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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.
While [[Formation_damage|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 injection ==
 
Water is commonly injected into formations for three primary reasons:


==Water injection==
Water is commonly injected into formations for three primary reasons:
*Pressure maintenance
*Pressure maintenance
*Water disposal
*Water disposal
*[[Waterflooding]]
*[[Waterflooding|Waterflooding]]


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 treating facilities|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.  
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_treating_facilities|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.  
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 ==
 
There are two main properties of injection water that determine the formation damage or the injectivity of water injection wells:<ref name="r1">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</ref><ref name="r2">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</ref><ref name="r3">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</ref><ref name="r4">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</ref><ref name="r5">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</ref><ref name="r6">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</ref>


==Causes of formation damage==
There are two main properties of injection water that determine the formation damage or the injectivity of water injection wells:<ref name="r1" /><ref name="r2" /><ref name="r3" /><ref name="r4" /><ref name="r5" /><ref name="r6" />
*Total dissolved solids in the injection water
*Total dissolved solids in the injection water
*Total suspended solids (solids and oil droplets) 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:


The salinity and ion content in the injection water control two types of formation damage in an injection well:
*Freshwater sensitivity of the formation
*Freshwater sensitivity of the formation
*Precipitation of inorganic scale
*Precipitation of inorganic scale


===Fines migration===
=== Fines migration ===
In water-sensitive formations, if fresh water is being injected from a nearby lake or river, caution must be exercised to ensure that [[Formation damage from fines migration|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===
In water-sensitive formations, if fresh water is being injected from a nearby lake or river, caution must be exercised to ensure that [[Formation_damage_from_fines_migration|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.
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.  
 
=== 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:
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:
*pH
*pH
*Temperature
*Temperature
*State of oxidation of the brine
*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.  
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===
=== Solids and oil droplets ===
The presence of solids and oil droplets in the injection fluid can result in severe and rapid declines in injectivity. <ref name="r1" /><ref name="r2" /><ref name="r3" /><ref name="r4" /><ref name="r5" /><ref name="r6" /> 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.<ref name="r3" /> 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.


<gallery widths=300px heights=200px>
The presence of solids and oil droplets in the injection fluid can result in severe and rapid declines in injectivity. <ref name="r1">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</ref><ref name="r2">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</ref><ref name="r3">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</ref><ref name="r4">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</ref><ref name="r5">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</ref><ref name="r6">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</ref> 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.<ref name="r3">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</ref> 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.
 
<gallery widths="300px" heights="200px">
File:Vol4 Page 258 Image 0001.png|'''Fig. 1—Behavior of Well A10: (a) injectivity decline; (b) pressure and rate data.'''<ref name="r3" />
File:Vol4 Page 258 Image 0001.png|'''Fig. 1—Behavior of Well A10: (a) injectivity decline; (b) pressure and rate data.'''<ref name="r3" />
</gallery>
</gallery>


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. <ref name="r7" /><ref name="r8" /><ref name="r9" /><ref name="r10" /><ref name="r11" /><ref name="r12" /><ref name="r13" /> 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. <ref name="r14" /><ref name="r15" />
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. <ref name="r7">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</ref><ref name="r8">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</ref><ref name="r9">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</ref><ref name="r10">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</ref><ref name="r11">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</ref><ref name="r12">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</ref><ref name="r13">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</ref> 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. <ref name="r14">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</ref><ref name="r15">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</ref>
 
== Water quality ==


==Water quality==
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:
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
*Sedimentation tanks
*Sand filters
*Sand filters
*Cartridge filters
*Cartridge filters
*Flotation devices
*Flotation devices
*Hydrocyclones  
*Hydrocyclones


See [[Removing hydrocarbons from water]] and [[Removing solids from water]] for more information.  
See [[Removing_hydrocarbons_from_water|Removing hydrocarbons from water]] and [[Removing_solids_from_water|Removing solids from water]] for more information.


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.
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.


==References==
== References ==
<references>
 
<ref name="r1">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</ref>  
<references />
<ref name="r2">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 </ref>
 
<ref name="r3">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 </ref>
== Noteworthy papers in OnePetro ==
<ref name="r4">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</ref>
<ref name="r5">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 </ref>
<ref name="r6">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</ref>
<ref name="r7">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</ref>
<ref name="r8">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</ref>
<ref name="r9">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 </ref>
<ref name="r10">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 </ref>
<ref name="r11">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 </ref>
<ref name="r12">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</ref>
<ref name="r13">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 </ref>
<ref name="r14">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 </ref>
<ref name="r15">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 </ref>
</references>


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


==External links==
Type Curves for Injectivity Decline SPE 165112
 
== External links ==
 
Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro
Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro


==See also==
== See also ==
[[Formation damage]]
 
[[Formation_damage|Formation damage]]
 
[[Thermal_recovery_by_steam_injection|Thermal recovery by steam injection]]


[[Thermal recovery by steam injection]]
[[Facilities_for_steam_generation|Facilities for steam generation]]


[[Facilities for steam generation]]
[[Surface_water_treatment_for_injection|Surface water treatment for injection]]


[[Surface water treatment for injection]]
[[PEH:Formation_Damage]]


[[PEH:Formation Damage]]
== Category ==
[[Category:1.8 Formation damage]] [[Category:YR]]

Revision as of 10:51, 29 June 2015

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 injection

Water is commonly injected into formations for three primary reasons:

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

There are two main properties of injection water that determine the formation damage or the injectivity of water injection wells:[1][2][3][4][5][6]

  • 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

Fines migration

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:

  • pH
  • Temperature
  • 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. [1][2][3][4][5][6] 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.[3] 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.

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. [7][8][9][10][11][12][13] 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. [14][15]

Water quality

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
  • Hydrocyclones

See Removing hydrocarbons from water and Removing solids from water for more information.

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.

References

  1. 1.0 1.1 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
  2. 2.0 2.1 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
  3. 3.0 3.1 3.2 3.3 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
  4. 4.0 4.1 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
  5. 5.0 5.1 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
  6. 6.0 6.1 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
  7. 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
  8. 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
  9. 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
  10. 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
  11. 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
  12. 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
  13. 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
  14. 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
  15. 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

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

Type Curves for Injectivity Decline SPE 165112

External links

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

See also

Formation damage

Thermal recovery by steam injection

Facilities for steam generation

Surface water treatment for injection

PEH:Formation_Damage

Category