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When design-to-first-oil takes 10 years, keeping up with communication technology can be a challenge. Elaine Maslin details what BP has done for its latest North Sea projects (originally published in OE's December 2017 issue).

With new technologies appearing all the time, it’s a job to keep up. BP’s Steve Cottam is doing his best to do just that, however. Cottam is Clair Ridge project lead, instrument and control engineer for BP. Clair Ridge (pictured in construction, right) is the second phase of the Clair field, with first oil planned for early summer 2018, via a new fi xed facility able to produce some 120,000 b/d.

The facility has been designed for a 40-year life and BP wants it to be in the top quartile for production effi ciency, Cottam says. Part of the plan is connectivity and the same plan has been applied to the new Glen Lyon floating production (FPSO) vessel, BP’s replacement for the Schiehallion FPSO, as part of its Quad 204 redevelopment. Glen Lyon came onstream in May 2017 with 100,000 b/d production planned. 

Design work on these projects started in 2008, the year the iPhone 3G came out, Cottam says. It’s nearly 10 years from design work starting to first production, and the plan is to make it work for 40 years – that’s the challenge. Both Clair Ridge and Glen Lyon are fiber-connected with wireless infrastructure on board. All the instrumentation is smart, with some 50,000 data points on Clair Ridge, and more on Glen Lyon, Cottam says. The data is sent onshore for long-term historization. Onshore, there is also a full facility operator training simulator with dynamic simulation, and a 3D PDMS model.

Offshore, the wireless infrastructure is based on hazardous and non-hazardous areas, with an instrumentation level WirelessHart, linking into process control systems, and a second separate wireless network. WirelessHART is wireless based on the Highway Addressable Remote Transducer Protocol (HART), which was developed as a multi-vendor, interoperable wireless standard, enabling secure, remote access for vendors to support their equipment. “This is huge for our drilling vendors,” says Cottam, who was speaking at the Censis and Oil & Gas Innovation Centre joint event, Internet of Things goes Offshore, in Aberdeen early October. 

On Clair Ridge, there are 125 wireless internet gateways across the plant, with good wireless coverage across the facility, Cottam says. This means staff out on the plant can connect on the spot with an advanced collaborative environment (ACE) at offi ce, but also to experts – where ever they might be. “This is now standard for BP,” Cottam says. With the advent of 4G LTE, which could also be used for connectivity within the platform, there now further options, Cottam suggests. 

Enabling this world isn’t just about hardware, however, Cottam says. As well as the ACE, there’s a functional support BP’s Clair Ridge facilities, during installation in 2015. Photos from BP. PRODUCTION organization, standard maintenance procedures, an onshore team monitoring plant and maintenance performance, dashboards, KPIs, trending, online engineering calculations, etc.

As well as applying these technologies to its latest facilities, BP is looking at installing wireless networks on existing facilities, including its oldest. “We need to move from reactive to predictive, onshore and offshore,” says Cottam, from automated analysis of heater exchangers, predicting failure, to comparison of rotating equipment performance across assets – “focusing on the problem and not symptoms, as previously.” 

Image: The Glen Lyon. Image from FPSO.

Having the network on older facilities means wireless instrumentation can be deployed, such as wireless corrosion instrumentation, which can be clamped or glued on existing facilities, he says. 

Looking ahead, event monitoring, and early warnings can be enabled and then the knowledge captured and shared, he says. As this revolution kicks in, BP will be looking to incorporate more use of ATEX approved portable devices offshore, for inspections, material tracking, all improving “wrench time,” as well as non-intrusive, quick deploy wireless instrumentation. Tracking personal outside the cabins would also help account for staff in the event of a muster event, instead of having to search for someone across the plant (when it can take 20 minutes just to walk from the control room to the furthest part of the plant). 

Such a world could prove problematic for staff – who would have to carry PDAs, a gas detector, tough book, radio, tools, etc. Instead, Cottam suggests that workforce clothing could incorporate much of these devices, i.e. introduce wearables. The gas detector would be incorporated in the suit, radio in the helmet, etc. 

