Statoil has completed a farm-in transaction with ExxonMobil Exploration and Production South Africa Limited (ExxonMobil), acquiring a 35 percent interest in the ER 12/3/154 Tugela South Exploration Right.

The remaining interests are held by the operator ExxonMobil (40%) and co-venturer Impact Africa Limited (Impact Africa) (25%).

“This opportunity is in line with Statoil’s exploration strategy of access at scale. It represents access into a frontier basin where we believe we see indications of an active petroleum system and which has impact potential,” says Nick Maden, senior vice president for Statoil's exploration activities in the Western Hemisphere.

“The position strengthens and increases the optionality in Statoil’s long-term international portfolio. We look forward to working with ExxonMobil, Impact Africa and the South African government to explore for oil and gas in this new area for Statoil,” says Maden.

The Tugela South Exploration Right covers an area of approximately 9,054 square kilometers. It is located offshore eastern South Africa in water depths up to 1,800 meters.

The farm-in represents a country entry for Statoil into South Africa. Statoil enters in an early exploration phase with a step-wise exploration program. Work commitments between 2015 and 2017 include the acquisition of 1,000 square kilometers of 3D seismic data and geology and geophysics (G&G) studies. There are no commitment wells during this exploration period.

The information obtained from the initial studies and seismic survey will form the decision basis for the co-venturers’ next steps in the Exploration Right.

Statoil has decided to cancel the contract with Songa Trym, four months before the expiration of contract on 4 March 2016.

Songa Trym (Photo: Kjetil Larsen - Statoil)

Statoil has previously notified Songa Offshore that the rig would be suspended for a period, and Statoil has tried to find other assignments for the rig after the suspension period and up to the expiration of contract.

“We informed the supplier earlier in October about suspending the contract after the rig has completed the drilling operation on the Tavros well on the Visund field. Statoil has hoped for further activity in the remaining contract period, but we now realize that we must cancel the contract, as we have not succeeded in finding more assignments. We regret that we need to cancel the contract before it expires,” says Tore Aarreberg, head of rig procurements in Statoil.

The Norwegian Petroleum Directorate wants unmanned wellhead platforms to be considered more often as an alternative to subsea tie-back in connection with development decisions.

A new study will look into the benefits and disadvantages of wellhead platforms.

The unmanned wellhead platform Tambar (BP) in the North Sea.
(Photo: BP)

"The main argument in favor of unmanned wellhead platforms as a concept, is that this could be an efficient development solution in terms of both cost and production. In fact, it is just as functional and robust as a subsea development, and it is also more accessible for inspection and maintenance," says Niels Erik Hald, principal engineer in the Norwegian Petroleum Directorate.

An unmanned wellhead platform is a facility with a fixed substructure installed on the seabed, with dry wellheads located on the platform deck. The concept is an alternative to subsea wells where the wellheads are placed on the seabed. There are various types of unmanned wellhead platforms – from simple facilities to more advanced solutions including e.g. process equipment. Some can be entered from vessels, while others have bridges or helicopter decks.

The Norwegian Petroleum Directorate has commissioned a study with the objective of gaining further knowledge about the different types of unmanned wellhead platforms. The plan is for the study, to be performed by Rambøll Oil & Gas, to be submitted to the authorities towards the end of December of this year.

The API Director of Upstream Erik Milito released the following statement regarding the Obama administration’s decision to deny Arctic offshore development extension requests and scheduled 2016 and 2017 Arctic lease sales:

“Our industry’s strong interest in developing our country’s vast offshore oil and natural gas resources in Alaska was undermined years ago when the administration began implementing a system of regulatory and permitting unpredictability and uncertainty.

“Investment decisions have been directly thwarted by the policy decisions of the administration related to Alaskan Outer Continental Shelf development, and lease extensions are clearly justified under the circumstances. And while it is not surprising that Interior canceled the remaining lease sales because there was an absence of nominations, it is the significant regulatory uncertainty that has created the reluctance on the part of our industry. Still, America’s oil and natural gas industry remains firmly committed to the long-term development of offshore Alaska resources.

