Summary Two waste water disposal wells in a carbonate reservoir in Saudi Arabia suffered loss of injectivity due to severe formation damage. A thorough experimental study was conducted to evaluate the use of acid-in-diesel emulsions to stimulate these wells, which had several tight zones. The emulsified acid consisted of 70 vol% of 15 wt% HCl, 30 vol% diesel, and an emulsifier. This is the first time emulsified acid has been used to stimulate disposal wells. Experimental results indicated that the acid-in-diesel emulsion behaved as a shear-thinning fluid. The stability and reaction rate of the acid with reservoir rocks were found to be a function of emulsifier concentration. Coreflood results showed that the emulsified acid formed wormholes in tight carbonate cores. Permeability ratio (final/initial) of reservoir cores increased exponentially with the acid injection rate. The acid-in-diesel emulsion was used to acidize both disposal wells. The treatment included an in-situ gelled acid stage for acid diversion, and an emulsified acid stage to create deep wormholes in the reservoir. The treatment was very successful and the injectivity of both wells has significantly increased. Field data indicated that longer soaking times were needed to stimulate disposal wells. This is to ensure complete acid spending. Introduction It is well known that water disposal wells lose their injectivity with time. Waste water usually contains oil, suspended solids, and chemicals used in the water-oil separation plants. These chemicals include demulsifiers, corrosion inhibitors, and biocides. The rate of injectivity loss is a strong function of the concentration and size of suspended oil and solids present in the disposed water.1 A major source of suspended solids in the waste water is corrosion products. For example, iron sulfide particles are present in waste water in cases where the crude oil is sour.2 The injectivity of disposal wells can be partially restored by flowing back the well. This method can only be used in cases where the reservoir pressure is high. This procedure, however, does not fully restore the injectivity of the damaged wells. In reservoirs where the pressure is low, there is a need to stimulate these wells using a suitable acid treatment. In carbonate reservoirs, the case of interest in the present study, hydrochloric acid (up to 28 wt%), formic acid (up to 10 wt%), acetic acid (up to 10 wt%), and combinations of these acids, can be used to remove formation damage and enhance well injectivity. However, the reaction rate of hydrochloric acid with calcite is very fast.3,4 In conventional acid treatments, where 15 wt% HCl is used at low-injection rates, the acid reacts with the carbonate rock and causes surface washout only.5 This means that the acid will not penetrate the damaged zones and, as a result, the efficiency of the stimulation treatment will be low. One way to overcome this problem is to use acid-in-diesel emulsions.6,7 Diesel acts as a diffusion barrier between the acid and the rock.8–10 Thus, the reaction rate of the acid with carbonate rocks becomes slower. This gives the acid the ability to penetrate deeper into the formation by creating wormholes (i.e., channels with high permeability), which enhances well performance.11–14 Acid-in-diesel emulsion has several advantages besides its slow reaction rate with the rock. It has a relatively high viscosity, which results in a better sweep efficiency that will improve acid distribution in heterogeneous reservoirs.15 Also, the live acid does not come in contact with the well tubulars. Therefore, there is minimum corrosion to well casing and tubing. As a result, the concentration of iron in the live acid reaching the formation will be low.16 The presence of iron in the acid is a major concern because it will precipitate once the acid is spent.17–19 Emulsified acid has been successfully used to stimulate oil wells,16 high-temperature gas wells,20 and horizontal wells.21 However, to the best of the authors' knowledge, this acid was never used to stimulate waste water disposal wells. Therefore, the objectives of this study were to:improve the injectivity of waste water disposal wells using acid-in-diesel emulsions, andevaluate the treatment in the field. Experimental Studies Laboratory Testing. Acid-in-diesel emulsions were prepared in the laboratory according to the formula given in Table 1. The volume ratio of HCl (15 wt%) acid to diesel was 70:30. Diesel was mixed with the emulsifier (a cationic surfactant) in a Waring blender at medium speed, while a corrosion inhibitor (a filming amine), a chelating agent (EDTA), and a reducing agent (sodium erythorbate) were mixed with 15 wt% HCl acid in a separate beaker. The acid was gently added to diesel in the blender. The two phases were mixed in the blender for 10 minutes at high speed. It is worth mentioning that a cationic surfactant was used to prepare the emulsified acids tested in the present study. However, emulsified acids can also be prepared using suitable anionic or nonionic surfactants.22 A cationic surfactant was used in the present work to minimize surfactant loss due to adsorption. The acid-in-diesel emulsion was evaluated for field application. Experimental tests included rheology, thermal