Offshore production: It’s expensive and difficult

Current poor market conditions notwithstanding, oil and gas produced from increasingly deep water will be critical in the long term.

By Peter Welander September 30, 2015

Offshore oil and gas production has an interesting past, it undeniably has a future, but its current state of being isn’t so hot. Of course, upstream production, in general, is suffering terribly, and offshore producers and drillers are among the worst off. Why? Offshore production is expensive and difficult; two things that don’t work well in a world of $40-per-barrel oil. In the future, offshore production will be more expensive and more difficult to find, extract and process, but that’s where some of the largest oil and gas deposits are waiting. As has been said in this article series before, all the easy deposits have already been exploited. Oil companies must look down the road in the short and long term and determine where the next barrel will come from, and increasingly, that barrel will come from somewhere covered by water.

The aforementioned water is getting deeper. While the vast majority of active offshore platforms are in less than 200 m of water, the vast majority of active leases are in 1,000 m and deeper. Brazil’s Santos Basin fields are already producing, even though they are under 2,000 m of water and another 5,000 m of rock and salt. That is not an easy field to exploit, and that oil does not come cheaply, but recoverable reserves from these deposits are estimated around 7.5 billion barrels. Such numbers are hard to ignore.

Offshore drilling and production has many challenges, and those following the industry have seen stories about companies struggling with equipment and nature. France’s Total has had its problems trying to drill new wells off of South Africa and super-major Shell is struggling with storms in the Arctic. The elements do not always cooperate. Even sites that have been producing for years are having a hard time. In May 2015, The Economist published a story asking if the inefficiencies built into British platforms in the North Sea have doomed them from ever operating profitably again. It stated: "Operating expenditures in North Sea oil have doubled in 15 years. Only a fifth of that increase, at most, is because of increased activity. The biggest reason is inflated costs, reckon consultants at McKinsey, followed by pure inefficiency, such as needlessly high standards and complexity."

Reduce costs: How?

There is still much to learn about reducing costs. "It’s like where shale was 10 years ago," said Randy Miller, vertical marketing director for gas for Honeywell Process Solutions. "We know where the oil is. We know how to get it. But we have to start employing great ideas, and then move through multiple iterations, to make it more cost effective and technically effective."

As Miller points out, shale producers developed new technologies to reduce drilling costs drastically in a few years. While offshore producers have not been standing still, more effort has been directed toward the needs of working in more extreme environments than reducing costs. And as The Economist explained, the price of oil was high enough for enough years to cover the inefficiencies. The answer now has to be a multi-prong effort of using technical advances to support lower costs, as has been the case with shale production. The higher degree of complexity with offshore production provides more areas to look for savings.

Reducing the little remaining fat

Some answers will be technical, but others will relate to adopting "lean" production techniques from other industries that have had to work within highly competitive environments for far longer than oil and gas operations in the North Sea. Producers and oil exploration companies in the Gulf of Mexico generally operate with a high degree of efficiency, although current prices have squeezed profits out of even the best. Safety-both for people on the platform and the environment-cannot be sacrificed, which means there are points where costs can no longer be cut.

"Hundred-dollar oil facilitated a great economic environment across the industry because all oil and gas companies were making money," said Steve Campbell, deep-water business development manager for Yokogawa. "Deep-water operators were not questioning vendors in the same way they are now with $40 oil. They’re applying greater scrutiny on several metrics: overall general efficiencies, value-added work opportunities, and creative ways to lower cost and maximize value while margins remain tight. We’re working directly with these producers to extend their control system life and exercise creative ways of formulating new solutions to help them gain a competitive edge for positioning when the market becomes healthy again."

Automation: Help and hindrance

Offshore production operations have long had a reputation for using automation and control systems that don’t integrate easily. For a variety of reasons, the hardware on most platforms comes from an assortment of providers that use lots of independently-functioning controllers. This is certainly not unknown among land-based facilities, but on platforms, it reaches higher levels.