But, it would also enable the likes of augmented video conferencing out on the plant, where an onshore expert can draw over the fi eld technician’s field of view or show them a step by step procedure. Meanwhile low-power, low-cost smart sensing feeds cloud analytics, which support cognitive automated alerts. Onshore staff will be able to access interactive 3D models, containing process data, P&IDs and maintenance routines, all in one place. But, Cottam warns, there are “soft issues,” such as staff use of social media during an incident, or use of non-certified devices, if a mobile network is in range of plant, and offshore work force buy-in. “We used to design these facilities on paper,” he reflects. 

The Internet of Things, a world in which equipment and instrumentation can talk to each other and modify operating parameters – across platforms, fleets and whole businesses – accordingly, is close at hand. Having the communications infrastructure in place is what will help make it happen. Elaine Maslin reports (originally published in OE's December 2017 issue).

In an industry with a large fleet of production facilities designed and built before the dawn of the internet, with limited communications infrastructure, embracing the likes of Big Data and the Internet of Things (IoT) can be a challenge.

The industry already has a signifi cant amount of instrumentation and more data than some say they can cope with. The challenge has been around gaps in connectivity, connecting devices, and dealing with the data generated. 

Fiber optics have taken the industry a huge step forward, while 4G LTE cellular networks are expanding wireless communications capabilities offshore. The next step to enabling an offshore IoT is plugging the gaps, with the likes of newer networks, such as LoRa wide area networks (WAN), offering possible solutions.

This infrastructure would help realize the world in which equipment can communicate. It would also allow technicians out on the plant to talk to onshore experts via the likes of live augmented reality video links. This world is coming. In a trial offshore the Netherlands, an onshore surveyor was able to verify an inspection offshore via a 4G data link.

BP is fitting out its latest North Sea developments, Clair Ridge and Quad 204 (the Schiehallion/Loyal redevelopment) with the latest technologies, including wireless networks across both facilities, as well as trying to future proof them. Read more here.

IoT and its possibilities for the offshore industry were discussed at a joint Censis and Oil & Gas Innovation Centre (OGIC) event, “IoT goes Offshore,” in Aberdeen early October.

“It’s the start of a disruption that is set o be as big as the internet in the 1990s,” says Mark Begbie, business development director, Censis, an industryled Innovation Centre for Sensor and Imaging Systems, who says perhaps in the past it would have been called telematics, or machine-to-machine communication.

OT phone home 

The backbone of this revolution is communication infrastructure. For the past 17 years, Tampnet has been connecting fixed facilities with fi ber optic cables, laid out throughout across the North Sea. In the UK North Sea, there’s 26,500km of this fiber alone, giving 240 facilities in the UK, Norwegian and Danish North Sea a fast data link to onshore. 

In 2013, with the introduction of 4G LTE in the Tampnet network, low latency, high capacity communications were extended to were then introduced to mobile assets. LTE (Long Term Evolution) is a standard for high-speed wireless communications for mobile devices using the likes of GSM (Global System for Mobile Communications, a second-generation digital cellular network). Tampnet is building its coverage through placing base stations on facilities around the North Sea, using the existing network as a backhaul to onshore.

“Using existing infrastructure, we [have] deployed 4G LTE base stations covering a similar area to 75% of the UK,” says John Main, sales manager for Tampnet. “Installing our base station on a 100m tower can give 40-50-60km range,” enabling coverage for mobile assets in those areas. He says 28 base stations have been installed, most recently on Talisman Repsol Sinopec UK’s Clyde platform in the UK North Sea. Another will be installed before year-end, with a further 9-10 due to be installed next year.

This coverage has provided an alternative to VSAT (very small aperture terminal – a satellite communications system), with reduced latency from 600 milliseconds (ms) down to 40ms, and increased bandwidth connectivity speed: testing the system on a new facility, staff were able Skype home to family using a 4G hotspot created on a vessel’s bridge.

In November, the firm won a contract to operate the offshore communications networks in the Dutch North Sea, which will include tying the area in to the existing subsea fiber network and merging the LTE network into the wider basin.

Looking in

However, says Main, 4G LTE doesn’t just have to be used for communication between facilities or to shore. Pointing a single 4G LTE antenna into a facility could cover 85% to 100% of the platform for mobile devices, Main says. This could enable an operator to video conference with an onshore subject matter expert on the spot. Tampnet has 24 projects in the pipeline involving internal-focused antenna, Main says.

