Unconventional resources call for unconventional responses to artificial lift problems.

Progressing cavity pumps (PCPs) and electric submersible pumps (ESPs) are two artificial lift techniques being employed in a variety of new production applications. PCP pumps are particularly well suited to pumping higher viscosity, higher solids content and high gas-liquid ratio fluids under conditions that reduce the efficiency of other artificial lift systems. They can also offer lower capital investment and operating costs in some cases. The lower silhouette of a PCP drive unit, as compared to a conventional pump jack, reduces the visual impact of the system, an issue that is becoming increasingly important in environmentally sensitive areas.
All of these factors have combined to enhance the potential for PCP applications in a number of niche markets, including steam-assisted production of heavy oil and downhole separation and disposal of produced water, and in coalbed methane (CBM) well dewatering. At the same time, ESP pumps have seen a number of improvements in motors, gas separators, rotor/stator designs and variable-speed drives that enable these pumps to be deployed across a broader range of applications. In one case, ESPs are being enhanced in ways that make them more applicable to CBM water production. A number of examples of these new developments are highlighted below.
SAGD Field Tests
One potential problem with using PCPs for thermal recovery applications is the effect of high temperatures on the elastomer stator of the PCP. Conventional materials limit the use of these pumps to temperatures below about 250°F (121°C). Recent field tests of a new elastomer developed by Kudu Industries for use in their PCPs show promise for wider use of PCPs in high-temperature environments.
Steam-assisted gravity drainage (SAGD) is a thermal recovery technology developed for producing the heavy oil and bitumen resources of western Canada. The approach employs twin horizontal wells, one above the other, and a multi-phase steam injection and production process.
In the first phase, steam is circulated through both wells to preheat the surrounding reservoir. Then, steam is injected into the reservoir via the upper horizontal well, creating a "steam chamber" within the surrounding rock. The viscosity of the very low-gravity, high-viscosity bitumen and heavy oil in the rock is reduced, allowing the hot liquid to drain under the force of gravity towards the lower horizontal lateral, from which it and water are produced. Bottomhole temperatures during the steaming phase can range from 350°F to 460°F, and during the production phase from 210°F to 320°F.
EnCana is currently developing two of the four major SAGD projects in Canada. The Foster Creek project, producing about 15,000 b/d late last year, is currently ramping up to 20,000 b/d from 24 well pairs. The project ultimately could grow to 100,000 b/d by 2007. EnCana's Cristina Lake project is slated to produce another 10,000 b/d by 2003 and grow to 70,000 b/d by 2008. Suncor's Firebag project and PetroCanada's MacKay River project are also under way, with production of 30,000 b/d to 35,000 b/d from each expected to come onstream between 2003 and 2005. A significant number of smaller projects and pilots are also under way.
At EnCana's Senlac field in western Saskatchewan (previously a PanCanadian pilot project), lifting of heated oil and water from seven well pairs is currently carried out with gas lift. According to Sandeep Solanki, an engineer with EnCana's Onshore North America Division's Thermal Recovery Business Unit, this approach has several inherent problems. These include:
• wellhead and flow-line erosion (there can be up to 5% sand in the produced fluids);
• flow instability and slugging outside of a rather narrow range; and
• limitations based on compression capacity and fuel requirements for steam generation.
A pumping system would permit lower producing pressures (and thus a reduced steam-oil ratio), smaller sized separators and lower fluid velocities (smaller flow lines, fewer sand clean-outs and reduced slugging). While PCPs would be an ideal choice for this application, operating temperature limitations have precluded their use.
New elastomer field tests
According to Ray Mills, vice-president of Kudu Industries in Calgary, Alberta, the company has developed a new high-resiliency hydrogenated acrylonitrile-butadiene copolymer elastomer (Elastomer 198) that maintains its physical properties up to 320°F (160°C). This material has excellent abrasion resistance, good resistance to hysteresis and superior resistance to hydrogen sulfide and CO2. Elastomer 198 is the third generation of high-temperature elastomers Kudu Industries has tested.
