Wednesday, 24 January 2018

United Oil & Gas Plc updates on the Podere Maiar well

United Oil & Gas Plc updates on the Podere Maiar well

United Oil & Gas Plc the London Stock Exchange listed oil and gas exploration and development company, notes that Po Valley Energy Limited, the operator on the Podere Maiar 1 well on the Selva Gas Field in the Podere Gallina licence has made an announcement relating to significant gas flows.

Strong gas flows on test have confirmed a significant commercial discovery for United Oil & Gas Plc at its Selva gas field in northern Italy.

The Company announces today that PVE have reported that the strong gas flows have resulted from successful flow testing of the recently drilled Podere Maiar 1dir exploration well on the Selva gas field within the Podere Gallina Exploration licence in northern Italy (PVE 63% Operator; United Oil & Gas Plc 20%; Prospex Oil & Gas Plc 17%).

That drilling program intersected two identified gas reservoirs, C1 and C2, in the Medium-Upper Pliocene sands of the Porto Garibaldi Formation.

The thickest level C2 (net pay 25.5 m) reported a peak flow rate of 148,136 scm/day on a 3/8-inch choke and a pressure differential of 11 bar with no water production. Pressure recovery to formation pressure occurred in 2 minutes. The higher level C1 (net pay 15.5 m) also reported strong flow test results with a peak flow rate of 129,658 scm/day on a 3/8-inch choke with good pressure recovery (about 12 minutes).

The strong flow rates from two gas-bearing levels 99.1% methane gas content and the well’s 600m proximity to the Italian national gas grid pipeline connection, clearly make the Podere Maiar 1 dir well a commercial discovery. As Operator, Po Valley will now prepare and submit a production concession application to the Italian Ministry, in the first half of 2018. The Ministry has been formally informed of the discovery and officials attended the successful test.

United Oil & Gas Plc CEO Brian Larkin said: “We are delighted to announce a commercial discovery on our Italian well. This result is a significant development milestone for our business. The flow test results exceeded our pre-drill expectations and we are now on the road to production. Po Valley will now incorporate this well-test data into the development plan and submit it as part of the application to the Italian authorities to convert a portion of the existing “Exploration Licence” into an “Exploitation Licence.”

“We will continue to keep markets updated on potential deal flow along with operational portfolio developments.”

Petrofac secures key North Sea contract

Petrofac secures key North Sea contract

Petrofac’s Engineering and Production Services (EPS) division has been awarded a new Offshore Manning Services contract by Chevron North Sea Limited (Chevron).

The three-year award, which came into effect last week, will involve the provision of Operations, Maintenance and Construction personnel across five of Chevron’s North Sea assets – the Captain Wellhead Protector Platform, Captain Floating Production Storage and Offloading vessel, Alba North platform, Alba Floating Storage Unit and the Erskine platform. Around 85 personnel currently supporting these assets will transfer to Petrofac from multiple organisations at the end of a transition period.

The contract builds upon Petrofac’s existing relationship with Chevron in the UKCS where it currently provides Engineering and Construction Services.

As part of this new scope, Petrofac will support and deploy offshore personnel via its dedicated 24/7 Operations Hub, through which all of its labour supply contracts are managed. The Hub offers the flexibility of shared resources across contracts, enabling fluctuating client requirements to be managed in a flexible, cost-effective way.

Dave Blackburn, Senior Vice President, EPS West, said: “We are delighted to have secured this new scope with Chevron in support of its North Sea business. Our offshore labour supply expertise is strong and assured. This award is a testament to our ability to provide a tailored, scalable approach to manning services, in pursuit of efficiency.

“We look forward to deploying our expertise and working collaboratively with Chevron and our new team members to effect a safe and seamless transition to operations across these five assets.”

Mark Tool and Elite Elastomers form MTE joint venture

Mark Tool and Elite Elastomers form MTE joint venture

Mark Tool and Elite Elastomers have entered into a joint venture focused on the research, development and end-use application for complete elastomeric subsea high-temperature thermal insulation systems. The systems can be installed via three methods: S-Lay, J-Lay and Reel-Lay. The newly formed company has been named MTE, representing the combined strengths of Mark Tool and Elite Elastomers.