For IoT, where thousands of sensors might be connected to a network, most of which don’t need to send huge amounts of data, especially if they’re smart or use edge analytics (i.e. process at site and only send what they need to), network capability doesn’t have to be so high. 

Øyvind Skjervik, Tampnet’s chief architect, says the firm is looking into NB-IoT (narrowband internet of things) and CAT-M1, a narrow band, low frequency, IoT-friendly version of LTE. While LTE has a high bandwidth, working at 20MHz with 240 megabits per second (mbps), CAT-M1 works at 1.4MHz with 1mbps and NB-IoT at 180kHz with 60kbps bandwidth. It can reach areas conventional LTE cannot and, because it requires less power than LTE, a NB-IoT device can operate up to 10 years on a battery, making the technology ideal for sensors.

Cat-M1 will be used where extended coverage is needed to connect devices relying on more bandwidth consuming, always on, applications like voice and video CAT-M1 connected devices to do their thing for longer. Such technology is being used to monitor shipping containers, with the signal able to go through 4-10 layers of containers in a shipping hold, Begbie says. 

“There's a lot of gathering of information today. IoT brings in a new era,” says Skjervik – sending what’s needed. Sensors can be low cost with a long battery life and with “extreme” network coverage. Tampnet hopes to run a pilot next year. 


Low power wide area networks (LPWAN) such as LoRaWAN are offering something similar. They have a long range, i.e. 3km in an urban environment or 10km in rural environment, equating to 12.5sq km. LoRa is a type of radio modulation technology using license-free radio frequency bands, with a protocol. For more local applications, there’s also near field communications (used for contactless payments), radio frequency identifi cation (used for tracking parcels in warehouses etc.), and bluetooth, among others. “LPWAN is the new kid on the block,” says Graham Kerr, technical director at Censis. “It has a high-range, low-rate data rate, which doesn't matter so much for IoT.” 

Cults Telecom Services has been developing an LPWAN network as part of a trial within Aberdeen. But, the fi rm also worked with the Oil & Gas Technology Centre and Rowan Drilling to see how an LP-WAN network would perform on a drilling rig. The firm set up a network on the Rowan Gorilla VI jackup, with a base station positioned on top of the radio room. The rig was in the Port of Dundee at the time and the trial a success, including covering below deck and over the water by the rig, says Tim Everitt, of Cults Telecom. 

Big data, digitalization, and IoT have become this decade’s buzz words. Slowly but surely, they’re also actually starting to shape and become more than just words in the offshore oil and gas industry.

Tuesday, 24 October 2017 03:08

Hess inks $2 billion Norway sale

Aker BP has agreed to buy Hess Norge, which includes major stakes in the Valhall and Hod fields, from Hess for US$2 billion as the US oil firm continues an offshore asset sale.

Yesterday, Kosmos Energy said it had agreed to acquire Hess' 85% stake in two long-producing oil fields, Cieba and Okume, in Equatorial Guinea for $650 million. Announcing the deal with Aker BP, Hess said it is now also moving to sell its Danish assets, comprising a 61.5% stake in the South Arne field. 

Through today's sale, Aker BP - will become the sole owner of the Valhall and Hod fields, taking on Hess’ 64.05% and 62.5% stakes, respectively. 

Hess CEO John Hess said: “Proceeds from these asset sales, along with cash on the balance sheet, will prefund development of our world class investment opportunity in offshore Guyana, where we have participated in one of the world’s largest oil discoveries of the past decade [the Liza discovery]."

Aker BP says the move will strengthen its position on the Norwegian Continental Shelf, increasing production and reserves “significantly,” with an estimated proven and probable (2P) reserves of 150 MMboe and best estimate 2C contingent resources of 195 MMboe.

Aker BP is planning to submit a plan for development and operation for the Valhall Flank West project in late 2017, with estimated first oil in 2020. In addition, Aker BP is maturing a number of additional projects in the area, including the North and South Flank projects.