stability, compatibility, reactivity with reservoir rocks, and coreflood experiments. The apparent viscosity of the acid-in-diesel emulsion was measured as a function of shear rate using a Brookfield viscometer Model DV-II. To conduct thermal stability tests, acid-in-diesel emulsions were prepared in a 100 cm3 graduated cylinder and placed in an oil bath at 130°F (close to the bottomhole temperature). The volume of the separated acid (lower phase in the graduated cylinder) was monitored as a function of time. The reaction rate of the acid-in-diesel emulsion with reservoir rocks was measured at 75°F and atmospheric pressure. Core plugs from the same reservoir were cut into cylindrical slices of 1.5 in. diameter and 0.3 in. thickness. The rock slices were immersed in tested acids and their weight loss was measured as a function of time. The acid was continuously mixed using a magnetic stirrer set at 300 rpm. The effect of emulsifier concentration (2 to 20 gal/1,000 gal of 15 wt% HCl) on the reaction rate of the acid-in-diesel emulsions with reservoir rocks was also investigated using the above method. 13,16

An oil producing well (Well-A) in a carbonate reservoir was dead due to severe formation damage. The well was acidized by regular 15 wt% HCl, but remained dead. A thorough experimental study was conducted to evaluate using acid-in- diesel emulsions, 70 vol% HCl (15 wt%):30 vol% diesel, to stimulate this well which had several tight zones. Experimental results indicated that the acid-in-diesel emulsion was a viscous and non-Newtonian fluid. The thermal stability of the acid decreased as temperature was increased. The stability of emulsified acid also decreased in the presence of reservoir rock. The emulsified acid was found to be compatible with native crude oil and acid additives, except mutual solvents and demulsifiers. The reactivity of the emulsified acid with reservoir rock was slower than that of the 15 wt% HCl by a factor of 45 at 24 C. The reaction rate of the emulsified acid increased as temperature was increased. Coreflood results showed that the emulsified acid formed deep wormholes in tight carbonate cores (< 50 md). At the same acid volume and flow rate, the emulsified acid penetrated deeper into the core compared to the regular acid which caused face dissolution. Permeability ratio (final/initial) of reservoir cores exponentially increased with the acid injection rate. The size and number of the wormholes depended on the acid injection rate. The acid-in-diesel was successfully applied in Well-A using a coiled tubing unit, whereby the well productivity has been increased by several orders of magnitude. After the treatment, a flowmeter test indicated that the percentage production of tight zones has increased by a factor of 2. P. 9

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractSeawater power injectors and saltwater disposal wells are used to maintain reservoir pressure in a carbonate reservoir in Saudi Arabia. Various forms of hydrochloric acid were used to stimulate damaged wells and restore the injectivity of these wells. The forms of the acid used were regular, emulsified, and in-situ gelled acids. Acid diversion was achieved by using a coiled tubing unit, nitrogen foam, in-situ gelation, emulsified acid or combinations of these methods.A comprehensive investigation was undertaken to assess the effectiveness of acid treatments performed in the field and improve the outcome of the acid jobs. Laboratory and field investigations were conducted simultaneously to address formation damage and associated problems. These investigations included coreflood tests to screen various acid formulae, and analysis of field samples to identify the damaging mechanism. More than 80 acid jobs were analyzed in this study. A new empirical coefficient was identified and used to evaluate these jobs. The coefficient was based on: 1) the ratio between the pre and post acid injectivity indices, 2) the rate of decline of normalized well injectivity index, and 3) the incremental cumulative injection from the Hall plot following the acid job and before the first change in the slope. In addition, chemical analysis of acid returns (spent acid) was used to assess the damaging mechanisms and determine the type and concentration of various acid additives.Improper use of emulsified acid and in-situ gelled acid was found to result in poor field results. The outcome of acid jobs was found to be a function of the volume ratio of regular to insitu gelled acid. Good field results were obtained when the volume of in-situ gelled acid was 15-30% of that of the regular acid (15 wt% HCl). Furthermore, the study confirmed that acid injection using coiled tubing enhanced the efficiency of the acid treatment. This paper highlights the importance of conducting laboratory and field evaluation of acidizing treatments. The following new findings were obtained: 1. A new job index was developed and used to assess acid treatments in the field. 2. Severe formation damage can result from the improper use of in-situ gelled acids. 3. Analysis of spent acid was effectively used to optimize the concentration and type of various acid additives.% of the post job pressure loss due to skin = -8% Job Index = 225 MM bbls 2 (Fig. 7). Job Index/gal/ft = 109 MM bbls 2 (Fig. 7A).

