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FRANCE / CASE STUDY

All-metal pump weathers thermal, chemical oil sands operations

MATHIEU RAE, Shell Canada; LAURENT SEINCE, PCM; and MIKE MITSKOPOULOS, Kudu Industries

A recent run of an all-metal progressing cavity pump (PCP) in a SAGD application for Shell demonstrated the pump’s wide operating range in terms of production volume, pressure, temperature and viscosity. The pump remained downhole during various steam and chemical stimulations designed to reduce differential pressure between the injector and producer.

Background. Shell’s Orion field in Cold Lake, Alberta, produces from oil sands in the Clearwater formation. The reservoir has an oil viscosity of about 75,000 cP at reservoir temperature (15°C). The virgin reservoir has pressure below hydrostatic, an estimated permeability of 1–2 D, 33% porosity, 70% oil saturation and 10°API oil at a depth of 1,300 ft.

Primary recovery from Orion field is by steam-assisted gravity drainage (SAGD); two horizontal wells are drilled together with about 5 m (16 ft) of vertical separation and little to no horizontal offset. The upper well injects steam to heat the surrounding bitumen, in the form of a steam chamber, to lower the viscosity of the bitumen, which drains to the producing well below. The initial static differential pressure between the injector and producer is theoretically 50 kPa—10 kPa/m (water head) at 5-m separation. Allowing for some natural heterogeneity, friction and other factors in a dynamic situation, a differential pressure of about 300 kPa is expected and acceptable. Orion, however, can see differential pressures up to a few thousand kilopascals.

In natural lift, the No. 1 producing well on Shell’s pad 105 (P105 P1) was completed with a short and long tubing string. This allowed for well circulation and production from the heel or toe. When converted to artificial lift (Fig. 1), a pumped multi-mode distributed temperature system was installed to monitor subcool (i.e., condition in which the water temperature is below the associated saturated temperature) and well inflow.

All-metal PCP. French pump maker PCM’s Vulcain all-metal PCP has now been in use for four years in various thermal enhanced oil recovery methods, including those used for in-situ oil sands production. To date, about 100 pumps have been deployed worldwide, with the longest run time being over two years.

The completion of a well equipped with the high-temperature all-metal PCP package is very similar to one for a conventional elastomer PCP used in cold production. The key differences are:
• All-metal rotor and stator, able to withstand a broad range of static and dynamic temperatures and viscosities (up to 350°C)
• High-temperature Oryx surface seal and drivehead, manufactured by Kudu Industries, at surface
• Wellheads designed for high-temperature applications, including polished-rod BOP and blind rams for workovers.

There are intrinsic limitations to elastomer seals in PCPs. The expansion coefficient makes it impossible to run the same pump over a wide temperature range, and the mechanical properties of traditional elastomers tend to break down at temperatures exceeding 150°C. The all-metal PCP selected for the Orion field application consists of a helical rotor and a metal stator constructed of multiple hydroformed elements. The thermal expansion coefficient of the stator is equal to that of the rotor, so the pump characteristics remain consistent over a wide temperature range (40°C to 260°C). The alloys used are corrosion resistant to H2S, CO2 and aromatics, which can cause problems for elastomer PCPs. Additionally, the metal pump has proven resistant to external chemical stimulations.

Although the all-metal PCP does not have the same interference fit between the rotor and stator as an elastomer PCP, the efficiency is still adequate, as the fit can be precisely adjusted with the patented hydroforming process used for manufacturing.

SAGD operation and results. P105 P1 began circulation in June 2008. After one month the well had a short shut-in followed by another after three months of circulation. By this point, inter-wellbore communication was confirmed, meaning the well was ready for SAGD operations. Unfortunately, over the next year, the well began having difficulties producing fluids to surface due to low bottomhole pressures (BHPs) while still being subcooled.

Fig. 1. Well P105 P1 (SAGD producer) completion.

