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CHOPS production rate increase mechanisms

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The following four mechanisms are thought to be responsible for the significant oil-rate enhancement in cold heavy oil production with sand (CHOPS) wells.[1][2][3][4][5][6][7][8][9][10][11][12][13][14][15][16]

  • Fluid flow rate increases if the sand matrix is allowed to move because the Darcy velocity relative to the solid matrix increases with matrix movement.
  • As sand is produced from the reservoir, a zone of enhanced permeability is generated and grows outward, allowing a greater fluid flux to the wellbore.
  • A sharp pressure drop in highly viscous gassy oil leads to generation of a "foamy oil" zone, which aids continued sand destabilization and helps move solids and fluids toward the wellbore.
  • Solids motion in the near-wellbore environment eliminates fines trapping, asphaltene deposition, and scale development on the formation matrix outside the casing.

Darcy velocity increase with sand influx

In an immobile porous medium, the Darcy velocity, vf, is taken relative to a fixed reference frame. However, if the matrix is moving, the Darcy velocity is the differential velocity:


This effect can be substantial in several circumstances.

During early sand influx in viscous reservoirs (μ > 5000 cp), sand content may approach 40 to 45% by volume of the gas-free produced material. The reservoir is mined almost hydraulically, and sand flux is largely responsible for the flow enhancement. However, sand flux diminishes with time, and this effect gradually becomes less important.

If the dominant sanding mechanism is piping channel ("wormhole") growth at the advancing tip, the sand is liquefied at almost the same rate at which the heavy oil is entering the channel tip. Therefore, at the tip, the sand concentration in the fluid is high, and, during flow toward the wellbore, it is diluted progressively by fluid influx from adjacent reservoir zones. The farther the tip is from the wellbore, the more dilution occurs and the lower the produced sand cut becomes with time.

Sanding implies a continued liquefaction of the sand fabric. Because of the high viscosity, the velocity of the suspended sand grains, vs, is similar to or somewhat less than the fluid velocity, vf. The pressure gradient is


Here, dp/dl = the 1D pressure drop, μ = viscosity, and kp = a measure of the permeability of the sand-fluid mixture. Thus, little impedance to flow and small pressure drops arise if the solid phase is moving at the same rate as the fluid phase. Theoretical analyses suggest that this process can perhaps double the liquid rate at the well. This effect may remain important locally at the sites in the reservoir where sand is being liquefied.

Permeability enhanced zone development

Solids withdrawal through liquefaction and transport to the well creates "space" within the producing horizon. This space is not a void; it is a "remolded" zone of higher porosity (dilated) sand or it is filled with sand/water/oil/gas slurry. The growth of this remolded zone increases the apparent permeability of the wellbore region. With continued sand production, the well behaves as if it has an increasing radius with time. Assuming that the permeability of the remolded zone is much higher than the virgin formation, the enhancement effect may be expressed as


The remolded zone is unlikely to be a uniform zone with sharp boundaries. Fig. 1 shows the conceptual model considered to be more correct. There is a region near the wellbore in which high-porosity slurry exists, but, for the most part, the zone is viewed as a dilated, partially remolded region with diffuse gradational boundaries. Assuming that the sand in a cylinder dilates from 30 to 35% and that the overburden does not deflect downward, for each cubic meter of sand produced, 20 m3 of reservoir must dilate. If sand is produced mainly from channels rather than a cylindrical zone, the affected region may be much larger. After 100 to 300 m3 of sand has been produced, there is a remolded region of 1000 to 5000 m3, giving an increase of 50-fold to 100-fold in the effective well radius depending on the zone thickness. Production enhancement from this effect alone should approach 4-fold to 5-fold, providing other conditions remain the same.

The remolded zone porosity is indeterminate, but near-wellbore values of 42 to 44% have been calculated with through-the-casing compensated neutron logs. Occasional thin zones beneath shale caprock may register porosities of greater than 70%, indicating that small cavities can be sustained. These values were obtained from a well in which production had been inactive and free gas bubbles had gone back into solution. 44% is close to the maximum porosity for loose sands in grain-to-grain contact under low stress.

3D seismic data taken over a field from which sand was produced show somewhat elongated (elliptical) zones of low seismic velocity and high attenuation.[17] These zones are far larger than expected for an actual cavity, indicating that they are high-porosity zones in which stresses are low but grains are still in contact.

Foamy behavior in viscous oil

The third flow-enhancement mechanism is related to exsolution of dissolved gas. This is a type of solution-gas drive, but there are a number of important differences compared with conventional solution-gas behavior.

The heavy oils exploited by CHOPS have gas (> 90% CH4) in solution; the bubblepoint usually is at or near the pore pressure. Wells are subjected to aggressive drawdown and gas exsolves as bubbles; however, a continuous gas phase is not formed. The gas remains as bubbles that expand in response to pressure decline during flow to the well; hence, the bubbles act as an "internal drive," driving the slurry to the well at a velocity greater than predicted by conventional liquid flow theories (v ∝ 1/r). Because bubbles move with the fluid and discrete gas channels apparently do not develop, there is no direct drainage mechanism to deplete gas pressures far within the reservoir. Thus, gas/oil ratios (GORs) remain constant, and virgin pressures may be encountered in infill drilling only a few hundred meters from existing producing wells.

