run a directional well from that point. Also, cementing is used to plug a well to abandon it. Deepwater is one of the most challenging cementing locations where operators face a triumvirate of challenges including low temperatures, low fracture gradient and shallow flow hazards.

A new way That all changed last year when it was announced that Total had successfully utilised an innovative cementless completion technology in the Moho North Albian field that they had developed in partnership with Welltec.

The technology was Welltec Annular Isolation (WAI). Moho Nord is a deep offshore oil project situated 75 kilometres off the Congolese coast. It came on stream in March 2017 and is the largest oil project ever undertaken in the Republic of the Congo. The field will produce untapped reserves in the Moho-Bilondo license block, which covers an area of 320 kilometres and four reservoirs situated at water depths of 750 to 1,200 metres.

Given the challenges that cementing presents to operators they have long been searching for an alternative completion method that both reduces risk and saves operation expense. By using an innovative cementless technology it is possible for an operator to save up to $75 to $100m over a 15 to 20 wells deepwater field development plan can be achieved.

This solution is equally as viable for onshore and shallow offshore markets. Approaching it

from a larger scale makes the value proposition more obvious. “We like to think that we work on solutions that are best for the well and the overall project,” Gbenga Onadeko, Senior Vice President, Welltec Africa, says. “In most cases, our industry is integral to the economies of the oil and gas producing countries. We therefore believe that we are having a positive impact on the overall wealth of the nations we operate in.

“Total initially selected a cemented and perforated liner solution, the liner length was short and deep, implying the volume of cement was relatively small, which increases the operational risk of cementing the reservoir section. Because of the potential of cement contamination and also to increase the success rate of placing it behind the liner, the volume of cement pumped was increased by enlarging the hole (under-reaming) and drilling deeper i.e. a longer rat hole section, which placed the toe of the well within less preferential sections

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Completions

of the formation increasing the drilling and production risks.

“With the liner deployed and cement in place, the WAB is expanded quickly under full surface control sealing against the formation rock, displacing the cement, providing a high integrity pressure isolation between zones. This in turn

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ensures that even if channels or micro-annulus are present in the cemented interval, effective isolation is still achieved within the annulus.”

The long road to adoption Even under the long-term depressed state of the price of oil that has necessitated a drive

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to greatly improve operational efficiency the oil and gas sector is still risk averse when it comes to adopting innovative techniques. The deployment of this project started four years ago when the Total team arrived in the Congo to prepare for the deployment. “Initially the Total team was not ready for a full cementless solution, so they used one of our products, which is called the WAB, in the wells in addition to the traditional cement,” Onadeko says. “Normally, the WABs can be used without cement to isolate several sections of the well, but in this case, because they had some technical issues, they decided to go with the WABs for their isolation properties in addition to cement.

“For most of the wells on this project, we had already deployed the WABs. But then towards the end of 2017 amidst the height of the industry downturn when the sector was really feeling the low cost per barrel, Total realised that this project was costing far too much. It had been sanctioned when the price of oil was much higher, and they urgently needed to cut costs, which provided us an opportunity to utilise this technology with its associated cost saving. In December 17 they invited all the service companies that had a contract with them on this project, to come and discuss how they could slash the well drilling costs by half.”

Another reason that Total had confidence to proceed with the cementless WAI solution came about by chance. “On one of the WAB operations they put it in a long zone and accidentally put it into a well section thereby shutting off the hydrocarbon instead of water,” Onadeko explains. “Then they had to shoot some explosives into that hole to perforate it and the WAB was robust enough to withstand the shock; it did not impair their production.

So that was another reason why they could go ahead and use the cementless solution, knowing now that they can perforate through and get a diversion.

“We develop cutting edge technologies and work extremely hard to convince our clients to deploy the value adding solutions. One of values we add to the industry is to assist our clients in overcoming their initial reluctance. We want to ensure that these technologies are included in their field development plans to avoid paying premiums later due to rush mobilizations.

Completions

Including the technologies in their initial plans reduces the risk of budget variation.”

The WAB and the WAI The WAI provides long length open hole zonal isolation, significantly reducing the free annulus space between the casing and the open hole. The removal of this annular space can be beneficial in highly layered reservoirs of varying permeability, where selective production, stimulation or water shut off is required.

Its metal expandable sleeve is hydraulically expanded, under full surface control using the rig pumps. Sealing on the open hole is achieved using a series of compliant, elastomeric seals, backed up by full circumferential metal to rock contact fins that prevent seal extrusion under high differential pressure.

While the WAI is suited to zonal isolation, the WAB for well completions can be utilised to provide solutions to many requirements throughout the completion phase of a well.

Its leak rate capability, when set in cased hole, makes it ideal as a high-pressure production packer for both high pressure gas and oil well applications. In addition to this it can rotate and reciprocate during installation and cementing operations, and then expand and seal, on demand. In horizontal applications this allows the WAB to be incorporated as a Rapid Set Liner Hanger, reducing both risk and complexity in these often-challenging applications.

“The WAB gives us a zone of isolation,” Onadeko adds. “What we mean by that is you have a seal between a liner and reservoir and then you have a distance between that packer and the well. So, you have like an open anulus between these two packers for zonal isolation purposes. What the WAB gives you is seal integrity between the liner and the rock.

Once you have established your seal then you are able to simulate, inject or produce into a certain zone.”

When cementing fails The main competition to this technology has been cement, where liners are cemented in a well. The challenges are where the trajectories and the geometry of the wells become more difficult. In these instances, it becomes very

challenging to assure the seal when using cement, despite that the bulk of wells today are completed with cement. But because cement does not always deliver the optimum seal between the liner and the anulus it makes it very difficult to compartmentalise your well.

“What the WAI gives you is cement replacement,” Onadeko continues. “Instead of leaving either cement between the packers or an open anulus, then the WAI fills the anulus with confined compartments; each WAI will be a compartment that’s isolated from the next compartment. We have no open anulus, we have no cement, but the whole of the anulus is now compartmentalised. With that achieved, you can then decide if you want to leave that compartment isolated, or whether you want to perforate it, stimulate it or produce it or inject into it. The WAI breaks down your reservoir into two metre compartments. And then you’ve got control over each two metre compartments.

And each department has high integrity in relation to sealing.”

There are several things to consider when removing cement from the completion process.

Cement has three functions that it is trying

to achieve for the well. The first as we have already discussed is to provide sealing which is not always possible as the well geometry becomes more challenging. For the Moho project Total had a tremendous challenge in ensuring the cement was going to seal. The second function of cement is to provide an anchor between the liner and the rock. Finally cement also supports the rock formations. If the formation is unconsolidated it provides a support to the rock to make sure it does not cave onto the liner.

“When we remove the cement, we need to be sure that we’ve addressed all three, the sealing, the anchoring and support of the rock,” Onadeko explains. “The WAB delivers two of those; it gives you the anchoring or sealing, but across the open anulus you are dependent on the rock having some sufficient mechanical properties that it won’t start to fall in onto the liner. Where the WAI will give you the sealing and the anchoring, it also gives you this mechanical support to the rock. So, WAI is really cement replacement in its full entirety, without the risk of the challenges presented by the geometry.” n

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Big Data

Data is king Whether process plant, module or installation, the refinement of risk and maintenance planning is a constant process and one that involves the management of a vast set of variables.

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verything from wave conditions to wind speeds, pipeline pressure to valve performance, all must be factored in order to understand the performance and condition of an asset and its innumerable components.

Principles of risk, reliability and maintenance (RRM) On an oil and gas producing asset there are hundreds of thousands of pieces of

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equipment. Just one failure can cause issues, production slow down or worse. “Safety is at the heart of all risk, reliability and maintenance (RRM) activities,” Rickard Dalman, operations manager, integrity management at Oceaneering says. “RRM frameworks help manage issues, assess reliability and schedule work using a riskbased approach to maintenance management.

“By leveraging data and expert operational

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and engineering knowledge, specific areas of concern can be identified, and appropriate performance standards implemented to ensure all effort and investment produces the greatest effect.”

The RRM approach involves a comprehensive review of topsides equipment on an asset. Examples include production, auxiliary and safety systems, and can also

Big Data

incorporate the subsea infrastructure, the wellheads and the production facilities. RRM works by seeking to understand how critical each piece of equipment is, taking into account different perspectives and defining what’s most important for a process, system or module through criticality assessments. These assessments are followed by assignment of maintenance strategies and tasks, where runto-failure is not an option.