“Arctic oil and natural gas represent incredible potential for American energy security, jobs and revenue for the government. Access to the region’s oil and natural gas resources will remain necessary to provide energy supplies to meet the world’s growing demand and vital to keeping America’s status as a world leader in energy.”

API represents all segments of America’s oil and natural gas industry. Its more than 625 members produce, process, and distribute most of the nation’s energy. The industry also supports 9.8 million U.S. jobs and 8 percent of the U.S. economy.

CGG announces that it has been appointed as technical consultant by the Gabonese Republic’s Ministry of Petroleum and Hydrocarbons to help with the promotion of its 11th Licensing Round focusing on five highly prospective deepwater blocks.

The round was formally opened on 27th October 2015 by His Excellency, Minister for Petroleum and Hydrocarbons, Mr. Etienne Dieudonné Ngoubou, at this week’s 22nd Africa Oil Week conference in Cape Town South Africa. The round will then be promoted by a series of road shows starting in Libreville on 24th November, followed by Paris on 26th November, Singapore on 30th November and Houston on 3rd December 2015. A delegation from the Direction Generale des Hydrocarbures (DGH) as well as a technical team from CGG will be attending to answer any questions.

The round will be open for five months starting on 27 October 2015 and bids can be submitted from 15 February 2016 onwards and by no later than 31st March 2016. Prequalification for the bid round will require the purchase of a minimum amount of seismic data.

The deep water of Gabon has significant unexplored potential within a structurally complex setting, particularly in the pre-salt section. In response to the exploration challenges, CGG has been appointed to advise the Gabonese Republic on the promotion of the 11th Licensing round and has worked directly with the Ministry to acquire over 25,000 km2 of new 3D BroadSeisTM multi-client seismic data as part of an integrated geoscience program to support it. The new survey will enable better imaging of this exciting and underexplored area, and covers areas downdip and adjacent to recent pre-Aptian salt discoveries, such as Leopard, Diaman, Ruche and Tortue. It will benefit from integrated gravity and magnetic interpretation to enhance the pre-salt imaging and additional, complementary datasets including offshore hydrocarbon seeps and a full geological prospectivity report will be available.

Jean-Georges Malcor, CEO, CGG, said: “Ever since we acquired our first geophysical survey there in 1932, CGG has actively supported Gabon’s development of its natural resources. We are delighted to continue our fruitful cooperation with the Gabonese Republic by offering our full portfolio of Geoscience expertise to help promote the 11th Licensing Round. Given the high quality of the intermediate results we have seen so far from our recent BroadSeis survey, we expect the final results to be a significant resource for clients to de-risk this promising exploration arena. We are pleased to announce that several companies have already pre-committed to the dataset.”

The two new giant compressors that started up on the Troll A platform this month will help increase gas recovery by 83 billion cubic meters. The occasion attracted a platform visit from EEA and EU affairs minister Vidar Helgesen.

“Europe is in a transition phase with regard to both competitiveness and climate. Stable and competitive gas deliveries from the Norwegian continental shelf (NCS) play a key role along these two axes. Higher production and flexibility from the Troll field is therefore good news to both Norway and Europe,” said Helgesen during his visit.

The compressor module before departure from Thailand. (Photo: Aibel)

“This is a new strategic milestone for the Troll field. The compressors are an important investment to ensure sustainable, long-term production and activity on the Norwegian continental shelf (NCS),” says Gunnar Nakken, newly-appointed senior vice president for the operations west cluster.

The compressors ensure a daily export capacity from the Troll field of 120 million standard cubic meters of gas, totaling 30 billion standard cubic meters of gas per year. This is equivalent to the consumption of 10 million households in Europe.

The compressors are an important measure to meet the Troll field's long-term production profile, currently extending to 2063. They are operated by land-based power from Kollsnes west of Bergen, ensuring zero emissions of carbon dioxide and nitrogen oxides from the platform. “This is an important climate contribution from Statoil,” Nakken emphasizes.

