The majority of oil wells today require some sort of artificial lift technique to either maximize recovery or enable the well to produce at all at economic rates.

Even in the face of the current industry downturn that has resulted in operators significantly lowering their capex budgets, the market for these technologies is expected to continue to grow at a compound annual growth rate of about 10% through 2020. The current global market for artificial lift is estimated to be about $15 billion. Artificial lift and its related technologies and services will continue to play a key role in well production throughout the world, especially as operators venture into ever more challenging fields. The tight and negative operating margins being faced by operators these days is expected to be the norm for the immediate future; as such, it is logical to expect an increase in reliance on artificial lift as operators find themselves severely capital-constrained and driving hard to maximize recovery from existing wells.

In this environment, there is likely to be a push toward those lift technologies that either minimize well interventions on greenfield projects or can be economically retrofitted to existing brownfield assets. For the former, operational uptime, availability and reliability will be key to keep opex down. For the latter, operators will seek to develop technologies that can be applied, inexpensively, through a secondary investment in producing assets where significant additional reserves can be realized to maximize tail-end recovery and extend asset lifetime.

In its simplest form, artificial lift can be done through either gas-lift techniques or pump-assisted lift techniques. The latter includes a variety of methods including electric submersible pumps (ESP), hydraulic submersible pumps (HSP), progressing cavity pump systems, positive displacement screw pumps, reciprocating rod lift and hydraulic jet lift. Selecting the most appropriate artificial lift technology is essential to well profitability, with each method having distinct advantages and disadvantages for capex and opex.

Improving subsea production
In the specific area of subsea production wells, the focus is on equipment availability and reliability. The costs associated with interventions to manage equipment failures or changeouts can severely impact field economics. It is in this context that the HSP has achieved notable success through improved reliability, service life and flexibility of operation, ultimately providing a low and predictable opex profile.

The HSP was originally developed to address failure issues associated with ESPs, specifically their electrical components, limited resilience in the face of elevated free gas levels and sensitivity to installation and operational errors.

While the developments of ESPs undoubtedly made incremental improvements to the robustness of the technology and consequently reduced the occurrence of some failure modes, reliability is still often seen as limited and, with the current tight operating margins, presents a threat to meeting the economic threshold for application of pumps to field developments.

In contrast, the SPX FLOW HSP offers an electric-free solution, removing many of the sensitivities that can lead to operating envelope and availability limitations and prematurely short runlives. This technology uses a high-speed multiphase helico-axial pump end and hydraulic turbine driver powered by topside-located conventional water injection systems. Key features and benefits offered by the SPX FLOW HSP include:
• Wide operating envelope with the widest possible operating range of any centrifugal well pump;
• High speed with super-synchronous operating speeds, providing greater head and flow per stage and resulting in a more compact pump set overall;
• Advanced materials of construction designed to provide excellent resistance to erosive wear and corrosion;
• Multiphase capability, enabling continuous pumping at elevated free gas levels with no risk to the HSP;
• Integrated pump and driver with a one-piece high-precision shaft design that eliminates the requirement for drive couplings between pump and driver ends;
• Plug-and-play design, reducing installation time and eradicating problems stemming from installation activities at the rig floor; and
• Fluid commingling, enhancing availability by improving production path flow assurance.

Through the above attributes, the HSP has been able to demonstrate a mean time to failure (MTTF) of more than double the design target life of five years and more than three times the MTTF of typical equivalent electric motor-driven systems.

HSP in gas, heavy oil applications
The HSP has been successfully used long term in Chevron’s Captain Field subsea well development in the U.K. North Sea. Although discovered in 1977, the field was not produced until 1997, when technological advances in horizontal drilling and downhole pumps enabled the operator to reach and produce the gassy heavy oil reliably.

To date more than 44 HSPs have been installed by the operator and have successfully proven themselves in continuous operation to gas void fractions of about 70%, demonstrating the excellent gas handling capability achieved by the combination of helico-axial design and the inherently variable speed turbine drive. Producing flow rates range from less than 2,000 bbl/d to more than 19,000 bbl/d, all from a single frame size, the HSP allows the operator to focus on optimizing reservoir drainage unconstrained by pump envelope and viscous oil flow assurance considerations.

The use of power water also enables the HSP rotor bearings to be continuously lubricated when in service, providing excellent triboligical conditions to minimize wear, even when the pump end itself is faced with significant erosive solids or high gas content. The dynamic nature of the turbine drive provides an inherent load-following variable speed characteristic, which delivers an automatic and instantaneous capability to range in speed and more effectively compress free gas in slug flow regimes. This feature mitigates gas locking, making it an optimal solution in handling gassy flows.

The HSP’s high reliability has demonstrated an MTTF of more than 11 years, with cumulative operational time of more than 200 years. As a result, the operator has experienced significant operational cost savings over the past 15 years and continues to do so through latelife slot redrill campaigns.

HSP in brownfield applications
With the HSP, SPX FLOW has sought to move reliability risks from the wellbore to the much more readily accessible surface facilities and to rely upon the robustness of conventional pressurized water systems as the power delivery medium. The simplicity, flexibility and scalability of the system lends itself to good uptime, and the familiar water injection system technologies on which it is based mean that service, maintenance and upgradability are easily achieved.

In brownfield assets, operators have the opportunity to make use of their existing water injection pumping equipment—which often have excess capacity in the late life phase of mature fields—to provide power fluid to drive retrofitted HSP technology. This can significantly reduce the cost and footprint requirements for any supporting topside drive equipment. SPX FLOW’s aftermarket field service engineers can perform site survey and re-rate solutions as necessary to upgrade pre-existing injection equipment to the required power water specification.