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Formation damage from fines migration

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Fines migration is a recognized source of formation damage in some production wells, particularly in sandstones. [1][2] This can challenging to diagnose. This page discusses the potential for fines migration as a source of formation damage.

Identifying damage caused by fines migration

Direct evidence of fines-induced formation damage in production wells is often difficult to come by. Although most other forms of formation damage have obvious indicators of the problem, the field symptoms of fines migration are much more subtle. Indirect evidence such as declining productivity over a period of several weeks or months is the most common symptom. This reduction in productivity can usually be reversed by mud-acid treatments. A large number of wells around the world follow these patterns of reduction of productivity followed by significant improvements when subjected to a mud-acid treatment. This behavior most often suggests a buildup of fines in the near-wellbore region over a period of time. Field studies and laboratory experiments have indicated that the fines causing the permeability reduction include:

  • Clays
  • Feldspars
  • Micas
  • Plagioclase

Because the mobile fines are made up of a wide variety of minerals, the clay content of the reservoir may not always be a good indicator of the water sensitivity of the formation.

Low salinity brines

Core flow tests conducted in the laboratory clearly show that if low-salinity (< 2%) brines are injected into water-sensitive rocks, large reductions in permeability (up to a factor 500) are obtained (Fig. 1). [3][4][5][6] It is now well established that this dramatic reduction in permeability is almost entirely a result of fines migration. Evidence is shown clearly in Fig. 1. Reversal of flow results in a temporary increase in permeability as the fines plug pores in the reverse flow direction.

Fine-grained minerals are present in most sandstones and some carbonates. They are not held in place by the confining pressure and are free to move with the fluid phase that wets them (usually water). They remain attached to pore surfaces by electrostatic and van der Waals forces. At "high" (> 2%) salt concentrations, the van der Waals forces are sufficiently large to keep the fines attached to the pore surfaces. As the salinity is decreased, the repulsive electrostatic forces increase because the negative charge on the surfaces of the pores and fines is no longer shielded by the ions. When the repulsive electrostatic forces exceed the attractive van der Waals forces, the fines are released from pore surfaces. [7] There is a critical salt concentration below which fines are released. [3][7] The typical magnitude of the critical salt concentration is in the range of 5,000 to 15,000 ppm (1.5%) sodium chloride. For divalent ions, this concentration is significantly lower. If a water-sensitive sandstone is exposed to brine with a salinity below the critical salt concentration, fines are released, and significant reductions in permeability are observed (Fig. 1).

Fluid velocity

Fines migration can also be induced by mechanical entrainment of fines, which can occur when the fluid velocity is increased above a critical velocity. [6][7][8][9][10][11] Gruesbeck and Collins, [6] among others, have measured the critical velocity for sandstones. Typical reported values of critical velocities are in the range of 0.02 m/s. This translates into modest well flow rates for most oil and gas wells.

It has been experimentally observed that critical flow velocities for fines migration are lower when the brine phase is mobile. Critical velocities are an order of magnitude higher when the brine is at a residual saturation. This implies that fines migration will be more important with the onset of water production in a well, which is indeed the case. It is often observed that well productivities decline much more rapidly after the onset of water production. In such instances, more frequent acid treatments are needed to maintain production after water breakthrough.

Wettability of rock

The extent of permeability reduction observed is also a function of the wettability of the rock. More oil-wet rocks tend to show less water sensitivity, maybe because the fines are partially coated with oil and are not as readily accessible to the brine. Significantly smaller reductions in permeability are observed when the rock is made less water-wet. [5][11]

Other causes

The above observations imply that fines migration can be induced by any operation that introduces "low" (< 2%) -salinity or "high" (> 9%) -pH fluids into a water-sensitive formation. Fines migration can also be induced by "high" flow rates in the near-wellbore region, particularly in wells producing water. Examples of such operations include loss of freshwater-mud filtrate or completion fluid to the formation, steam injection in a huff 'n' puff operation for recovering heavy oil, water injection from a freshwater source, high well production rates (flow velocities above the critical velocity), and water breakthrough in production wells.

Prevention

To prevent fines migration and clay swelling, various chemical treatments have been designed. These include polymers containing quaternary ammonium salts, [12] hydrolyzable metal ions such as zirconium oxychloride, [13] hydroxy-aluminum, [14] and polymerizable ultrathin films. [15]

Each of these methods relies on coating the fines (which are usually negatively charged) with large polyvalent cations that can attach irreversibly to the mineral surfaces. When the electrostatic charges on the fines are neutralized, the likelihood of fines migration is reduced significantly. Fines-stabilizing chemicals have been used in treatments such as acidizing, gravel packing, and fracturing. The effectiveness of such treatments is discussed extensively in Borchardt[16].

