Artificial lift technology has long been an essential part of the oil and gas production process, with the vast majority of wells around the world benefiting from artificial lift in various forms. Electrical submersible pumping (ESP) systems have played a significant role, enhancing output for more than 70 years.

Overall demand for products and services that enhance oil recovery is expected to grow significantly, driven by an expected decline in production from existing wells (at roughly 6% annually) and the increasing complexity of developing new reserves.

ESP deployment is one of the fastest growing segments in the industry, with an estimated 120,000 systems in operation today. For an increasing number of oil wells, the technology is the only viable artificial lift option. The technology will be paramount in helping producers meet the rising global demand for hydrocarbons, as maturing fields are expected to account for more than 70% of global oil production output by 2012.

Such technology is required to perform in increasingly challenging conditions – fields are being developed where the wells are deeper and operating at higher temperatures and pressures; operators are entering more remote locations and setting up operations in more harsh environments; and crude oils with higher viscosities, higher volumes of entrained sands, and solids in more corrosive conditions are being produced using ESP systems.

ESPs have become a vital part of E&P's advance into the deepwater and subsea environment as the industry seeks to maximize production of these frontier reserves. In fact, ESPs make up the biggest area of expected market growth for artificial lift technology.

This figure shows a schematic of the ESP system (right) in a vertical boosting station, installed on Shell’s Perdido development in the GoM. (Image courtesy of Baker Hughes Inc., FMC Technologies, and Shell)

Improving reliability

Extending the run life between incidences of mechanical or electrical failure on these systems remains a key focus. Operators want as little nonproductive time as possible.

ESP systems have become the focus of a strong and coordinated technology push by both suppliers and operators as they research and develop new ways to meet the needs of the expanding application envelope.

The expectations placed on ESP performance are growing rapidly, and manufacturers have responded with major enhancements such as improved metallurgy, motors that can operate at higher downhole temperatures, more efficient pumps, and greater gas handling capability. ESPs now are more capable of operating over extended ranges and at higher temperatures, encompassing almost all current production conditions.

The vast majority of ESPs are deployed onshore and have an average a run-life of between two and three years, but ESP systems are not confined to land operations. They are being deployed in subsea applications with ever-increasing stepouts and water depths.

There are around 80 subsea ESP systems installed worldwide, predominantly in the North Sea and China. To put the offshore ESP market into perspective, it is estimated that there are approximately 120,000 ESPs operating onshore in any single year.

According to Ben Gould of Baker Hughes, presenting at the 2011 Offshore Technology Conference in Houston, for most companies an ESP with a service life of two to three years is considered acceptable. "While most operators will ask for longer run lives, when they weigh that against the additional cost of procuring such a system, the economics will not justify the added expense.

"However, when we look at the offshore, and particularly the subsea environments, the economics drastically change. The cost of an ESP system is relatively small versus the cost of a workover, so the additional upfront cost associated with a higher-end ESP becomes less significant."

The Baker Hughes dual subsea ESP bypass system will be used on the Big Foot field in the deepwater GoM. The system allows for reservoir access and the ability to switch between ESPs without intervention. (Image courtesy of Baker Hughes)

Pushing the limits

The technology involved in the design, engineering, and deployment of ESP systems also has changed dramatically in recent years, driven by operators asking suppliers to push the equipment toward its operational limits and at the same time asking for longer run lives.

This is not to say that ESPs cannot run longer – one onshore system in the US ran for a reported 24 years, while an ESP in the North Sea achieved nearly 20 years. But the average in the North Sea is approaching four years of operation.

Many of the subsea wells are equipped using redundant systems, meaning there are two ESP systems installed in the well, usually one in operation and one on standby.

Gould pointed to one of the most recent advancements in this dual-ESP approach where the ESPs are separated by a packer between the two systems. "The idea of having the ESP systems stacked on top of each other allows for the units to be installed in a smaller wellbore. It also means that the control lines and motor lead extension can be protected from damage during running in the hole by installing them in the can and not having them rub against the annulus during installation."