During the past 18 months Statoil has started up low-pressure compressors on Troll A, Kvitebjørn, Heidrun, Kristin, Åsgard and Gullfaks, the last two on the seabed. This increases the recovery rate by more than 1.2 billion barrels and extends the life of the installations. The project has extended the expected life of Troll A from 2045 to 2063.

These investments in existing fields give highly profitable barrels. The field recovery increase the compressors provide, 83 billion standard cubic meters of gas or 533 million barrels of oil equivalent, is more than the Aasta Hansteen and Valemon fields combined,” says Nakken.

The main supplier Aibel built the compressor module at its yard in Thailand, the integrated utility (IU) module was prefabricated in Poland and assembled in Haugesund, where the smallest module was also built. The three modules total more than 6,000 tons.

Five new 70-kilometre-long cables have been laid between Troll and land, and a converter station has been built at Kollsnes. On the platform the current is converted back into alternating current. The converters, cables and the compressors' engines have been supplied by ABB.

Leading engineered servicing company for wellbore clean up and abandonment, Coretrax, has successfully completed an extensive three year decommissioning contract with global operator Hess Corporation for the first designated abandonment campaign of its kind. The project began in 2012, involving 30 well abandonments at the FFFA and IVRR fields in the UK North Sea.

As part of this abandonment campaign, Coretrax successfully ran 45 bridge plugs and cement retainers, including some with a drillable brush. Due to extensive section milling operations required on the project, Coretrax provided its BOP cleaning and swarf recovery string to remove swarf from ram cavities and protect the blow out preventer (BOP). In some cases up to 40kgs of swarf was recovered per run.

John Fraser, global business development director of Coretrax, said: “At a time when decommissioning is climbing the agenda within the oil and gas industry, we really valued the opportunity to be part of this successful collaboration with Hess and its contracted partners.

“As part of the project we ran the blow out preventer magnet and jetting sub up to three times after over 30 milling operations and there was virtually no swarf within the cavities, which gave the entire team the confidence to progress to the next stage immediately. Our products were highly successful, and none of our cement plugs had to be re-set.

“As abandonment continues to be a costly and lengthy process, the utilisation of products that offer cost and time efficiency as well as safety benefits, are imperative for efficient and effective decommissioning operations. We are proud to have achieved real success for our client. These results are a real testament to our products, services and team. I believe this project will lead the way for future decommissioning and abandonment projects in the North Sea and beyond.”

Coretrax was established in 2008 to provide a bespoke and tailored service and offers a wide range of downhole tools and services which provide progressive solutions to improve time efficiency, maximise cost reduction, reliability, damage prevention and technological advancement to the global oil and gas industry.

The company currently employs 36 people across its bases in Aberdeen, Dubai, Abu Dhabi, Iraq and Saudi Arabia. This number is projected to increase within the next nine – 12 months due to increased business activity globally.

Norwegian petroleum and other liquids production, which had been declining since 2001, increased in 2014 and will likely continue increasing in 2015. The production growth in 2014 was mainly the result of new fields coming online, but also included a small increase in output from existing fields. Production has continued to grow in the first half of 2015 and is expected to remain relatively stable over the next few years as growth from new fields balances declines from older fields.

Source: U.S. Energy Information Administration, based on Norwegian

Petroleum Directorate Petroleum development projects in the North Sea generally have long lead times, meaning that production from a new field occurs several years after the decision to develop that field. These lead times often increase for projects that are farther north or far from existing infrastructure. The decisions to develop many of the fields now coming online in Norway occurred around 2012, when Brent crude oil prices averaged more than $100 per barrel. The current price is about half that level. In 2014 and the first half of 2015, four new fields with significant volumes of liquids production came online. Another four fields are scheduled to come online in the second half of 2015 and in 2016.

Source: U.S. Energy Information Administration, based on Statistics Norway

Although production in Norway has not yet responded to lower oil prices, investment in Norway's oil and natural gas industry is declining. This decline will likely lead to lower production in the future. Annual growth in total investment slowed to 1% in 2014 after being more than 15% in each of the preceding three years, and investment is expected to decrease in 2015. Currently, funding is being diverted toward the shutdown and removal of equipment at old fields and away from finding and developing new fields. Spending on exploration and field development in the first half of 2015 was 18% lower than in the first half of 2014, while spending on shutdown and removal was more than 70% higher.

