The objective of this work was to evaluate iron control chemicals used in acidizing systems in high-temperature sour-gas wells. This work is required because iron compounds that precipitate during acidizing can reduce reservoir permeability in the critical near-wellbore area. Formation damage from fines and precipitated material can be difficult to remove in subsequent remediation treatments. A high temperature see-through cell was used to investigate the behavior of 28 wt% HCl acid formulae provided by three different service companies. Temperatures up to 300°F and pressures up to 500 psi were used in this work. This is the first time in the literature that these high acid concentrations have been studied at 300°F. Previous studies in the industry are available for acid concentrations of up to 15 wt% HCl, temperatures of up to 250°F, and pressures of 500 psi. The following conclusions are made:Nitrilotriacetic acid (NTA) in 28 wt% HCl at 300°F degrades completely after 5 hours. Therefore, NTA is not effective as an iron control chemical under these conditions.At 250°F, 77% of the initial NTA remains after 24 hours.It was estimated that the degradation rate of NTA doubles for each 14°F increase in temperature in the range 250 to 300°F.Service company acid formulae degrade to produce black precipitates in 28 wt% HCl at 300°F. These materials contain significant amounts of polyaromatic hydrocarbons and chlorinated aromatics.The acid formulae of two companies oxidize iron (II) to iron (III) at 300°F in live acids. In spent acid at 300°F, iron (III) is reduced to iron (II) by all three acid formulae. Both reactions may lead to degradation of acid additives.The acid formula from Company C shows an increase in iron sulfide precipitation in spent acid compared to a control. The acid formulae from Companies A and B show no significant effect on iron sulfide precipitation, when compared to a control.In coreflood tests, iron sulfide precipitates immediately when acid containing dissolved iron (II) and hydrogen sulfide spends on a carbonate rock at high temperature. Iron sulfide accumulates on the injection face, not within the rock itself. The following recommendations are made:Reduce total iron concentration in the injected acid to the lowest practical level.Pickle tubing, mixing tanks and lines before the acid treatment.Eliminate the use of NTA at temperatures above 250°F.Investigate other chelating chemicals and hydrogen sulfide scavengers for control of iron sulfide precipitation at temperatures above 250°F. Introduction Iron compounds that precipitate during acidizing can reduce reservoir permeability in the critical near-wellbore area. Formation damage from fines and precipitated material can be difficult to remove in subsequent remediation treatments. Acids can become contaminated with iron by reacting with iron-containing corrosion products in the surface equipment, coiled tubing, well casing, or wellbore as well as iron-containing minerals in the formation.1,2 The economically important gas-producing zones in Khuff wells in Saudi Arabia are the Khuff B and C reservoirs. Permeability of these carbonate formations ranges from 0.01 to 10 mD while average temperature ranges from 250°F to 280°F (121.1 to 137°C).3 Bottom hole pressures of up to 7,000 psi are found. At these high temperatures and pressures, the chemical compatibility and effectiveness of iron control chemicals is of great importance.

Nitrogen/heat generating system (N/HGS) is a thermal-chemical method comprising huge amounts of heat and nitrogen gas generated by reaction between two nitrogen-containing aqueous salts, ammonium chloride and sodium nitrate. The inherent properties of this system make it a good additive in matrix acid stimulation and clean-up treatments for heavy oil wells. The generated heat tends to reduce the oil viscosity, thus enhancing oil mobility while the generated nitrogen gas will reduce hydrostatic pressure of the oil column. Both actions will help the reservoir to better cleanup. Lab results showed that N/HGS was effective in removing oil-based mud filtercake damage. Application of N/HGS cleanup fluid in HP/HT filter press cell was associated with an increase in pressure of more than 100 psi and in temperature of nearly 40°C. An optimized N/HGS formulation was very effective on filtercake removal; nearly 81% of flow efficiency was obtained. The N/HGS formulation contains in addition to the basic nitrogen-containing salts an organic acid, an emulsion breaker and a viscosity reducer. The organic acid, acting as a reaction catalyst in N/HGS, is also proposed to dissolve bridging material presents in filtercake, calcium carbonate. Application of this system, for first time in Saudi Arabia, to remove oil-based filtercake damage from a sandstone horizontal well was very successful. The N/HGS components were pumped in a way to be mixed in the wellbore of the horizontal section. Coiled tubing was used to pump one component while the other component was pumped through the annulus. The reaction of N/HGS components was associated with generation of huge heat as detected by the Distributed Temperature Survey (DTS) which showed that reservoir temperature increased from 153 to more than 300°F. Following the N/HGS treatment, the dead well was able to produce naturally with a competitive production rate compared to offset wells treated with conventional clean-up fluids.