"Offshore puts everything in modules that are constructed in different places across the globe," Campbell said. "Many times, each module is equipped with its own logic solver, and those things are all brought together in a shipyard where everything is assembled and the home runs are brought back to the distributed control system (DCS). In many cases, the DCS is essentially a dashboard, and the heart and soul of the process is distributed across programmable logic controllers (PLCs) in the modules. PLCs are capable of executing this strategy, but companies are realizing the value of a more integrated strategy as used in the downstream community."

Campbell added that companies would have seen that discussion primarily as a technical matter when oil prices were higher, but they now see cost saving aspects to the decision. Integration, when deployed well, can reduce costs and in this environment, but there is also a reliability element. "With large oil and gas companies, these decisions are being made at a high level with a global perspective of how to manage their automation kit," he said. "They tell us that from a longevity and fleet management standpoint, we need to eliminate multiple points of failure. If we can capture everything in one automation platform, risk is reduced and we can achieve lower system costs."

Find common communication

Making these platforms communicate with each other easily is a challenge, and the first step is finding a common communication protocol. Sometimes that means going back to an old but reliable approach. "In the offshore industry, we find that most applications use Modbus TCP and Modbus RTU.," said Ben Trombatore, recently retired project manager for Wood Group Mustang. "Modbus has been around a long time, and it is a robust, deterministic communication protocol offered by many instrument and equipment suppliers in their standard offerings. Still, using Modbus efficiently requires more attention to setting up the data maps and associated transfer files. The advantages of data packing reduces the number of read and write commands, allows better organization to streamline data transfer, and allows the user to move more data with minimum bandwidth. If this is overlooked, it can quickly slow the response and refresh times of the control system if a number of these interfaces are being handled simultaneously."

The equipment doesn’t help

Traditionally, offshore fields bring connections from various wellheads to one common platform where oil, gas, and water are separated. All that equipment must be supported on the platform and people have to be there to maintain it. Such an approach makes for a large and complex platform, but all the equipment is where it can be reached and serviced. The amount of equipment on the sea floor is minimized. This approach also involves pumping a lot of water to the platform, which has no value. More recent developments tie the wellheads together on the sea floor and move the initial separation process down there as well. All that equipment can now be taken off the platform, and the gas and oil streams arrive already separated without pumping up any water.

Companies developing this technology talk about a future where all equipment can be installed on the sea floor without the need for platforms at all. Everything will be controlled from land-based facilities. There will need to be visits by technicians for maintenance, but nobody has to spend months at a time living on a dangerous platform. Production companies can avoid associated costs and risks to be able to produce in bad weather.

This is an appealing picture, undoubtedly. However this advantage comes with two major concerns. First, so much equipment is installed on the sea floor where access is a problem. If a pressure sensor fails, now what? How does a maintenance technician change it when it is below a few hundred or thousands of meters of water? Divers might be able to reach the skid depending on the depth. Another choice is a remotely operated vehicle that can go down and repair the problem devices. Neither of these options are inexpensive, but they’re better than the third alternative, which is pulling up the skid.

Undersea skid builders say they are doing much to improve the instrumentation and modularize equipment to make it maintenance-friendly, relatively speaking, even under 1,000 m of water. The control systems running these installations use highly-sophisticated diagnostic platforms to ensure failures are infrequent, and those that do happen provide warnings. It is difficult to imagine a more compelling argument for predictive and proactive maintenance.

Another concern is integration. Connecting the sea floor system to the topside platform installation has to span a communication barrier as great as the water itself. As mentioned earlier, integration among disparate modules in the production chain is a particular problem with offshore installations. This sea floor to topside connection represents the most significant disconnect.

FMC is the largest player in the subsea equipment segment of the industry, and it created a communication protocol, FMC-722, designed specifically for its subsea skids. Vendors working on the topside, including ABB, Emerson, Honeywell, Kongsberg, Siemens, Yokogawa, and perhaps others, accepted this situation and used this protocol for the sake of expedience. However, others in the field were not so anxious to surrender that space and asked for standardization on a less proprietary protocol.