Principal contributor: Justine Barden

Source: EIA

Global integrated drilling waste management and environmental services firm, TWMA, has been awarded two major contracts, building on a strong relationship with Maersk Oil North Sea UK (Maersk Oil) spanning more than a decade.

The projects, which are led by an Aberdeen-based team, involve work on the Culzean development – one of the largest gas discoveries in recent years in the UKCS – and the continuation of provision of innovative technology across Maersk Oil’s Central North Sea operations.

To ensure the company continues to offer the best, most cost-effective and safe solutions available to the global oil and gas industry, multi-million pound equipment investments are being made. The new work will also result in the creation of up to 20 new jobs.

TWMA men at work

Neil Potter, Chief Operating Officer at TWMA, said: “We are delighted to have been selected to support Maersk Oil on these projects as they expand their drilling activity within the UK sector of the North Sea.

“Our experienced, skilled team are working closely with Maersk Oil and have been since the award to carry out the pre-fabrication R&D activity needed for the Culzean operations. To date, this has included working on-site in Singapore with rig builder Hercules to develop solutions where we aim to use our proven technical know-how to design, manufacture and install best-in-class technology to handle Maersk Oil’s drilling waste processing requirements.

“By delivering exceptional results that improve operational efficiency while maintaining a quality service over a considerable period of time, we have nurtured a strong working relationship with Maersk Oil. We are delighted to have been awarded a new scope of work on the prestigious, high-profile Culzean development and a renewed agreement for the continuation of our services across Maersk Oil’s Central North Sea projects.

“Despite extremely challenging market conditions, TWMA has maintained high-levels of investment in R&D which is exceptional in the current climate and demonstrates our awareness of the need to continue to build on our strengths and offer the best possible integrated drilling waste management services and environmental solutions.’’

The Culzean project involves TWMA providing drilling waste processing and waste management services for five years with the option of two one-year extensions.

Delivered using a 950kW electric drive within TWMA’s proprietary TCC RotoMill and EfficientC equipment, the Culzean project will also see TWMA recruit up to 20 personnel to support the existing workforce within the engineering, commissioning and operations phase.

The second contract will provide existing drilling waste processing and management services for Maersk Oil’s Central North Sea projects, again utilising the firm’s TCC RotoMill and EfficientC technologies. The new agreement will continue for the next three years, with the option for two one-year extensions.

Through its venture capital arm, Evonik has invested in Airborne Oil & Gas (IJmuiden, Netherlands). The specialty chemicals group now holds a minority interest in the Dutch company. The investment was made jointly with HPE Growth Capital (HPE) and Shell Technology Ventures. The parties have agreed not to disclose the volume of the transaction. Airborne Oil & Gas (AOG) possesses a unique technology for the production of thermoplastic composite pipes for a variety of offshore oil and gas applications.

The current offshore oil & gas infrastructure consists of either rigid steel pipes or so-called flexibles. The latter comprise of multiple layers of steel and polymers. AOG’s thermoplastic composite pipes dispense with steel entirely and are therefore not susceptible to corrosion. They have extremely high mechanical stability but are also flexible. As an added advantage they are lightweight and can be fabricated in lengths of up to 10 kilometers, which means that AOG’s pipes can be installed relatively simply and cost effectively. Rigid steel lines are welded together from segments that are 10-20 meters long, using highly specialized and costly pipelaying vessels.

AOG’s thermoplastic composite pipes are suitable and beneficial for a wide range of offshore applications. A number of operators have qualified AOG’s pipes for offshore oil & gas transport lines, where the benefits of low cost installation and the absence of corrosion offer breakthrough improvements. A considerable amount of the 150,000 to 200,000 km of globally installed transport lines is over 20 years old and in need of replacement, which is an attractive entry point for AOG.