Foamy oil is developed in an induction zone in which bubbles nucleate in response to –Δp. Assuming that a bubble nucleates in a pore subjected to a pressure gradient, it will displace to block the pore throat, reducing the fluid-flow capacity of the throat and causing the local pressure gradient to rise. Fig. 2 illustrates how pore-throat blockage by bubbles leads to higher pressure gradients. This helps destabilize sand because it increases the local drag force on grains. In a porous medium, the hydrodynamic drag force can be expressed as

Here, the hydrodynamic body force, F, is proportional to the cross-sectional area, A, the grain width, w, and the pressure gradient, ∂p/∂l, corrected by a grain shape factor, S, of less than 1. Fig. 3 illustrates the mechanics. During the process, the gradient becomes large enough and the restraining forces small enough to cause the grains to mobilize. This process is known as liquefaction (or piping). A large hydrodynamic force can overcome small amounts of cohesion, although it is more likely that any true cohesion in UCSS is destroyed by the shearing and dilation that precede liquefaction.

Elimination of skin effects

Heavy oil contains asphaltenes, which are semisolid materials made of complex organic molecules. These materials precipitate with pressure decline and gas depletion, blocking pores and impairing the production rate of wells. In the interstices of typical heavy-oil reservoirs, there are fine-grained siliceous minerals (silica, clay minerals) that can be mobilized under high-pressure gradients and viscous drag forces. These minerals may accumulate at pore throats and form stable blockages.

If sand is kinematically free to shear, dilate, and undergo liquefaction, pore-throat blockages will continually clean themselves up. This has been confirmed in sand management approaches for high-rate oil wells (see Cold heavy-oil production with sand (CHOPS) and other production technologies for heavy UCSS reservoirs). Such wells develop more and more "negative skins" as blockages are cleaned up through sand bursts. Although not a physically correct view, a well on CHOPS may be viewed as having a massively "negative" skin.

Change of mechanisms with time

During early production, flow distance is short, pressure gradients are large, and sanding rates are high. The effect of sand flow increasing fluid flux dominates enhancement. Foamy-oil processes are developing near the wellbore, aiding destabilization; high initial sand cuts and gas contents in CHOPS wells confirm this.

After approximately 100 to 300 m3 of sand production, the drainage area is large, and larger quantities of oil can slowly ooze across interfaces under the flow gradients. Sand is destabilized locally, but the second process (large drainage area) now dominates fluid flow. Foamy-oil behavior helps drive fluids toward the wellbore and helps destabilize sand, particularly in local zones in which pressure gradients are high. Gas/oil ratios (GORs) remain constant, which is an important and revealing fact.

In the late life of a CHOPS well, after more than 1000 m3 of sand has been produced, solution-gas-drive depletion begins. GOR values slowly climb, indicating that a connected gas phase or a small gas cap has formed, as indicated by gas slugging in older wells. Water influx is more likely because of coning effects and the large, permeable, near-wellbore region. The CHOPS process can attenuate and decay, and the disturbed, remolded zones can interact between wells.

Apparently, the dominant mechanisms evolve during the CHOPS process. However, if sanding ceases, oil rates always drop precipitously. Sand recompaction and perforation blockage create traps for asphaltenes and clays, almost totally blocking fluid production. In practice, when a well suddenly ceases production without precursor phase changes (e.g., sudden water increase), workover strategies focus on:

  • Reopening perforations
  • Perturbing the formation
  • Reducing capillary effects.

Because of their higher density, sand particle flow may be retarded slightly during flow because of inertial effects, and there is a tendency for larger particles to settle more rapidly in the near-wellbore vicinity. Larger particles also arch around perforation openings more effectively. This hydrodynamic sorting may be responsible for the sharp drops in sand and oil production rates often observed in stable producing wells.


kp = permeability of the sand-fluid mixture
Q = production rate, L3/t, m3/d
Qo = initial production rate, L3/t, m3/d
r = radius (from the center of a circular opening or well), L, m
ro = initial effective well radius before sanding, L, m
vf = fluid velocity, L/t, m/s
vs = solid (mineral) velocity, L/t, m/s
μ = viscosity, m/Lt, cp