Welcome OPC UA

For a variety of reasons, both practical and political, an organization, the MCS-DCS Interface Standardization (MDIS) group, was formed bringing together operating companies, subsea equipment vendors, and control system vendors. Its aim is to solve the integration and communication issues between the sea floor and platform. As its website states: "MDIS was formed with a vision to optimize the MCS to DCS communications of topside systems, by defining and establishing a standard for the interface, to simplify implementation of data communication links, whilst increasing the data quality. By implementing the MDIS standard, the operator will benefit from simplified implementation and testing of the MCS-DCS interface, a single common interface to all subsea vendors’ equipment, reduced risk of interface failures and reliable control and monitoring via the DCS. The focus of MDIS is on the interface between the MCS and the DCS, to simplify this communication channel the MDIS network will define standard objects through which data relating to physical subsea components will pass through the interface, standardize the implementation of these objects and define a procedure for testing and certifying products to ensure compliance to the MDIS standard."

Working with groups that often have vastly different agendas can present some interesting challenges. Rachael Mell, network manager for MDIS takes a very practical approach. "Given the nature of the work we’re doing, the vendors get involved a bit more, and then we rely on the operators to make a decision when there are things the vendors can’t decide on," she said. "The operators are the customers, so they get their say at the end of the day."

The organization considered a variety of possible protocols and chose one that was rather forward thinking: OPC UA. There were more practical approaches (at least in the short term) that were discarded in favor of this one. However it has little in the way of actual equipment presently available. Vendors involved in the project have been developing products, and the effort has been going on long enough for the organization to sponsor a "plug-fest" last June in Amsterdam where the companies all came together to see how interoperable it all really is.

"We had 12 companies participate with hardware, some of which was still prototypes, but we had a series of clients connecting to a series of servers, and they were able to communicate and complete the test cases we designed," Mell said. "It went really well, better perhaps than some expected since it was the first time we’d run something like that. OPC UA is very familiar to the DCS vendors that work in a variety of industries, but to the subsea vendors, it’s new."

Business downturns can serve both as a help and hindrance to these kinds of developments. But a large enough group of companies are looking far enough down the road to recognize the importance of this kind of effort. Mell added, "Some of the operators in the network are very keen to push this forward, so I don’t think the timeline is going to suffer from the downturn. Whenever you have these downturns, we hear more talk about standardization as a way of cutting costs and reducing the development time on projects, which makes everything more economical."

There are still many questions to be settled and developments to be made. For example, members of the group are trying to create a large enough collection of objects to support all the devices encountered in a real-world operation, and they are working on developing a consensus on the necessary level of cyber security protection.

Returning (hopefully) to better times

When it comes to oil consumption, American consumers are notoriously fickle. While high gasoline prices made the huge SUVs of the early 2000s less practical, large vehicles are back again in 2015 with full-size pickup trucks leading automotive sales. Will increased production, to fill those big tanks, bring back better times? And what will happen as prices recover?

"We’ve been in this constraint for about a year," said Honeywell’s Miller. "Offshore projects in the North Sea or in the deep water off the coast of Brazil are multibillion-dollar investments and those take a long period of good margins to justify. This project has been halted, and we’re going to need some period of oil price recovery before investment comes back to that area. The capital side has been affected much more deeply than the operations side.

"As prices recover, producers are going to be looking at return on investment in a shorter time frame. So whether it’s onshore or offshore, investment has to be paid back in a shorter time frame, even if it isn’t the larger fields that have a larger payback. Projects that generate cash flow are the projects that come back the earliest. Once we have a longer period of price stability, the bigger programs that have a bigger payback over the longer period of time start to return. We need a long period of price stability for these projects to come back like they were a couple of years ago. But without a major shock to the supply side, we’re probably going to be below $100 for the next few years." 

– Peter Welander is a contributing content specialist for Oil & Gas Engineering. Edited by Eric R. Eissler, editor-in-chief, Oil & Gas Engineering,


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Original content can be found at Oil and Gas Engineering.