“The RRM project can be driven by the operator or partner however, in many instances, a specialist is brought in to help identify and work through the process to consider which pieces of equipment or systems are most important for each individual asset, with efficient and effective maintenance plans created according to particular standards,” Dalman adds. “Safety is obviously paramount throughout, as well as financial, reliability

and operational factors that must also be considered.”

Driven by data Because of the sheer quantity of equipment and parts on an asset, identifying where problems have occurred can be a costly and time-consuming task, particularly when it comes to analysing performance and understanding what equipment is the most critical.

“Today, advances in condition-based monitoring technologies and data analytics mean that huge amounts of operational information can be gathered to provide a snapshot of the performance of specific equipment,” Dalman continues. “This enables operations to make smarter decisions, and by honing in on the optimal maintenance routines they can ensure they are making the right

decisions, at the right time and for the right commercial reasons.

“Enhanced data gathering enables maintenance optimisation on a grand scale. The aim is for work to be carried out at the correct time from a safety and value perspective. Never too early that it’s an unnecessary cost, nor too late that an issue is missed.

“With an optimal RRM strategy, the operator has the ability to make confident, informed and optimised plans around how and where to focus maintenance efforts.

In turn, optimising time spent carrying out maintenance and inspections, freeing up hours that could be focused on other critical tasks, or safely eliminating the need for certain inspections completely.”

A simplistic example of this is the adoption of a proactive spare parts strategy, which will ensure that you have the right

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Big Data

equipment, in the right quantities and accessible within the right time frame. It may not be necessary to keep an inventory of 5,000 bolts, however having the right amount of specified pressure safety valves (PSVs), for example, would be critical and absolutely necessary. “Reviewing and optimising your spares strategy will guarantee you are addressing and managing risk, as well as potentially saving of hundreds of thousands, or even millions of dollars, through accurate control and visibility of equipment stock,” Dalman explains.

A more complex example is the ability to use a RRM approach to assess historical data, extracted from an asset’s computer maintenance management system (CMMS) or other source. This data is then analysed by experts using customised algorithms and data analytics techniques to identify problems, reduce waste and refocus maintenance activities. “This can identify ‘bad actors’, poor performing equipment or one-off failures that often dictate the overarching schedule,” Dalman says. “These can then be uniquely identified, and a specific maintenance or replacement plan can be put in place. Thus, enabling asset owners to manage costs and efficiencies more effectively, without compromising safety and without incurring additional risk.”

Benefits to asset owners As advances in data gathering and processing start to make their mark on oil and gas asset management, the benefits are clear. “Where the itemisation and monitoring of the otherwise overwhelming number of components on a drilling or exploration asset would once have been impossible to do manually, independent and experienced partners can now make this not only possible, but a highly efficient process,” Dalman concludes. “More so the benefits to asset owners speak for themselves. Reduced risk through enhanced risk management and increased production reliability are the holy grail of hydrocarbon production, and RRM puts this in reach for everyone. Not only now but for decades to come.” n

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CASE STUDY – BRAZIL OVERVIEW The RRM principle is something Oceaneering has been successfully providing its customers for many years. One example of the organisation’s approach to RRM was on an offshore installation in Brazil, which had recently changed ownership.

The customer purchasing an already operational asset and was also entering a new geography which provided various risk and unknowns. The new owner had to be sure that the maintenance and risk planning process was one they could trust and rely on for the future.

“With an acquiring asset, it is always more difficult to review and plan risk because there are many unknowns in relation to performance, reliability and condition,” Dalman explains. “There are hundreds of thousands of components to consider, have all of them been accurately maintained and inspected at the right time? Have they been replaced? Are the records accurate or, in some cases, able to be interpreted?”

There were some distinct challenges in this case. The operator approached Oceaneering as the expert service provider to translate the data into its existing company computer maintenance management system. The inherited maintenance strategy was focused on run-to-failure, whereas the new operator wanted to adopt a preventive maintenance strategy aligned with its global approach to maintenance management. It was also unsure whether data sets were complete, and it required a level of reassurance that all the relevant information was available or could be retrieved.

Oceaneering performed analysis to identify any gaps and missing information - then used its own technical experience coupled with historical data from similar assets to compensate for missing information. From there, schematics and technical databases were cleansed and updated to provide an accurate picture of the asset’s status. This included an assessment of more than 160,000 equipment tags. “As with many operators, this customer had a clear preference on how it wanted the maintenance information to be structured, so the programme was built to meet its individual requirements, recommending improvement opportunities to reduce costs along the way,” Dalma explains.

The implementation of the RRM approach has fundamentally changed the way in which the maintenance programme is now executed on the asset. It has delivered measurable benefits to the customer including: • A 50% reduction in annualised hours, leading to a year-on-year saving of $10million • Mitigated risk by providing accurate identification of safety critical equipment that was invisible in previous plans • Reclassification of more than 30,000 redundant equipment tags • Precision, control and visibility of maintenance on the asset supports efficient use of people on board (POB) resulting in less exposure to harmful activities • A uniform approach for maintenance management, in line with the customer’s global standards

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Big Data

Time for oil and gas to face the music on data The maxim that data is the new oil had been floated around the oil and gas sector for several years now and while that might be overly simplistic it will play a crucial role going forwards if it can be managed effectively. To do that the sector could do worse that take a look at how the music industry handles data.

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hether or not data is the indeed the new oil, we still need hydrocarbons.

With supplies diminishing, and it becomes even more expensive to get hydrocarbons out of the ground, innovation

should be top of the agenda for the oil and gas industry. To find new ways of boosting efficiency and cutting costs, innovating is the only path forward.

There is one significant obstacle that stands

in the way of every innovation within the sector and, ironically, it is a mirror image of the traditional fear of oil and gas businesses. “It is not a shortage that threatens progress within the industry, it’s a glut; not of crude

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Big Data

but of data,” Simon Tucker, managing partner, energy & commodities at Infosys Consulting, says. “Until the industry can solve its data management challenges, it will be unable to deliver the new technologies that will help to keep down prices at the pump and also deliver on safety and energy efficiency. In their search for a solution, oil and gas businesses are looking to an unlikely source of inspiration.”

Taking inspiration from unlikely places Anyone from the oil and gas industry should have an instinctive feel for the challenges of data. Like information, crude oil sits in vast lakes far from sight; it needs to be extracted and refined before it’s of any use to anyone.

But while the great oil and gas pipelines are constantly depleting reserves, data pipelines are always adding to the lakes, and therein lies the problem. “As these data lakes grow into oceans, businesses in every sector are struggling to cope,” Tucker adds. “The sheer size and complexity of oil and gas projects mean that these businesses often have to deal in petabytes, with upwards of tens of thousands of new rows of data generated every day.

“New technologies such as IoT have contributed to data volumes exploding at a far

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faster rate than businesses’ ability to manage and make sense of them. But, as is so often the case, technology provides answers to problems of its own making. One such answer lies in an app that will be familiar to many of the younger employees in the oil and gas industry: Spotify.

“As its users know, Spotify is much more than an online music repository. It’s a place to find the latest tracks, to find suggestions for new songs or artists, and to listen to (and create) curated playlists.

“Within a few years, we can envisage oil and gas companies using the same dashboard approach that has made the Swedish music service so popular. A Spotify-esque dashboard will enable oil and gas companies to visualise the data they work with, get suggestions, identify trends, discover new data sets, and pull all of this into one place to manipulate and report on it. This enables staff to examine realtime data, see if infrastructure such as drilling rigs, pipelines and production platforms are performing as they should, and try to maximise value based on real-time trends.”

Drilling down into data platforms Using a music streaming service as the

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model for the mind-boggling complexity of the oil and gas industry might sound like a bit of a pipedream, but the principles of good design are universal. With a dashboard-based approach, workers can easily find the data they need to work with, obtain and request information from colleagues, and discover new data sets from across their segment.

“Once they’ve got what they need, they can then pull it into one easily-managed workspace where they can analyse and manipulate the data, and report on it using advanced tools,” Tucker continues. “There’s no reason why the interface design can’t mimic the same simplicity that Spotify (or other apps) have used to drive their popularity among users.”

Tucker explains that the ability to access and visualise data is crucial for monitoring performance in real-time, as well as to match up engineering, maintenance and production data to provide an holistic view of operations.