AOG Flowlines ready for shipment to a customer

For Evonik, the oil & gas industry is an attractive growth market and an important innovation field. Furthermore, the company is a market leader in polyamide 12, marketed as VESTAMID®, which is well-proven in pipes for oil and gas production and transport “Airborne Oil & Gas is an excellent strategic match for Evonik,” says Bernhard Mohr, head of Venture Capital at Evonik. “Their unique pipe technology and Evonik's high performance polymer portfolio enable us to develop new solutions for the industry.

“In Evonik we’ve gained a strategic investor with an extensive knowledge of plastics for oil & gas applications,” says Eric van der Meer, CEO of AOG. “We hope this will give us additional impetus to develop our business further.”

Excellent mechanical properties thanks to unidirectional tapes AOG’s pipelines consist of three layers: An inner plastic pipe is covered with a composite of unidirectional tapes, which in turn is sheathed by plastic. Polymers such as polyethylene, polypropylene, polyamide 12 and PEEK can be used. Unidirectional tapes are thin plastic bands in which continuous reinforcing fibers are embedded in parallel alignment. When a number of such bands are stacked vertically at defined angles and fused together, it results in an extremely stable composite.

AOG’s special expertise lies in the design of both the composite material and the finished pipe, for a variety of applications: All the layers are melt-fused to one another inseparably, which explains the outstanding mechanical properties of the pipelines. AOG is therefore regarded as an innovation leader in thermoplastic composite pipelines for oil & gas applications.

As part of its venture capital activities, Evonik plans to invest a total of €100 million in promising start-ups with innovative technologies and in leading specialized venture capital funds. The regional focus is on Europe, the US, and Asia. Evonik currently has holdings in seven start-ups.

The United Arab Emirates (UAE) was the world's sixth-largest oil producer in 2014, and the second-largest producer of petroleum and other liquids in the Organization of the Petroleum Exporting Countries (OPEC), behind only Saudi Arabia. Because the prospects for further oil discoveries in the UAE are low, the UAE is relying on the application of enhanced oil recovery (EOR) techniques in mature oil fields to increase production.

Source: U.S. Energy Information Administration, International Energy Statistics

Using EOR techniques, the government plans to expand production 30% by 2020. EOR is an expensive process, and at current prices, these projects may not be economic. However, despite today's low oil prices, the UAE continues to invest in future production.

The Upper Zakum oilfield is one region that has been targeted for further development. The field is the second-largest offshore oilfield and fourth-largest oilfield in the world, and it currently produces about 590,000 barrels per day (b/d). In July 2012, the Zakum Development Company awarded an $800 million engineering, procurement, and construction contract to Abu Dhabi's National Petroleum Construction Company, with the goal of expanding oil production at the Upper Zakum field to 750,000 b/d by 2016. Production from the Lower Zakum field should also increase, with oil production eventually reaching 425,000 b/d, an increase from the current level of 345,000 b/d.

The UAE produced 1.9 trillion cubic feet (Tcf) of natural gas in 2013. A top-20 global natural gas producer, the UAE also holds the seventh-largest proved reserves of natural gas in the world, at slightly more than 215 Tcf. Despite its large reserves, the UAE became a net importer of natural gas in 2008 as a result of two things: the UAE reinjected approximately 30% of gross natural gas production in 2012 into its oil fields as part of EOR techniques, and the country's rapidly expanding electricity grid relies on electricity from natural gas-fired facilities.

Source: U.S. Energy Information Administration, International Energy Statistics

To help meet growing internal natural gas demand, the UAE has increased imports from Qatar and plans to increase domestic natural gas production. However, the UAE's natural gas has a relatively high sulfur content that makes it difficult to process, making it hard for the country to develop its extensive reserves. Advances in technology and growing demand have made the UAE's reserves an economic alternative to imports from Qatar, and UAE has several ongoing projects that will increase the country's production in coming years.

The UAE has also announced its intention to expand non-oil energy assets, in an attempt to reduce reliance on natural gas for power. For more analysis of the UAE's energy sector, see EIA's Country Analysis Brief on the United Arab Emirates.

Principal contributors: Alex Wood, Kelsey Tamborrino

Source: www.eia.gov

DNV GL has secured a contract to provide in-service verification and classification services to a range of facilities at the Ichthys LNG project in Australia.

