Oil & Gas

InterMoor Wins Contract on Mad Dog Phase 2 Project

2MadDogInterMoor, a leading provider of mooring services, foundation solutions and offshore installations in subsea services group Acteon, has been awarded a service contract with Subsea 7 to provide mooring and tow services for BP’s new Mad Dog 2 project.

The contract with Subsea 7, BP’s subsea offshore installation contractor on the project, will involve InterMoor securing the new semi-submersible production platform at depths of 4,440ft in the U.S. Gulf of Mexico. InterMoor will install the new Mad Dog 2 platform which includes wet tow and mooring installation.

Tom Fulton, InterMoor’s global president, said: “This project win is a testament to the confidence both BP and Subsea 7 have in our long-standing expertise and experience. The reassurance that InterMoor’s strong track record can give to clients with complex projects is evident in the awarding of this contract.”

25 More Years in the ACG Field

Statoil, together with co-venturers and the Azerbaijan Government sign amended and restated Azeri-Chirag-Deepwater Gunashli PSA.

The Azerbaijan Government and the State Oil Company of the Republic of Azerbaijan (SOCAR) together with BP, Statoil, Chevron, INPEX, ExxonMobil, TPAO, ITOCHU and ONGC Videsh signed the amended and restated Azeri-Chirag-Deepwater Gunashli (ACG) Production Sharing Agreement (PSA) which will be effective until the end of 2049.

4ACGfield imageThe Central Azeri Platform. (Photo: Stuart Conway / BP)

The agreement was signed in Baku and is now subject to ratification by the Parliament (Milli Majlis) of the Republic of Azerbaijan.

BP is the current operator of the field and will remain the operator under the extended ACG PSA. Statoil originally entered the PSA in 1994 with an 8.56% share.

As part of the new agreement, SOCAR will increase its equity share from 11.65% to 25% and the participating interest of all partners will be revised. Statoil's share will be adjusted to 7.27%.

All international partners will make a total payment of USD 3.6 billion to the State Oil Fund of the Republic of Azerbaijan which collects income on behalf of the Azerbaijan government. This amount will be divided according to the partners' participating interest and Statoil's share will be approximately USD 349 million. The extension represents a major milestone for Statoil and all the participating companies which will continue generating value from the asset for many decades to come. Subsequent to this agreement, SOCAR and its co-venturers have also agreed to progress engineering development work to evaluate an additional production platform in the ACG contract area.

Lars Christian Bacher, Statoil's Executive Vice President for Development and Production International, welcomes the result and states that the extension represents a major step for Statoil. "This year we celebrate 25 years of Statoil presence in Azerbaijan and we cannot find a better way to celebrate this milestone than by extending our participation in the ACG field for a further 25 years. The ACG field represents a world-class development and will be a key asset in our international portfolio for many years to come."

Since 1994, when the PSA was first signed, the ACG field has received USD 33 billion of investment and produced 3.2 billion barrels of oil production. In the first half of 2017, total production from ACG averaged 585,000 barrels per day.

Consortium to Tackle Major North Sea NDT Challenge

1Consortium TRAC 2A consortium of organisations has set out to tackle one of the most enduring challenges in the North Sea: the non-destructive testing (NDT) of corroded pipes under insulation and engineered temporary pipe wraps.

The group – which includes TRAC Oil & Gas; the University of Strathclyde; and CENSIS, the Scottish Innovation Centre for Sensor and Imaging Systems – will methodically audit the tools, capabilities, and approaches currently used by industry to look at the steel surfaces of assets; often obstructed by layers of material.

While there are a number of NDT technologies on the market, many are ineffective when used on pipes that are protected by insulation. They tend to average out wall thickness where corrosion “scabs” have formed, failing to pinpoint specific areas of vulnerability.

Taking and interpreting these readings is further complicated by the varying dimensions, materials, locations, and accessibility of different oil and gas assets. While insulation can be removed, it requires significantly more time in challenging conditions, making the task more dangerous to the technician undertaking the inspection, and ultimately more expensive to the company.

After assessing the limits of what is available, the consortium will then explore how improvements can be made, including the development of new techniques for accurately identifying and measuring areas of corrosion. The first phase of the project is a feasibility study, the results of which will be shared with wider industry and its stakeholders, including the Health and Safety Executive.