“This will have a hugely beneficial effect on the industry’s first priority, safety, by enabling workers to access up-to-the-second information about everything from corrosion to structural strength to leaks – vital for preventive maintenance projects,” he says.

“Increasing the safety of operations is crucial

Big Data

to the future of the sector. The more businesses can move to unmanned operations, the safer oil and gas becomes – simply put, there will be fewer people in harmful environments.

“Having the right data visualisation and management platform promises a far more efficient and timely way of maintaining equipment and infrastructure, enabling workers to spot issues in real-time, rather than spending six to nine months setting up a project to stitch together the data. In doing so, it could well prevent a major disaster – financial, environmental or both.”

The technology enabling success The benefits of data management and visualisation platforms are myriad, from enabling more unmanned operations that keep humans out of dangerous situations, to driving low-carbon operating models for the future of

energy. But these platforms are only the ‘front end’, and there are several key developments on which they rely.

Not least of these is artificial intelligence, which is crucial for managing huge volumes of data 24 hours a day and extracting value from it. “It’s not humanly possible to manually manage petabytes of data, and harder still to be smart with it,” Tucker adds. “AI tools are developing to allow employees to suggest ways of using and analysing the data their business holds – and visualising the data on top of this will further improve the outcomes.”

Equally important is 5G, which is especially vital given that so many oil and gas installations are located many miles from the nearest wired networks. Only 5G can cope with the vast volumes of information generated and transmitted from these locations. “Not only will the much lower latency of 5G increase

the amount of data points available, and move this data into the system faster, but the major change will be around surveillance,” Tucker concludes. “Without the latency of current networks, businesses can operate unmanned terminals using cameras and drones in real-time analysis. This means workers can remotely spot fires and leaks much faster and more safely than humans could, and they can transfer and react to this information much more quickly and efficiently.

“The oil and gas sector is undergoing a complete transformation as it moves from being focused on fossil fuels to prospecting in new fields such as mobility, battery power, electric vehicles and smarter fuels and lubricants. Data management and visualisation platforms will be central to their mission of becoming major players in creating a world that’s no longer reliant on hydrocarbons.” n

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Offshore

Design, digital and detail; saving millions with conductor analysis The design, maintenance and monitoring of key components such as risers and conductors has developed significantly as the industry has matured.

Today, highly developed digital technology is playing a huge part, not only in providing efficiency and cost savings, but also improving the safety of operations.

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onductor and riser systems must withstand all potential environmental conditions, but also need to be designed to contain the maximum pressure expected during operations.

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The new approach The obvious, but huge, benefit of analysing and testing conductor designs digitally is that it can be done very safely onshore rather than trying it out in the North Sea, waiting, and

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potentially dealing with disaster. Any conductor and riser system can be modelled in the virtual world, with nobody in harm’s way. “Although this kind of data modelling has been used before, it is advances in the software

Offshore

and processing power that have allowed a huge leap in its capabilities,” Martin Harrop, riser analysis manager, Aquaterra Energy, says.

“Tens of thousands of numbers can be inputted, millions of calculations can be conducted, with varying loads, conditions, materials and so on all factored in, producing far more accurate and less conservative results than ever before.

“To date, the tendency has been to conduct this kind of analysis later in the development phase. With the plans drawn and the equipment ordered, it’s more often treated as a final check before work commences.

Although there’s nothing intrinsically wrong with that approach, especially from a safety point of view, a significant amount of equipment expense and time can be saved if analysis is done early on in the process.

Hundreds of real-world scenarios can be modelled relatively cheaply and quickly in the analytical world, pushing the boundaries which would have been too inefficient through paper-based systems.”

Harnessing this new era of high-powered computer models removes conservatism from the design stage, because impossible or inefficient options are quickly ruled out or refined. In doing so, more cost effective and streamlined designs can emerge that are still fit-for-purpose.

Integrated teams and actionable outcomes This early stage analysis approach has recently been used to tackle a design feasibility project on a platform in the Norwegian sector of the North Sea. The installation had been active for around 15 years and the owners were looking to add two more conductors in order to enhance its production.

With two available conductor slots, the solution seemed obvious - almost beyond question. Two conductors would be installed in the two spare slots, maximising the use of the pre-existing infrastructure.

One question did remain, however.

These vacant slots did not have all necessary lateral guide supports installed and therefore the conductor performance could be compromised. So, a means to provide this support had to be found.

“A retrospective installation of a lateral guide support below water level was deemed very risky, as it would involve divers,” Harrop adds. “Initially, the client planned to install two supports: one above the water level and one below the water level. A hugely complicated job, not to mention in a difficult North Sea environment. Aquaterra Energy’s integrated analysis and engineering team was brought in to show how this might be possible.”

Reliable results The analysts started by getting a comprehensive understanding of all the equipment within the plans and on-site including conductor design, water depths, environmental conditions, location of the guides and a variety of other different design specific parameters. The information was then used to build a representative computer model in specialist software, allowing the team to simulate exactly how the system could react under many different conditions.

“One of the key factors to simulate was the North Sea conditions, as when a storm hits the waves can induce significant load and movement on the conductors,” Harrop explains.

“The loads were then read and compared to industry safety codes which are set by API and DNV, allowing an accurate picture as to whether they were acceptable.”

Not stopping there, the Aquaterra Energy team took this a step further, looking at higher level models, varying ideas around how the support could be designed, where it could be placed and how it could be installed at a few different elevations. Ultimately challenging the client’s idea to see if there were any better solutions available to them.

“With the analysis team being under the same roof as the offshore teams, it allowed potential solutions to be challenged on a feasibility basis, and therefore no solution was suggested that wasn’t possible to deliver,” Harrop says.

Significant savings and a new approach Through open dialogue and collaboration between the client and analysts, a rather welcome result awaited in the data. “The outcome of this assessment was significant, and saved the client over £4million in project costs and additional untold savings on future maintenance,” Harrop continues.

As to how this was achieved Harrop explains that the analysis found a workable solution by only adding a support just above the water level. “This was achieved by optimising the conductor pipe by increasing the wall thickness and designing out the need to install a support below the water level,” he explains. “This mitigated the need for an expensive second support and significantly simplified the planned operations. Notably, divers were no longer required as the required support was above the water level, improving safety through reduced risk. As Aquaterra Energy works closely with its clients, the recommendation was made after liaising with the client to make sure they could obtain the required pipe size on time for the operations to begin.

“In providing independent advice, quickly, it gave a fresh perspective for this type of project in future. In today’s environment, where safety, efficiency and enhanced production are close bedfellows, it has been all too easy for the industry to go with what’s been done before – but new and advanced analysis supports the drive to optimisation in the 21st century.” n

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Sustainability

Utilising flare gas to generate power for the oil and gas sector Dynamic expansion of the oil and gas industry continues to fuel the demand for new technologies that tackle the impact of flare gas emissions globally.

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hile the production of oil has grown by roughly 30 per cent over the past two decades, reaching 18 million barrels per day in 2019 in the United States, the climate impact of flare gas, typically considered a waste by-product by the oil and gas industry,

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continues to be of concern. Globally 140 million cubic meters of natural gas are flared annually, emitting more than 300 million tons of carbon dioxide (CO2) into the environment.

According to Cummins, a lack of infrastructure to capture and sell the flare gas released when

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drilling for oil is a major environmental problem. “Governments, development institutions and oil companies around the world are being pressured to look at the amount of money spent in gas flaring and the damage it is causing to the environment,�

Linda Nezerwe, technical specialist at Cummins,

Sustainability

and expert in emissions control for both diesel and gas generator sets, says. The company recently launched the HSK78G natural gas generator series, designed to provide reliable power regardless of the natural gas source or the climate, and capable of generating power from very aggressive fuels otherwise considered waste products.

“The quantity of unburned fuel that needs to be flared is usually known, but the question is what to do with it,” she added.

Flare gas and the environment According to Cummins, billions of dollars in wasted natural gas could be used to

generate reliable, affordable electricity and yield billions more per year in increased global economic output.

“The World Bank has launched an initiative called Zero Routine Flaring by 2030 which encourages investment in technologies that utilise the unburned fuel and find ways to protect the environment whilst bringing financial benefits,” Nezerwe continues.

“Maximising flare gas to generate electricity would ensure that the oil and gas industries are helping nearby communities while also protecting the environment. Countries like Norway, Algeria, Canada and the United

States have made a lot of progress in limiting local oil companies on how much flare gas is allowed. More and more countries are joining the movement.”

