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Acid placement and coverage
A leading cause of unsuccessful acid treatment is failure to contact all the damage with the acid. Fluids pumped into a formation take the path of least resistance. This makes the placement and coverage of the acid an important component of the treatment design.
Acid flow paths
In a typical treatment, most acid enters the formation through the least damaged perforation tunnels, as the schematic in Fig. 1 shows. 
Fig. 1—Acid entry into formation through perforations.
When this happens, it is easy to conclude that acidizing is very expensive and does not work well. Acidizing works well to remove damage when the type of damage is known, the treatment is designed properly, and it is properly executed. Extreme damage may require more than what is discussed. Actions required may include a chemical soak and swabbing the soak back before acidizing or reperforating, and/or fracturing to bypass damage.
Numerous methods help control acid placement. Selection is based on:
- Wellbore hardware
- Formation characteristics
- Field experience
Additional guidelines are provided in McLeod. The four main types of zone coverage techniques in matrix acidizing are:
- Density segregation
These methods also can be combined in treatments.
Opposed cup packer or perforation wash tool
This perforation wash tool allows selective injection of acid into closely spaced perforations in high-permeability formations. High rate and/or pressure should be avoided when using either this tool or closely spaced straddle packers. High pressures can cause the cups to leak or turn over or the tool to separate at the port (the weakest part). High pressure can also establish communication behind the pipe between the point of injection and nearby perforations without removing damage from the plugged perforation. This type of isolation is best used for removing damage from severely plugged perforations in high-permeability formations. A field example of this technique in a Gulf Coast sandstone is given by McLeod and Crawford. 
Squeeze packer and retrievable bridge plug
A good method of isolating perforated intervals is to use a retrievable bridge plug and a squeeze packer. The bridge plug is set in blank sections of casing between perforated sections. The treatment usually begins with the lower set of perforations and finishes with the upper set. Straddle packers may be used in a similar way and have been used successfully in the Permian Basin to better clean damaged perforations.
Ball sealers can be divided into two categories:
- Heavier (sinkers) than the fluid
- Lighter (floaters) than the fluid
Successful use requires a good cement job on the installed casing and round good quality perforation holes. Sinkers have been used the longest and usually require 200% excess ball sealers and a high pump rate (greater than 5 bbl/min). The high pump rate usually prohibits their use in sandstone matrix acidizing, but they may be used in fracture acidizing or perforation breakdown. Floaters, or neutral-density ball sealers, provide excellent mechanical isolation for matrix acidizing at injection rates of 1 bbl/min or higher. The density or specific gravity of these ball sealers is matched to the fluid being pumped so better ball action will take place. Surface flowback equipment must be modified to catch the floating ball sealers during flowback.
Ball sealers are limited in their use. They are not used in:
- Long intervals with high-perforation density
- Wells perforated with more than 4 shots/ft, low-rate treatments (1/4 to 1/2 bbl/min)
- Gravel-packed wells
Regardless of the type of treatment or ball used, treatment will be more effective when density of the ball is very close to the density of the fluid used in the treatment.
Pre-gravel pack acid treatments
One effective way to divert acid in a treatment before gravel packing is to use slugs of hydroxyethylcellulose (HEC) gel and gravel-pack sand. Ammonium chloride brine mixed with HEC at a concentration of 90 lbm/1,000 gal can be mixed in 5-bbl batches with 100 lbm of correctly sized gravel-pack sand. The combination of viscosity and sand packing helps divert acid to other perforations. The unique feature of this method, as opposed to other "particulate diverters," is that the perforation tunnel is packed with gravel-pack sand instead of some other material that would prevent gravel-pack slurry from entering the perforations during later slurry placement.
