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 injection

Water is commonly injected into formations for four primary reasons:

• Pressure maintenance
• Water disposal
• Waterflooding
• Water circulation in a geothermal doublet

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 three potential sources of injectivity change during water injection: physical, chemical and biological.

The most common properties of injection water that determine the formation damage or the injectivity of water injection wells are:

• 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

It is also worth noting that other factors can also affect water injectivity:

• Bacteria in the injection water that multiply downhole
• Thermal effects
• Hydro tensile fracturing of hydro shearing

Some of these may positively affect injetivity enven though injectivity increase with time is seldom reported.

Additionally, well construction maybe a factor of injectivity decline when tubulars are affected by corrosion or when completion technology has not be properly designed.

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. 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.

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  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.

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.

Remediation

As inferred above, damage prevention is the best way of maintaining water injectivity. However, the subsurface formation if the largest and most efficient filter that one will probably ever facing. the best way for unplugging a well, is by flowing it back. Therefore some preventative methods can be developed to make it possible:

1. Drill the injector wells before reservoir pressure is too low to flowback the wells
2. Physically isolate injection zones from shaly zones
3. Install surface piping in such a way that flowback is easy
4. Conduct proper chemical analysis to ensure compatibilty of injected water with formation water and mineralogy at downhole conditions
5. Properly filter and treat injection water before injecting

When flowback has failed or is impossible, reperforating, fracturing or chemical stimulation can be considered. in these cases the usual rules applicable to each technique apply.

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

Alfenore J., Longeron D. and Saintpère S., “What Really Matters in our Quest of Minimizing Formation Damage in Open Hole Horizontal wells”, SPE 54731, presented at 1999 SPE European formation Damage Conference held in The Hague, The Netherlands, May 31- 1st June

Burton R. and Hodge R., “The Impact of Formation Damage and Completion Impairment on Horizontal Well Productivity”, SPE 49097 presented at the 1998 SPE Annual Technical Conference and Exhibition in New Orleans, LA, September 27-30

Dambani, S. L., et al. “Analysis of Injectivity Decline in Some Offshore Water Injectors”, SPE  172469-MS , August 2014.

Ezeukwu, T., Thomas, R. L., & Gunneroed, T. (1998, January 1). Fines Migration Control in High-Water-Cut Nigerian Oil Wells: Problems and Solutions. Society of Petroleum Engineers. doi:10.2118/39482-MS

Friedheim, J., Guo, Q., Young, S., & Gomez, S. “Testing And Evaluation Techniques For Drilling Fluids-Shale Interaction And Shale Stability”, 11-502 American Rock Mechanics Association, January 2011

Griffin, J. M., Hayatdavoudi, A., & Ghalambor, “A. Design of Chemically Balanced Polymer Drilling Fluid Leads to a Reduction in Clay Destabilization“, SPE 12491-PA, February 1986.

Guedes, R. G., Al-Abduwani, F. A. H., Bedrikovetsky, P. G., & Currie, P. K. “Injectivity Decline Under Multiple Particle Capture Mechanisms” SPE 98623-MS January 2006.

Guinot F., and Meier P., “Can Unconventional Completion Systems Revolutionise EGS? A Critical Technology Review”, SPE-195523-MS, presented at the SPE Europec and 81st EAGE Conference and Exhibition, London 3-6 June 2019

Khatib, Z. I. “Prediction of Formation Damage Due to Suspended Solids: Modeling Approach of Filter Cake Buildup in Injectors” SPE 28488-MS, January 1994

Morgenthaler L., McNeil R.,Faircloth R., Collins A. and Davis C., “Optimization of Stimulation Chemistry for Openhole Horizontal Wells”, SPE 49098 presented at the 1998 SPE Annual Technical Conference and Exhibition in New Orleans, LA,

Olatunji, I. et al. “Managing Injectors Impairment in a Deepwater Field”, SPE 172463-MS, August 2014

Pang S. and Sharma M. “Evaluating the Performance of Open Hole. Perforated and Fractured Water Injection Wells”, SPE 30127, presented at the 1995 SPE European Formation Damage Conference, May 15-16.

Pang S. and Sharma M. “Predicting Injectivity Decline in Water Injection Wells”, published in SPE Formation Evaluation 194-201, September 1997.

Pautz J.F., Crocker M.E. and Walton  C.G., “Relating Water Quality and Formation Permeability to Loss of Injectivity ”, SPE 18888, proceedings of the 1989 SPE Production Operations Symposium, Oklahoma, March 13-14.

Ryan D.F.,Browne S.V. and Burnham M.P., “Mud Clean-up in Horizontal Wells: A Major Industry Study”, SPE 30528 presented at 1995 SPE Annual Technical Conference and Exhibition in Dallas, USA, October 22-25

Weaver, J. D., Nguyen, P. D., & Loghry, R. “Stabilizing Fracture Faces in Water-Sensitive Shale Formations”, SPE 149218-MS, January 2011.

Zain Z.M. and Sharma M.M., “Cleanup of Wall-Building Filter Cakes”, SPE 56635 presented at the 1999 SPE Annual Technical Conference and Exhibition in Houston., October 3-6

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