Having two ESP systems in the same wellbore has its advantages, including a longer run time. The well can continue to produce when a workover is planned while also allowing the workover to be carried out in conjunction with other work rather than having to mobilize a rig for a solitary pull.

Several studies have shown an interesting advance in the technology involving a combination of an in-well ESP system working in tandem with a seabed boosting system, where the ESP would only have to move the fluid to the sea floor and then let the seabed boost system provide the added pressure to move the fluid to the host production facility. This would allow the well to be drawn down to maximum capacity for the longest length of time to maximize the well's productivity.

"To date this has only been done for a few wells because most of the subsea wells are capable of free-flowing to the seabed boost system so the in-well ESPs are typically not required. There are several projects in the planning phases that will use both an in-well ESP and a seabed boosting system," Gould said.

"The industry will continue to deploy subsea ESP systems in shallow to medium water depths and will continue to learn from these installations. Approximately 40 seabed boosting systems have been successfully deployed in up to 2,400 m (~8,000 ft) water depth. Some have direct vertical access and the ability to be pulled and installed without a rig, but the majority of them are deployed in areas where a rig will have to be used in order to work on the systems."

William Milne, director of business development, Artificial Lift at Baker Hughes, described the offshore deepwater and subsea environment as the fastest-growing market in artificial lift systems, with predicted growth of more than 500% over the next 10 years.

"We are collaborating with major operators to help them come up with artificial lift solutions for a number of projects globally to economically produce from deep reservoirs," he said. "This will require step changes in capability and an innovative approach to the development of key technologies. It is critical to evaluate designs from a system point of view in the subsea deepwater environment – taking into account anything that could impact the performance and longevity of the production solution."

The company also was involved early in the process with Shell, receiving a contract to help the operator with innovative enhanced run-life 1,600 hp ESP systems for its Perdido ultra-deep project in the Gulf of Mexico (GoM), where the ESPs were installed inside 107-m (350-ft) caissons installed in dummy wells in the seafloor as part of a subsea boosting system to help pump around 125,000 b/d of liquids to the field's spar platform.

"Operators would like us to put more and more horsepower in the well to increase productivity and reduce associated well costs," Milne said. "We are also working in partnership to enhance reliability. It's a question of accelerating the development program to match the ambitions of the operators."

Efforts such as these are pushing the technology envelope for ESPs. Testing and development of such tech- nologies takes time, a substantial amount of money from both sides, and plenty of cooperation.

The longevity of any ESP system depends on a full understanding of the environment that the unit will be exposed to and how it will be operated. Other run-life factors include proper qualification, testing, and selection of materials including elastomers and metals, and the pump stage design.

Impressive results

Combined efforts are producing some impressive results. Baker Hughes noted that improved ESP technology and manufacturing controls have extended ESP run times for critical well applications when announcing a major award in the GoM.

The contract awarded by Chevron will supply ESP systems for the operator's Big Foot development project. The ESP systems and production packers will be run in seven producing wells, plus mud line packers for three injection wells.

This award marked the first deployment of ESP systems inside the well-bore in the deepwater GoM. The systems will be placed at a true vertical depth of approximately 4,900 m (~16,000 ft).

Big Foot is in 1,600 m (~5,200 ft) water depth in the Walker Ridge area and is being developed via an extended tension-leg platform with an onboard drilling rig and production capacity of 75,000 b/d of oil and 25 MMcf/d of gas. Deployment of the ESP systems is scheduled to begin in 2014.

The 1,200 hp dual ESP systems will be among the highest horsepower in-well systems ever deployed in an offshore environment. The ESP systems are deployed on dual bypass systems, allowing for reservoir access and the ability to switch between ESPs without intervention.

"Longer term, the experience and knowledge gained from Big Foot can potentially be applied to other developments in the deepwater market to extend field productivity," said Richard Williams, GoM president for Baker Hughes.