The contract marks INPEX’s commitment to continue working with DNV GL as it prepares to transition from the project execution phase to the operational phase of the mega project. DNV GL has provided vendor inspection, verification and offshore classification support to the USD 34 billion venture since 2012.

This latest contract will see DNV GL continue its expert support to the project as it transitions into operation in 2017. The primary scope of work includes in-service verification of the Ichthys facilities; the central processing facility (CPF), floating, production, storage and offloading (FPSO), subsea production system, gas export pipeline, onshore combined cycle power plant and onshore LNG plant. DNV GL will also provide in-service classification of the CPF and the FPSO hulls.

Richard Palmer, (photo) Regional Manager for Australia, New Zealand and Papa New Guinea, DNV GL, Oil & Gas said: “The transfer of the Ichthys LNG project to operation will mark a significant moment in Australia’s oil and gas industry. We have learned a great deal from supporting Ichthys and a range of mega project operators in Australia as the country moves closer to becoming the world’s largest LNG producer. We look forward to applying our experience in Australia and gas projects in other countries to support the safe and efficient operations from the project’s first day in service.”

Located 220 kilometers offshore Western Australia, the Ichthys field is situated on block WA-285-P in the Browse Basin, Timor Sea. This gas and condensate field lies at a water depth of 250m, and represents the largest discovery of hydrocarbon liquids in Australia in 40 years. The Ichthys LNG project is ranked among the most significant oil and gas projects in the world. It involves some of the largest offshore facilities in the industry, a state-of-the-art onshore processing facility and an 889 km pipeline that will unite them for an operational life of at least 40 years.

First production is scheduled for 2017 and the project is expected to produce 8.9 million tons of LNG and 1.6 million tons of LPG per annum, along with more than 100,000 barrels of condensate per day at peak. Gas and condensate from the Ichthys field will be exported to onshore facilities for processing near Darwin via the 889 km pipeline. Most condensate will be directly shipped to global markets from an FPSO facility permanently moored near the Ichthys field in the Browse Basin.

Brazil will lead global growth in the Floating Production, Storage and Offloading vessel (FPSO) industry despite the country’s national oil company, Petrobras, recently facing allegations of corruption, says research and consulting firm GlobalData.

Petrobras registered its biggest ever loss in 2014, partly due to the write-down resulting from the corruption scandal, which in turn resulted in spending cuts on its future projects.

GlobalData’s report* states that despite the challenges, Brazil has spearheaded recent growth in the global FPSO industry, with the country deploying 17 FPSOs between 2009 and 2014.

Adrian Lara, GlobalData’s Senior Upstream Analyst, says: “Petrobras’ strategic plans in 2013 and 2014 had almost 40 FPSOs deployed in Brazil through 2020. Based on the company’s latest plan, there are currently seven FPSOs still on time for delivery, whereas 11 have had their delivery date moved back a couple years and about 12 FPSOs are now expected after 2020.”

While Petrobras is planning to spend $108.6 billion, or 83% of its total capital expenditure, on the exploration and production sector as part of its 2015-2019 Business and Management Plan, corruption allegations have hampered its ability to execute the planned projects, including those involving FPSOs.

Lara comments: “Planned projects have been affected in large part by the ongoing investigation into corruption. In particular, domestic shipyards have been hit hard.

“Sete Brasil was set to build 29 offshore rigs for Petrobras but has scaled back to 15. The uncertainty around when and how many rigs will be available will have a knock-on effect on FPSO delivery dates.”

Despite these challenges, Petrobras plans to prioritize oil production projects focusing on sub-salt resources and will deploy and operate a higher number of FPSOs than any other company in the world by 2019, according to the report.

Matthew Jurecky, GlobalData’s Head of Oil & Gas Research and Consulting, concludes: “FPSOs are an ideal development option for offshore oil fields given current uncertain oil prices, as they can easily be scaled up if the market improves, or scaled down to maintain economic viability despite low oil prices.

“For example, the Sea Lion development in the Falkland Islands is progressing through reducing the initial scope despite being a frontier project.”

