To optimize production on its Petronius offshore platform, Chevron engineers decided to drill an additional seawater injection well and expand the surface facilities to meet the increased pumping requirements. After evaluating numerous pump options, company representatives contracted with Schlumberger to provide a RedaHPS (horizontal pumping system) for this application. This article outlines the technical and economic drivers for this decision and highlights many of the benefits afforded by the use of this pumping system, especially for offshore installations.

Project requirements

The Petronius platform, located in 1,750 ft (533 m) of water in the Viosca Knoll 786 block of

Figure 1. This pumping unit is built around a rigid skid to which all rotating components are mounted including the motor, thrust chamber, mechanical seal and pump. (Images courtesy of Schlumberger)
the Gulf of Mexico, uses seawater injection to maintain reservoir pressure and maximize reservoir sweep and ultimate recovery. Due to field maturity, the volume of required injection water has increased beyond the capacity of the original injection pumps installed on the platform. To maintain reservoir pressures above bubble point and to optimize oil production, the operator needed to increase the capacity to inject treated sea-water into producing reservoirs. A decision was made to drill a second injection well and to add additional injection pumps to the platform.

Pump criteria

The new pumping units had to meet several criteria including:
• Quick delivery to coincide with completion of the injection well;
• Ease of maintenance to minimize downtime;
• Low capital costs; and
• Environmentally friendly — minimal noise, vibration and emissions.

The overriding goal was to minimize the time required to bring the new injection well online and maximize and optimize production. Every additional day waiting to install a pump after completion of the new injection well translated into lost production and lost revenue for the operator, so quick delivery was imperative.

To maintain the increased production levels afforded by drilling the second injection well, the pumping units had to be operationally efficient and as maintenance free as possible. Equally important, if a problem did arise with a pumping unit, it was essential to minimize down time for repair to minimize the negative impact on production.

Finally, because of confined space and personnel proximity, the pumping unit needed to be as quiet as possible to minimize noise pollution. It also needed to have a minimal level of vibration or the ability to be isolated so as to limit force transmissibility to surrounding structures, and it needed to have little or no exhaust emissions to minimize air pollution.

Pump options

Typically, the company uses API-610 split-case multistage centrifugal pumps or barrel pumps for seawater injection. Logically, Chevron representatives approached several manufacturers of these pumps and solicited bids for this project. In response, the bids received specified 36 to 52 weeks for standard delivery and a high initial equipment cost (up to US $1.2 million). These delivery times would not support the plan for drilling and completing the injection well, which was scheduled to be completed within 26 weeks from the time the request for quotes was sent out.

The company also investigated the use of remanufactured API-610 pumps. However, this option was not considered viable due to questionable reliability and the higher probability of downtime should repairs be necessary.

As another alternative, the operator considered renting positive displacement pumps. These
Figure 2. The two pumping units as installed on the platform were plumbed in parallel with one another to deliver a total flow of 700 gpm at 3,500 psi to the injection well.
pumps offered several advantages to the API-610 pumps including low cost (renting versus initial capital expense) and quick delivery (approximately 4 weeks). While the quick delivery was an advantage, it was not a project driver as the time frame to drill and complete the well exceeded the time to source the rental pumps. Also, while use of these pumps offered financial benefits, the pumps posed numerous environmental problems including higher noise levels, vibration and exhaust emissions (for diesel driven pumps), disqualifying them as a viable alternative for this project.

Faced with options that were either financially or environmentally unattractive, Chevron representatives contacted internal resources and other local engineering firms to discuss other available pumping technologies. Through these discussions and a thorough cost-benefit analysis, the selected pumping system solution emerged.

Pumping unit overview

The modularity of the HPS unit distinguishes it from traditional API-610 pumps and positive displacement pumps. This pumping unit is built around a rigid skid to which all rotating components are mounted including the motor, thrust chamber, mechanical seal and pump (Figure 1). Standard units are designed to maximize structural rigidity while minimizing flexure and vibration. The skid can accommodate up to a 1500-HP electric motor with its gearbox. Different engine drives (gas or diesel) can be accommodated as well. The motor is directly coupled to a thrust bearing section that is designed to withstand thrust loads produced by the pump up to 18,000 lbf while minimizing heat generation.

The modular design of this pumping unit makes it a logical choice when minimizing downtime is a priority. The unit makes use of a spacer coupling between the motor and the thrust bearing section that allows for easy separation of the motor and the thrust bearing assembly. This allows the motor and the bearing section to be easily removed for repair or replacement if necessary.

Further, the use of a spacer coupling allows for rear pullout of the thrust bearing section to allow for easy access to the seal assembly without moving the motor or the pump. Use of a dropout spool between the pump and the discharge piping allows the pump to be removed from the unit by simply loosening the pump clamps. All of these features facilitate quick repair, eliminate the need to realign the motor and pump after servicing the thrust bearing assembly or the mechanical seal, thus minimizing downtime and the associated loss of pumping capacity.

The right solution

After a detailed search and analysis of the market and discussion with other users of this pumping unit, the operator made the decision to use it also for the seawater injection well for this project. The service company engineers worked with the operator engineers to specify two 1,250 hp HJ350N HPS units for the project. The two units were designed and built within budget, delivered and installed within 16 weeks from receipt of order. Based on their modular design, readily available components and ease of manufacture, the operator saved 40% on initial capital spending and a minimum of 20 weeks of lead time compared to using traditional API-610 split-case or barrel pumps. The target lifetime for these pumping units is the same as that for an API-610 pump: 20 years with regular maintenance.

The two units were designed for operation with a 1.25:1 speed increaser to deliver 350 gpm at a discharge pressure of 3,500 psi. The two units were installed on the platform and plumbed in parallel with one another to deliver a total flow of 700 gpm at 3,500 psi to the injection well (Figure 2). The footprint of each unit measured 4 ft wide by 39 ft long (1.2 m by 12 m). The pumps were brought online in 2003 after the drilling and completion of the injection well and performed efficiently within specification over a broad range of operational conditions.

Quick resolution

Shortly after commissioning, one of the pumping units experienced a high vibration shutdown. Unable to determine the cause and with no apparent signs of damage, several attempts were made to restart the unit. However, the pumps would not develop nearly the discharge head required for normal system operations. A service company field technician was flown to the site and examined the pumps to determine the source of the problem. Preliminary findings indicated that the pump diffusers were spinning in one of the pumps, leading to internal mechanical damage and a loss of hydraulic performance. The pump was subsequently removed from the platform and transported back to the service company’s manufacturing facility in Oklahoma where it was subjected to a detailed dismantle, inspection and failure analysis.

To minimize downtime, the operator had stocked a spare 26-stage pump element in the event that one of the pumps needed to be repaired or replaced. This pump was sent to the project platform and once on site it took only two technicians four hours to install the new pump and return the unit to service. This turnaround time compares to 36 to 48 hours typically associated with an API-610 split-case pump when spares are on hand.

If spares are not available, or if there is casing damage, four or more weeks of downtime can be expected for an API-610 split-case pump. This downtime directly translates into lost production for the operator and has a significant negative economic impact. The failure associated with the pumping unit on this project, while unfortunate, clearly demonstrated the value that this type of pumping unit brings in minimizing downtime associated with pump repair or replacement and highlights the value of the modular design of the unit.

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