To help promote fluid lift, a proactive artificial lift installation was commissioned in December 2009. Prior to artificial lift, the well had a constant pressure differential, which was thought to result from the reservoir heterogeneity. After recompletion, the well-pair communication issue—i.e. pressure differential—grew. In the first four months of operation, the steam-to-oil ratio (SOR) had improved from 8.4 to 5.2, but oil production has diminished from 88 bpd to 63 bpd. During this period, the producer BHP dropped from about 2,000 kPa pre-lift to 900 kPa, with the injector pressure rising to 5,000 kPa without inducing a steam breakthrough, Fig. 2. Clearly, a skin factor was impeding inflow.

To confirm the plugging, a lower-cost alternative to promote communication was deployed: steam stimulation. Steam was injected down the producer wellbore casing at pressures exceeding the operating reservoir pressure to promote well-pair communication. After completing a thorough safeguard, the stimulation was executed on April 21, 2010, with the PCP stator and rotor in hole. After 10 consecutive days of 260°C steam, communication with the injector was reestablished. After a short shut-in “soak” phase to allow the injected steam to reach subcool, the PCP was started with no signs of efficiency loss and the well regained communication with the injector.

Fig. 2. Bottomhole pressures and pump load from PCP installation through chemical stimulation.

Following steam stimulation, oil production increased to a peak of 210 bpd with a total fluid flow average of 940 bpd and an SOR drop to 4.6. The BHP had increased from 900 kPa to about 3,500 kPa. Unfortunately, throughout the summer and fall, the producer BHP slowly declined back to 900 kPa. Even though the pump load was increasing with the drop in pressure, the all-metal PCP maintained efficiencies of 40%–50%.

In March 2010, Shell kicked-off a thorough and systematic pressure differential study to understand the well communication loss. By the fall, a sustainable and cost-effective wellbore chemical stimulation that eliminated the pressure differential and re-established well communication was ready for trial on P105 P1.

On Nov. 30, the chemical stimulation was executed. The well was able to regain communication, produce the highest oil rate to date, 250 bpd, drop to a 3.9 SOR and lift about 1,070 bpd of gross flow using steam injection equivalent to 940 bpd of cold water. The all-metal PCP continued to generate 50% pump efficiency.

Conclusions. The innovative process used by Shell showed that production can be optimized by combining steam and chemical stimulation. The well has now produced for 14 months with total gross flowrates varying from 440 bpd to 1,570 bpd at pump speeds ranging 125–170 rpm. The pump load has varied from 150 ft-lb to 1,000 ft-lb. Bottomhole temperatures have ranged from 125°C to 260°C. While the operating conditions have varied significantly, an underlying improvement in SOR, 8.4 before lift to 4.6 after lift to 3.9 after chemical stimulation, can be linked to these two methods.

The high-temperature package handled the wide range of operating temperatures and associated viscosities, intakes and differential pressures. Speed adjustment enabled the pump to fit production and well capability as downhole conditions varied. Due to low rotating speed, no emulsion issues arose and run life performed by the equipment surpassed the original expectation of one year. To date, Shell has installed 12 all-metal PCPs at Orion field with no failures to date. One pump was pro-actively pulled for a liner re-completion.

MATHIEU RAE is the Thermal Production Engineering Lead for Shell’s Orion SAGD facility, having worked for Shell Canada Ltd. for five years in cold and thermal development. He earned a BS degree in mechanical engineering and a diploma in technology management and entrepreneurship from the University of New Brunswick in 2005.

LAURENT SEINCE is Vice President of PCM Canada, having worked in PCM’s oil and gas division for 15 years. He earned an MS degree in mechanical engineering from the Ecole Nationale Supérieure de Mécanique et des Microtechniques in France after which he worked for seven years in Alstom’s fluid mechanics division as a mechanical engineer and project manager.

MIKE MITSKOPOULOS works in technical support for Kudu Industries, where his work has focused on the all-metal PCP since its initial field trial in 2008. He previously spent 1½ years in Kudu’s Bonnyville, Alberta, service center working as a pump technician and lead hand. he earned a petroleum engineering diploma from the Northern Alberta Institute of Technology.