Progressing cavity pumps applied to oil field multiphase fluids

Solution compared to conventional separation is cost-effective and are useful for multiphase fluid transfer of crude oils.

By Robert Kurz, NETZSCH April 27, 2018

Heavy oil, extra heavy oil, and bitumen generally require special production techniques to overcome their high viscosity. While many in the industry have focused on such methods as steam-assisted gravity drain (SAGD), cyclic steam injection (CSI), and vapor recovery, flow assurance solutions also are important.

These well streams combine crude oil, water, gas, and sand. The proportions of each vary by region and reservoir. There are distinct economic, environmental, and facilities management advantages to transferring the complete well stream to gathering and processing facilities rather than well site component separation. To make this transfer, the pump system must be reliable, safe, and capable of handling variations in fluid composition and process conditions.

Positive displacement pumps, especially the progressing cavity pump (PCP) are a good choice for multiphase fluid transfer of crude oils with high viscosity. The PCP is a cost-effective solution compared to other conventional in-field pumping alternatives.

Stimulating reservoirs

In recent years, attempts have been made to increase production rates using new ways to stimulate reservoirs. Most of these methods incorporate flow assurance and surface transport techniques. Selecting pumps to transport multiphase fluids, consisting of oil, water, gas, and formation solids (sand), is important. Multiphase fluids in traditional field developments typically free flow to gathering stations through surface lines pushed by the natural formation pressure, as shown in Figure 1.

However, heavy oil and extra heavy oil pose unique challenges for pipeline flow because the increased viscosities result in high friction losses.

Figure 2 shows a typical production model for multiphase flow. Flow assurance is critical for managing production rates. Flow-line resistance influences production rates. For heavy oil regions, it is a key factor when deciding on a production philosophy.

A simple way to use a multiphase pump is shown in Figure 3, where a pump applied at the well head boosts the well flow to gathering and processing stations. In this case, multiphase pumping is simply a way to add energy to the unprocessed well fluids, enabling the liquid/gas mixture to be transported long distances without prior separation.

Two typical in-field separation operating scenarios are conventional separation close to or at the wellsite or multiphase pump use. Separation close to the wellsite is not always possible and may require significant infrastructure and investment. This increases facility investment costs due to complexity or extreme environmental conditions. For example, cold temperatures are often associated with heavy oil fields. Figure 4 shows a diagram of conventional separation equipment.

Table 1 provides a simplified comparison between the two operating scenarios.

An assessment suggests that multiphase pumping is the simpler choice from an equipment perspective. Environmentally speaking, an enclosed system to handle gas with little or no need for gas venting to the atmosphere is a more desirable option.

Pumps at the well head or on pump pads must handle changing process conditions due to formation or well behavior variations. This is especially so because multiphase pumps deployed in depleting fields often demonstrate unstable cycling behavior, with active production periods followed by inactive periods. In addition, unprocessed multiphase oil streams may have entrained (free gas) fractions as high as the high nineties.

The pump equipment already deals with challenging conditions. When sporadic slugging is thrown into the equation, it can affect the pump. Slugging can cause gas flow to be limited to periods lasting from 15 minutes to several hours. The pump must cope with such variations. During gas slugging periods, it is likely that some liquid will be carried with the gas as liquid or vapor. The worst-case scenario for a pump is long duration of dry gas flows, which is tantamount to the pump dry running. These technical design and control challenges must be overcome to ensure equipment in service is reliable and efficient. 

Process and environmental

Besides their benefits, multiphase pumps also pose some process and environmental challenges. The following conditions must be addressed in a successful multiphase pump implementation:

  • Well shut-in pressure is often high, >20 bar. Pump suction-side design is for the shut-in pressure, as well as the normal running pressure, typically much lower.
  • Varying inlet pressures lead to varied required displacement volumes, so the pump must have a variable speed drive to vary the flow rate.
  • The pump must tolerate periods of gas slugging.
  • Installation is nearly always outside. The pump must handle extreme heat and cold.

Good system integration is required to overcome process challenges, including prolonged slugging. More than in any other PC pump application, the system needs to be orientated to work with the pumps to ensure they are not damaged during such times.

Figure 5 shows a simple way to protect against damage from overheating caused by prolonged slugging or dry running. The dry run protection device embedded in the stator can detect any frictional heat build-up due to lack of lubrication from the pumped fluid. The control system reacts by starting a lubrication pump. In the simplest form, dry0run protection can trip the pump until the temperature reduces. System complexity will vary based on geographical location.

Figure 6 shows a small lubrication pump injecting liquid into the suction side of the pump. Lubricant injected is collected process fluid or can be water or oil from separate sources.

Another example is a simple liquid collection tube and recycling line arrangement, widely used in Russian oilfields. It usually is applied with a recycle line flow controlled by a manually set throttle valve. The leakage collection device is sized for a buffer of fluid. This allows a reasonable operating period during typical slug flow durations.

Pump equipment must be protected from harsh environmental conditions, especially extreme cold temperatures.

The pump stator is made of an elastomer. Effective pump operations depend upon flexible elastomeric properties. As temperature falls, elastomeric properties and tear strength reduce. As they approach the glass transition point, pieces of the stator material can become mechanically overworked and shear off. Elastomer recipes can be adjusted to increase the rebound rate and change the effect of low temperatures. Alternative stator material recipes are successfully and reliably applied in extremely cold Russian oilfields. 

Mechanical seal selection

Mechanical seal selection is less critical than might be expected. It is essential that O-ring material is selected based on expected temperatures, especially when operating in exceptionally cold temperatures. Seal selection depends on the gas fraction and the expected risk that the field could operate in slugging conditions.

For low gas fractions (<60%), using single mechanical seals with either no quench (API plan 02) or a simple quench (API plan 62) proves successful. Where gas fractions are higher, the use of higher integrity solutions can be considered, such as, for example, a double mechanical seal and systems. The simpler the solution, the more reliable it is likely to be. Even for higher gas fractions, the use of tandem seals with simple atmospheric buffer fluid tanks is very effective and avoids needing more expensive and complex double-seal and plan-53 systems.

Carefully select the buffer or barrier fluid. Use of 75/25 glycol/water solutions and diesel has been successful, with upgrades to fluids like isopropyl alcohol (isopropanol) or methanol.

PCPs are forgiving to mechanical seals because the shaft speeds are very low and stuffing box pressure is the same as the suction pressure. Only one shaft seal is required, unlike twin screw pumps with four shaft seals. 

Robust handling

PCP equipment can be easily tailored to meet the demands of multiphase oilfield locations. Elastomer selection is essential to deal with cold conditions. Use of package process and control solutions is especially critical. A PCP is simple to control. Temperature increases are easily detected and the pump responds well and quickly to control adjustments. The fluid handling qualities are extremely useful for handling low or very high viscosities. The PCP can also handle gas fractions as high as 99% and can tolerate slugging conditions even without requiring control systems.

Robert Kurz is manager, field oil & gas, NETZSCHE.