MTE will build on Elite Elastomers’ elastomeric material research and development innovations and Mark Tool’s application and manufacturing technology. MTE, which will initially focus on the Gulf of Mexico, will enable the two companies to grow within the field of high temperature subsea thermal insulation systems while offering complete turn-key solutions. 

Jerome Hebert, Mark Tool and MTE owner, commented, “We are excited to partner with Elite Elastomers to develop a new, complete, elastomeric solution system for the subsea thermal insulation market. We look forward to combining our capabilities and technologies to deliver innovation in the end-use application. We are excited about the state-of-the-art production capabilities this new chapter will bring, as it will allow us to provide our customers with an insulation system from the splash zone to the sea floor.”

Steve Glidewell, president, Elite Elastomers and owner of MTE, said, “We are thrilled to have established this joint venture and look forward to combining our efforts with the Mark Tool team. MTE’s product is unique in the market. It is the only insulating material capable of operating at 350 degrees Fahrenheit while capable of being deployed using the J-Lay, S-Lay and Reel-Lay methods.”

The joint venture team will be formed from current Mark Tool and Elite Elastomers employees and will be located in Louisiana and Mississippi in the U.S.

Maersk Discoverer drills in shallow waters

Maersk Discoverer drills in shallow waters

Maersk Discoverer moved the boundaries for drilling in shallow waters when successful drilling operations commenced in 285 meters water depth. This is the shallowest water drilling operation in Dynamic Positioning mode ever conducted for both Maersk Drilling and for client BP and constitutes another operational highlight for Maersk Drilling.

“Well done to everyone involved with this operation,” says Angela Durkin, COO of Maersk Drilling. “This is another example of achieving operational excellence by working together across departments within Maersk Drilling.”

In 2015, BP asked Maersk Drilling if it was possible for Maersk Discoverer to drill a well in only 408-meter water depth. Normally, Maersk Drilling’s Deepwater D rigs are designed to operate in water depths as shallow as 460 meters and as deep as 3050 meters in Dynamic Positioning mode.

The gain for the client was that it would save costs and rig time associated with mooring. After a suitable risk assessment, the well was safely and efficiently drilled, completing the 408-meter operation.

After this success, BP returned with an even greater challenge: Drill a well in 285-meter water depth in Dynamic Positioning mode.

“Initially, it seemed too great a challenge,” says Allan McColl, Rig Leader on Maersk Discoverer. “It was paramount that we ensured safe operations, even in such shallow waters.”

To assess the risk of the operation, Mr McColl and his local Cairo rig team enlisted the support of Technical Organisation. “After working closely with our Technical Organisation, we were able to return to the customer with the good news that we could, in fact, drill the well.”

But then the client added another challenge: Drilling in Dynamic Positioning mode in 285-meter water depth with a window of time that covered the highest number of months possible.

With further TO support, and with a detailed analysis of conditions, it was established that drilling operations would be possible in the months of May through October. To verify this conclusion, a major risk assessment, facilitated by the TO Technical Safety Department, was begun. “In the end,” says Mr McColl, “the proper risk management steps ensured us of a successful outcome.”

The operation can now report that the well has been successfully drilled with no non-productive time associated with rig positioning. The rig left location on 15 October and moved on to drill in comparatively deep water, with a depth of 388 meters.

“But the story does not quite end there,” says Mr McColl, and stresses the importance of the money saved for the client. “We have saved our customer time and money by operating in Dynamic Positioning mode, compared to mooring the rig to drill and run completions on three wells. That is something we can be proud of. This cooperation has moved boundaries within our business – and, on top of that, produced a happy customer.”

ADNOC to expand carbon capture, use and storage technology

ADNOC to expand carbon capture, use and storage technology 

The Abu Dhabi National Oil Company (ADNOC) is planning to significantly expand its use of Carbon Capture, Use and Storage (CCUS) technology to meet a six-fold increase in the utilisation of CO², for Enhanced Oil Recovery (EOR), over the next 10 years. The volume of the greenhouse gas safely locked away underground will be equivalent to the CO² emitted by more than one million motor vehicles each day.

