Perdido layout.

Artificial lift methods continue to be crucial for optimizing oil production, sanctioning projects, and determining asset profitability. In fact, according to the Society of Petroleum Engineers, more than 80% of the world’s oil wells are on some kind of artificial lift. Among the oil majors, only Shell operates more than 4,000 artificially lifted wells. Innovative lift designs and new applications guide the way to extending asset lives and maximizing project performance.

Eventually, most wells will need some form of artificial lift since the technology accelerates and then replaces natural well reservoir flow. The main types of artificial lift are gas lift and pumping methods.

The first lift type mentioned above, gas lift, works by injecting natural gas deep in the well tubing to decrease the density of the column and increase the flow of fluids into the well bore and to the surface. A high reliability gas-lift orifice can stimulate production substantially through reduction of well servicing induced deferment.

The second type of lift, pumping, occurs when additional energy is added to the well system by either electric or hydraulic means.

Several other forms exist, such as surfactant injection and plunger lift, and still others are in development. The industry as a whole does not prefer one type of lift over another. Some of the technology applications are still relatively new, and different conditions call for specific methods. A number of factors play into each type of application: bubble size; gas injection point; flow control; quality of data; and the various difficulties associated with the depth, distance, and expense of production projects.

Reducing bubble size
In gas lift, the size of the bubbles in the production tubing affects the total energy loss of the producing fluid column. Generally, smaller bubbles allow more efficient flow, but larger-sized bubbles, or “Taylor bubbles,” congregate in the center of the tubing. This stimulates different flow velocities for liquids and gas, and therefore excessive energy is shed in the form of a pressure loss.

An innovation suggested by Shell engineers involves inserting a passive mechanical device, or an orifice plate, downhole into the production tubing at the point of slug flow. This would break up larger bubbles and create a flow of smaller, dispersed bubbles.

Once inserted, the orifices do not break up the larger bubbles directly but instead generate turbulence in the liquid of the production tubing that then splits the bubbles. Shell calls this technology the “Bubble Breaker.” It is currently being field-tested and may increase production by up to 10% or allow for a 10% reduction in lift gas requirement for the same production rate.

Detecting CO2
While bubble size is one factor for optimizing production, the placement or depth of the gas injection point is critical as well. A CO2 tracer detects tubing leaks and can determine if gas lift valves in the production tubing are open or closed, without disturbing well operation. The gas-lift well can provide information without having to enter the well bore with slickline tools, thus reducing the risk to staff due to crane work, road travel, and boat movement; risk to the asset from slickline entry into the well; and associated risk to the environment.

The presence of the CO2 is detected by installing a small separator on a split stream of the production flow line, and the gas obtained from the separator is then directed to a CO2 analyzer. The measured transit time of the tracer gas is analyzed by the WinGLUE software to determine tubing entry points of lift gas.

Processing integrated models
Integrated production system modeling tools, which seamlessly communicate with each other, deliver the best product that the combination of tools produce and generate the superior final result. One artificial lift study involved the Europa field in the deepwater Gulf of Mexico (GoM).

Undiscounted results of the Europa model suggested seafloor boosting can add 5 to 9 MMboe unique recovery. Engineers on this study continue to investigate cost savings and scheduling with the Mars host that would allow the Europa artificial lift to proceed into the next phase.

For gas lift assets requiring integrated models, the surveillance engineer calibrates the WinGLUE models with well test data and then hands the results of the calibrated performance curve over to the GAP application from Petroleum Experts. This speeds up the modeling process by allowing the engineer to model a gas-lift well in a single application instead of two.

Installing seafloor caisson ESPs
While seafloor boosting technology has been available for more than a decade, electric submersible pumps (ESPs) provide the latest options for subsea boosting. ESPs offer a new application for familiar and relatively mature technologies, high pressure boost capability and absolute pressure rating, and improved recovery when located in wells.

Progress continues in testing and field developments. For example, Artificial Lift Company of UK and ConocoPhillips recently installed a retrievable rigless ESP system.

This year, Shell plans to install 11 caisson ESP systems. Four have already been installed in Brazil at BC-10, and seven more systems are scheduled within the next year at both BC-10 and the Perdido project in the GoM. Meanwhile, full-scale system testing (30,000 bo/d, 55 MMcfd, 1,500 hp ESP) continues at the Shell Gasmer Prototype Facility in Houston.

ESPs can supply a 1,000- to 2,000-psi boost at the seafloor with record horsepower at 1,500 hp and a likely 30,000 b/d flow rate. ESPs are pushing the limits of the industry on boost, power, and flow rate.

Real-time analysis and remote monitoring
Onshore, virtual real-time surveillance data informs engineers of operations offshore. An OSI PI Process Book, the superior engineer’s toolkit, is an advantage for the oil production project.

Acquiring good data and applications aids decision-making, and accessing updated models speeds the process. Goals can be met using the FieldWare suite of applications for artificial lift management, well testing, and real-time optimization with Production Universe data-driven models.

For deepwater advancements, additional tools will be ready later this year to make full use of world-class data systems along with rigorous equipment protection, remote engineering alarms, and fully trained surveillance teams.

Managing lift challenges
Success with artificial lift means overcoming potential issues with things like tubing integrity, gas injection points, extensive distances, and expensive component repairs.

Supplying power at such an offset distance is merely the beginning of the test. Add power to the equation, and you have a real feat. For example, Shell required an umbilical of 6.7 miles (11 km) and achieved a company record for horsepower at its BC-10 project.

Of course, it is expensive to install and replace components at the record-breaking depths and distances of these wells. The industry is challenged to minimize failures in the system and high replacement costs. To avoid these issues, well design demands innovative thinking and thorough planning.

Artificial lift is an integral and growing part of the production business. Major oil companies and equipment suppliers continue to make progress in addressing the factors involved in artificial lift techniques and recovering more oil from increasingly greater depths and longer distances while more effectively managing costs.