The elastomer was first tested in a surface flow loop at 320°F for 3 months using an Orinoco heavy crude and performed as expected throughout the test. Solanki reports that, "The elastomer was then installed in a PCP in a SAGD producing well at Senlac, where it has operated without problem for over 2 months at temperatures ranging from 311°F to 249°F (155°C to 120°C). Over that time the system pumped about 945 b/d at a bottomhole pressure (BHP) of 650 psi, operating at about 300 RPM. Bottom sediment and water content of the produced fluid averaged about 30%."
EnCana's Solanki adds that additional extended field trials are currently under way. Ultimately, widespread use of high-temperature elastomers in SAGD applications will require their incorporation into large volume pumps (5,000 b/d to 9,500 b/d models) with higher power drives. In addition, the issue of rod wear in slightly deviated holes must be addressed. In the Senlac test well, the pump was set at 2,400 ft (732 m), just into the deviated portion of the hole, and 1-in. Corod was employed to mitigate wear.
Downhole separation and disposal
Another application for PCPs has been tested in Southern Alberta, also by EnCana and Kudu. Since late 2001 the company has been conducting a nine-well pilot project using PCPs to perform downhole water-gas separation and disposal. The technology is well suited for producing intervals of the Viking (Bow Island) sandstone, an uphole re-completion of wells originally targeting the Lower Mannville. Water from gas productive zones of the Viking is pumped from the casing using a PCP and a Chriscor Downhole Injection Tool, and discharged below a packer into a wet interval of the same formation. These wells produce between 35 and 350 Mcf/d of gas, but might produce hundreds of barrels of water over the same time period. This can amount to a significant handling and disposal cost. Also, the wells do not produce efficiently when slugging water.
Downhole separation and disposal improves the production efficiency and reduces operating costs, allowing the economic limit of these wells to be extended. According to Rex Matthias, the EnCana engineer currently responsible for this pilot, "The technology is good, but one must choose the applications carefully." Matthias reports that two of the nine wells are still producing, and that EnCana is evaluating the overall economic criteria for selecting additional candidate wells. "In an area with existing water disposal infrastructure, the benefit is not as great as in an area where downhole separation and disposal allows you to avoid those capital investments. But there are situations where this approach makes sense." In addition, Matthias notes that the footprint of a well with downhole separation and disposal is smaller (less piping and facilities) and that the low profile of PCP drive heads allows wells to be operated in areas with moving irrigation systems where pump jacks would be a barrier.
According to David Hill, downhole tools product manager with Kudu Industries, "Downhole separation and water disposal makes good sense in mature or low rate gas wells when they require frequent swabbing to maintain production, when water handling costs rise relative to the value of the gas produced, or when wells are not supported by an existing water handling infrastructure." Key to success is careful selection of candidate wells. It is particularly important to understand the pressures required for injection into the disposal zone and if they will exceed fracturing pressure or stuffing box limitations. Hill notes that Kudu currently has more than 100 systems in operation in Kansas, Oklahoma, Colorado, Canada and the Former Soviet Union.
ESP pump innovations
for CBM applications
Weatherford Artificial Lift Systems (WALS) has developed a patented version of their ESP: the CBM-ESP. This pump takes into account the special needs and combination of conditions required in CBM applications. It is designed and manufactured in a combination of compression fit and tapered configuration that allows it to handle abrasive materials, free gas and large variations in flow rate. After 3 months of lab and field-testing, a prototype was installed in a well in the Powder River Basin (where the expectations of run life with conventional ESPs are sometimes measured in weeks), and the new pump achieved a run life three times greater than average. "After being pulled, repaired and rerun, the pump was still performing as designed, with the major result being lower operating costs," said Bill Grubb, general manager, WALS ESP Systems. "Since then, more than 1,000 CBM-ESP pumps have been installed in over 100 different design configurations involving size, number of stages and construction materials."
Grubb reports that in addition to fines production, a regional problem facing CBM producers has been the reluctance of power companies in the Powder River Basin to allow large numbers of variable speed drives to be used. Due to the phenomenon of harmonics, momentary power supply fluctuations resulting in severe voltage spiking can lead to interruptions in the overall power supply system. Since a large portion of the operators in the Powder River Basin were using variable speed drives to help manage the variation in water production rates from CBM wells, it became clear that an alternative needed to be found.