To meet the increased demand for CO², which will be injected into Abu Dhabi’s maturing oil reservoirs, ADNOC has drawn up ambitious plans to capture the greenhouse gas from its own operations. ADNOC aspires to achieve up to 70% ultimate oil recovery rate from its reservoirs, which is twice as much as the global average, applying conventional recovery methods.

To date, ADNOC has stored approximately 240,000 metric tons of CO², collected from Emirates Steel Industries (ESI), by injecting it into its reservoirs at Rumaitha and Bab oilfields to bolster oil recovery. 

Starting in 2021, ADNOC will gradually increase the utilisation of CO², expecting to reach 250 million standard cubic feet per day (MMscfd) by 2027 by capturing additional CO² from its gas processing plants and injecting it into different onshore oil fields.

Abdulmunim Saif Al Kindy, Director of ADNOC’s Upstream Directorate and Chairman of Al Reyadah said: “As we push forward plans to create value by maximising oil recovery over the lifetime of our fields, we will increasingly utilise a range of Enhanced Oil Recovery technologies, of which carbon capture, use and storage is not only good for the environment but also makes sound business sense.

“Replacing rich gas with CO² injection into ADNOC’s maturing fields will allow the more productive use of valuable clean-burning natural gas, whether for power generation, desalination or as petrochemicals’ feedstock. This is a prime example of how clean technology can be integrated with traditional energy to optimise resources and reduce the environmental footprint.” 

In the oil industry, CCUS technology works in three stages. Carbon dioxide is first captured on site, then it is compressed and dehydrated. Finally, it is transported via a pipeline for injection into oilfields, where it can be leveraged to enhance oil recovery. Using primary and secondary (waterflood) recovery techniques, between 30-35% of oil are recovered on a global average. Including waterflood, ADNOC achieves up to 50% recovery rate from its fields. EOR techniques, such as the use of CO² and CCUS, can help increase recovery to up to 70%.

The International Energy Agency (EIA) believes carbon capture and storage technologies have a key role to play in realising a sustainable, climate-friendly future energy scenario and are expected to account for about one-sixth of required emissions reductions by 2050. 

ADNOC was the first National Oil Company to pilot CO² injection for EOR in 2009. In 2016 ADNOC joined forces with Masdar to launch Al Reyadah, the first commercial-scale CCUS facility in the Middle East and North Africa (MENA). Al Reyadah is now fully owned by ADNOC and integrated into ADNOC Onshore.

ABB completes the tallest e-houses on a floating LNG facility

ABB completes the tallest e-houses on a floating LNG facility

With a height of a five-story building, the world’s tallest, single lift prefabricated electrical structures – or e-houses – for offshore use are being installed on a floating liquefied natural gas facility (FLNG). The installation, for Petroliam Nasional Berhad (Petronas), is also the world’s first commercial floating LNG facility featuring ABB e-houses which are used to manage the electrical requirements.

This is Petronas’ second floating liquefied natural gas (PFLNG 2) facility and will be moored over the deep-water Rotan gas field, located off the Malaysian coast.

In addition to its impressive size, the project was completed with a record of two million man-hours with zero lost time injury. A priority for safety has also been embedded into the future operations of the facility by incorporating the latest technologies adapted to corrosive offshore environments. The fully engineered electrical system contained within the e-house will include transformers, switchboards, motor control centres and ABB’s Process Power Manager that ensures reliable and stable electricity supply to the FLNG facility.

The two e-houses are currently en-route to Samsung Heavy Industries’ yard in Geoje, Korea, for installation on the vessel.

“ABB’s long history of pioneering new technologies and expertise in the automation field is a perfect match for the floating LNG market,” says Per Erik Holsten, ABB Managing Director for Oil, Gas and Chemicals. “From concept to realisation, our engineered solution is one of the optimised factors that allow oil and gas companies to exploit fields that are traditionally deemed as uneconomical. The PFLNG 2 project is also a testimonial of our commitment to stakeholders on safety, quality and customer satisfaction, irrespective of the magnitude of the project.”