Early January 2017, Valhall and Hod passed 1 billion boe produced, which is more than three times the volume expected at the opening of the field in 1982. “The ambition is to produce a further 500 MMboe,” says Aker BP.

Aker BP CEO Karl Johnny Hersvik says: “Aker BP has a clear ambition to be the leading independent offshore E&P company. This transaction is an important step in that direction. Taking full ownership and control allows Aker BP to pursue upsides more aggressively.”

However, the firm says it will seek to sell or swap a minority interest in the fields to partners who want to work with Aker BP to target upside potential in the area.

During the first nine months of 2017, Hess Norge’s share of production from the Valhall and Hod fields was about 24,000 boe/d.

The Valhall field center consists of six separate steel platforms for living quarters, drilling, production, water injection, and a combined process- and hotel platform. Two unmanned and remotely operated flank platforms (North and South) sit about 6km north and south of the field center. 

The Hod field is developed with an unmanned wellhead platform, 13km south of Valhall, and is remotely operated from the Valhall field center. All wells on the Hod platform are currently shut-in and awaiting plugging and abandonment. The Hod reservoir is now being produced from wells drilled from the Valhall South Flank platform.

Hess Norge today has 19 staff. Board members are Johan Nic Vold (chair), Anders Nymann, Brian Truelove, Martin Edwards, Helena Deal and Gerbert Schoonman. Edwards is also managing director. The deal is expected to close by the end of the year.

Hess' sales process relating to its Danish assets is expected to be completed in 2018. The South Arne field produced an average 11,000 boe/d net to Hess in 1H 2017.

Image: Valhall.

Friday, 20 October 2017 03:18

Chevron sanctions Captain EOR project

US oil major Chevron is moving ahead with plans for an enhanced oil recovery (EOR) project using polymer technology on its Captain heavy oil field in the UK North Sea.

The Captain field was discovered in 1977, in Block 13/22a on the edge of the outer Moray Firth. The billion-barrel field achieved first production in March 1997 – 20 years ago this year – thanks to developments in horizontal drilling and down-hole pumps. 

Stage 1 of the EOR project, which follows several EOR pilot programs at Captain, will see the drilling of up to six long-reach horizontal injection wells. 

Since 2010, Chevron has been trialing polymer EOR on its Captain heavy oil field. Earlier this year, the firm started its fourth pilot project on the field to further refine its polymer EOR plans for Captain. 

Norway's Statoil has also been putting the technology to test on its Heidrun field, with plans for further pilots on other fields in coming years.

Meanwhile both of these firms, along with BP and Shell, which have been considering use of polymer EOR on the Quad 204 project, have been taking part in an industry Task Force on EOR, which today, under the Oil and Gas Authority, published Polymer Enhanced Oil Recovery - Industry Lessons Learned. Find the document here

The Captain facilities comprise a wellhead protector platform and bridge linked platform connected to a floating production, storage and pffloading vessel.

For many years, the field has been under waterflood, which means a lot of effort is put into water production and treatment (some 300,000 b/d of water are produced). However, there is still a lot of bypassed oil, because of the way waterflood results in a “coning” effect in the reservoir.

Chevron Upstream Europe managing director Greta Lydecker said: “Sanctioning Stage 1 EOR at Captain is an important milestone in the development of the technology, which we believe will improve the recovery rate from older fields and help extend the life of assets.”

Oil & Gas Authority (OGA) Area Manager Eric Marston said: “Polymer EOR has the potential to increase recovery, extend field life and stimulate field redevelopments. Chevron, along with BP, Shell and Statoil, has been a driving force behind the industry-led EOR task force. I commend their openness in sharing their lessons learned with the wider industry and their contribution to the OGA’s ‘Polymer Enhanced Oil Recovery – Industry Lessons Learned’ publication which will be published shortly.”

CNSL holds 85% and is the operator of the Captain field, Dana Petroleum (E&P) holds 15%.

Read more

Elaine Maslin surveys some of the heavy oil field developments in the UK Continental Shelf, plus some of the technology aimed at unlocking it.

Offshore enhanced oil recovery pilots by Chevron and Statoil in the North Sea are paving the way towards helping to get more heavy oil out of the ground. Elaine Maslin reports.

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