The World Bank initiative brings together governments, oil companies, and development institutions who recognise the flaring situation is unsustainable from a resource management and environmental perspective, and who agree to cooperate to eliminate routine flaring no later than 2030. Governments and oil companies that endorse the initiative will publicly report their flaring and progress towards the initiative on an annual basis.

What to do with the unburned fuel?

Flaring of gas contributes to climate change and impacts the environment through emission of CO2, black carbon and other pollutants. It also wastes a valuable energy resource that could be used to advance the sustainable development of producing countries. For example, according to The World Bank, if this amount of gas were used for power generation, it could provide about 750 billion kWh of electricity, or more than the African continent’s current annual electricity consumption. While associated gas cannot always be used to produce power, it can often be utilised in a number of other productive ways or conserved.

In creating technologies to tackle environmental protection, Cummins says that proposed technologies for replacing gas flaring should not add additional complexity or bring added cost burdens to the operator. “Refineries will routinely flare gas during normal oil processing operations to reduce the unwanted gas in normal production. The major challenge is what to do with the excess gases.

“Current technologies such as Flaring Recovery Systems (FRS) have the goal to recover some of the flare gases and introduce them back to the refineries,” Nezerwe says.

“Although these technologies have proven to be effective, they require a lot of upfront cost for equipment and management of the gas quality. However, thanks to technological advancements, today’s oil and gas companies are increasingly utilising natural gas generators

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Sustainability

that burn raw gas instead of burning it off which is wasteful and harmful to the environment.

“This is where generator set manufacturers can play a big role,” she continued. “These generator sets can use a wide variety of fuels including low energy fuels and fuels that are often unused to produce electricity for neighbouring communities. By designing and manufacturing products that can utilise flare gasses for electricity production, lean burn combustion technologies are capable of combusting fuels of various energy levels and composition to produce power. They can produce electricity with high efficiency and very low exhaust emissions.”

How does lean burn technology work?

A lean burn engine uses excess air in the combustion chamber to have lower combustion temperatures and therefore lower NOx emissions making it an environmental friendly option. The generator’s high efficiency can be further improved by also capturing waste heat from the engine coolant as well as the exhaust gas for processes within the facility or to consumers nearby. For example, the Cummins HSK78G engine is capable of operating with high or low energy density fuel with a combined heat and electrical efficiency of around 90 per cent of the fuel input.

Utilising flare gas to generate power does present engineering challenges. Flare gas will consist of a complex mixture of different gases. The composition will depend upon the source of the gas going to the flare system, however, associated gases released during oil-gas production mainly contain natural gas which is more than 90 per cent methane with ethane and a small number of other hydrocarbons. Gas flaring from refineries will commonly contain a mixture of hydrocarbons and in some cases hydrogen.

It’s important to recognise that the changing gas composition will affect the heat transfer capabilities of the gas, something which engine manufacturers will understand to ensure the performance and feasibility for their products.

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“This new lean burn technology pushes new levels of efficiency, transient performance and gas variation well beyond former natural gas generators,” Nezerwe explains. “When generator set manufacturers describe features of their products, the focus is usually on the generator set outputs such as heat and electricity. But the new series of Cummins generator sets also bring the added benefit that it is able to burn flare gas, pipeline natural gas, and biogas, as well as even the lowest-BTU fuels with high efficiency and low emissions.”

A critical development for the oil and gas industry is the advancing technology in natural gas generators to utilise fuel sources that would otherwise be considered waste products. This leads to robust power solutions even with very aggressive fuels with minimal derating. These advancements in power generation applications allow operators to

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utilise environmentally harmful raw flare gas for diverse purposes instead of simply burning it, with clear benefits to the environment.

The result is that routine flaring can be reduced and transformed into a more environment friendly option while also helping communities through the supply of electricity.

Investment in research and development across the industry continues to be a priority to come up with more efficient and costsaving options to cut losses, utilise the associated gases and save the environment.

As governments, development institutions, manufacturers and oil companies commit to more efficient operations and implement advanced technologies to lower the environmental footprint of drilling, generator set manufacturers have a significant role to play in manufacturing products that can utilise flare gases to generate power. n

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+44 (0)203 675 9530

Interview

Working towards a low carbon future

Oil & Gas Technology spoke to Matthew Chinn, executive vice president of new equipment sales and customer operations for Siemens Oil & Gas, about the importance of decarbonising the entire oil and gas supply chain

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GT: How important is it that the oil and gas sector decarbonises its operations?

Matthew Chinn: There’s considerably more focus today on a low-

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carbon future than there was even a year ago, so it’s critical that the oil and gas sector considers the carbon-free future world. Oil and gas continues to be the backbone of the

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global energy supply and natural gas will likely become even more important in decades to come. The industry’s challenge is to employ the right mix of technologies to achieve a

Interview

are seeing a tipping point for a cleaner world – with themselves, and with their customers, shareholders, and other stakeholders.

In the oil and gas industry, we clearly need to tackle our emissions, but also help our customers make low-carbon choices. While oil and gas companies remain under pressure to reduce emissions, most emissions associated with oil and gas come from consumption, rather than production. Decarbonisation truly happens with consumer choices, such as what cars we buy and how we heat, cool and light our homes.

low-carbon world while ensuring reliable production and sustainable supply. The energy industry plays a key role in meeting this goal and taking steps to make it happen. People

OGT: Oil and gas companies are increasingly looking to decarbonise their activities. How can Siemens help them?

Matthew Chinn: For Siemens, sustainability is a matter of leveraging the right technologies to reduce environmental impact, improve equipment performance, and reduce both CAPEX and OPEX. We’re developing a range of cleaner technologies that support the energy transition and reduce emissions.

While we’re traditionally known as a leading rotating equipment supplier, all aspects of the energy value chain fall within our remit. New transmission and distribution technologies – like high-voltage direct current (HVDC) and efficient, flexible gas turbines – are just two examples. Our all-electric oil and gas production concept based on HVDC transmission equipment can power a production plant using renewable energy from the grid, as opposed to using mid-sized gas turbine engines.

Traditionally, oil platforms have been powered by mid-size gas turbines. Equinor is one oil major that has adopted HVDC technology to cut emissions from its offshore facilities on the Norwegian continental shelf.

Carbon emissions from gas turbines produce up to 80 percent of Equinor’s entire carbon emissions, leaving considerable room for massive reductions. In 2018, Equinor saved over one million tonnes of CO2 emissions from its operations by partnering with us to find smarter, more efficient and sustainable solutions and reinforced its position as a trailblazer for a cleaner oil and gas sector.

OGT: Are there any particular elements of the oil and gas supply chain that you are targeting?

Matthew Chinn: A key element is our advanced gas turbine technology. Today, we can effectively recycle stored hydrogen into electricity by using it as fuel. This year, as part of our commitment toward environmental sustainability, we signed a European industry agreement that promised our new gas turbines can be operated with 20 percent hydrogen (mixed with natural gas) by 2020 and 100 percent hydrogen from 2030 onwards. Parts of these commitments have already been fulfilled, as much of the Siemens gas turbine portfolio can use fuel mixtures with hydrogen levels of 30 percent or higher, and even up to 100 percent in some turbine models.

We recently launched a performance enhancement for the SGT-800 industrial gas turbine that is used in many oil and gas applications. The upgrade – designed to provide operators with significant fuel savings and consequent CO2 emissions reductions – offers up to a 3.5 percent increase in efficiency and can be performed in conjunction with a scheduled major overhaul to minimise production impact and keep CAPEX to a minimum. Similarly, gas processing plants typically use multiple diesel engines.

However, converting from diesel to gas – or even electric power – eliminates a major source of CO2 emissions.

OGT: What are the key technologies for decarbonisation?

Matthew Chinn: A key enabler is Proton Exchange Membrane (PEM) electrolytic technology for generating “green hydrogen” from water at an industrial scale. To generate green hydrogen at the scale needed to decarbonize the world’s energy, Siemens and key partners have spent the last 10 years investing in generating hydrogen from water using PEM electrolysis technology.

This process uses low-cost renewable energy sources to split water (H2O) into its constituent elements without generating carbon emissions. The hydrogen can then be used as a zero-emissions fuel or combined

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Interview

with other elements as a molecular component in core industrial feedstocks.