  1. Dusseault, M.B. and Santarelli, F.J. 1989. A Conceptual Model for Sand Production in Poorly-Consolidated Sandstones. Proc., ISRM-SPE Intl. Symposium Rock at Great Depth, Pau, France, Balkema, Rotterdam, 2.
  2. Smith, G.E. 1988. Fluid Flow and Sand Production in Heavy-Oil Reservoirs Under Solution-Gas Drive. SPE Prod Eng 3 (2): 169-180. SPE-15094-PA.
  3. Yeung, K.C. 1995. Cold Flow Production of Crude Bitumen at the Burnt Lake Project, Northeastern Alberta, Canada. Proc., 6th UNITAR Conf. on Heavy Crude and Tar Sands, Houston.
  4. Guo, F. et al. 1997. Heavy Oil Flow Under Solution Gas Drive: Non-Thermodynamic Equilibrium. Proc., CIM Petroleum Society 48th Annual Technical Meeting, Calgary, paper 97-127.
  5. Loughead, D.J. and Saltuklaroglu, M. 1992. Lloydminster Heavy Oil Production: Why So Unusual? 1992 Heavy Oil and Oil Sands Technology Symposium, Calgary.
  6. Maini, B.B., Sarma, H.K., and George, A.E. 1993. Significance of Foamy-oil Behaviour In Primary Production of Heavy Oils. J Can Pet Technol 32 (9). PETSOC-93-09-07.
  7. Dusseault, M.B. 1998. Canadian Heavy Oil Production Experience Using Cold Production. Proc., Trinidad and Tobago Biennial SPE Conference, Available on CD-ROM from SPE Trinidad and Tobago Section.
  8. Chalaturnyk, R.J., Wagg, B.T., and Dusseault, M.B. 1992. The Mechanisms of Solids Production in Unconsolidated Heavy-Oil Reservoirs. Presented at the SPE Formation Damage Control Symposium, Lafayette, Louisiana, 26-27 February 1992. SPE-23780-MS.
  9. Geilikman, M.B., Dusseault, M.B., and Dullien, F.A. 1994. Sand Production as a Viscoplastic Granular Flow. Presented at the SPE Formation Damage Control Symposium, Lafayette, Louisiana, 7-10 February 1994. SPE-27343-MS.
  10. Geilikman, M.B., Dusseault, M.B., and Dullien, F.A.L. 1994. Sand Production and Yield Propagation Around Wellbores. Proc., CIM Petroleum Society 45th Annual Technical Meeting, Calgary, paper 94-89.
  11. Geilikman, M.B., Dusseault, M.B., and Dullien, F.A.L. 1994. Fluid-saturated solid flow with propagation of a yielding front. Presented at the Rock Mechanics in Petroleum Engineering, Delft, Netherlands, 29-31 August 1994. SPE-28067-MS.
  12. Geilikman, M.B., Dusseault, M.B., and Dullien, F.A.L. 1995. Dynamic Effects of Foamy Fluid Flow in Sand Production Instability. Presented at the SPE International Heavy Oil Symposium, Calgary, Alberta, Canada, 19-21 June 1995. SPE-30251-MS.
  13. Geilikman, M.B. and Dusseault, M.B. 1997. Fluid-Rate Enhancement from Massive Sand Production in Heavy Oil Reservoirs. J. of Petroleum Science & Engineering 17: 5.
  14. Geilikman, M.B. and Dusseault, M.B. 1997. Dynamics of Wormholes and Enhancement of Fluid Production. Proc., CIM Petroleum Society 48th Annual Technical Meeting, Calgary, paper 97-09.
  15. Shen, C. and Batycky, J. 1996. Some Observations of Mobility Enhancement of Heavy Oils Flowing Through Sand Pack Under Solution Gas Drive. Proc., CIM Petroleum Society 47th Annual Technical Meeting, Calgary, paper 96-27.
  16. Metwally, M. and Solanki, S. 1955. Heavy Oil Reservoir Mechanism, Lindbergh and Frog Lake Fields, Alberta, Part I: Field Observations and Reservoir Simulation. Proc., CIM Petroleum Society 46th Annual Technical Meeting, Banff, Alberta, paper 95-63.
  17. Mayo, L. 1996. Seismic Monitoring of Foamy Heavy Oil, Lloydminster, Western Canada. Proc., 66th Annual Intl. Meeting of the Soc. of Exploration Geophysicists, 2091.

Noteworthy papers in OnePetro

Dusseault, M. B., Ma, Y., Xu, B., Liang, C. X., & Wu, G. 2002. CHOPS in Jilin Province, China. Society of Petroleum Engineers.

Rangriz Shokri, A., & Babadagli, T. 2012. An Approach To Model CHOPS (Cold Heavy Oil Production with Sand) and Post-CHOPS Applications. Society of Petroleum Engineers.

Han, G., Bruno, M., & Dusseault, M. B. 2007. How Much Oil You Can Get From CHOPS. Petroleum Society of Canada.

Han, G., Bruno, M., & Dusseault, M. B. 2004. How Much Oil You Can Get From CHOPS. Petroleum Society of Canada.

Dusseault, M. B., Spanos, T., & Davids, B. 1999. A New Workover Tool For CHOP Wells. 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 physical mechanisms

Combining CHOPS and other production technologies

CHOPS reservoir assessment and candidate screening

CHOPS operational and monitoring issues

Heavy oil


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