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Formation damage in injection wells
While formation damage is typically a problem affecting the productivity of well, it can also pose problems for injection. Understanding the causes of this type of formation damage is important so that efforts to prevent it can be undertaken. This page discusses the types of formation damage that affect injection wells.
Water is commonly injected into formations for three primary reasons:
- Pressure maintenance
- Water disposal
In such projects, the cost of piping and pumping the water is determined primarily by reservoir depth and the source of the water. However, water treatment costs can vary substantially, depending on the water quality required. In most cases, the well injectivity is a crucial factor in determining the cost of water injection. Maintaining high injectivities over long periods of time is extremely important for all water injection projects.
Historically, a great deal of expense and effort have been expended in treating water to ensure that very-high-quality water is being injected so that the injectivity of the well can be maintained over a long period of time.
Causes of formation damage
- Total dissolved solids in the injection water
- Total suspended solids (solids and oil droplets) in the injection water
The salinity and ion content in the injection water control two types of formation damage in an injection well:
- Freshwater sensitivity of the formation
- Precipitation of inorganic scale
In water-sensitive formations, if fresh water is being injected from a nearby lake or river, caution must be exercised to ensure that fines migration is not a major factor. This can be achieved by ensuring that the salinity is above the critical salt concentration for the rock. Injection wells are usually less susceptible to fines-migration problems than production wells, because the fines being generated are pushed away from the wellbore, leading to less severe impairment in the near-wellbore region and therefore relatively small losses in injectivity. In some instances in which the reservoir contains large proportions of clays and fines, severe injectivity losses may be experienced when injecting below the critical salt concentration.
Scales and precipitates
The precipitation of inorganic scale is a major concern when injecting brines with a high concentration of divalent ions. The hardness of the injection water is a good indicator of its scaling tendency. Should the water analysis indicate large concentrations of calcium, magnesium, iron, or barium, a water treatment facility that softens the water may be required. This is also an issue when injecting seawater into formations that contain brines with high salinity.
Large persistent drops in injectivity are expected when inorganic scales are formed in injection wells. Most field experience, however, indicates that the injection fluid quickly displaces the native brines away from the near-wellbore region with very little mixing. Inorganic scale precipitation resulting from incompatibility between the injection and reservoir brine is therefore not usually an issue for most injection wells. Geochemical interactions between injected fluids and the reservoir minerals can sometimes result in the formation of insoluble precipitates. Scale precipitation can also be induced by changes in:
- State of oxidation of the brine
The formation of insoluble iron precipitates as a result of corrosion is a common source of damage in injection wells. These precipitates, mixed with other organic material, can result in severe and irreversible reductions in well injectivity. Careful analysis of both the formation brines and injected fluids and a check of the reservoir mineralogy are necessary. Checking for compatibility and ensuring that inorganic scale precipitation does not occur at reservoir temperature and pressure conditions are important when any water injection program is planned.
Solids and oil droplets
The presence of solids and oil droplets in the injection fluid can result in severe and rapid declines in injectivity.  If the injection pressure is below the fracture gradient and if fracturing is undesirable from a reservoir engineering or environmental point of view, small concentrations of solids can result in rapid reductions in well injectivity. As an example, 5 ppm of solids being injected into a well at 10,000 B/D computes to 45 kg of solids being injected every day. This large volume of solids can result in severe and rapid plugging of the injection well in a relatively short duration. Field experience in many parts of the world suggests that matrix injection of clean brines containing 3 to 5 ppm of suspended solids results in injection well half-lives (time it takes for injectivity to decline to half its value) of 3 to 6 months. Fig. 1 shows the injectivity of a well in the offshore Gulf of Mexico. Seawater was being injected into this well at the rates indicated. As the figure shows, despite the relativity good quality of the water, a rapid reduction in injectivity was observed in this and other wells in this field. This reduction led to costly stimulation and workover operations in these subsea wells.
Fig. 1—Behavior of Well A10: (a) injectivity decline; (b) pressure and rate data.
In other field experiences, water has been injected into injection wells with minimal impact on injectivity. A good example of this type of injection well behavior is the injection of produced water in Prudhoe Bay field in Alaska, where 2,000 ppm oil plus solids in the injection water has been routinely injected with relatively little impact on well injectivity. The apparent lack of formation damage is a consequence of thermally induced injection well fractures that propagate hundreds of meters into the formation.  A great deal of work has been done to study the impact of water quality on the growth of fractures in water injection wells and the impact of injection well fractures on reservoir sweep and oil recovery. 