Bill Brown, Technical Manager at TRAC Oil & Gas, said: “Inspection is becoming more important as the UKCS continues to mature – estimates suggest that a high proportion of assets are approaching or, indeed, have exceeded their original design life. We’re at the point now where, against the backdrop of a sustained low oil price, if a platform has to shut down for maintenance, it may never start producing again. We, therefore, need as much accurate data as possible to make informed decisions.

“By taking regular readings on an asset’s condition, we can determine whether they are fit for purpose and operations can keep oil flowing, all within as safe an environment as possible. To do this effectively, we need to take stock of all the technology available, verifying its capabilities and limitations. From there, we’ll be able to look at potential new methods for inspecting the integrity of assets, using non-destructive techniques.”

Dr Gordon Dobie from the University of Strathclyde’s Department of Electronic & Electrical Engineering added: “Decades of oil, gas, water, and chemicals passing through pipes has taken its toll on a range of assets, requiring regular inspection and increasing the importance of the data we get back from tests. Despite a greater need than ever before for accurate inspection and condition monitoring technologies, minimal funding is available for maintenance of infrastructure.

“Working with TRAC’s team, we’re examining what companies currently do to measure wall thickness, repeating it in the lab on specimens, and trying to develop a standardised approach to getting more accurate information from NDT. We’re validating what the instrumentation is saying about the thickness of walls with a view to filling a real and significant gap in the technology already available.”

CENSIS brokered the relationship between TRAC and the University of Strathclyde, and will provide project management support as the initiative progresses.

Rachael Wakefield, Business Development Manager at CENSIS, commented: “Being able to accurately analyse corrosion under insulation is the holy grail of NDT. We’ve already learned a great deal from working with TRAC about the technical and economic challenges facing the industry. This project demonstrates that there’s a real opportunity for oil and gas companies to enhance their offering and tackle some of the biggest problems facing the industry – not only in the North Sea, but across the globe.”

ExxonMobil Says Baytown Restart Activities Continue, Pipelines Beginning to Transport Fuels

2ExxonMobilExxonMobil said on Tuesday, September 5, 2017, that facility assessments and restart activities continue at its Baytown refinery, and that it has made significant progress in restarting chemical production, pipelines and other logistical infrastructure in the Houston area. The company’s fuel terminals in Houston are open and supplying gasoline and diesel to customers. Offshore production platforms in the Gulf of Mexico are beginning to return to normal operations. Production units at the Beaumont refinery remain shut down due to flooding in the lower level of the refinery.

Safety remains the company’s first priority as facility assessments continue and operations begin to resume.

Efforts are underway to transport refined products from unaffected regions to communities and customers in the most severely impacted areas. The company is also delaying scheduled maintenance at other ExxonMobil refineries to continue producing gasoline and diesel to relieve the supply situation. Personnel from the Baton Rouge, Billings and Joliet refineries are being deployed to Baytown and Beaumont to help restore operations.

The company has allocated supplies of fuel for use by emergency responders, and has thus far provided nearly 650,000 gallons to responders working in areas impacted by the storm, including Beaumont, Baytown and the greater Houston area, as well as Dallas and Baton Rouge. In Beaumont, ExxonMobil engineers continue to assist the city with restoring the municipal water system, which was impacted by flooding. The company has distributed 30,000 bottles of water and about 400 pounds of toiletries in Beaumont. About 4,500 gallons of bleach have also been provided to Jefferson County for distribution to residents and businesses in impacted areas.

“Our teams have been working around the clock to restore operations as quickly and safely as possible so we can supply fuels to our customers,” said Darren W. Woods, chairman and chief executive officer. “The incredible efforts our employees have put behind maintaining critical operations under challenging conditions has been remarkable.”

ExxonMobil has also been assessing impacts on its onshore and offshore oil and gas production assets. Galveston 209 offshore platform systems are safe and operational, and startup operations are underway. The Hadrian South subsea production system in the Gulf of Mexico has been deemed safe and operational, and production has resumed. Crews from ExxonMobil subsidiary, XTO Energy, have begun assessments and are bringing onshore wells on line when safe to do so.

ExxonMobil employees are also contributing their time toward assisting area residents in need. For example, the company’s U.S. Production unit is initiating a volunteer program to continue assisting fellow employees, ExxonMobil annuitants, and the greater community. Employees have also volunteered at several area shelters, including the George R. Brown Convention Center in Houston, the Fort Worth Convention Center, and others in the region.

