New technology boosts well recovery, cuts costs

The goal of Pemex’s “intelligent field” is to extend oil production from 30-year-old offshore platforms like those in its Gulf of Mexico Cantarell field.Owners and operators of offshore wells aim at improving efficiency, cutting costs, reducing failures and down time, while maximizing economic benefits. It’s no easy task under the best of circumstances. Reaching these goals requires a sophisticated system of technical tools whose success depends on what one expert called, “an ascending hierarchical order of control,” meaning that field devices and monitoring must unite with a multi-variable and perfected process management.

Each element depends upon the proper functioning of the level immediately below it. The rigs must have proper equipment such as hoists, top drives, mud pumps, and generic devices, but the rig also requires a very valuable and essential IT system that must include a centralized component to handle subsea production operations, topside oil and gas process handling, off-loading operations, and safety systems for people, equipment, and the environment. That is exactly where automation comes in.

For companies, this means there will be a strong need to invest in digitally-enabled networks and equipment that provide significant improvement in the acquisition and distribution of data. Officials from Marathon, Shell, and Exxon, among others, have said system-wide integration stands or falls on the capacity to break down the barriers between previously unconnected business/ supervising/directing elements.

Simply put, there is a lot at stake.

The latest generation of enhanced IT solutions for distributed monitoring includes automation improvements that embody all aspects of plant operations. This can make a big financial difference for processing, utility, drilling, and subsea applications, studies say. Since operating costs are a contributing factor to the cost per barrel of production and maintenance, operators must aim at reducing the cost per barrel, cut down field operating expenses, and costs of workovers, utilities, repairs, maintenance, and chemical treatments, as well as labor. At the same time, when automation is working effectively, it will record the history of the well. This gives the crew an accurate picture of machines and conditions underground.

Smart data through automation can also forecast coming problems through advanced software and sensors that alert operators when something has gone wrong or is about to go wrong – all in real-time. Remote diagnostics and maintenance mean fewer service calls and lower support costs. Alarm systems can notify personnel to repair malfunctions, and with the right software. In addition, drilling problems can be identified, nullifying the need to send in crews and avoiding the expense of travel to rigs.

The automation evolution provides operations with centralized control to handle subsea production operations, topside oil and gas process handling, off-loading operations, and safety systems for people, equipment, and the environment. This security also extends to zone protection around the outer areas of the production operation.

Communication movement

In the downstream environment, if not there yet, operators are pretty close to having total communication from the sensor to the boardroom. But that movement is coming along slowly upstream. “There are people tracking the real-time data for their assets on each individual asset and they are rolling that out to onshore support centers; and presenting a series of dashboards to those individuals onshore and further up to management,” says David Bleackley, senior director global accounts at AspenTech. “Depending on what role you have in the organization, you will get a different visualization of data referring to different assets. This enables (management) to distribute work functions and tasks differently between those tasks that need to be tracked offshore and those tasks that need to be monitored onshore, and the skills to be deployed.”

One of the benefits means the end user can glean knowledge and expertise from anywhere in the world.

“You don’t need to have the experts locally. You can have support teams and management teams that meet every week and have a schedule of calls with individual assets to go over what the production targets are, what the principal issues are for maintenance and safety, problems that occurred, and strategies they need to look over for the next few days,” Bleackley says. “The offshore team and the onshore team are seeing the same data from the asset together at the same time.”

That ends up meaning the different teams can gather information and bring them together in a series of key performance indicators (KPIs). “The asset manager of the whole block is not interested in the same information as the rotating machinery specialist who wants to get down to the nitty-gritty into the nature of his major compressors. The manager of the block wants to know which assets are on production target, which ones are under, and which ones we have working on spec. He is watching his performance against his production schedule.”

At the same t ime, Bleackley adds, “engineers are able to use process models and supplement that data by taking in real-time data from the assets, and they are quickly able to learn what-if scenarios with the real-time data against the model of the system to see what they could achieve. That is something you are going to see more of in the coming months.”

The relationship between process control and profitability control can be thought of as a cascade control strategy with profitability control as the primary loop and efficiency control as the secondary loop.In a similar vein, Schlumberger relies on its Automated Workflow Management & Advanced Data Analysis program that provides a workflow automation system spanning the entire data of workflow automation, while serving the needs of different end-users. The system can also perform data capture, cleansing and conditioning, preprocessing, and validation as well as monitoring workflow support. The multi-data stores and multi-databases bridge the gap between operational systems such as SCADA and the production engineer’s desktop. Petrobras is using the system to explore the potential of heavy oil reservoirs in ultra-deep waters, reserves that could yield 1.4 billion barrels of oil.