References

  1. Gray, D.H. and Rex, R.W. 1996. Formation Damage in Sandstones Caused by Clay Dispersion and Migration. Clays, Clay Minerals 14 (1): 355.
  2. Muecke, T.W. 1979. Formation Fines and Factors Controlling Their Movement in Porous Media. J Pet Technol 31 (2): 144-150. SPE-7007-PA. http://dx.doi.org/10.2118/7007-PA
  3. 3.0 3.1 3.2 Khilar, K.C. and Fogler, H.S. 1983. Water Sensitivity of Sandstones. SPE J. 23 (1): 55-64. SPE-10103-PA. http://dx.doi.org/10.2118/10103-PA
  4. Valdya, R.N. and Fogler, H.S. 1992. Fines Migration and Formation Damage: Influence of pH and Ion Exchange. SPE Prod Eng 7 (4): 325-330. SPE-19413-PA. http://dx.doi.org/10.2118/19413-PA
  5. 5.0 5.1 Sarkar, A.K. and Sharma, M.M. 1990. Fines Migration in Two-Phase Flow. J Pet Technol 42 (5): 646–652. SPE-17437-PA. http://dx.doi.org/10.2118/17437-PA
  6. 6.0 6.1 6.2 Gruesbeck, C. and Collins, E. 1982. Entrainment and Deposition of Fine Particles in Porous Media. SPE J. 22 (6): 847–856. SPE-8430-PA. http://dx.doi.org/10.2118/8430-PA
  7. 7.0 7.1 7.2 Sharma, M.M., Yortsos, Y.C., and Handy, L.L. 1985. Release and Deposition of Clays in Sandstones. Presented at the SPE Oilfield and Geothermal Chemistry Symposium, Phoenix, Arizona, 9-11 March 1985. SPE-13562-MS. http://dx.doi.org/10.2118/13562-MS
  8. Das, S.K., Sharma, M.M., and Schechter, R.S. 1995. Adhesion and Hydrodynamic Removal of Colloidal Particles From Surfaces. Particle Science and Technology 13: 227.
  9. Chamoun, H. et al. 1992. Factors Controlling the Hydrodynamic Detachment of Particles from Surfaces. J. Colloid and Interface Science 147 (4).
  10. Sharma, M.M. and Yortsos, Y.C. 1987. Fines Migration in Porous Media. AIChE J. 33 (10): 1654.
  11. 11.0 11.1 Freitas, A.M. and Sharma, M.M. 1997. Effect of Surface Hydrophobicity on the Hydrodynamic Detachment of Particles From Surfaces. Langmuir 15: 2466.
  12. Borchardt, J.K., Roll, D.L., and Rayne, L.M. 1984. Use of a Mineral Fines Stabilizer in Well Completions. Presented at the SPE California Regional Meeting, Long Beach, California, 11-13 April 1984. SPE-12757-MS. http://dx.doi.org/10.2118/12757-MS
  13. Peters, F.W. and Stout, C.M. 1977. Clay Stabilization During Fracturing Treatments With Hydrolyzable Zirconium Salts. J Pet Technol 29 (2): 187-194. SPE-5687-PA. http://dx.doi.org/10.2118/5687-PA
  14. Coppel, C.P., Jennings Jr., H.Y., and Reed, M.G. 1973. Field Results From Wells Treated With Hydroxy-Aluminum. J Pet Technol 25 (9): 1108-1112. SPE-3998-PA. http://dx.doi.org/10.2118/3998-PA
  15. Sharma, B.G. and Sharma, M.M. 1994. Polymerizable Ultra-Thin Films: A New Technique for Fines Stabilization. Presented at the SPE Formation Damage Control Symposium, Lafayette, Louisiana, 7-10 February 1994. SPE-27345-MS. http://dx.doi.org/10.2118/27345-MS
  16. Borchardt John, K. 1989. Cationic Organic Polymer Formation Damage Control Chemicals. In Oil-Field Chemistry, 396, 396, 10, 204-221. ACS Symposium Series, American Chemical Society. http://dx.doi.org/10.1021/bk-1989-0396.ch010

Noteworthy papers in OnePetro

Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read

F.O. Stanley, BJ Services, S.A. Ali, Chevron USA Production Co., and J.L.Boles, BJ Services, 2013. Laboratory and Field Evaluation of Organosilane as a Formation Fines Stabilizer. Paper SPE 29530 presented at the Production Operations Symposium held in Oklahoma City, OK, U.S.A, 2-4 April 1995. http://dx.doi.org/10.2118/29530-MS

External links

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See also

Formation damage

PEH:Formation_Damage

Category