Use of Real-Time Operations Growing Upstream

Sanjaya Sood, Vice President Global Real Time, Schlumberger

If a brand new oilfield product or service becomes widely used in less than a decade, that is fast. It is no secret that the petroleum industry is conservative when it comes to adopting new technology. With the increasing pressure to maintain supplies from existing fields, however, that is changing. Today, technologies that improve production and reduce risk are more important than ever. You can see this in the growing range of tools and services that employ “real time” capabilities. But what are the benefits to those who adopt these technologies, and is real-time capability alone the key to unlocking additional value for operators?

The meaning of “real time” depends on its use. Aircraft controls, for example, are real-time systems that must process data and respond instantaneously with 100% accuracy. If we are referring instead to the credit card reader at a gas pump, the transaction is not instantaneous, but nearly so. Within the upstream oil business, wireline tools provide data almost instantly, and today there are drilling systems that feed back downhole information quickly. Drillers use them to guide the bit, adjusting for the fact that the data they are getting is actually several minutes old. Real-time capability can be defined as the use of digital technology to rapidly transfer field data to individuals or control centers, and the ability of humans or intelligent control devices to respond with equal speed to the data they receive. The benefit is that more efficient systems let operators direct valuable resources to other areas.

Incremental Changes

Adopting real-time capability is a process of incremental change. In an oil field, the beginning of that journey might be a simple feedback device that tells production operators what they need to know without having to visit their wells every day. At the other end of the spectrum might be an automated system that responds to changing field conditions and makes adjustments on its own. But full automation will not happen overnight. And there is no right or wrong place to be along the journey. An operator’s requirements for automation might depend on several things: a desire to improve efficiency, the benefits of the investment, availability of the technology itself, and access to expertise and processes to implement change most effectively.

There are three main reasons for deploying systems with real-time capability. The first is the growing shortage of skilled professionals in the industry, fueled in part by the coming retirement of a large portion of the workforce. Systems in which one can collaborate remotely or receive and share information quickly allow one person or team to monitor several locations at once, thereby improving efficiency.

The second reason is the need to operate in harsh or environmentally sensitive regions, where monitoring and controlling operations from a distance can offer safety and environmental benefits. The third driver is that systems that feed back data in real time may increase production by allowing operators to respond quickly to changing conditions in the well.

More than a decade ago, producers saw the beginnings of remote wellsite operations using Web-based technology. Today, many operators collect data from various sources and combine them into a single datastream using the standard wellsite information transfer standard mapping language. Streaming data into applications gives system operators the ability to analyze trends and continuously update the geological context of the wellbore.

In drilling, applications that monitor the amount of vibration at the drill bit help operators to drill new wells faster. Reducing vibration can greatly extend the life of the drill bit, which means fewer trips out of the hole to replace it. A growing number of operators are also steering the drill bit directly from an off-site operation support center, where teams of geoscientists and engineers can view the same data. Such centers can monitor numerous wells at a time, allowing engineers to immediately investigate any unusual data and address well problems.

Supervisory control and data acquisition systems have provided operators with reliable production data for decades. Wells are now equipped with an increasing number of sophisticated sensors to provide downhole and surface measurements. These measurements, including multiphase flow and equipment performance, can be analyzed remotely from a collaboration center or scattered around the globe. Through a Web interface, production engineers can also receive warnings about wells that need attention.

Electrical submersible pumps, for example, can be started remotely and their speed controlled to optimize production. For some operators, the objective is to find the best pump settings and learn when to change them to achieve optimal production. This process of surveillance, active diagnosis, and management of artificial lift systems has proved valuable—pumps last longer, and, when the workflow is optimized, wells typically show average production increases of nearly 20%.

Subsea Applications

Subsea applications offer perhaps the most dramatic use of systems that employ real-time technology. Offshore, where the price of individual wells routinely tops USD 60 million, the ability for off-site experts to collaborate can significantly lower a field’s development cost, assist safety concerns, and speed the time to first oil. Once the wells are in place, monitoring their performance is critical.

Onshore, systems that remotely monitor high-temperature wells are used for recovering heavy oil and bitumen, which may constitute more than two-thirds of the world’s remaining resources. Producing heavy oil requires mobility improvements and usually the reduction of viscosity. One option is thermal recovery, and an effective method (given the right reservoir conditions) is steam-assisted gravity drainage (SAGD). With SAGD, drillers install matching pairs of horizontal wells, one about 5 m above the other. The top well is the steam injector and the bottom well is the producer.

Permanent downhole monitoring tools provide continuous temperature readings for the entire length of the horizontal well. The data, with accurate interpretation, show which zones are contributing to production, where the steam is having an impact, and where steam may have broken through. The instant feedback allows operators to redirect the steam as needed to improve steam management and optimize production while improving efficiency. This, in turn, reduces the environmental impact of thermal operations.

Although many systems for managing oilfield operations in real time are available now, they do not provide full benefit on their own. Tools play a role, but only by combining them with experts—the people and processes—can technology deliver its true value. There are gaps in the technology itself, but continued R&D should create new real-time capabilities in the future.

Sanjaya Sood is Vice President Global Real Time, for Schlumberger, leading the company’s global effort in real-time enabled solutions. He joined Schlumberger as a field engineer in 1981 and worked for 10 years in different field positions in operations, sales, and management. Later, he served in senior management positions, including Vice President and General Manager in charge of India, and Vice President with Information Solutions. Sood studied mechanical engineering at the Indian Institute of Technology. He is on the board of several start-up technology companies.