CHOPS case histories

Cold heavy oil production with sand (CHOPS) is a relatively recent technology. As such, only a few case histories of its application over a number of years have been published. Nonetheless, those that are available provide insight into the application of this technology.

Luseland field, Saskatchewan

A detailed Luseland field case history has been published. It had a long history (12 to 15 years) of slow production with reciprocating pumps, an attempt to produce with horizontal wells (6 wells, all failures), and then a conversion to CHOPS through reperforation and progressing cavity (PC) pump installation.

Table 1 shows basic field parameters. Fig. 1 shows the 1982 to 2003 production history of the field. Approximately the same number of wells has been on production since 1984; therefore, the majority of the production increase can be ascribed to flow-rate enhancement as the result of CHOPS.

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  Table. 1-Luseland field parameters.

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  Fig. 1-Luseland production history from 1982 to 1998.

Figs. 2 through 4 are individual well production plots that show increases of up to 10-fold in oil rates for individual wells. These are not new wells. They are conversions that gradually were operated more aggressively; therefore, they show production histories different from those illustrated in Fig. 5. Fig. 6 shows a less successful conversion to CHOPS.

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  Fig. 2-CHOPS Well 5/4, Luseland field, Saskatchewan.

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  Fig. 3-CHOPS Well 3/17, Luseland field, Saskatchewan.

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  Fig. 4-CHOPS Well 14/8, Luseland field, Saskatchewan.

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  Fig. 5-Production profile for a typical CHOPS well. (Actual data are smoothed.). Same as Fig. 2 in Typical cold heavy-oil production with sand (CHOPS) well behavior

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  Fig. 6-CHOPS Well 13/8, Luseland field, Saskatchewan.

In 1998, approximately 10,000 m³ of sand were produced with approximately 200,000 m³ of oil and 120,000 m³ of water. Annual oil production leveled and then declined after 1999. Overall, rates went from 2 to 8 m³/d pre-CHOPS (1991) to 5 to 50 m³/d (average of 21.6 m³/d/well in 1998) for an overall 4.9-fold increase. Expected per-well recovery went from 3 to 8% to 12 to 25% oil originally in place (OOIP). Although water production has increased, the water-to-oil ratio (WOR) in 2000 was lower than in 1994. Sand-handling requirements have increased 10-fold as oil production increased approximately 5-fold. In the most productive wells, the gas/oil ratio (GOR) has remained roughly constant or climbed only slowly since CHOPS was implemented.

Various operational and workover strategies were changed to cope with sand production. For example, in some cases, 3.5-in. tubing was changed to 4.5-in. tubing to cope with higher torques as sand influx increased. Sand-handling costs dominate operating expenses (> 30%), but because oil production is much higher, unit costs have dropped to less than half [ i.e., from Canadian $65 to 80/m³ to $20 to 40/m³ (per-well basis)] . As of 2003, the most productive wells in this field had produced more than 700,000 cumulative barrels of heavy oil, and the average of the original wells has exceeded 250,000 barrels. These are remarkable values for viscous oil produced without thermal stimulation.

Comparisons of cold production from horizontal wells and CHOPS wells

Horizontal wells have been used widely for heavy-oil production in the last decade. The question arises: are horizontals, perhaps with multilaterals, better for heavy-oil production? Issues of relative performance, absolute performance, and implementation of follow-on technologies complicate the answer. A limited study was carried out *

in four different fields in which horizontal wells are adjacent to vertical wells (Plover Lake, Lindbergh, Cactus Lake, and Luseland). Table 2 presents specific data for the Plover Lake field.

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  Table 2-Plover Lake Vertical and Horizontal Wells Comparison.

Plover Lake field is a Bakken formation unconsolidated sandstone (UCSS) reservoir similar to the Luseland field in all aspects, except that the average pay is 20 to 25% thinner. Table 2 shows the production data for 10 wells (four vertical and six horizontal) from the same section (one square mile).

The horizontal wells first used steam in a line drive from vertical wells to drive oil toward the horizontal producers. The performance of the horizontal wells, even with steamdrive, did not match the performance of the vertical wells in terms of total oil or lifespan. The best of the six horizontal wells produced a total of approximately 157,000 bbl; the best vertical well produced 265,990 bbl and was still producing successfully when the data were collected. The horizontal wells displayed higher water/oil ratios (WORs), attributed by the operator to the greater odds of proximity to active water. Vertical CHOPS wells in other areas of this field generally have performed even better.

Lindbergh field is a thin (4 to 8 m), Cretaceous, heavy-oil field with approximately 10,000 cp viscosity oil in fine-grained 30% porosity sand approximately 600 m deep. Fig. 5.37 presents a sample plot of production from the Lindbergh field for a vertical well, and Fig. 5.38 presents a sample plot of production from the Lindbergh field for a horizontal well. These are new wells, not converted wells. When all costs are considered, it appears that in most heavy-oil fields in which the viscosity is less than 15,000 cp, CHOPS is far more profitable than horizontal wells.

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  Fig. 7-Vertical well in Lindbergh field, Alberta.

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  Fig. 8-Horizontal well in Lindbergh field, Alberta.

In Plover Lake field as well as Lindbergh and Luseland fields, attempts to achieve cold production from horizontal wells were economic failures, but in fields with different geology and lower viscosity (e.g., Cactus Lake, Amber Lake, Pelican Lake), horizontal wells have been successful. However, when the economics are compared carefully, it appears that CHOPS vertical wells provide more total oil (albeit more slowly), lower capital expenditures, and lower WORs. For example, in Pelican Lake and Amber Lake fields, production declines for 1000-m-long horizontal wells have been 35 to 45%, indicating a short well life.

* El-Sayed, S. and Dusseault, M.: unpublished data and report (2000).

Noteworthy papers in OnePetro

Istchenko, C., & Gates, I. D. 2012. The Well-Wormhole Model of CHOPS: History Match and Validation. Society of Petroleum Engineers. http://dx.doi.org/10.2118/157795-MS

Jayaraman, B., Zhang, D., Vanderheyden, W. B., & Ma, X. 2013. Multiscale Simulation of CHOPS Wormhole Networks. Society of Petroleum Engineers. http://dx.doi.org/10.2118/163603-MS

Han, G., Bruno, M., & Dusseault, M. B. 2007. How Much Oil You Can Get From CHOPS. Petroleum Society of Canada. http://dx.doi.org/10.2118/07-04-02

Wang, R., Yuan, X., Tang, X., Wu, X., Zhang, X., Wang, L., & Yi, X. 2011. Successful Cold Heavy Oil Production with Sand (CHOPS) Application in Massive Heavy Oil Reservoir in Sudan: A Case Study. Society of Petroleum Engineers. http://dx.doi.org/10.2118/150540-MS

Rangriz Shokri, A., & Babadagli, T. 2012. Evaluation of Thermal/Solvent Applications With And Without Cold Heavy Oil Production with Sand (CHOPS). Society of Petroleum Engineers. http://dx.doi.org/10.2118/158934-MS

External links

Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro

See also

Cold heavy oil production with sand

CHOPS reservoir assessment and candidate screening

CHOPS operational and monitoring issues

CHOPS production rate increase mechanisms

CHOPS physical mechanisms

Combining CHOPS and other production technologies

PEH:Cold_Heavy-Oil_Production_With_Sand

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Cenk Temizel, Reservoir Engineer