Employees can take advantage of the ExxonMobil Foundation’s volunteer involvement program. In the United States, the program provides qualified organizations a $500 donation on the employee’s behalf for every 20 hours volunteered, up to four times per volunteer per year.

“Volunteerism has been a core value for the company since its earliest days,” Woods said. “Our employees are committed to assisting residents in their communities also impacted by effects of the storm. Our thoughts remain with all area residents during this challenging time, and we hope our efforts in working with disaster relief agencies and local first responders have provided comfort to families and individuals in need.”

ExxonMobil has also established an employee and retiree donation match program to support relief and recovery. Employee and retiree contributions to the American Red Cross and Salvation Army will be matched on a one-to-one basis up to $25,000 per donor and up to $3 million in total, which will generate up to $6 million for the disaster relief organizations. The company has donated $2.3 million in advertising time to the Red Cross that has been dedicated to high-profile televised public service announcements. These commitments, along with $1 million in initial contributions to the American Red Cross and United Way of Greater Houston and about $1 million worth of in-kind contributions in South Texas, total about $10.3 million.

Employee safety and well-being remains a top priority, and those who need to work remotely are being encouraged to do so. Health and counseling services are available on request for employees. Hotlines have been established to provide updated information to employees across different geographical locations. Constant contacts between managers and employees, as well as the company’s automated employee tracking system, have been instrumental in ensuring employee safety.

Expro Secures Multi-Million Dollar Well Services Contract with Repsol Sinopec Resources UK Limited

4Expro wireline unit Leading international oilfield services company, Expro, has secured a five-year master services agreement with Repsol Sinopec Resources UK Limited, for well services across its UK North Sea assets.

The contract is valued at $8million/£5million for the first calendar year, which will be reviewed on an annual basis - including options to extend beyond the initial term.

Expro’s award includes well intervention services across all of Repsol Sinopec’s UK North Sea assets for production assurance and enhancement, well integrity, subsea, reservoir and decommissioning and abandonment applications.

The wireline and cased hole logging services include personnel to supervise all offshore intervention activity, including slickline and electric line conveyance, memory and real time cased hole logging (including production logging and calliper services), explosive and perforating services, downhole cameras, gauges and sampling.

Expro is committed to improving well performance through an experienced team of engineers, supervisors and integrity specialists, providing solutions for every stage of the well life cycle.

The company’s services cover all aspects of well servicing activity from office-based planning and co-ordination, through to well site execution and supervision. Expro’s worldwide experience extends across different well conditions, from shallow land gas storage wells to highly complex deepwater HPHT environments.

Expro’s UK Area Manager Gary Sims said:

“Securing this significant agreement gives a major boost to our UK well intervention business, as we work hard to maintain contracts with valued, long term customers. It continues our excellent relationship with Repsol Sinopec (formerly Talisman), which goes back to the company’s arrival in the North Sea two decades ago.

“The experience of our personnel, our strong safety culture and our commitment to service quality were critical in securing this contract - we look forward to further strengthening this relationship with Repsol Sinopec in the future.”

Gas to Become World’s Primary Energy Source By 2035

6 1Oil and gas forecast 2050 Energy Transition Outlook 2017 coverOil and gas will be crucial components of the world’s energy future, according to DNV GL’s forecast of the energy transition. While renewable energy will grow its share of the energy mix, oil and gas will account for 44% of world energy supply in 2050, compared to 53% today. Gas will become the largest single source of energy from 2034.

DNV GL’s Energy Transition Outlook (ETO), a forecast that spans the global energy mix to 2050, predicts that global demand for energy will flatten in 2030, then steadily decline over the next two decades, thanks to step-changes in energy efficiency. The fossil fuel share of the world’s primary energy mix will reduce from 81% currently to 52% in 2050.

Demand for oil will peak in 2022, driven by expectations for a surge in prominence of light electric vehicles, accounting for 50% of new car sales globally by 2035. However, the stage is set for gas to become the largest single source of energy towards 2050, and the last of the fossil fuels to experience peak demand, which DNV GL expects will occur in 2035.

Gas will continue to play a key role alongside renewables in helping to meet future, lower-carbon, energy requirements. Major oil companies intend to increase the share of gas in their reserves, and DNV GL expect an accelerated shift by 2022 as they decarbonize business portfolios.