*Global FPSO Industry Outlook – Brazil Leads Record FPSO Deployments Despite Deteriorated Project Economics

The Bureau of Safety and Environmental Enforcement (BSEE) and Mexico’s National Agency for Industrial Safety and Environmental Protection of the Hydrocarbons Sector (ASEA) have signed a letter of intent to strengthen cooperation, coordination and information sharing related to the development, oversight, and enforcement of safety and environmental regulations for development of offshore hydrocarbon resources.

The ceremony of signature was conducted by BSEE Director Brian Salerno and ASEA’s Executive Director, Carlos de Regules Ruiz-Funes. The signing took place after the closing of this year’s International Regulators’ Forum (IRF) Offshore Safety Conference in Washington, following on their earlier meeting in September. Mexico and the U.S. have a long history of mutually beneficial cooperation on conservation, management and sustainable development of natural resources. This continued cooperation between BSEE and ASEA is in keeping with broader bilateral efforts for cooperation in the environmental and hydrocarbons sector between the two countries. The letter of intent lays out areas in which the two agencies may coordinate, to include:

Periodic information and experience exchanges;

Organization of bilateral events and visits of delegations; Participation as observers in activities related to their respective authorities;

Conducting of joint studies and research where appropriate; Training of staff; and

Further cooperation by way of any other terms BSEE and ASEA may hereafter mutually determine.

ASEA was formally established on March 2, 2015 and is responsible for the regulation and oversight of all oil and gas production, as well as industrial safety and environmental protection in Mexico. The Mexican agency works with the goal of providing certainty to both investors and society. ASEA’s vision is based on adherence to international standards and best practices in regulation across the world, and it carries out its international collaboration with the intent of implementing the best technical processes in the newly established Mexican hydrocarbon sector.

With ExxonMobil reported to be moving the Liza discovery in deepwater Guyana into pre-Front-End Engineering Design (FEED) less than five months after confirming the find, the project has the potential to yield significant returns for investors, according to analysts with research and consulting firm GlobalData.

The company’s latest analysis states that a Floating, Production Storage and Offloading vessel (FPSO) development at the field would return above 19.8% in a flat-oil-price scenario of US$61.68 per barrel (bbl).

Furthermore, Anna Belova, Ph.D., GlobalData’s Senior Upstream Analyst, explains: “While there is risk around the assumed initial production rates of 20,000 barrels per day (bd) per development well, there is upside in additional cost efficiencies as low oil prices have been accompanied with decreases in FPSO leasing terms and drillship dayrates.

“Additionally, the 201 million barrels (mmbbl) recoverable reserves estimate falls on the lower end of 700 mmbbl of oil reserve suggestions from Guyana’s minister of governance. Higher reserve scenarios, recovering upward of 600 mmbbl, have an Internal Rate of Return (IRR) over 35% while capturing the economies of scale realized with FPSO developments.”

While the cost metrics for the Liza scenarios are consistent with other global developments with a leased FPSO production concept, the economic metrics are more favorable than global averages due to the competitiveness of the Guyanese Production Sharing Agreement (PSA) regime.

Matthew Jurecky, GlobalData’s Head of Oil & Gas Research and Consulting, says the project will benefit from the prevailing low-cost environment.

Jurecky comments: “The Liza project will also be well-placed to benefit from any uplift in oil prices post-development. Its commercial success could redefine the basin as a global deepwater production player.”

Key findings from this year’s Oil and Gas UK activity survey state that the annual average expected spend on decommissioning on the UK Continental Shelf (UKCS) over the second half of the decade has increased to £1.8billion from £1.5billion. With the low oil price, rising costs and ageing infrastructure, the huge task of removing redundant installations from the North Sea is gathering momentum.

With the pace of decommissioning activity accelerating, Mark Walker, Client Partner at Optimus Seventh Generation, a behavioral change consultancy, discusses the vital need for leadership to help ensure projects are as safe as possible.

With over 600 offshore oil and gas installations in the North Sea, of various sizes, and more than 10,000km of pipelines, wells and accumulations of drill cuttings, the biggest concern is how the infrastructure can be removed in a safe and cost effective manner.