PFLNG 2 will enable the liquefaction, production and offloading of natural gas in the Rotan field, and produce 1.5 million tonnes of LNG each year. The non-propelled vessel will be moored using an external turret.

Tuesday, 23 January 2018

Wintershall continues to invest in domestic oil and gas production

Wintershall continues to invest in domestic oil and gas production

Wintershall is continuing to invest in the domestic production of crude oil and natural gas: "We're sending a clear signal with our activities in Germany. Oil and gas from local sources have excellent prospects," said Andreas Scheck, Head of Wintershall Deutschland, at the company's traditional New Year Reception in Barnstorf, Lower Saxony. 

Wintershall's largest German onshore oil field in Emlichheim is currently laying the foundation for a substantial development of further crude oil reserves over the coming decades, explained Mr Scheck. A modern, high-resolution 3D seismic survey, which will be completed at the end of February, will allow Wintershall to plan new wells along the German-Dutch border. Emlichheim in Lower Saxony, which is one of the largest and most tradition-steeped oil production sites in Germany, has produced oil almost constantly for the last 70 years. "That's a world record!" said Mr Scheck. Wintershall successfully completed a drilling campaign in Emlichheim in 2017.

Wintershall’s Barnstorf site, which is the headquarters for its German activities, is also being equipped for the future. Wintershall is currently investing around 6 million euros in the construction of a new laboratory building, which is set to be opened in the summer of 2018. Every year, around 2000 international rock samples from all production regions covered by the globally operating company are processed here. The laboratory's order volume has increased by about 30% since 2012. "The new building underlines the importance of Wintershall's expertise in petrophysics, production analytics and Enhanced Oil Recovery (EOR)," said Mr Scheck. 

At the beginning of 2017, Wintershall completed the modernisation of the crude oil processing plant on the operating site at Barnstorf with the commissioning of the fourth and – for the time being – last tank. "The tanks are cutting-edge technology and ensure oil production to the highest environmental standards," said Mr Scheck. At the same time, Wintershall is expanding production with new oil wells. Six wells have been spudded in the past two years in the Bockstedt oil field near Barnstorf, and further drilling is planned for 2018 as well.

"Our domestic production not only helps to secure supplies in Germany but also creates important jobs and income for Germany's federal states and municipalities," emphasised Mr Scheck. Just as important is the know-how that Wintershall can garner in Germany and then utilise worldwide. An excellent example of this is the Staffhorst site in the district of Diepholz, where Wintershall has been producing sour gas since 1965. There are still many large-scale sour gas fields around the world whose development requires Wintershall's expertise, for example in Abu Dhabi. 

Following the success of the recent drilling with a production of 7500 cubic meters of natural gas per hour, Wintershall is now planning a further drilling project in Staffhorst. "International experts come to northern Germany to benefit from our practical experience. A production site like Staffhorst once again shows that the expertise we garner here in Germany opens doors to energy partnerships worldwide, for example in the Gulf region. This, therefore, enables us to impress in global competition," said Mr Scheck.

Wintershall is also investing in domestic oil production in southern Germany. For example, Wintershall completed a state-of-the-art 3D seismic survey at the Landau site (Rhineland-Palatinate) in early 2017. "We achieved very good measurement results," said Mr Scheck. Geologists and reservoir engineers are currently exploring the potential for new drilling. Wintershall has been recovering crude oil in Landau for over 60 years.

"All our projects in the previous and coming year underline the future viability of domestic promotion," explained Mr Scheck. To date, Wintershall has produced more than 40 million tons of domestic crude oil in Germany – as much as Saudi Arabia has supplied to Germany in 20 years. 

"This is making an important contribution to energy providers. Furthermore, we're also establishing ourselves as a technology centre for Wintershall worldwide, creating jobs in the region and investing in the training of young people through our research projects," continued Mr Scheck. Wintershall Deutschland is currently training 47 women and men. Overall, Wintershall has already trained more than 500 young people in Barnstorf.