Formation damage

Removing Fines-Migration Formation Damage in the Putumayo Basin in Colombia

This paper summarizes a wide variety of sandstone-acid-stimulation case histories, highlighting aspects such as mechanical conditions and operational practices.

Fig. 1—Location of Putumayo Basin.

To date, more than 100 sandstone-acidizing treatments have been performed in several Colombian oil fields, targeting the Villeta and Caballos Formations in the Putumayo Basin. Fines migration has been the main damage mechanism treated with this type of chemical stimulation. This paper summarizes a wide variety of sandstone-acid-stimulation case histories, highlighting aspects such as mechanical conditions and operational practices.


The Putumayo Basin is located in southern Colombia. The Putumayo Basin shows a stratigraphic sequence containing Early Cretaceous (marine) to Miocene/Pliocene sediments (fluvial). Fig. 1 above illustrates the location of the Putumayo Basin.

Sand Villeta Formation

The T Sand samples examined are fine-to medium-grained sandstones. They are composed primarily of quartz grains cemented primarily with quartz overgrowths and authigenic clays. ­Rare-to-minor cements include solid hydrocarbon, pyrite, and dolomite. X-ray-­diffraction (XRD) analyses show that all of the sandstone samples are composed primarily of quartz and clay minerals.

Feldspars are absent from all but one sample. Given that virtually all of the framework grains are quartz, with possibly minor argillaceous grains, the sandstone is classified as quartzarenites. Scanning-electron-microscope (SEM) photographs show authigenic kaolinite filling intergranular zones and possibly replacing grains.

Caballos Formation

Samples in this formation are all sandstones. Estimated average grain size ranges from very fine sand to medium sand. The framework grain suite is dominated by quartz. The grains are cemented primarily by quartz overgrowths and authigenic clays. XRD determined that all of the samples are composed primarily of quartz and clay minerals. Feldspars are rare to absent from these sandstones, confirming that virtually all of the framework grains are quartz and the sandstones should be classified as quartzarenites. Clay-mineral content averages 7.8%, with illite and mixed-layer illite/smectite more common than kaolinite. SEM photos show that these clays are authigenic.

Designing an Effective Treatment

To determine appropriate fluids, acid types, concentrations, and treatment volumes, a software simulator with a logical process was used. The structured process consisted of two phases.

Candidate Selection and Skin Analy­sis. A formation-damage-adviser tool ranked potential damage mechanisms. Fines migration was confirmed as the primary damage mechanism. This result agrees with the mineralogy and the detailed surveillance of skin by pressure-transient analysis (PTA), which indicated a progressive increase in formation damage with production rate.

PTA identified Well 1 and Well 2 as having a total skin prejob value of 32 and 60, respectively. These wells were selected as candidates because they showed potential for improved productivity on the basis of general information about the (undamaged) reservoir quality, such as permeability, thickness, porosity, and saturation.

Fluid Selection. For this stage, the software has two applications—an acid expert and a geochemical simulator. The acid expert provides acid-formulation recommendations for a matrix-acidizing treatment. The geochemical simulator confirms that there are no issues with the formation of precipitates during the progression of the secondary reaction.

The recommended treatment consisted of the following stages: organic preflush, brine conditioner, acid preflush, retarded hydrofluoric acid (RHF), and a fines-stabilizer system. Conventional matrix acidizing with HF is effective only for removing shallow clay damage 1 or 2 in. from the wellbore. RHF is a system designed for treating sandstone formations that have been damaged from the migration or swelling of silica, feldspars, and clays up to 2 to 6 in. from the wellbore. The primary advantages of using RHF include the following:

  • Deeper penetration of live HF into the formation.
  • Retarded reaction with quartz sand and silica to promote deep-damage removal and improve compatibility with feldspar-containing formations.
  • Minimized damage to formation consolidation. RHF reacts less with the quartz cementation that holds the formation grains together.
  • Acts as a clay stabilizer to control fines migration during and following the treatment.

Stimulation Treatment

Three steps are necessary when acidizing sandstone reservoirs: preflush, main flush, and post-flush. The stimulation trend was designed for these steps as follows:

  • Tubing pickling. This was performed with hydrochloric acid (HCl) or acetic/formic acid, depending on the logistics at the location. The treatment was pumped to a circulating sleeve (not into the formation) before pumping the stimulation fluid sequences.
  • Organic preflush. A low-interfacial-tension aromatic/aliphatic solvent mixture was used as a preflush and was allowed a 2-hour soaking period to dissolve asphaltenes covering the target fines.
  • Brine conditioner. 5% ammonium chloride allowed the establishment of chemical equilibrium.
  • Acid preflush. A mixture of organic acids (acetic and formic) was used as a preflush to dissolve calcium carbonate before the RHF main treatment.
  • RHF (main treatment fluid). An RHF (15 wt% HCl, 1.5 wt% HF, and 5 wt% AlCl3•6H2O) system that has proved to be successful was used as the main treatment.
  • Fines-stabilizer brine. 5% ammonium chloride with a stabilizer was used to help minimize the tendency to disperse or deflocculate naturally occurring fines within the formation matrix.

