The capability to transform economically marginal heavy oil wells into reliable, profitable producers is becoming increasingly important as low-gravity reserves account for an ever greater share of global oil supplies. Field implementation of a newly introduced technology indicates it could be a means to that end.

CHOPS

Operators in the Lloydminster region of Saskatchewan and Alberta have been implementing cold heavy oil production with sand (CHOPS) processes since at least the early 1980s and began transitioning to downhole progressive cavity pumps (PCPs) in the early 1990s to overcome the viscosity- and sand-related limitations of pump jack-driven pumping systems. But viscosity-induced production problems have persisted.

The variable viscosity of reservoir fluids from Cretaceous Mannville group geologic intervals can cause severe oil-water slugging downhole as the formation water migrates through and around the heavy oil. The highly viscous oil does not flow or load into the pump as easily as the free water, which leads to higher bottom solids and water (BS&W) readings at surface, low pump efficiencies, and high torque requirements. Solids production from the unconsolidated reservoir increases the severity of torque fluctuations on pumping assembly components. Produced sand typically settles and packs in and near the well bore or accumulates in production components and in flowlines connecting wellheads to tank batteries. This leads to high rates of equipment failure, unscheduled production interruptions, and an increased need for servicing and maintenance.

These issues conspire to undermine the economics of CHOPS projects in the Lloydminster area and have inspired a local saying: “If you’re producing heavy oil, you’re producing sand.”

A new dispersant chemistry designed to reduce the apparent viscosity of low-gravity crude oil in the well bore has been integrated into production operations in the past year at about a dozen wells producing low-gravity crude from early Cretaceous Mannville group geologic intervals composed of unconsolidated sandstones, silts, and shales. Operators have deployed the new chemistry in wells that had been achieving lower-than-expected production rates, requiring frequent servicing and maintenance intervention, and/or experiencing high rates of equipment failure.

Adding the new dispersant pushed production numbers consistently up. (Images courtesy of Champion Technologies)

How the chemistry works

When mixed with water and injected downhole, the new dispersant chemistry creates a water-external macro-emul- sion (or dispersion) in the reservoir near the well bore in which a water-wet film prevents heavy oil from adhering to surfaces of the rod string, downhole pump, or production tubing. Dispersed in the water-external macro-emulsion, reservoir fluids and sand enter the pump easily and are lifted to the surface more reliably; the steadier flow eases the stress on pumping assembly components. The emulsion is tight enough to lift sand up through production tubing to the surface and carry it through the flowline, but loose enough to allow production stream constituents to separate cleanly after reaching the storage tank.

Principal effects documented at wells being treated with the dispersant technology include drastically lower operating costs and incremental production gains up to 300%. Operating costs have been curtailed through a combination of pump torque reductions greater than 50%, increased well operating speeds greater than 100%, less sand accumulation in production equipment and flowlines, and less downtime while awaiting service or maintenance.

In addition, the emulsion can be resolved easily with a conventional emulsion breaker before sale, allowing producers to avoid paying purchasers’ crude treating fees. And residual derivative chemicals in sale oil following treatment have proven to have no discernable effects on separation facilities.

With only a small number of wells treated commercially, drawing conclusions about the long-term effectiveness of the new dispersant technology’s potential would be premature. But with the ease of integrating injection of the chemistry into an existing production system and low treatment costs, the technology is strengthening the competitiveness of CHOPS as a viable recovery option for low-gravity reserves.

A Champion representative rates the dispersant chemical injection rate.

Well field test

The new CHOPS chemical technology was put to the test on the 7-24 well in Morgan field in the Lloydminster area.The 7-24 well was drilled directionally at a 35-degree angle in July 2010 to a measured depth (MD) of 744 m (2,441 ft) and a true vertical depth of 611 m (2,005 ft). It was perforated between 689 m and 693 m (2,274 ft) MD in the Lloydminster member of the Mannville group. The Lloydminster sub-unit is an early Cretaceous formation up to 30 m (100 ft) thick com- posed of unconsolidated quartz sand with silt.

The well came online in August 2010 producing about 1 cu m/d of 11.7°API gravity crude. Viscosity of the low-gravity crude exceeded 120,000 centipoises (cPs). The average BS&W of produced fluids was 30%, with sand cuts as high as 15%.

Production from the well fluctuated, increasing to 7 cu m/d by December 2010, before dropping to 5 cu m/d in February 2011. In May 2011, the last month before a field test was initiated with the new dispersant chemistry, production averaged 9 cu m/d.

The high-viscosity crude created drag as it traveled up the 4½-in. production tubing, limiting the speed at which the producer could rotate the 15 Series PCP downhole to 65 rpm. Under normal operating conditions, the PCP requires 1,200 ft/lb of torque.

After the 7-24 well was serviced in June 2011, a treatment program was initiated in which 1,980 ppm (to produced oil) of the new dispersant chemistry, diluted in a volume of water equal to 30% of the produced total fluid (oil and water), was injected continuously down the annulus to the reservoir. At that time, the downhole PCP was upsized to a 27 Series.

The production response was immediate. Production for the full month of June averaged more than 13 cu m/d, followed by 16 cu m/d in July and 22 cu m/d in August.

In late August, the 7-24 well was serviced again and the PCP upsized once more to a 45 Series. Production in September averaged 26 cu m/d.

At the end of November, the PCP was running at 135 rpm, and the rod torque was at 800 ft/lb.

After deducting chemical program costs, the producer is realizing a net gain of more than US $4,000/day in increased oil sales, or $1.4 million per year.