Another deepwater project in the Campos basin offshore Brazil saw one of Baker's ESPs set a run-life record of more than 1,360 days of continuous operation in more than 1,350 m (4,430 ft) water depth after being installed and starting up in the summer of 2007.

This beat a previous record of about 1,300 days for a subsea ESP completion in shallower waters and is clear evidence of the increasing run times being achieved by the industry.

Remaining challenges

Although ESP systems are suited for the environments they will encounter in extreme water depths and temperatures, there are technology challenges remaining.

Currently, penetrator systems and wet mate connectors that allow cables to pass through the wellhead are being developed for the higher pressures that the ESP systems might be exposed to, and elastomers required in the system need to be developed to withstand the higher temperatures that may be present. There also is an expectation of run-lives of up to 10 years, which is currently beyond today's average, making ESP systems a more economically viable producing method for exploiting new and mature reserves.

Sidebar

Rigless deployment of ESPs

Most ESP systems are installed with the use of a rig and the pumping system attached to a tubing string.

This method is still the quickest and most economical way to install the systems onshore and in some mature offshore fields. For subsea well completions where a rig must be mobilized at considerable cost, however, this is not normally the case. If a vessel is not available or is delayed due to bad weather, it can result in lost or deferred production and additional costs.

Several methods of rigless and riserless deployed ESP systems are being studied and developed that allow for the use of a vessel of opportunity rather than having to mobilize a rig. This has substantial implications for improving economics and making ESP systems a more attractive option.

Artificial lift specialist Zeitecs is making a case for combining the ongoing improvements in equipment run-life with expedient retrieval and replacement of failing or ineffective ESPs using wireline technologies.

In theory, according to the company, an operator using up-to-date relevant field data and C-FER data can design an optimal ESP system with a predictable run-life. In practice, however, the variation around the mean can still range from an infant mortality within 90 days to a run of up to six to 10 years. According to Zeitecs, early failure for an operator is always the most significant economically, operationally, and logistically. An early failure impacts investment return, the rig used to complete the well is already assigned elsewhere, and redirection of the rig back to the well also defers other planned oil or gas production.

ESPs, however well-designed, engineered, and built, will fail at some point. It is this unpredictability of the point of failure that causes such disruption and costs to operators.

Zeitecs’ Shuttle technology enables the rigless retrieval and redeployment of conventional ESPs (up to 562 series) through tubing by means of standard oilfield wireline, rod, or coil tubing technology.

The application of such a system effectively changes any ESP workover from a complex rig operation to a standard well services operation, enabling a more rapid recovery from unpredicted failure. With a rigless system, a failed ESP can be repaired or replaced without the traditional workover costs of a rig. This means less deferment and maximum field recovery.

A rigless system also optimizes production as it ensures flow continuity and allows for pump optimization. ESP change-out and well recovery operations can be reduced from weeks or months to just a few days, the company said.

The application of a Shuttle system can change any ESP workover from a complex rig operation to a standard well services operation, enabling more rapid recovery from unpredicted failure. (Image courtesy of Zeitecs Inc.)

Shuttle vs. tubing

Shuttle technology consists of three main elements: a permanent downhole power installation, a downhole docking station, and a wireline-conveyed shuttle system to retrieve and replace the ESP. The system is installed on tubing in exactly the same way as a traditional ESP and requires virtually the same running and testing procedures.

The cable is protected through the application of premium cable, permanent installation and the recommended use of a fluid-filled casing-tubing annulus by a deep set packer.

The Shuttle docking system connects the ESP system to the fixed downhole power supply. This plug-and-play technology, according to Zeitecs, means that any manufacturer’s ESP may be installed using this system, allowing an operator the optimal ESPs to match prevailing well requirements.

According to public technical information, traditional ESPs require on average one workover every three years.

In one offshore application, the Shuttle saved more than US $3 million in operating costs proportional to production rate compared to an ESP system deployed on conventional tubing in an offshore well. The technology also allowed for the avoidance of four workovers during a 15-year lifecycle.