In high hazard industries, and specifically the energy sector, we talk about safety culture and understand the importance of it but do not always understand how we can assess it and, therefore, how we can improve it.

Optimus Seventh Generation has developed an approach to safety culture assessment, drawing upon High Reliability Organisation (HRO) principles, seeking a diagnostic as a means of providing the assurance that things are as they should be. They ask the diagnostic to identify the most significant safety issues confronting the organization or site, gathering evidence of safety culture by a combination of observation and audit of work products and perception-based surveys and interviews.

The diagnostic seeks to establish the aspects of resilience that are present, i.e:

• The ability of the business to stop something bad from happening
• The ability to stop something bad becoming worse
• The ability to recover something bad once it has happened

Resilience is assured not just by the behaviors of people but also by the consistent application of processes and procedures as well as the functionality of safety critical equipment.

The diagnostic is also looking for what barriers there are and how many are in place, with the use of personal protective equipment (PPE) at one end of the scale as the weakest defence and the elimination of hazards at the other end of the scale as the strongest. Between these we would hope to see others that give the business the ability to detect hazards by fixed detection systems, hazard spotting and management processes, adequate planning and active monitoring.

The glue that would hold all of the above together is the leadership.

Many operators are seeking less expensive alternatives to deliver decommissioning work, but want to ensure that safety remains a priority. However there are needs to be the acknowledgement that there may be gaps in their safety culture that should be addressed to deliver successful, safe projects. Optimus Seventh Generation imparts the skills and capabilities to deliver incident-free projects by motivating the workforce to follow the rules and to intervene, while educating leaders so they understand the influence they have over their teams.

When we deploy our leadership and workplace safety coaches in the field, our clients and their workforce often ask; what does an authentic leader look like? How will we know them when we see them? Our coaches encourage our clients to turn that statement around and ask; what do followers want? One of the principal roles of a leader is to create an engaged workforce or, more simply expressed, to create followers. Without an engaged workforce, there is no relationship and no leadership.

At Optimus Seventh Generation, we have recognized that this poses challenges for our industry - to incorporate authenticity as an assessment criterion for our current and future leaders during selection and to re-design our leadership training to establish authenticity as an outcome of such programs.

Working with safety leaders in individual companies or in our open course – Leading Safety Performance ™ – we have witnessed many “light bulb moments” when leaders have realised what skills they require to be authentic and have left with a strong desire to be that authentic person and to lead based on their values.

It is clear that those organisations whose culture is underpinned by strong values will create a workforce willing to engage with new safety processes and will therefore be best equipped to protect both their people and their assets. If these values have been socialised within the business and are used by leaders at all levels in an authentic manner then the safety culture in our industry will create the resilience it needs.

Case Study

In May 2015, Optimus Seventh Generation was awarded its first decommissioning contract with a major North Sea operator to supply induction training, through its program Induction Plus™ and back to back health and safety advisors to support the safe decommissioning of a floating production, storage and offloading vessel in the North Sea.

When embedded by the presence of Optimus safety advisers, Induction Plus™ helps influence the decision-making of all involved, ensuring rules are being followed and incident-free projects are being delivered.

The four-hour induction is aimed at projects experiencing a large influx of new, often subcontracted, labour during decommissioning and construction projects or shutdowns. It educates the attendees on the company’s expectations with respect to compliance with the company’s safety rules, alongside a motivational element to engage the project team with ‘why’ compliance is important and how they can raise their awareness of the hazards specific to the asset.

Optimus worked with leaders to educate them with the understanding that their decision making is key in the project’s success, increasing workforce engagement, which helps ensure that the work force remained focused and motivated creating a safe environment.

The work scope is based in the North Sea, where fields continue to provide opportunity in the current climate with collaboration being key between operators, the supply chain and, more pertinent than ever right now, specialist safety professionals.

This is an exciting project for the team, and the North Sea operator will be able to take advantage of Optimus Seventh Generations’ 12 years’ of providing specialists safety support services to the energy sector to decommission the floating production, storage and offloading vessel, in a safe and environmentally responsible way.