Soluble particulate diverters
Selection of the optimal particulate diverter is based on the kind of fluid injected and/or produced. The diverter must be temporary and easily removed; otherwise, there will be a new kind of damage to be treated and removed. Oil-soluble resin (OSR) is one of today's more common diverting agents. OSR is slowly soluble in toluene, xylene, condensate, crude oil, and EGMBE (mutual solvent). OSR should be mixed on site with a blender and immediately pumped or added to the acid "on the fly" with a chemical injection pump. If OSR diverters are mixed off location or are allowed to stand for an hour or more, they will clump and may cause pump failure or plug perforations. OSR diverters should not be used with solvent-acid mixtures, which dissolve the resin enough to reduce its effectiveness. The chart in Fig. 2 shows the application of high concentrations of OSR to achieve significant pressure increases by more effective diverter action. The annular pressure (static column of fluid between the well tubing and coil tubing) shows pressure increases when diverter concentration increases.  Please refer to Brannon for a full explanation. Shown in Fig. 3 are gamma ray logs before and after using radioactive tracers with OSR diverters in a California well.  Such tracers are excellent diagnostic tools to find where the acid is going. In this case, radioactive intensity shows that most of the acid bypassed the preferred interval and went behind the casing and entered a thief zone behind the pipe.
Fig. 2—Pressure response to acidizing using OSR diverter.
Fig. 3—OSR diverter evaluation radioactive tracer.
Benzoic acid flakes or powder are soluble in toluene, xylene, alcohol, and some condensate fluids. They dissolve very slowly in water/gas. Benzoic acid is often used because it is soluble in the fluids normally encountered in oil/water wells; however, if not well dispersed or mixed, it will plug perforations. Benzoic acid plugs do not dissolve fast because not enough fluid can flow by it to dissolve the plug. One well took 6 months to return to normal productivity after being treated with caked benzoic acid powder delivered to the location.
Thickening the acid through use of soluble polymers, nitrogen and foaming agents, or dispersing oil (either as loose two-phase mixtures or with emulsifiers) is useful in high-permeability formations with deep damage. Design is difficult; therefore, experience and on-site flexibility are important for success. Excellent results have been obtained with staged foam slugs between acid stages in high-permeability Gulf Coast gas wells to remove near-wellbore damage. This technique is so promising because the diverter (gas and fluid) disappears when the foam breaks with little chance of damage as with slowly dissolving particulates. See Gdanski and Behanna for useful guidelines.
Fadele et al. show that diverters often need not be used in gas wells because of the natural viscous diversion. Water and acid are 100 times more viscous than gas, and this provides a natural diversion for acid entering a gas formation. This may be one reason acidizing works better in gas wells than in oil wells. Other recent papers offer further improvements with viscous acids and diverters. 
Other significant factors are the rathole below the lowest perforation and the space just above the top perforation and below the packer. Rathole fluid should be heavier than the acid, and fluid above the top perforation should be lighter than the acid. If not, acid can end up in the rathole rather than the formation. Acid left in the borehole can cause casing leaks below the treated interval. Spotting acid over the perforations before injecting is very important in low to moderate permeability (10 to 50 md), and density segregation must be planned to achieve the best contact of acid with damaged perforations in these formations. Concentric tubing helps to achieve accurate placement of the acid in the wellbore to take advantage of density segregation.
Concentric tubing is preferred for matrix acid treatments, because it:
- Allows the rathole to be circulated clean
- Permits better placement for acid contact with all perforations
- Bypasses production or injection tubing debris
- Can be acid cleaned on surface before running into the hole
- Limits pump rate to 0.5 to 1 bbl/min because of fluid friction pressure in small tubing (1 to 1.5 in.)
Advances in acid diversion
The design and implementation of diverting systems has been advanced by recent design techniques but still relies on guidelines and field experience. Hill and Rossen have provided a better means to compare diverting methods and design diverting treatments. Gdanski and Behenna have provided some appropriate guidelines for foamed acids or foamed-diverter stages.
