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Combining CHOPS and other production technologies

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CHOPS is not suitable for all heavy unconsolidated sandstone (UCSS) reservoirs. Recovery factors greater than 20% of OOIP are unusual; values of 10 to 16% are more common. However, combining CHOPS with other production technologies may increase ultimate recovery factors.

Hybrid production schemes

Through yield, dilation and liquefaction, and perhaps through channeling, CHOPS creates a large region of greatly enhanced permeability. Is it possible to exploit this with other technologies?

Fig. 1 shows a possible scheme of simultaneous development of a reservoir for CHOPS and SAGD.[1][2] The reservoir is at least 15 to 20 m thick. The recommended well spacing is approximately 5 times the reservoir thickness. CHOPS is started well before SAGD. The permeability-enhanced zone develops upward toward the top of the zone. SAGD wells are started after CHOPS has produced 12 to 14% of OOIP, then operated to maximize lateral migration of the steam chamber. When heat breakthrough occurs in a CHOPS well, the PC pump is removed and it is shut in. The high permeability should allow the SAGD process to access and exploit the oil in the reservoir quickly. After all, the natural limit on SAGD rate is the formation permeability. The CHOPS wells are converted to monitoring wells or process-control wells for inert gas injection or partially miscible gas placement (hybrid CHOPS-VAPEX-SAGD scheme). Clearly, many issues such as placement of perforations, repressurization approaches with the CHOPS wells (inert gas, miscible gas, hot water, steam), and details of sequencing must be addressed in practice.

Similarly, CHOPS can be combined with VAPEX and THAI. In all cases, enhanced permeability, high compressibility, and low lateral stress generated by CHOPS can be exploited, in principle, to increase production with horizontal well approaches.

Staged production schemes

CHOPS probably can never be used subsequent to other recovery schemes if the reservoir has been depleted of gas. Also, if a thermal process has been used, not only is gas depleted, but mineral and coke cementation also may have occurred, giving the sands enough cohesion to resist attempts at CHOPS.

However, in many cases, such as the Luseland example (see Case History in Luseland field, Saskatchewan), slow conventional production with some sand ingress was converted successfully to CHOPS. Whether this could ever be done successfully for horizontal wells (see Comparisons of cold production from horizontal wells and CHOPS wells) is uncertain because of well-cleaning costs, but CHOPS may be used in zones left untouched by drawdown from horizontal well production.

CHOPS is more suitable for use before other approaches. For example, cyclic steam-stimulation recovery factors are, at most, 20 to 25% of OOIP, but if CHOPS is used first, the low σh, high k, and high Cm zone will promote a far better conformance than CSS normally achieves. After a 15% CHOPS phase, the CSS process could produce an additional 15 to 20% of OOIP. After CHOPS, CSS should be successful because steam fractures will be better contained and "recompaction" drive[3] enhanced because of the presence of the large remolded zone.

Pressure pulse flow enhancement

Continuous pressure pulsing has been used to sustain production of heavy oil through CHOPS. This new approach involves continuous high-amplitude but low-frequency excitation of the liquid phase in an excitation well.[4] Although the database is still limited, all three excitation well cases completed to date have been economic successes. The aggressive pressure pulses sustain sand flux to offset wellbores, destabilize the interwell regions so that vertical stresses yield and dilate sands through shear, and overcome permeability channeling and perhaps collapse open channels so that conformance is improved.

Can heavy-oil fields be successfully waterflooded?

Despite a seemingly intractable mobility ratio (> 1,000), waterflooding has been used in heavy oil in Canada. Apparently, given the low cost of wells, enough maintenance of oil rate takes place to justify the practice because only a few percent (1 to 4% OOIP) additional oil is produced in this manner toward the end of a CHOPS project.

Waterflooding recently has been used along with aggressive pressure pulsing.[5] The inertial energy introduced by the pulsing helps overcome capillary blockages as well as reduces viscous fingering associated with water injection. This has assisted in stabilizing waterflood front conformance and increasing sweep efficiency

Extension of CHOPS concepts to high-rate oil and gas wells

Sand management principles that evolved from CHOPS were used in 1995 in modest offshore Adriatic Sea gas wells[6] and later in offshore North Sea high-rate oil wells.[7] In these cases, sand is not excluded. Wells are operated with small irregular sand bursts, properly managed to reduce risk. These wells are cheaper to complete and average 35 to 40% greater production than adjacent wells with gravel packs or sand screens. Preliminary well histories also suggest that intervention costs are reduced. The penalty for these economic benefits is required continuous monitoring and analysis, but in more than 200 wells with production rates as high as 4500 m3/d, there is only one outright failure of the method that required the use of sand exclusion methods.