Siemens complements its PEM technology capability with carbon capture and utilization (CCU) technology required for many parts of power-to-gas and powerto-liquids processes. We can offer the CCU industry a wide range of electrification, automation, and digitalization products from our portfolio, plus global domain expertise and experience to assist operators.

OGT: How can digital technologies help?

Matthew Chinn: To make oil and gas production cleaner – producing more energy with less carbon – we also need to make it safer and smarter as well. The only way to do that is to fully embrace digitalization.

Realising the true value of data lies in knowing how to analyse it. Translating huge quantities of information into a valuable

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resource can lead to better data-led operational decision-making that can be executed more quickly. More data, automation and intelligent analysis are already creating significant efficiency gains and cost savings throughout the oil and gas sector and improving safety and reliability. For example, ‘digital twin’based systems can integrate data and enable design, testing and training in virtual, risk-free environments.

Applicable from the subsurface production equipment to central processing facilities, new techniques are also creating new opportunities in operations and maintenance.

Advanced data analytics maximise the value of equipment throughout its lifecycle and enable new approaches, such as predictive rather than scheduled maintenance strategies.

And developments like the increased use of normally unmanned installations are also made possible by intelligent digital systems.

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OGT: What about Siemens Oil and Gas; how is it decarbonising its own operations?

Matthew Chinn: The use of innovative technologies such as advanced energy management and energy-efficient drives, as well as increasing automation are pillars of our emissions reduction strategy. We’ve made a commitment to become completely carbon neutral by 2030. Across the company and in every business unit, Siemens aims to be the world’s first major industrial company to achieve a net-zero carbon footprint.

In 2015, carbon dioxide emissions across the company, including the oil and gas division, were on the order of 2.2 million tonnes annually. Today, that number has been slashed by more than one-third. Cross-sector measures to improve efficiency and reduce the energy footprint of our production facilities and buildings is

Interview

expected to save about €20 million a year on energy costs from 2020 onwards.

To reduce emissions further, Siemens is using distributed energy systems at our production facilities and office buildings, deploying low-emission and e-mobility vehicles across the global vehicle fleet, and moving toward a clean power mix increasingly reliant upon natural gas and wind power.

OGT: How do you view the future prospects of the oil and gas sector amidst the drive for clean energy?

Matthew Chinn: A carbon-free world is an absolute necessity and our future reality. The Stone Age didn’t end because the earth ran out of stone or that it became too expensive to produce. Better alternatives became available.

This same process is taking place right now across the oil and gas sector, but it too is a transitional process. Oil and gas will continue

to be used and will inevitably play an important role in the energy mix of the future.

As one of the many activities to decarbonize the world’s energy production and use, Siemens is active in the “Powerto-X for Applications” Working Group at the Mechanical Engineering Industry Association (VDMA), which has 3,200 member companies and is Europe’s largest mechanical engineering organization. Our involvement with VDMA is part of Siemens’ commitment to social and environmental responsibility.

Some of the world’s leading oil and gas majors are already announcing their commitment to raise performance standards in terms of energy efficiency and sustainability.

Royal Dutch Shell, for example, is one of the world’s biggest oil developers but reportedly is already spending billions of dollars a year on its new energies division. Not every oil and gas company can match the resources of Shell

but every company can adopt a low-carbon philosophy and adopt appropriate measures wherever possible.

Right now, considering the precise route to a carbon-free world is less important than beginning the journey by embracing energy efficiency, reducing emissions where possible, and preparing for the clean, low-carbon oil and gas business of tomorrow.

Matthew Chinn is the executive vice president of new equipment sales and customer operations for Siemens Oil & Gas. In this role, he has worldwide responsibilities for new equipment solutions and customer operations. Chinn is also the head of Siemens Oil and Gas Market Development Board which includes responsibility for leading the Siemens Corporate Account Managers (CAM) organisation responsible for managing and facilitating strategic relationships across the broader Siemens enterprise. n

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Innovation Focus

Schlumberger introduces intelligent wireline formation testing platform

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chlumberger has introduced the Ora intelligent wireline formation testing platform at the SIS Global Forum 2019 in Monaco. The platform leverages a new architecture and metrology for enhanced performance, enabling dynamic reservoir characterization in all conditions, including where previously impossible.

The Ora platform is rated to 200 degC (392 degF) and 35,000 psi and includes a new focused radial probe, a dual-inlet dual packer, laboratory-grade metrology, new measurements, and the highest flow rate pump

in the industry. The digitally enabled hardware can automate complex workflows, reduce operating time by more than 50 per cent and deliver the highest precision fluid analysis and zero contamination samples. Furthermore, deep transient testing is now possible on wireline.

The platform is built on a digital infrastructure, providing a new customer experience, enabling real-time decisions in a cloud-native environment.

“Characterising dynamic reservoir properties is becoming more critical and difficult than ever as drilling for hydrocarbons

is moving towards complex geologies and challenging environments,” Djamel Idri, president, wireline, Schlumberger, said.

“Moreover, analysing this data to make business decisions can take weeks if not months. The Ora platform was built to address these challenges, with new wireline formation testing hardware and digital edge solutions enabling our customers to make faster and better decisions.”

The Ora platform has successfully completed more than 30 field trials worldwide in a variety of operating environments in the North Sea, US Gulf of Mexico, West Africa, Middle East, North Africa, and Central America. In Mexico for Pemex, the Ora platform was the first ever wireline formation tester to collect high-quality gas condensate samples in a challenging carbonate formation with permeability below 0.03 mD and 182 degC (360 degF) at 20,000psi pressure. This helped Pemex announce the tripling of estimated reserves for Mexico’s most important land discovery in the last 25 years.

In deepwater Gulf of Mexico for Talos Energy, the Ora platform obtained high-quality downhole fluid analysis data in a challenging well geometry, which was immediately integrated and visualized in the reservoir context. The reservoir model was then updated using a bespoke Schlumberger reservoir fluid geodynamics workflow, enabling real-time assessment of lateral and vertical connectivity for early completions decisions. n

Simulator tests show life-saving potential of new oilfield product

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new oilfield product to prevent one of the oil and gas industry’s most deadly situations is about to undergo field trials next week after simulator testing revealed astonishing results. Safe Influx helps avoid well blowouts by automating well control operations and removing the human risk factor

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associated with well control.

Invented last year by Phil Hassard, head of drilling simulation at Robert Gordon University, the technology is about to get its first outing in the field at the Weatherford Land Rig at Bridge of Don Aberdeen following successful tests on a DrillSIM:6000 drilling

Innovation Focus

E&P industry intelligence gets shake-up with launch of MapStand platform

pstream industry intelligence start-up, MapStand, has launched its disruptive go-to source to unlock essential E&P information for oil and gas professionals. The platform provides access to a free, real-time and trusted upstream industry intelligence resource. Subscribers can easily navigate comprehensive data on global E&P activities, assets and events, opening a world of project opportunities.

Enabled by powerful and geo-related

search capabilities, subscribers can locate precisely the information they need on E&P projects, licenses, assets, infrastructure and planned activity as well as new exploration opportunities. Traditionally, accessing such data has involved time consuming research often requiring specialist skills and expensive subscription commitments.

In a departure from traditional E&P industry databases, the MapStand platform will enable users to connect with peers and industry

experts to share knowledge and experience.

Subscribers can not only upload their profiles, but can link them to relevant projects and assets to further highlight skillsets. Geo-tagged daily news feeds keep users up to date with global E&P events, putting industry news into context on the map.

“The MapStand platform is designed specifically from the user’s viewpoint,”Francis Cram, founder and CTO of MapStand, said. “We aim to lift the barriers and frustrations involved in gaining genuinely useful insight into E&P activities, helping professionals engaging with the sector to make informed decisions and contribute to rapid innovation.”

Individual subscribers have free access to MapStand’s global activity map to search project and company information; receive live upstream oil and gas news feeds; upload their profile; and will be able to connect with other professionals. A paid professional level subscription will provide access to advanced functionality and resources.

A further fee-based subscription will enable enterprise subscribers to directly stream or download digital data layers into their own inhouse systems or to their projects, without the need for special tools or software and under flexible data licensing terms. n

simulator. Dozens of tests were carried out on the simulator replicating a huge range of well conditions from extreme to normal operations and monitoring the effects of influx flows both with and without the product.

The data test results were impressive. When Safe Influx technology was used, influx size was dramatically reduced to a safe minimum five times faster than conventional methods.