While demand for hydrocarbons will peak over the next two decades, significant investment will be needed to add new oil and gas production capacity and operate existing assets safely and sustainably. However, the results of DNV GL’s model reinforce the need to maintain strict cost efficiency in order to achieve the margins necessary for future capital and operational expenditure.

6 2Elisabeth Trstad 3Elisabeth Tørstad, CEO, DNV GL – Oil & Gas

“We have seen impressive and important innovative efforts across the energy industry, resulting in cost saving and efficiency gains. The oil and gas industry must continue on a path of strict cost control to stay relevant. Coming from a tradition of technological achievements, and having the advantage of existing infrastructure and value chains, this industry has the potential to continue to contribute to energy security and shape our energy future,” said Elisabeth Tørstad, CEO, DNV GL – Oil & Gas.

“Increased digitalization, standardization and remote or autonomous operations will play a central role in achieving long-term cost savings and improving the oil and gas industry’s carbon footprint. We also expect the industry to turn to innovations in facility design, operating models and contracting strategies,” Tørstad added.

DNV GL has published a suite of reports on the Energy Transition Outlook, which are available to download free of charge. The main ETO report covers the transition of the entire energy mix to 2050. Three sector-specific supplements will accompany this: an oil and gas supplement and a renewable, power and energy supplement are both available this week. A maritime supplement will be available later this year. DNV GL’s oil and gas supplement considers some of the key trends identified by the company’s model across the sector’s value chain, and explores their implications.

Download a complimentary copy.

Kosmos Energy Successfully Completes Tortue Drill Stem Test

4 2KosmosEnergy copyKosmos Energy (NYSE: KOS) announces that it has successfully completed the drill stem test (DST) of the Tortue-1 well, demonstrating that the Tortue field is a world-class resource and confirming key development parameters including well deliverability, reservoir connectivity, and fluid composition.

4 1GreaterTortueMap testThe Tortue-1 well flowed at a sustained, equipment-constrained rate of approximately 60 million cubic feet per day (MMcf/d) during the main, extended flow period, with minimal pressure drawdown, providing confidence in well designs that are each capable of producing approximately 200 MMcf/d. The DST results confirmed a connected volume per well consistent with the current development scheme, which together with the high well rate is expected to result in a low number of development wells compared to equivalent schemes. Initial analysis of fluid samples collected during the test indicate Tortue gas is well suited for liquefaction given low levels of liquids and minimal impurities. Data acquired from the DST will be used to further optimize field development and to refine process design parameters critical to the front-end engineering and design (FEED) process anticipated to begin later this year.

“The positive results from the DST confirm that the Tortue field is a world-class resource and validates the assumptions that underpin our development concept,” said Andrew G. Inglis, chairman and chief executive officer. “The combination of high well rates, large connected volume per well together with a gas well-suited for liquefaction is why we believe Tortue is one of the lowest cost pre-FID greenfield LNG projects. The Kosmos BP partnership remains aligned on delivering a final investment decision for the project in 2018 and first gas in 2021.”

The Tortue-1 well is located in water depths of approximately 2,700 meters offshore Mauritania. The DST was conducted by the Atwood Achiever drillship, which has now mobilized to the Hippocampe prospect in Block C-8 offshore Mauritania to begin exploration drilling operations. Kosmos is exploration operator of Block C-8 with a 28% participating interest. BP is named operator with a 62% participating interest, and Societe Mauritanienne des Hydrocarbures et de Patrimoine Minier (“SMHPM”) has a 10% participating interest.

John Crane Asset Management Solutions Wins North Sea Maintenance Build Contract with Maersk Oil

5John Crane Maersk contractJohn Crane Asset Management Solutions has secured a contract to supply Maersk Oil with data services to support the planned maintenance strategy at one of the largest new developments in the UK North Sea.

At the Culzean field, John Crane Asset Management Solutions will provide data build services as well as establishing a maintenance plan for all topside equipment. A Detailed Criticality Analysis and Maintenance Definition (DCAMD) strategy will be developed to cover high-criticality equipment with generic procedures being used for non-critical appliances.

The Culzean gas condensate field has resources estimated at 250-300 million barrels of oil equivalent. Located in the Central North Sea, the high pressure, high temperature field is expected to commence production in 2019 and supply enough gas to meet 5% of total UK demand at its peak in 2020/21.