Hill and Rossen compared the techniques of injection rate diversion, coined MAPDIR (maximum pressure differential and injection rates):
- Particulate diverting agents
- Viscosified fluids
- Foamed acid
MAPDIR results in effective treatment of lower-permeability layers but at the expense of much larger volumes of acid. It may also be limited in use by pump and tubing capacities. Wells can clean up faster because no particulates are used. Also, treatment time is less to achieve the same reduction in skin factor as other techniques. The particulate diverting is most efficient in terms of volumes of acid and, thereby, is generally more economic if treating time is not a large economic factor. Oil soluble resins are not completely oil soluble, and sometimes plugging by these resins may not be temporary. Better quality assurance/quality control (QA/QC) is required for successful implementation. Quality assurance is the pretreatment planning to ensure that proper materials and procedures are used. Quality control is on-site supervision and testing to ensure that quality treatment is performed. Foam diversion is nondamaging in that surfactants are soluble and removable in produced water and nitrogen is recovered. Foams are most difficult to design and are not completely understood in terms of their behavior in different formations; however, guidelines for designing and implementing foam treatments are provided by Gdanski and Behenna.  Foams tend to be more stable in high-permeability layers and, therefore, reduce the acid losses in these layers. They also tend to be more stable in water zones and less stable in oil layers, providing some selectivity in treating wells with high water cuts or nearby bottom water. Viscosified fluids are similar to foam but provide a more consistent fluid hydrostatic pressure when well pressure limitations are present. The viscous behavior of these fluids in different formations is not well defined. These systems may be combined with MAPDIR when rate is limited by equipment.
- 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. http://dx.doi.org/10.2118/20155-MS.
- McLeod, H.O. 1986. Matrix Acidizing to Improve Well Performance. Short Course Manual. Richardson, Texas: SPE.
- McLeod Jr., H.O. and Crawford, H.R. 1982. Gravel Packing for High Rate Completions. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 26-29 September 1982. SPE-11008-MS. http://dx.doi.org/10.2118/11008-MS.
- Gidley, J.L. 1985. Acidizing Sandstone Formations: A Detailed Examination of Recent Experience. Presented at the SPE Annual Technical Conference and Exhibition, Las Vegas, Nevada, 22-26 September 1985. SPE-14164-MS. http://dx.doi.org/10.2118/14164-MS.
- Brannon, D.H., Netters, C.K., and Grimmer, P.J. 1987. Matrix Acidizing Design and Quality- Control Techniques Prove Successful in Main Pass Area Sandstone (includes associated papers 17274 and 17466 ). J Pet Technol 39 (8): 931-942. SPE-14827-PA. http://dx.doi.org/10.2118/14827-PA.
- Gdanski, R.D. and Behenna, R.R.: “Experience and Research Show Best Designs for Foam Diverted Acidizing,” Oil &Gas J. (1993) 91, No. 36, 85.
- Fadele, O., Zhu, D., and Hill, A.D. 2000. Matrix Acidizing in Gas Wells. Presented at the SPE/CERI Gas Technology Symposium, Calgary, Alberta, Canada, 3-5 April 2000. SPE-59771-MS. http://dx.doi.org/10.2118/59771-MS.
- Chang, F., Qu, Q., and Frenier, W. 2001. A Novel Self-Diverting Acid Developed for Matrix Stimulation of Carbonate Reservoirs. Presented at the SPE International Symposium on Oilfield Chemistry, Houston, 13–16 February. SPE 65033. http://dx.doi.org/10.2118/65033-MS.
- Buijse, M.A. and van Domelen, M.S. 1998. Novel Application of Emulsified Acids to Matrix Stimulation of Heterogeneous Formations. Presented at the SPE Formation Damage Control Conference, Lafayette, Louisiana, 18–19 February. SPE-39583-PA. http://dx.doi.org/10.2118/39583-MS.
- Saxon, A., Chariag, B., and Rahman, M.R.A. 2000. An Effective Matrix Diversion Technique for Carbonate Formations. SPE Drill & Compl 15 (1): 57-62. SPE-62173-PA. http://dx.doi.org/10.2118/62173-PA.
- Hill, A.D. and Rossen, W.R. 1994. Fluid Placement and Diversion in Matrix Acidizing. Presented at the University of Tulsa Centennial Petroleum Engineering Symposium, Tulsa, Oklahoma, 29–31 August. SPE-27982-MS. http://dx.doi.org/10.2118/27982-MS.
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