“Well control is the biggest risk in the oil and gas industry and every year we see blow

outs resulting in loss of life,” Phil Hassard, co-founder and technical director at Safe Influx, said. “Numerous studies show that up to 67 per cent of these blow outs are caused by human factors so we knew that removing these and automating well control would mitigate the risk. Although we recognised we had a potentially revolutionary product, we needed to test the concept to be sure and this is where Drilling Systems’ simulators came in.

“Using Drilling Systems’ DrillSIM:6000 we

were able to test how Safe Influx technology functioned in a wide range of well types and different conditions. We were thorough in our research and used widely differing variations of reservoir properties, formation pressures and mud weights. We took readings of this data and compared the results with and without using the Safe Influx system.

The results were remarkable. There were huge differences with the system dramatically reducing the influx size.” n

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Innovation Focus

Casing Tools develop transformational plugging and abandonment technology

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transformational tool which could significantly reduce the cost of decommissioning is being developed

by Aberdeen-based oil and gas technology company Deep Casing Tools (DCT) in collaboration with the Oil and Gas Technology Centre (OGTC) and Total.

The UK is expected to spend more than £15b on oil and gas decommissioning over next decade with the global figure for the same period estimated at £84b ($105b). Plugging and abandonment (P & A) is the complex process by which a well is closed permanently and typically accounts for about 45% of projected decommissioning costs.

Current technologies used for P & A – cut and pull; perforate and wash and, as a last resort, section milling – can create significant challenges with research revealing that around 20 per cent of all pulling operations take longer and cost more than anticipated. Early trials have shown that DCT’s Casing Cement Breaker can make these operations more predictable and reliable and can have a major impact on the length of an operation.

“Early results show that up to 90 per cent less force is required to pull a casing following a run with the Casing Cement Breaker,” David Stephenson, DCT’s chief executive, said. “One company told me

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they are currently taking up to 70 days to cut and pull some casing in the Norwegian North Sea. It is too early to say how much we could reduce that by, although we hope it will ultimately be 90 per cent, but even if it were only ten per cent that would be a huge reduction given rig rates of up to £350,000 a day.”

This idea for this latest innovation came after a brainstorming session with an inventor and former colleague of Stephenson. “We started with some ideas, did some sketches and then built a small model tool to test the principle,” he said. “We built a load of samples, ran the tool, and even in those early workshop tests we reduced the force required to pull a piece of casing by 90 per cent using Casing Cement Breaker.”

DCT then built a larger workshop prototype and approached the OGTC for assistance. The OGTC canvassed members and it attracted the interest of Total who offered in-kind funding and the OGTC offered cash support.

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“We now have a three-way partnership with the OGTC and Total,” Stephenson added. “The tool will be trialled early next year on wells in Total’s Alwyn and Franklin fields in the first quarter of next year, with the aim of it being fully commercial by the end of 2020.

“In the meantime, Equinor carried out a trial in the Huldra field, using the workshop prototype which confirmed the potential of what might be achieved. It reduced the force required to pull a piece of casing by about 40 per cent, which would mean a ten-day job would take six days, and that tool had really only been designed for workshop testing. We have taken the learnings from that trial, looked at how we can make it even better, addressed those issues and are now building a secondgeneration prototype. n

Innovation Focus

CGG GeoSoftware adds machine learning applications for reservoir characterisation

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eoSoftware, part of CGG’s Geoscience division, has announced that machine learning technology in Python ecosystems will be available in upcoming releases of its flagship HampsonRussell and Jason reservoir characterisation solutions.

Already attracting considerable industry interest in GeoSoftware’s PowerLog petrophysical software, Python ecosystems in HampsonRussell and Jason will let experts and data scientists completely customise machine learning and reservoir characterisation workflows by using extensively available Python machine learning libraries and also their own proprietary code.

Python ecosystems allow users to efficiently research and test various state-ofthe-art machine learning workflows for proof-

of-concept or commercial projects. Scripts and workflows directly access well, horizon and seismic data for use in machine learning, deep learning, visualization and numerical analysis. G&G experts and data scientists can use Ecosystem workflows pre-built by CGG or they can build their own new reservoir characterization workflows using the latest open source machine learning packages, such as Google’s TensorFlow.

HampsonRussell and Jason users, even those with limited expertise in machine learning or Python scripting, will now benefit from complete control over input data and analysis output. With Python ecosystems, users can process data with pre-built or client-proprietary Python scripts or Jupyter notebooks, and store input and output data

in either a HampsonRussell or Jason project database or a shared directory. Python ecosystem functionality will seamlessly integrate with the application’s data stores and viewers, eliminating the need to export, reformat and reload data.

“CGG already led the market by introducing Python ecosystem technology in PowerLog,” Kamal al-Yahya, senior vice president, software and smart data solutions, said. “We are now extending its benefits to the wider community of HampsonRussell and Jason users to enable effective research and application of machine learning technologies in reservoir characterization workflows. This new capability is another example of our commitment to innovation and making new technologies accessible to the industry, for generalists and experts alike.” n

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Innovation Focus

Wild Well Control adds new 10,000 psi-rated capping stack

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ild Well Control has added a new 10,000 psi-rated capping stack to its Wellcontained group of subsea containment equipment. The 10,000 psi-rated (10K) stack is rated to water depths of 10,000ft, and will play a vital role in supporting quick and effective service for subsea well control events in Northern Europe.

The stack’s modular design facilitates efficient deployment by crane vessel or drilling rig and regional coverage includes the following areas: North Sea; Baltic Sea; Celtic Sea; Irish Sea; Norwegian Sea; Barents Sea; and the North Atlantic waters, including Ireland and the UK. The new stack is the third system in Wild Well’s Wellcontained program of subsea emergency response services. The 10K stack and its associated equipment package will be staged in a ready-to-deploy state from Wild Well’s Montrose facility near Aberdeen and is subject to a separate membership agreement. The full subsea well intervention systems include subsea capping stacks, debris removal shears, hardware kits for the subsea application of dispersant and inhibition fluids and other ancillary equipment.

“With the recent expansion at our quayside location at the Montrose facility, we can support both the new 10K regional stack and our global Wellcontained response capabilities,” Chris LeCompte, Wild Well’s general manager of Wellcontained, said. “The increased facility space will allow for improved efficiencies and quick mobilization for fast response from this location for our regional and global clients.” n

Oxford Flow launches gas regulator valve to increase reliability

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xford Flow has launched its IM gas regulator valve to increase reliability and reduce costs for operators in the gas distribution, power generation, industrial gases and oil and gas sectors.

The launch follows a successful ongoing trial with SGN where the

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valve has been installed and commissioned with ease, regulating gas pressure smoothly with rapid changing demand profiles within an accuracy class of 1.5 per cent. This accuracy the valve offers in comparison to conventional technologies enables utilities and operators to achieve faster network stability on commissioning, even where flow rates vary

Innovation Focus

Smart end position monitoring for manually operated valves

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lectric actuator manufacturer Auma offers a new sensor system for signalling valve end positions which can be mounted to the company’s GS .3 part-turn gearboxes. The new solution allows plant operators to monitor the position of manually operated valves, and hence to collect crucial valve position information from all the valves in their plants – not just from motoroperated valves, which mostly use the integral limit switching functionalities of the actuators. The new sensor system adds intelligence to valves at a time when collecting and processing data from smart field devices is at the core of a rising number of

Industrial Internet of Things (IIoT) applications in process automation.

The sensor system can also be used in combination with electric valve actuators when redundant valve end position feedback is required in addition to the actuator-embedded functionality.

AUMA’s new sensor system uses inductive sensor elements which ensure contactless monitoring of the end position for 90° part-turn valves. In contrast to mechanical limit switches, AUMA’s electronic sensor system is wear-free and not subject to corrosion. It combines high

switching accuracy with robustness.

GS .3 gearboxes can be ordered with the integral sensor system as of now. Thanks to its modular design, the sensor system can also be easily retrofitted to existing GS .3 gearboxes in the field. The sensor system is available in two versions: a cost-efficient basic version and a fully-sealed premium version with aluminium housing offering enhanced IP69K protection.

The premium version is particularly suitable for outdoor installation. Both versions are available with ATEX approval for use in potentially explosive atmospheres. n

significantly. In addition, the valve’s compact construction reduces weight and the need for expensive lifting equipment during installation and maintenance.

In conventional valves, the diaphragm tends to be the most common failure point.