Well Mechanical Conditions

Well completions are performed with tubing-conveyed perforating (TCP) using 4½- to 4⅝-in. perforating guns with 5 shots/ft in 7-in. casing. Both producers and injectors use 3½-in., 9.3-lbm/ft tubing. For formation isolation, 7-in. hydraulic packers are used, followed by sliding sleeves that allow communication with the formation by being opened and closed with a shifting tool and a slickline unit as necessary. For injection wells in the Caballos Formation, sliding sleeves are used. For the T Sand formation, these are not required because injection is performed through the annulus.

Jet pumps are used as the lifting system for producing wells; these are fished before the stimulation treatment and then reinstalled to perform post-stimulation flowback for each stage when the conditions stabilize.

In the case of injection wells, produced water is treated to adjust injection parameters and then is pumped through two injection systems at 2,600 or 3,000 psi.

Treatment Execution and Records

In addition to the two case histories presented here, a third case history, involving acid stimulation and scale inhibition, is presented in the complete paper.

Case History 1: Typical Acid Stimulation in T Sand. After the integrity of the downhole equipment had been tested, a pickling treatment was performed. Before stimulation, 70 bbl of 5% ammonium chloride was circulated down the production tubing through the circulating sliding sleeve. The circulating sleeve was closed, and an injectivity test using 50 bbl of 5% ammonium chloride was performed, reaching 1.4 bbl/min with 1,948 psi of pressure at the surface. A total of 12 bbl of organic-solvent preflush was pumped and displaced with 71 bbl of 5% ammonium chloride, thus forcing the solvent preflush into the formation. During this stage of the treatment, a slight increase in pressure was observed, followed by a pressure drop at the end of the treatment stage. The treatment was allowed to soak for 2 hours to enable a reaction between the solvent preflush and the organic material in the formation. After this time, 25 bbl of acid preflush was pumped and displaced with 71 bbl of 5% ammonium chloride to force the acid preflush into the formation. After displacing the acid preflush, 64 bbl of RHF treatment—followed by 64 bbl of post-flush treatment (fines-stabilizer brine)—was pumped and displaced into the formation with 71 bbl of 5% ammonium chloride. Before the treatment entered the formation, the pump rate was 1.6 bbl/min at 391 psi at the surface. When the treatment plus 7 bbl of post-flush entered the formation, the flow rate increased to 1.8 bbl/min at 391 psi at the surface. At the end of the RHF stage, the pump rate stabilized at 1.75 bbl/min and 595 psi. Finally, 100 bbl of 5% ammonium chloride brine was overflushed to remove reaction residues from the well.

After stimulation, the T sand was open to production, showing a change in oil rate from 1,272 to 2,307 BOPD, which represented an increase of 81%.

Case History 2: Acid Stimulation and Conformance. This well was drilled and completed to 5,724-ft measured depth. Previous successful acidizing treatments had been performed on similar wells with the following dosages: 20 gal/ft of organic treatment, 80 gal/ft of organic-acid preflush, 100 gal/ft of RHF, 100 gal/ft of fines-stabilizer brine, and 70 gal/ft of 5% ammonium chloride as an overflush. In October 2012, a stimulation treatment for the T sand was performed. The skin factor dropped from 32 to -2.9, representing a productivity regain of 2.17.

Recently, high water production was identified in this well, and it became necessary to assist the acid-stimulation treatment with a relative permeability modifier (RPM). The RPM was used to decrease permeability to water in the treated zone. It was also desirable that the treatment not significantly affect hydrocarbon production because of increased water cut. The recommended treatment was applied successfully in this well, providing more than a twofold improvement in oil productivity. Also, a reduction in water cut of 10% was evidenced.


  • The acid-stimulation treatment was designed to remove formation damage caused by fines migration and focused on enhancing the production capacity, and it was applied successfully in these fields.
  • A suitable design of the stimulation treatment yielded an effective dissolution of the main damage mechanism, even in the presence of calcite scale and asphaltenes.
  • Acid stimulation combined with use of RPMs and scale inhibitors proved to be a successful field application for recovering oil-production rates and reducing water cut.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 178996, “Removing Formation Damage From Fines Migration in the Putumayo Basin in Colombia: Challenges, Results, Lessons Learned, and New Opportunities After More Than 100 Sandstone-Acidizing Treatments,” by Wildiman Reinoso, Fredy Torres, and Manuel Aldana, Grantierra, and Pablo Campo, Emilce Alvarez, and Erika Tovar, Halliburton, prepared for the 2015 SPE International Conference and Exhibition on Formation Damage Control, Lafayette, Louisiana, USA, 24–26 February. The paper has not been peer reviewed.