For IOCs, most of the newly developed automation technology has not only boosted oil Bloomproduction, but it has also raised the recovery rate of offshore wells to between 20% and 30%, and even in some cases, up to 60%, according to case studies. According to a BP study, by using the company’s Designer Water or Designer Gas program, the recovery success of 1% would result in an additional two billion barrels of oil. This is extremely promising.

Automation connection

Oil companies are pushing the limits in discovering new wells and oil, but they also need to push the envelope on existing wells to boost and extend production. When Pemex needed to extend oil production from 30-year-old offshore platforms in its Gulf of Mexico Cantarell field, one of the world’s largest, it envisioned an “intelligent field.”

One of the solutions in its intelligent program was a remote monitoring system that is cost effective and quickly installed to better manage the field, increase worker safety and improve environmental protection.

The operation involves about 200 production wells on more than 50 platforms with limited or non-existent power, and no communications infrastructure to transmit data to the onshore operations facility. Pemex was sending employees daily by boat to the platforms, located 50 miles from shore, to manually gather data to support production decisions. Beyond the cost, this approach was dependent on weather conditions, creating delays in decisions and safety risks for workers.

By using wireless technology, Pemex expects to gain better visibility of its production processes and field performance by adding monitoring points throughout the offshore facilities at a fraction of the cost of wired instrumentation. Battery-powered sensors and instrumentation can immediately obtain pressure, temperature, and valve position, providing operators with real-time information they need to react quickly to any change in the condition of the wells.

“If you can’t measure it, you can’t control it, said Bob Karschnia, vice president of wireless at Emerson Process Management. And, if you can’t control it, you can’t use it.”

With wireless technology, the maintenance lifecycle of the rig is fully visible to management, “acting as eyes and ears, as if people were still out there,” says Victor Lough, Invensys Operations Management product manager. Remote management also enables the experienced staff at the onshore control center to train new workers on the rig. This is not inconsequent ia l a s 40% of the workforce can retire in four years, says Peter Richmond, Invensys manager overseeing virtual training.

By using technology that mi r rors the gaming industry, “we’re working to make opportunities on a rig more attractive to a new generation.”

“The advancement of wireless technology, which was slow to be accepted in E&P, is now appealing,” Lough says. Using wireless technology, the signals it transmits are the measurements, observations, and calculations collected by the field operator using personal digital assistants loaded with workflow management solutions that communicate seamlessly, wirelessly, with an operations center. This mobile integration effectively closes the communication gap between operations, maintenance, and management, a key component of process safety management. “Mobile technology makes process management possible,” Lough says.

There are also significant space and weight advantages of using wireless for rig operations because “for every one pound above the water, you need five pounds of support below,” Karschnia points out. In addition, wireless technology offers lower cost and increased speed of engineering, installation, with proven reliability and security.

When the Pemex project wraps up, the oil giant anticipates considerable annual savings in logistics and installation, better field production optimization, and improved worker and environmental safety through a reduced need for offshore platform trips.

With this project underway, Pemex’s chief executive, Juan Jose Suarez Coppel believes that the company is going to boost output from its aging field.

“We foresee a stable and increasing Cantarell field,” Suarez Coppel said in a Bloomberg interview last summer. Expected output at the field, which fell 11% in 2011, “makes us comfortable” that Pemex will reach its goal to increase production this year, he said.

In the past decade, Cantarell’s production slid 74% to 500,674b/d last year. “We plan to increase production to 2.7 million b/d in the next couple years,” Suarez Coppel continued. Pemex will produce 3 million b/d “by 2017 or 2018, given that we invest enough.”

While that big jump in production is not solely the result of the wireless technology solution, it does play a part in the whole automation package that will bring Cantarell huge dividends.

Digital advantage

Getting more production out of existing wells will be the mission of the automation environment for the foreseeable future as there are no new disruptive technologies on the horizon, according to IDC’s Energy Insights.

In the 1970s, close-spaced 2D seismic data/ interpretation and water injection boosted production rates and recovery factors, the Energy Insights report said. In the 1980s, it was offshore technology and 3D seismic data/interpretation, which boosted rates. In the 1990s, it was horizontal drilling technology, electrical submersible pumps and deepwater/subsea technology that made progress and promised profits. But the report pointed out that the decade we now face shows no big, new technology that will likely have as big an impact as the technologies implemented in the 1970s, 1980s and 1990s.