Oxford Flow’s new design has eliminated the diaphragm, stem and external mechanical actuator. With only one moving part, the design minimises potential leaks and the risk of

fugitive emissions – maximising efficiency and reducing maintenance costs.

“This is not only a hugely exciting time for Oxford Flow, but a significant step forward for the valve industry,” Neil Poxon, CEO at Oxford Flow, said. “As many companies across the industries we serve look for ways to minimise costs, this gas regulator enables just that. Our recent valve testing and developments in the

UK, Germany and USA have enabled us to improve and perfect the regulator so that we can now roll the technology out to the wider industry with confidence.

“We believe this will be a pivotal moment that has a lasting impact on gas networks in the UK and beyond.” n

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Innovation Focus

Trendsetter expands connector product line for 20k intervention

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rendsetter Engineering has announced that they have been awarded a contract for the design, qualification and delivery of a 20K Hydraulic Intervention Connector by HWCG. The 20K connector is designed to interface with the HWCG 20K Capping Stack and would be utilised to conduct flowback or intervention operations after the capping stack has been installed.

“We are thrilled by this recent award from HWCG and look forward to delivering a great product,” Antony Matson, vice president of projects, said. “Trendsetter has been a market

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leader in developing and delivering products for HPHT applications, and this project represents yet another milestone for the Trendsetter’s subsea Connection System Product Line.”

The TC11/7 Hydraulic Intervention Connector will be the latest addition to Trendsetter’s extensive portfolio of connectors. The TC11/7 Hydraulic Intervention Connector leverages Trendsetter’s field proven hub and gasket profiles to provide 7” bore access and emergency disconnect capability for service up to 20,000psi.

This order marks Trendsetter’s fifth unique

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connection system to be designed, qualified, and delivered to the API 17TR8 HPHT standard.

Trendsetter’s goal is to bring Innovation to Intervention by developing readily configurable, bespoke solutions. Trendsetter’s connectors have been successfully deployed and operated around the world in a variety of applications, including high pressure well intervention projects. Trendsetter offers a full range of production and intervention connectors from 2” to 16” bore, pressures up to 20,000psi, and temperatures up to 400°F. n

Innovation Focus

Weir introduces continuous duty 5000-horsepower pump

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eir Oil & Gas has introduced its SPM Quintuplex Extended Max (QEM) 5000 E-Frac Pump. This new pump is the only true continuous-duty electric or gas turbine-capable 5,000-horsepower pump in production today.

The SPM QEM 5000 E-Frac Pump builds on the proven power and durability of the SPM QEM 3000 platform, having nearly one billion field cycles with zero NPT reported. The e-frac pump delivers two worldwide firsts: a frac pump designed from the ground up for electric or gas turbine and 5,000-horsepower capacity in a single unit, rated for service at 100 per cent of rod load, 24 hours a day, even in extreme conditions.

Frac site demands have dramatically expanded in the past six years. Today, lateral lengths are 43 per cent longer, the number of stages has increased 94 per cent, sand usage is up 85 per cent and horsepower-hours per well have increased 200 per cent. These factors,

combined with operating in increasingly complex environments, pushes conventional frac fleets to their limits with longer pumping hours and less frequent service intervals to increase daily stages. This reality requires frac pumps to provide ever-increasing durability and performance, but with diesel prices at more than $3 per gallon, adding horsepower alone doesn’t fully meet operators’ needs.

The pump’s compatibility with non-standard drivers, including electric and natural gas turbines, gives operators the flexibility of tapping into the electrical grid, remote power generation or a natural gas turbine generator which reduces diesel fuel spend, emissions, overall assets on location and maintenance intervals.

The pump minimises upfront capital investment as it can reduce a frac fleet from 20 conventional pumps and 100 bores per site to just eight pumps and 40 bores per site. With only eight pumps needed to match the output of 20 conventional pumps,

maintenance, noise pollution, safety hazards, emissions and overall footprint are reduced.

With intentional engineering to reduce maintenance, operators can experience millions of dollars in maintenance savings per year of use and reduce maintenance personnel costs by potentially 42 per cent.

The pump achieves its horsepower with enhanced structural rigidity through an engineered skid and segmented frame plates that dramatically extend component life. It also features a dual-pressure lubrication system designed to optimise delivery and distribution of clean lubricant to provide extended life and reduced non-productive time.

With a fit-for-purpose gearbox, as well as the industry’s largest bearing, the pump is capable of operating continuously at its full horsepower and higher torque applications. The high-ratio gearbox design allows for a small more efficient motor to be utilized. Furthermore, when utilising an eight-inch stroke the motor size reduction is even greater. n

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2018 OCTOBER The Future of Latin America Oil & Gas Digital Transformation Summit 1st – 2nd October Rio de Janeiro https://chameleonevents.co.uk/events/the-future-oflatin-america-oil-gas-digital-transformation-summit/ OilComm 2nd – 3rd October Houston http://2019.oilcomm.com/

Oil & Gas Thailand 9th – 11th October Bangkok, thailand http://oilgasthai.com/

Oil Trading & Logistics 27th – 30th October Lagos, Nigeria https://www.otlafrica.com/about-us

Oil and Gas Myanmar 2019 6th - 7th November Myanmar http://www.oilmyanmar.com/

121 Oil and Gas Investment 28th – 29th October London www.weare121.com/121oilgasinvestment-london

US-Mexico Natural Gas Forum 11th – 13th November San Antonio, Texas http://www.usmexiconaturalgasforum.com/

APOGCE 2019 29th – 31st October Bali, Indonesia https://www.spe.org/events/en/2019/ conference/19apog/asia-pacific-oil-and-gasconference-and-exhibition

Kuwait Oil & Gas (KOGS) 13th – 16th October Kuwait https://kogs-expo.com/ SPE Annual Caspian Technical Conference 16th – 18th October Baku, Azerbajan https://www.spe.org/events/en/2019/ conference/19ctce/spe-annual-caspian-technicalconference.html UK Onshore Oil & Gas Summit 21st – 22nd October Birmingham https://chameleonevents.co.uk/events/the-ukonshore-gas-oil-summit/ IADC Advanced Rig Technology 2019 Conference & Exhibition 22nd – 23rd October Amsterdam, Netherlands http://www.iadc.org/event/rig-technology-2019/ Future of Oil & Gas Canada: Digital Transformation Summit 28th – 29th October Calgary, Canada https://chameleonevents.co.uk/events/future-of-oilgas-canada-digital-transformation-summit/ SPE Russian Petroleum Technology Conference 22nd – 24th October Moscow, Russia https://www.spe.org/events/en/2019/ conference/19rptc/spe-russian-petroleumtechnology-conference-moscow.html 22nd International Trade Fair of Oil and Gas 22nd – 24th October Kiev, Ukraine http://oilgas-expo.com/en/

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ESSENTIAL DATES FOR PROFESSIONALS WORKING IN THE OIL AND GAS SECTOR

OTC Brazil 29th – 31st October Ro de Janeiro, Brazil OTC Brasil has been held biennially in Rio de Janeiro since 2011. The conference is organized by the Offshore Technology Conference (OTC) and Brazilian Petroleum, Gas and Biofuels Institute (IBP) and supported by 13 engineering and scientific organizations who work cooperatively to develop the technical program. http://www.otcbrasil.org/

Tanzanian Oil & Gas Conference 2nd – 3rd October Salaam, Tanzania https://www.cwctog.com/

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NOVEMBER Operational Excellence in Oil & Gas 4th – 6th November Houston, Texas https://www.oilandgasiq.com/events-opexinoilandgas Africa Oil Week 2019 4th – 8th November Cape Town, South Africa The Summit brings together governments, national oil companies, investors, and operators, as a hub to raise capital and to take projects to final investment decisions. Africa Oil Week attracts the highest quality speakers. Over the course of the week, 200 industry leaders, including Ministers, CEOs of NOCs, Directors of Hydrocarbons, and CEOs from major and independent companies, will debate the future course of the African upstream sector. https://www.africa-oilweek.com The Future of Petrochemical & Chemical Manufacturing Digital Transformation Summit 5th – 6th November Manchester https://chameleonevents.co.uk/events/the-futureof-petrochemical-chemical-manufacturing-digitaltransformation-summit/