After evaluating the operational characteristics of the Powder River Basin wells and the flexibility that a variable speed drive offered to operators, WALS developed the Weatherford Well Management System (WMS) surface unit. This system combines the use of back pressure to regulate flow with the use of a modern electronic control system to adjust production, approaching the ideal of continuous ESP operation. Following lab tests to prove the concept, field-testing was carried out in the Powder River Basin.
During the field tests, surface-monitoring equipment provided well performance parameters that were input into an electronic control system. Interactive software in the system controls the pump and optimizes its operation. Three wells were tested as part of the field test segment.
In the first case, a well operated with a variable speed drive ESP was producing 40 Mcf/d while the pump was cycling (stopping and starting) 25 times per day. The only change made to the well was the installation of the Weatherford WMS. After 3 days of operation, the well was producing 250 Mcf/d. The pump was running 24 hours per day and maintaining a fluid level 40 ft (12 m) above the pump. In the second test application, a well producing 50 Mcf/d with a variable speed drive-controlled ESP was cycling 40 times per hour. Within 2 days of the WMS installation, gas production peaked at 325 Mcf/d and cycling was reduced to four times per day.
In the third field test case, Grubb reports that the well was producing 25 Mcf/d, cycling 50 times per hour and being evaluated for abandonment. "After three days of operation, the WMS had reduced the well's cycle incidence from 50 times per hour to 5 times per day and increased gas production from 25 Mcf/d to 275 Mcf/d." Over a 30-day period the well stabilized, consistently making the 275 Mcf/d, at which point a decision was made to shut the Weatherford WMS off to evaluate the results. Within 36 hours, the cycle time increased to 50 times per hour and gas production became erratic, ranging from 20 Mcf/d to 30 Mcf/d. After a 2-week period, the WMS was turned back on and, within 36 hours, cycle time reverted to five times per day and gas production increased to a stabilized rate of 270 Mcf/d.
PCP's for downhole
CBM water disposal
PCPs have been used for some time in CBM applications in the United States. "When CBM production first began in the Black Warrior Basin in Alabama, PCPs were chosen for their ability to handle coal fines, frac sand and high fluid volumes at relatively low cost," said David Stuart, director of marketing with R&M Energy Systems. "There are still probably 900 to 1,000 PCPs operating in the Black Warrior." PCPs are rapidly finding a market in the Rocky Mountain CBM basins, particularly the Raton and Powder River Basins. In the Powder River, as the play moves westward, the need for pumps that can lift water from deeper coal seams increases. Stuart suggests that there are probably at least 2,000 PCPs in use in Rocky Mountain CBM projects.
Downhole separation and disposal of CBM-produced water using PCPs seems like it should have potential in plays where water disposal is becoming an environmental issue. But while there have been some tests of downhole disposal using conventional rod pumps, no PCP applications are currently under way. "There are a number of technical issues to overcome, chief of which involve rod friction and wear due to compression and a partially dry tubing string," Stuart said, "But several companies are investigating this technology."
Another issue is the necessary change in mindset. "Looking for a suitable downhole disposal zone and planning for its use has to start early on in the development stage of a field," said Jon Rudolph, principal with Produced Water Management Group LLC, in Colorado. "Once wells are drilled, it is probably too late to consider downhole disposal, even if it would have made good economic sense in the long run."
Rudolph points out that there have been a number of examples of downhole separation and disposal initiatives in East Central Oklahoma's Cherokee Basin CBM play, but with conventional rod pumping units. In each case, an up-hole re-completion of a coal zone at about 1,200 ft (366 m) was made in a depleted oil well. A 1 1/2-in. downhole pump was used to pump produced water from the casing/tubing annulus into the depleted oil reservoir disposal zone below a packer set below the coal seam, using the Reverse Flow Injection (RFI) System designed by Down Hole Injection Inc. In each case, the wells went from shut-in to producing 50-65 Mcf/d. About 20 CBM applications of these systems have been installed in the Cherokee Basin, injecting between 50 and 250 b/d of downhole separated water.
According to Rudolph, "Planning for downhole gas/water separation in advance when developing a new area provides the best economics."

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