Enhanced 3D and 4D seismic, ultra-deepwater, remote-operations technology will only provide incremental gains in the most demanding environments. As the IDC study said: “For many IOCs, all the good technology that was developed and implemented in the last 30 years has accelerated oil production and increased recovery factors from some 20-30% to up to 60%, but this will also cause higher decline rates and IOCs have to work harder and faster to stop this decline.”

The report continued, saying the ability of IOCs to access new oil reserves is becoming increasingly difficult because a good share of the remaining oil reserves are governed by state oil companies, many of which feel they do not need a lot of help. That is not likely to change in the coming years, since these state-owned oil companies can bring in the technologies and expertise from contractors to increase recovery factors and production rates.

That is why a digitally-automated environment will help ensure greater productivity and success in the coming years, if not decades.

An enterprise control system provides a real-time counterpart to the transactional enterprise resource planning system.With offshore fields often in difficult environments, there are great challenges installing and operating advanced communications. But all operators understand the tremendous value that comes from transferring abundant data into useful information and knowledge. After all, knowledge is king.

A study by the US Minerals Management Service (MMS), which is now two bureaus: the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety & Environmental Enforcement (BSEE), set out the potential of deepwater operations in the US Gulf of Mexico: “Approximately 350,000bbl of oil and 1.7MMcf of gas come from deepwater subsea completions each day. Subsea completions currently account for about 34% of deepwater oil production and about 50% of deepwater gas production. Very little deepwater oil production came from subsea completions until 1995, but by the fall of 1996, subsea production rose to about 20% of total production. Since 2000, subsea oil production increased slightly, whereas total deepwater oil production has increased dramatically.”

Digital tools will help optimize operations and maximize recovery. BP knows this and that is why it created a program called Field of the Future.

The oil giant is installing a range of standardized digital, sensing and control technologies in its operations, and is integrating data to enhance real-time operating efficiency and recovery.

In the North Sea, and in other new projects in the Gulf of Mexico, Azerbaijan, Angola, Indonesia, and Trinidad, digital technologies will be able to deliver vital information about well performance.

Advanced communication systems are facilitating better collaboration between onshore and offshore decision-making teams. Fiber-optic networks installed on the seabed, and as sensors downhole, are increasing data transmission and communications speeds.

These digital tools and sensors enable more effective monitoring of production, multiple well components, and well characteristics such as temperature. By improving monitoring and reducing downtime, they are saving multiple millions of dollars. In time, digital automation technology could allow production platforms to produce via remote control. In the coming years, BP plans to roll out Field of the Future technologies to 90% of its production. The company said this will enable them to add 1 billion boe to recovery, representing 5% of the current proved reserve base.

Smart technology

Smart tools and sensors are keys to gathering data and getting it to the proper decision makers.

Along those lines, General Electric (GE) is putting sensors on everything it touches with oil and gas subsea installations. The underwater remote monitoring system receives data from sensors that increase reliability by measuring vibration, temperature, and leak detection for well heads, manifolds, and production stations.

Shell will be the initial user of this technology.

With the value of deepwater assets deployed set to exceed US$225 billion by 2015, coupled with over $15 billion per year in lost production from equipment failure, GE’s condition monitoring system will help producers gain potential lost revenue.

Smart machines can send alerts when they need maintenance, before a breakdown. It is the equivalent of preventive and personalized care for equipment, with less downtime and more output.

“These technologies are really there now, in a way that is practical and economic,” says Mark M. Little, GE’s senior vice president for global research.

Most experts agree automation is a valuedriven spectrum, which includes remote control, mechanization, semi-automation, and full automation. The goal is to produce equipment strategies and tactics that are efficient, safe, reliable, and affordable. Safe, reliable, affordable – all very big words, but put simply: automation seeks the capacity to repair leaks at the well site, reduce well failures, lower utility costs, and make more efficient use of personnel. But most of all, automation allows the oil company to align itself with industry needs, available financial resources, and potential market opportunities.

Automation also means it is possible to increase yields, as well as meet and serve the rapid pace and pressures of the market. This includes strategies to drive down costs by eliminating waste and enhancing productivity.

Production costs per barrel are defined as field overhead expense coupled with costs associated with producing wells including: utilities repairs, workovers, maintenance, and labor among others. Optimized technology is the crucial key to lowering costs and boosting productivity. There is a lot at stake. OE Review

Richard Sale is a freelance writer based in Hillsborough, NC, and was United Press International’s intelligence correspondent for 10 years and also with the Middle East Times, a publication of UPI. He is the author of Clinton’s Secret Wars and Traitors.

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