ADIPEC 2019 11th – 14th November Abu Dhabi ADIPEC brings together professionals with real buying power, with billions of dollars’ worth of business concluded at the event each year. The oil and gas industry convenes in ADIPEC to not only decide on the future of the industry, but to purchase for now, meet with existing partners and discover new business opportunities for the future. https://www.adipec.com/ Oil & Gas Vietnam 2019 13th – 15th November Vung Tau City, Vietnam http://oilgasvietnam.com/ Algeria Oil & Gas Summit 19th – 21st November Algiers, Algeria https://www.algeria-summit.com/ Mozambique Gas Summit & Exhibition 13th – 14th November Maputo, Mozambique https://www.mozambique-gas-summit.com/ East Africa Oil and Gas Summit & Exhibition (EAOGS) 26th – 27th November Nairobi. Kenya https://www.tradefairdates.com/East-Africa-Oil-andGas-Summit-Exhibition-EAOGS-M13277/Nairobi.html DECEMBER 5th International Oil and Gas Conference 2nd – 3rd December Kuala Lumpur, Malaysia https://oil-gas.madridge.com/ Future of Middle East Africa Oil & Gas Digital Transformation Summit 3rd – 4th December London https://chameleonevents.co.uk/events/future-middleeast-africa-oil-gas-digital-transformation-summit/

IADC Annual General Meeting 6th – 8th November Austin, Texas http://www.iadc.org/event/2019-iadc-annual-generalmeeting/

Oil & Gas Environmental Conference 3rd – 4th December Dallas, Texas http://www.oilandgasconference.org/

5th Oil & Gas Africa 2019 7th – 9th November Dar-es-Salaam, Tanzania https://www.expogr.com/tanzania/oilgas/

8th Iraq Oil & Gas Basra Show 3rd – 5th December Basra, Iraq www.basraoilgas.com/

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7th Frankfurt Gas Forum 11th – 12th December Frankfurt, Germany https://www.energystreamcmg.com/forums/forumsseminars/7th-frankfurt-gas-forum-2019.aspx

2020 JANUARY 2020 The 7th International Conference on Petroleum and Petrochemical Engineering 6th – 8th January Ho Chi Minh City, Vietnam www.icppe.org/ International Petroleum Technology Conference (IPTC) 13th – 15th January Dhahran, Saudi Arabia http://2020.iptcnet.org/ Oil & Gas IOT Summit 20th – 23rd January Lisbon, Portugal https://www.oilandgas-iot.com/ National Biofuels Conference & Expo 21st – 24th January San Diego https://www.biodieselconference.org/ European Gas Conference 27th – 29th January Vienna, Austria https://www.energycouncil.com/event-events/ european-gas-conference/ LNG Bunkering Summit 28th – 30th January Amsterdam, Netherlands https://www.oilandgasiq.com/events-lngbunkering

FEBRUARY 2020 SPE Hydraulic Fracturing Technology Conference and Exhibition 4th – 6th February The Woodlands, Texas http://www.spe-events.org/hydraulicfracturing/ Homepage UK CCUS and Hydrogen Decarbonisation Summit 4th – 5th February Birmingham https://chameleonevents.co.uk/events/uk-ccus-andhydrogen-decarbonisation-summit/ Nigeria International Petroleum Summit 9th – 12th February Abuja, Nigeria https://www.nigeriapetroleumsummit.com/ Egypt Petroleum Show (EGYPS) 11th – 13th February Cairo, Egypt https://www.egyps.com/

Subsea Expo 11th – 13th February Aberdeen, Scotland Subsea Expo is the world’s largest annual subsea exhibition and conference, held 11-13 February 2020 at P&J Live in Aberdeen, and also includes the industry’s prestigious awards ceremony, the Subsea UK Awards. The free-to-attend exhibition, which will see 170+ exhibitors and 6,500+ visitors, is a quality-focused event showcasing the capabilities, innovations and cutting-edge technologies of the underwater sectors. https://www.subseaexpo.com International Petroleum Week (IPW) 25th – 27th February London https://www.ipweek.co.uk/ Offshore Pipeline 25th – 27th February Amsterdam https://maritime.knect365.com/offshore-pipelinetechnology/

MARCH 2020 SPE Drilling 3rd – 56th March Galveston, Texas www.spe.org/en/events/drilling-conference/home/ CERAWeek 9th – 13th March Houston, Texas The program of CERAWeek provides comprehensive insight into the global and regional energy future by addressing key issues—from markets and geopolitics to technology, project costs, energy and the environment, finance, operational excellence and cyber risks. https://ceraweek.com/ AUSTRALASIAN OIL AND GAS 11th – 13th March Perth, Australia https://aogexpo.com.au/

APRIL 2nd Argentina Gas & Oil Summit 1st – 2nd April Buenos Aires https://chameleonevents.co.uk/events/2nd-argentinagas-oil-summit/ Atyrau Oil & Gas 2020 8th – 10th April Atyrau, Kazakhstan https://oil-gas.kz/en/

MCEDD 21st – 23rd April London, England http://mcedd.com/

MAY OTC Houston 4th – 7th May Houston http://2020.otcnet.org/ AIPN 2019 International Petroleum Summit 19th - 21st May Bangkok, Thailand www.aipn.org

JUNE 27th International Caspian Oil & Gas Exhibition 2nd – 4th June Baku, Azerbaijan https://caspianoilgas.az/ IIOT and Digital Solutions for Oil & Gas 3rd - 4th June Amsterdam, Netherlands https://www.globuc.com/digitalsolutions/ EAGE 2018 8th – 11th June Amsterdam, Netherlands http://www.eage.org Global Petroleum Show 9th – 11th June Calgary, Canada https://globalpetroleumshow.com/ Data Driven Drilling & Production ? June Houston https://www.upstreamintel.com/data/

AUGUST Machine Learning & AI for Upstream Onshore Oil & Gas 28th – 29th August Houston http://www.machinelearning-ai-upstream-congress. com/

SEPTEMBER KIOGE 30th September – 2nd October Almaty, Kazakhstan https://kioge.kz/en/

Neftegaz 2019 13th - 16th April Moscow http://www.neftegaz-expo.ru/en/

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Final Word

All eyes on the Caribbean as replacement ratio dips to the lowest in decades According to figures from Rystad Energy the so-called resource replacement ratio for conventional resources now stands around 16%, meaning that only one barrel out of every six consumed is being replaced by new sources.

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il and gas companies have discovered 7.7 billion barrels of oil equivalent (boe) year-to-date, according to Rystad Energy’s latest global discoveries report.

“The industry is well on track to repeat the feat achieved in 2018 when around 10 billion boe of recoverable resources were discovered,” Palzor Shenga, senior analyst on Rystad Energy’s upstream team, said.

Russia has seen the most discovered resources thus far in 2019, with the Dinkov and Nyarmeyskoye discovery announced earlier this year holding around 1.5 billion boe of recoverable resources. Guyana and Cyprus nab the other places on the podium.

The so-called resource replacement ratio for conventional resources now stands around 16%, which is the lowest seen in recent history.

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“This means that only one barrel out of every six consumed is being replaced by new sources. This is the lowest replacement ratio we have witnessed in the last two decades,” Shenga added.

However, the industry has high hopes after the prolific success of ExxonMobil’s Stabroek block off the coast of Guyana and more recent discoveries by other operators in the region, which have led to a surge in offshore exploration in the Caribbean. More acreage is being made available for bidding, with some countries conducting their first-ever licensing rounds in 2019 and 2020.

Offshore drilling activity has been on a steady rise in recent years, with 23 new exploration wells expected in 2019. By comparison, only seven offshore wells were drilled in 2013.

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“We estimate the annual number of wells drilled could increase slightly to 25 wells in 2020, as more operators join the Caribbean exploration circuit,” says Santosh Kumar, an exploration analyst on the upstream team.

Rystad Energy expects the GuyanaSuriname basin will continue to occupy headlines with a few planned wells in both Guyana and Suriname. The basin is pinned as one of the most prospective, underexplored basins in the world and will definitely get a facelift from its current assigned volumes if hydrocarbons are established towards the east.

“Explorers have set their sights on establishing a working petroleum system and unlocking the underlying commercial prospectively of the basin. The latest update suggests that the basin could have a potential of around 13 billion boe,” Shenga said.

A wildcat exploration campaign led by Apache is currently underway in Guyana’s eastern neighbour, Suriname. Prior to this only 14 wells have been drilled in the GuyanaSuriname basin beyond water depths greater than 20 meters. n

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