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIron sulfide scale is present in sour gas, oil and water wells. It is present in various chemical species with different iron to sulfur ratios. Iron sulfide species with high iron content is soluble in acids, whereas those rich in sulfur are almost insoluble in acids. Iron sulfide scale was detected in several water supply wells where a sour gas is used for gas lifting operation. The objectives of this study were to determine the mechanism that led to the formation of this type of scale, to characterize this scale and determine the most effective chemical treatments to remove and prevent reoccurrence. Lab work included characterization of the scale, and examine various acids and non-acids formulae to remove various iron sulfide species.Several wells in a sandstone aquifer are used to supply water needed for the operation of gas oil separation plants (GOSPs). The reservoir pressure is low, therefore the water is produced using gas lifting. The gas used is an associated gas that is produced with the oil from a carbonate reservoir. The gas is sour with a hydrogen sulfide content of 2 mol%. In addition, the supply water contains total iron at 5-10 mg/L. Hydrogen sulfide reacts with the iron present in the aquifer water and precipitates iron sulfide on the well tubulars and gas injection nozzles. Accumulation of iron sulfide has caused many operational problems.Lab results indicated that iron sulfide scale deposited on the inside wall of the well tubulars. The scale was uniform with a thickness that increased from 0.025" above the gas injection point to 0.25" at the well head. The composition of the scale changes with the length above the gas injection point. Just above the gas injection point, the scale was identified as FeS whereas close to wellhead, the scale was identified as FeS 2 . Acid solubility varied across the length of tubing. In areas where there is FeS, acid solubility in 20 wt% was 85-90 wt%. On the other hand, acid solubility was only 3-5 wt% in areas where FeS 2 was present. Experimental results showed that 20 wt% could be used to remove a portion of the scale, however a suitable hydrogen sulfide scavenger should be added to the acid. Several non-acid formulae were tested and some of them were effective in dissolving acid-insoluble scale.Unlike typical types of oilfield scales, iron sulfide is present in different species. The chemical structure of these species affects the method that should be used to remove this scale. This study addresses various types of iron sulfide and methods to remove and prevent the formation of this type of scale.

Two wastewater disposal wells in a carbonate field in Saudi Arabia suffered loss of injectivity due to severe formation damage. Lab tests conducted on reservoir cores indicated that regular 15 wt% HCl did not form deep wormholes and caused surface wash-out only. A thorough experimental study was conducted to evaluate using acid-in-diesel emulsions to stimulate these wells which had several tight zones. The emulsified acid consisted of 70 vol% of 15 wt% HCl, 30 vol% diesel and an emulsifier (a cationic surfactant). This is the first time emulsified acid has been used to stimulate disposal wells. Experimental results indicated that the acid-in-diesel emulsion behaved as shear-thinning fluid. The stability of the acid was found to be a function of emulsifier concentration. The reaction rate of the emulsified acid with reservoir rocks depended also on emulsifier concentration at the reservoir temperature (55 °C). Very low reaction rates were obtained at emulsifier concentrations greater than 20 gals/1000 gals were of acid. These results indicated that longer soaking times would be needed to stimulate disposal wells. This is to ensure complete acid spending. Coreflood results showed that the emulsified acid formed deep wormholes in tight carbonate cores (< 100 md), where the core permeability increased after the treatment. Permeability ratio (final/initial) of reservoir cores exponentially increased with the acid injection rate. The size and number of the wormholes depended on the acid volume, injection rate and initial core permeability. The acid-in-diesel emulsion (280 cp at 2 s−1 and room temperature) was applied in two wastewater disposal wells. The designed treatment included a gelled acid stage for acid diversion, and an emulsified acid stage to create deep wormholes in the reservoir. The treatment was very successful and the injectivity of both wells has significantly increased.