Mono and diamine compounds were synthesized from 1, 12-dodecanediamaine, and evaluated as acid corrosion inhibitors for coiled tubing steel. The inhibition behavior of these compounds in concentrated HCl acid was examined using a gravimetric method. Weight loss tests were conducted in 28 wt% HCl acid at 60, 70 and 80 o C for 2 hours. The results showed that both mono and diamine inhibitors exhibited a good protection efficiency for coiled tubing steel in 28 wt% HCl acid. However, monoamine compounds showed better performance. Addition of an intensifier was effective to enhance protection efficiency for both amine moiety compounds where more than 99% protection was obtained for some inhibitors. The effect of intensifier concentration on inhibition efficiency is also addressed in this paper. The results obtained are very promising and suggest that some of examined corrosion inhibitors have a good potential to be used in acid stimulation treatments of oil/gas wells.

Organic deposit including asphaltene and paraffin may damage the near wellbore area and obstruct production tubings resulting in partial or total loss of well productivity. Most of asphaltene deposits are associated with paraffin. This paper presents a first successful field application of a lab proven/optimized chemical solvent to remove organic deposits from a dead oil well in a sandstone reservoir. A vertical gravel-packed oil producer well was dead due to deposition of organic material in 3 ½" production tubing forming obstruction to flow. The deposition is expected to take place due to long shut-in time as experienced in this well with high GOR. A bailer samples was obtained from this well. Analysis of the obstructing material indicated that they were mainly asphaltene associated with paraffin. Solubility of obtained organic deposits in several solvents was evaluated at reservoir temperature (188°F) and monitored as a function of soaking time. Several criteria were considered in selecting of the optimal solvent formulation, among which were safety and solvency power. The selected formulation incorporates asphaltene dissolver solvent and paraffin dissolver solvent in addition to surfactant. Application of the optimal solvent formulation, that exhibited the maximum solvency power in a minimum soaking time, was very effective in restoring well productivity while minimizing operational cost. A total of 12 feet of obstructing organic deposits were removed from the production tubing using coiled tubing in a multi-stage treatment. Following, the solvent was squeezed into the formation across the screens to maximize cleaning efficiency at the source. The sustainable oil production rate obtained and asphaltene content in flow back samples indicated that the treatment was very successful. To prevent further asphaltene/paraffin precipitation during shut-in time, asphaltene/paraffin inhibitor is recommended. A detail of asphaltene/paraffin formation mechanism, lab evaluation and field application results will be addressed.

Addition of halides (KCl, KBr and KI) to corrosion inhibitor systems is intended to enhance their inhibition efficiency due to the synergetic effect. Halides ions have been proven to be good corrosion inhibitor intensifiers in acidic or basic media and for both steel and aluminum. The halides ions themselves act as corrosion inhibitors. This paper sheds lights on some limitations of halides ions (Cl Ϫ and Br Ϫ ) in HCl acid solutions for low carbon steel. The inhibition performance of halides ions as a function of temperature, soaking time and acid concentration was investigated using the gravimetric method. A synthesized diamine corrosion inhibitor was used in this study and the synergetic effect with halides ions was investigated. The testing conditions included HCl acid concentrations of 15 and 28 wt%, soaking time of 1, 2, 4 and 6 hours, and temperatures of 60 and 80 and 104°C.The results revealed that the synergetic effect of Cl Ϫ and Br Ϫ ions failed at high temperature/acid concentration/soaking time and tended to induce more corrosion. In contrast, iodide ions maintained good intensifying properties with the synthesized diamine corrosion inhibitor at all examined conditions. The value of the synergism parameter was found to be greater than unity for iodide ions at all examined conditions and varied from 1 to less than 1 for Cl Ϫ and Br Ϫ ions depending on test conditions. The morphology of the corroded surface, examined employing stereomicroscopy, indicated that the corrosion attack occurred over the surfaces of all exposed low carbon steel with varying degree of severity. The most sever attack was observed in coupons exposed to inhibited 28 wt% HCl acid in the presence of Cl Ϫ and Br Ϫ ions. In contrast, the corrosion attack in the case of coupons exposed to inhibited HCl acid in presence and absence of iodide ions is less severe.