James Reid, Project Manager at John Crane Asset Management Services, said: “We are pleased to deliver a smooth planned maintenance programme for Maersk Oil that combines both preventative and condition based maintenance.”

In June, John Crane Asset Management Solutions announced it had been awarded a five-year contract to provide condition based maintenance services with another major operator in the UK North Sea.

In October 2015, John Crane Group announced it had acquired Aberdeen independent Asset Management business, XPD8 Solutions Ltd. Both contracts will enable the strengthened John Crane Asset Management Solutions team to use their expertise to fully meet the customer needs and further increase their asset performance.

John Morrison, Managing Director at John Crane Asset Management Solutions, said: “To be involved in supporting the maintenance strategy on one of the most significant projects on the UK Continental Shelf in recent years is fantastic news for the company. Having an effective strategy will stand the development in good stead for years to come, giving those in charge the confidence that their topside equipment will perform reliably and efficiently.”

John Crane Asset Management Solutions is a trading name of XPD8 Solutions Limited, which is part of John Crane, itself a division of the global technology company Smiths Group Plc.

Shell Starts Production at Gbaran-Ubie Phase 2 in Nigeria

The Shell Petroleum Development Company of Nigeria Ltd joint venture has started production at Gbaran-Ubie Phase 2, a key project in Nigeria’s Niger Delta region.

Phase 2 follows the success of the first phase of the Gbaran-Ubie integrated oil and gas development, which was commissioned in June 2010. Peak production of around 175,000 barrels of oil equivalent (boe) per day is expected in 2019.

10gbaran ubie projectPhoto credit: Shell

“Today’s announcement is a positive step for Shell’s global gas portfolio,” said Andy Brown, Shell’s Upstream Director. “It is also good news for Nigeria as gas from Gbaran-Ubie Phase 2 will strengthen supply to the domestic market and maintain supply to the export market.”

Eighteen wells have been drilled and a new pipeline constructed between Kolo Creek and Soku which connects the existing Gbaran-Ubie central processing facility to the Soku non-associated gas plant. First gas flowed from the wells in March 2016, with the facilities coming on stream in July 2017.

The Shell Petroleum Development Company (SPDC) is the operator of a joint venture between the government-owned Nigerian National Petroleum Corporation (NNPC, 55%), SPDC (30%), Total E&P Nigeria Ltd (10%) and ENI subsidiary Nigerian Agip Oil Company Limited (5%).

  • SPDC is the largest Shell company in Nigeria and produced the country’s first commercial oil exports in 1958.
  • A detailed breakdown of the peak production of Gbaran-Ubie Phase 2 is approximately 864 million standard cubic feet of gas per day (MMscf/d) and 26,000 barrels of condensate per

ENSCO DS-7 Contracted to Noble Energy in the Mediterranean Sea

2ENSCO DS 7Ensco plc (NYSE: ESV) announces that ultra-deepwater drillship ENSCO DS-7 has been awarded a contract by Noble Energy to drill two wells and complete four production wells at the Leviathan field development in the Mediterranean Sea. This contract is expected to commence in March 2018 and be completed in December 2018. The contract also includes four one-well priced customer options that if fully exercised would extend the contract into 2020.

Chief Executive Officer and President Carl Trowell said, “We are pleased to announce another significant contract award for one of our high-specification assets – our fourth drillship contract awarded during the third quarter. This award and our other recent contract wins validate our strategy, increase contracted revenue backlog and advance our efforts to drive growth and value creation for all Ensco shareholders.”

Mr. Trowell concluded, “As contracting activity continues to increase, customers are demonstrating a clear preference for established offshore drillers such as Ensco with operational track records, financial strength, superior technology and broad geographic reach. Our recent contract awards underscore that there is strong customer demand for the type of high-specification assets that will be added to Ensco’s fleet through our pending acquisition of Atwood, which will create a leading global offshore drilling company and better position us as the market recovery cycle unfolds.”

ENSCO DS-7 will be upgraded with a second blowout preventer. This upgrade, combined with the rig’s dual derricks and other technical specifications, will make it one of the most capable assets in the global fleet. As previously announced, this upgrade is expected to cost less than $10 million since it will utilize a blowout preventer currently in inventory. Following its upgrade, ENSCO DS-7 will mobilize to the Mediterranean Sea to begin its contract with Noble Energy.