Fig. 2 summarizes sand management principles. Two limits are shown: the sand-free line for rate vs. sand strength and an upper limit of either catastrophic sanding or facilities limitations. Sand 1 is the weakest sand in the stratum. It controls the production rate for "stable" sand bursts, which cause no well problems because they tend to decay and rarely recur. If the weakest sand is also a thin sand in the context of the producing interval, selective perforating can isolate it and perhaps generate additional production improvements (as for Sand 2).

Part of sand management is a sand-cleanup test, which is a protocol for aggressive well cleanup that deliberately surges the well at increasing flow rates until a sand burst enters. These bursts are not catastrophic well-blocking events; rather, they serve to unblock perforations and flush out wellbore fines or mineral blockages, thereby reducing mechanical skin effects. A well may have skin values of +5 to +10 before cleanup and values as low as −3 to −5 after cleanup. Effects on the productivity index are appreciable. Because the well is maintained on higher production rates after the cleanup, occasional sand bursts (5 to 50 kg) can take place every few days or weeks. These sand bursts are self-cleaning events that help sustain the low skin values.

The benefits of higher production rates, lower completion costs, and fewer interventions are substantial, but various design issues such as sand-influx detection and steel erosion have to be addressed. Another important advantage is that sand-management strategies do not ruin the well for later installation of sand-control methods (screens, gravel packs, etc.), whereas the reverse is almost never true, especially if there are behind-the-casing installations involving resin-coated sand. Thus, if sand management is not successful, the risk to the well life is minimal. Assessment of a well for sand management is a complex task requiring calculations of carrying capacity, erosive resistance of the production system, capacity to handle sand, and so on.[8]


  1. Dusseault, M. 1993. Cold Production And. Enhanced Oil Recovery. J Can Pet Technol 32 (9). PETSOC-93-09-01.
  2. Dusseault, M.B., Geilikman, M.B., and Spanos, T.J.T. 1998. Heavy Oil Production from Unconsolidated Sandstones Using Sand Production and SAGD. Presented at the SPE International Oil and Gas Conference and Exhibition in China, Beijing, China, 2-6 November 1998. SPE-48890-MS.
  3. Denbina, E.S., Boberg, T.C., and Rottor, M.B. 1991. Evaluation of Key Reservoir Drive Mechanisms in the Early Cycles of Steam Stimulation at Cold Lake. SPE Res Eng 6 (2): 207-211. SPE-16737-PA.
  4. Spanos, T., Davidson, B., Dusseault, M.B. et al. 1999. Pressure Pulsing At the Reservoir Scale: A New IOR Approach. Presented at the Annual Technical Meeting, Calgary, Alberta, Jun 14 - 18, 1999 1999. PETSOC-99-11.
  5. Dusseault, M., Davidson, B., and Spanos, T. 2000. Pressure Pulsing: The Ups And Downs of Starting a New Technology. J Can Pet Technol 39 (4). PETSOC-00-04-TB.
  6. Sanfilippo, F., Brignoli, M., Giacca, D. et al. 1997. Sand Production: From Prediction to Management. Presented at the SPE European Formation Damage Conference, The Hague, Netherlands, 2-3 June 1997. SPE-38185-MS.
  7. Dusseault, M.B., Tronvoll, J., Sanfilippo, F. et al. 2000. Skin Self-Cleaning in High-Rate Oil Wells Using Sand Management. Presented at the SPE International Symposium on Formation Damage Control, Lafayette, Louisiana, 23-24 February 2000. SPE-58786-MS.
  8. Tronvoll, J., Dusseault, M.B., Sanfilippo, F. et al. 2001. The Tools of Sand Management. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 30 September-3 October 2001. SPE-71673-MS.

Noteworthy papers in OnePetro

Tremblay, B. 2009. Cold Flow: A Multi-Well Cold Production (CHOPS) Model. Petroleum Society of Canada.

Istchenko, C., & Gates, I. D. 2012. The Well-Wormhole Model of CHOPS: History Match and Validation. Society of Petroleum Engineers.

Dusseault, M. B., & El-Sayed, S. 2000. Heavy-Oil Production Enhancement by Encouraging Sand Production. Society of Petroleum Engineers.

Dusseault, M. B. 2006. Sequencing Technologies to Maximize Recovery. Petroleum Society of Canada.

Dusseault, M. B. 2008. Oil Recovery and Technology Sequencing. Petroleum Society of Canada.

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 production rate increase mechanisms

CHOPS physical mechanisms

CHOPS operational and monitoring issues


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Cenk Temizel, Reservoir Engineer