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Acidizing candidates

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Wells may perform poorly or less than expected due to three factors:

  • Inefficient mechanical system (wrong size tubing in a flowing well or inefficient artificial lift equipment for pumping or gas lift wells)
  • Low reservoir permeability
  • Wellbore restriction because of formation damage or incomplete perforating

If the problem is formation damage, then matrix acidizing may be an appropriate treatment to restore production. This page discusses ways to evaluate whether a well is a good candidate for acidizing.

Selecting acidizing candidates

A good matrix acidizing candidate is any well producing from:

  • Formation with permeability greater than 10 md
  • Permeability of which in the near-wellbore or near-perforation region has been reduced by solid plugging.

This plugging can be either mechanical or chemical. Mechanical plugging is caused by either introduction of suspended solids in a completion or workover fluid, or dispersion of in-situ fines by incompatible fluids and/or high interstitial velocities. Chemical plugging is caused by mixing incompatible fluids that precipitate solids.

If formation damage is the cause for poor production, the well is a good candidate for acidizing. Formation evaluation for acidizing provides more information about assessing the nature of the formation damage.

Evaluate damage

Several methods can be used to evaluate the presence of damage:

  • Production history plots that show sudden change, slope change, and gradual change
  • Offset well comparison
  • Pressure buildup tests
  • Well performance analysis

Production plots

Production rate/time plots are normally available for oil/gas wells that show change of rate with time and that note significant events such as workovers and stimulation treatments. Damage is revealed by at least three different characteristics as previously listed. The first is a sudden change in productivity following an event like a workover, as shown in Fig. 1. [1] An unfiltered produced brine was used to kill the well during a workover to repair a tubing leak. In this example, formation damage is obvious in the reduced productivity immediately after the workover. This lowered productivity persisted until an acid treatment removed the damage. Many times the analysis of a damaged condition is not so obvious.

A depletion-type history curve may decline at a certain rate, as shown in Fig. 2. [2] This well followed a certain decline rate and then began to decline faster as shown by the change in slope. This is often characteristic of scale buildup around the wellbore from produced water. This well was diagnosed and treated with hydrochloric (HCl) acid to dissolve calcium carbonate scale, and production rate was restored.

Some changes occur so slowly over time that productivity change is difficult to detect. Overlaying history curves of different wells will reveal this change in productivity. Fig. 3 shows this overlay for two California wells. Increasing water production called attention to one well, and testing revealed a casing leak in this well. [1]

Offset well comparison

Often acidizing candidates are selected on the basis of offset well comparisons. The productivities of offset wells are compared, and the poorer-performing wells are selected for acidizing. Many times, this selection is made without sufficient well testing. Pressure buildup testing may be too expensive in terms of lost production during long shut-ins, or well interference may circumvent reliable long-time pressure data. Table 1 shows such an offset comparison. [3]

On the basis of production only, three wells are acidizing candidates. However, when one compares the formation potential through log analysis, as expressed by net porosity feet, only one well is a reliable acidizing candidate: Well B-1. Acidizing all three wells on the basis of production rate alone may provide only a 33% success. In waterfloods, it is also important to compare effective reservoir pressures around each well or to compare the injection rates from adjacent water injection wells. If a well's water injectivity is low, production will be less in the offset producing well.

Pressure buildup tests

Where wells flow naturally, as in natural gas wells or new oil wells, pressure buildup tests provide a reliable measure of reservoir permeability and wellbore condition (skin factor, S). The skin factor, S, when positive, indicates restricted flow; however, the restriction is not necessarily formation damage. A skin factor of 5 to 20 or more can result from inadequate perforation size and/or low shot density when combined with either non-Darcy or two-phase fluid flow. Two-phase flow effects and non-Darcy flow cause high skin factors by themselves and can amplify the restriction caused by limited perforating. Such an example is shown in the buildup test in Fig. 4. [3] See the chapter on fluid flow in the reservoir engineering section of this handbook for more details on this type of plot.

This gas well was perforated with sufficient underbalance to achieve clean undamaged perforations, yet the skin factor from the pressure buildup test was 11. Well flow analysis showed that this skin was caused mainly by high-velocity flow of gas into small perforations created by the small through-tubing perforating gun used in this well.

Other wells have been identified with high skin factors that were the result of limited perforating and two-phase-flow effects. One gas condensate well had a skin factor of 29, which was the result of liquid saturation buildup and non-Darcy flow around the wellbore after a compressor was installed to pull the well harder. Another well in a deep, overpressured oil reservoir had a positive skin factor even after fracturing because of a solution gas/oil ratio (GOR) over 1,200 scf/bbl and a high pressure drawdown. Acidizing such wells have caused productivity decreases because acidizing sometimes produces damage where no damage existed before acidizing; therefore, use the checklist shown in Table 2 before selecting acidizing candidates on the basis of high skin factors alone. [3]

A skin factor can be analyzed by well flow analysis to show when it is caused by the previously described effects or when it is the result of permeability damage. An example of such a damaged well is shown in Fig. 5. [3] This figure shows predicted gravel-pack pressure drop vs. flow rate for different effective shots per foot (perforations). This well was perforated adequately and should have produced much better after completion. Review of the completion procedure showed that formation damage probably occurred during completion, and a standard acidizing treatment was used to dissolve the damage. Performance significantly improved, as shown by the reduction of completion pressure drop and increase of flow rate in this gas well.


  1. 1.0 1.1 1.2 1.3 McLeod Jr., H.O., Ledlow, L.B., and Till, M.V. 1983. The Planning, Execution, and Evaluation of Acid Treatments in Sandstone Formations. Presented at the SPE Annual Technical Conference and Exhibition, San Francisco, California, 5-8 October 1983. SPE-11931-MS.
  2. 2.0 2.1 Farina, J.R. 1971. An Approach to Estimating Skin Damage and Appropriate Treatment Volumes. Proc., 18th Annual Southwestern Petroleum Short Course Association, Lubbock, Texas, 53–57.
  3. 3.0 3.1 3.2 3.3 3.4 3.5 McLeod, H.O. 1989. Significant Factors for Successful Matrix Acidizing. Presented at the SPE Centennial Symposium at New Mexico Tech, Socorro, New Mexico, 16-19 October 1989. SPE-20155-MS.

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See also

Matrix acidizing

Formation evaluation for acidizing