When fracturing injection wells is undesirable or unacceptable, the quality of the injection water plays an important role in determining well injectivity or formation damage in injection wells. Various water clarification devices are available, such as:
- Sedimentation tanks
- Sand filters
- Cartridge filters
- Flotation devices
These facilities significantly prolong the life of water injection wells and significantly reduce the formation damage. An economic analysis is thus necessary to ensure that the benefits are greater than the costs.
- Barkman, J.H. and Davidson, D.H. 1972. Measuring Water Quality and Predicting Well Impairment. J Pet Technol 24 (7): 865–873. SPE-3543-PA. http://dx.doi.org/10.2118/3543-PA
- Eylander, J.G.R. 1988. Suspended Solids Specifications for Water Injection From Coreflood Tests. SPE Res Eng 3 (4): 1287-1294. SPE-16256-PA. http://dx.doi.org/10.2118/16256-PA
- Sharma, M.M., Pang, S., Wennberg, K.E. et al. 1997. Injectivity Decline in Water Injection Wells: An Offshore Gulf of Mexico Case Study. Presented at the SPE European Formation Damage Conference, The Hague, The Netherlands, 2–3 June. SPE-38180-MS. http://dx.doi.org/10.2118/38180-MS
- van Oort, E., van Velzen, J.F.G., and Leerlooijer, K. 1993. Impairment by Suspended Solids Invasion: Testing and Prediction. SPE Prod & Fac 8 (3): 178–184. SPE-23822-PA. http://dx.doi.org/10.2118/23822-PA
- Wennberg, K.E. and Sharma, M.M. 1997. Determination of the Filtration Coefficient and the Transition Time for Water Injection Wells. Presented at the SPE European Formation Damage Conference, The Hague, Netherlands, 2-3 June 1997. SPE-38181-MS. http://dx.doi.org/10.2118/38181-MS
- Pang, S. and Sharma, M.M. 1997. A Model for Predicting Injectivity Decline in Water-Injection Wells. SPE Form Eval 12 (3): 194-201. SPE-28489-PA. http://dx.doi.org/10.2118/28489-PA
- Perkins, T.K. and Gonzalez, J.A. 1985. The Effect of Thermoelastic Stresses on Injection Well Fracturing. SPE J. 25 (1): 78–88. SPE-11332-PA. http://dx.doi.org/10.2118/11332-PA
- Detienne, J.-L., Creusol, M., Kessler, N. et al. 1998. Thermally Induced Fractures: A Field-Proven Analytical Model. SPE Res Eval & Eng 1 (1): 30-35. SPE-30777-PA. http://dx.doi.org/10.2118/30777-PA
- Martins, J.P., Murray, L.R., Clifford, P.J. et al. 1995. Produced-Water Reinjection and Fracturing in Prudhoe Bay. SPE Res Eng 10 (3): 176-182. SPE-28936-PA. http://dx.doi.org/10.2118/28936-PA
- van den Hoek, P.J., Matsuura, T., de Kroon, M. et al. 1996. Simulation of Produced Water Re-Injection Under Fracturing Conditions. Presented at the European Petroleum Conference, Milan, Italy, 22–24 October. SPE-36846-MS. http://dx.doi.org/10.2118/36846-MS
- Paige, R.W. and Murray, L.R. 1994. Re-injection of produced water - Field experience and current understanding. Presented at the Rock Mechanics in Petroleum Engineering, Delft, Netherlands, 29-31 August 1994. SPE-28121-MS. http://dx.doi.org/10.2118/28121-MS
- Oort, E.v., Velzen, J.F.G.v., and Leerlooijer, K. 1993. Impairment by Suspended Solids Invasion: Testing and Prediction. SPE Prod & Oper 8 (3): 178-184. SPE-23822-PA. http://dx.doi.org/10.2118/23822-PA
- Suárez-Rivera, R., Stenebråten, J., Gadde, P.B. et al. 2002. An Experimental Investigation of Fracture Propagation during Water Injection. Presented at the International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 20–21 February. SPE-73740-MS. http://dx.doi.org/10.2118/73740-MS
- Gadde, P.B. and Sharma, M.M. 2001. Growing Injection Well Fractures and Their Impact on Waterflood Performance. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, 30 September–3 October. SPE 71614. http://dx.doi.org/10.2118/71614-MS
- Saripalli, K.P., Bryant, S.L., and Sharma, M.M. 1999. Role of Fracture Face and Formation Plugging in Injection Well Fracturing and Injectivity Decline. Presented at the SPE/EPA Exploration and Production Environmental Conference, Austin, Texas, USA, 1–3 March. SPE 52731. http://dx.doi.org/10.2118/52731-MS
Noteworthy papers in OnePetro
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Type Curves for Injectivity Decline SPE 165112
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