High-temperature acidizing operations are challenging because of the highly corrosive nature of acids. Hydrochloric (HCl) acid has an especially high reaction rate, which increases the rate of tubular corrosion. In addition to the type and concentration of acids, factors such as temperature and metallurgy influence the rate of corrosion. To meet increasing demand for deeper stimulation at high temperatures, emulsified acid is predominately used. It contains acid in the internal phase and oil in the external phase, forming an invert emulsion. The outer oil phase creates a barrier for acid, allowing its slow release for reaction with reservoir rock. Emulsified acid systems provide several advantages compared to plain acid. The oil barrier especially helps with preventing corrosion by significantly reducing the contact of acid with the metal tubular. High fluid viscosity helps reduce fluid loss, distributes the acid more uniformly in the formation, and reduces the rate of corrosion. Selection of the proper corrosion inhibitor(s) is one of the most important criteria for high-temperature acidizing. The use of intensifier(s) with the inhibitor enhances the corrosion inhibition significantly. This makes it possible to use a higher concentration of HCl acid at temperatures as high as 350°F, thus enhancing the fluid efficiency. In this work, several corrosion inhibitors and intensifiers are studied at varied acid strengths and temperature conditions. To achieve good corrosion control, a synergy is required between corrosion inhibitors and corrosion inhibitor intensifiers. At the same time, they should not negatively impact the emulsion stability. A new emulsified acid system was developed using HCl acid strength up to 28%. High corrosion control imparted by inhibitor-intensifier synergy coupled with the slow reaction rate of emulsified acid makes this blend unsurpassed for use in extreme high-temperature conditions up to 350°F. This emulsified acid system has the potential for use in the Khuff formation of Saudi Arabia with the addition of a H2S scavenger. Testing with a commercially available scavenger exhibited good compatibility with the blend.

Scale formation has been a persistent challenge in many sour gas wells producing from one of the world's largest gas reservoir in Saudi Arabia. Accumulation of scale deposits on downhole tubular and in wellhead manifold interferes field operation, limits well accessibility and decreases well productivity. Extensive efforts have been devoted to understand the scale formation process and to develop cost-effective mitigation strategy. This paper discusses the up-to-date knowledge on the scale formation in these prolific gas wells and presents the descaling technologies deployed and currently considered.Scale composition analyses have been performed for a large number of deposits collected during well workovers and interventions. Wide range of mineral phases were identified and their distribution showed significant variations with samples. Scale often consisted of several different mineral phases. Iron sulfides were usually the dominant components, these included pyrrhotite, troilite, mackinawite, pyrite, marcasite and greigite. Ferric iron scales, such as hematite, magnetite, akaganeite, goethite and lepidocrocite, were also common in the scale mixtures. Common mineral scales, especially calcite, were often found. In addition, iron carbonate and other ferrous iron compounds were also identified. The relative abundance of these minerals showed wide-ranging variations from well to wells. Those variations also changed and with depth and time in the given wells. A more interesting phenomenon was the layered structure in the scale deposits, with two distinct layers having very different compositions. These results provided critical information for the understanding of scaling formation process.Scale removal with chemical method had limited success in past. Scale dissolvers, based on HCl acid, caused severe tubular corrosion and formation damage. Different mechanical techniques have been tested and implemented over the years. These field experiences are reviewed in the paper. Also, challenges and requirements for scale dissolvers are discussed.

Downhole scale deposition in the Khuff sour gas wells in Saudi Arabia has been a persistent problem, which negatively affects operation and production. Scale deposits are composed of predominantly iron sulfides with other types of minerals also present. Mechanical descaling treatment, although expensive and time-consuming, is often required. Effective scale dissolver is highly desirable to enhance descaling efficiency and to reduce treatment cost. An ideal dissolver is required to have high scale dissolving power, no damage to downhole completion and well productivity, and minimal H2S liberation. This paper presents the laboratory studies on the new scale dissolvers developed by service companies. These products have pH values ranging from strong acidic (pH < 2) to high alkaline (pH > 12). Dissolvers were evaluated for thermal stability, corrosivity to mild steel, and compatibility with formation water at downhole temperatures. The potentials of iron sulfide re-precipitation in spent solutions and free H2S generation were also examined. The qualified chemicals were then evaluated for their dissolving capacity using authigenic pyrrhotite and field scales at elevated temperatures. The obtained results show that most effective acidic dissolvers evaluated in this study were very aggressive to low alloy carbon steel at downhole temperatures. For these with acceptable corrosivity, formation of iron sulfide reprecipitation in spent dissolvers and the generation of a large quantity of free H2S gas also prevented them from field application. Some dissolver products were disqualified due to incompatibility with formation water. Dissolvers with near neutral and alkaline pH values, in general, were inefficient to dissolve the heterogeneous iron sulfide scales. The performance of tested dissolvers varied with scales from different wells, attributed by differences in composition, microstructure, and the presence of hydrocarbon. Results also suggested that pyrite and marcasite were possibly formed during the dissolution process. This paper presents an objective assessment on the currently available iron sulfide scale dissolvers, highlights the challenges on downhole scale dissolution in high temperature sour wells, and provides new insights on the scale dissolution process. The results suggest that further R&D efforts are required to develop more effective chemical solutions to mitigate the iron sulfide scale problem.

Development of gas resources in the Middle East is taking an increasingly higher priority, driven by the growing demand for gas based power generation as well as the motivation for replacing oil as furnace fuel as is the case in several middle-eastern countries. Such fields are often characterized by corrosion formation fluids including CO2 and H2S, formation solids and other non-hydrocarbon components. These associated components have the capability to adversely affect on compatability with well completions, design of production facilities, maintenance costs, reservoir assets and product sales value among others. The failure to have such information could represent much more risk than taking the decision to perform downhole sampling and laboratory analysis. Corrosion induced by the presence of sweet or sour gas combined with water production has led to major well integrity issues in some of these fields. Continuous monitoring and remedial programs have been implemented to issues either before or when they occur. Sacrificial tubing completions are deployed periodically inspected using corrosion monitoring tools and replaced based on established criteria. However, this process is associated with high monitoring, completion hardware, work-over and intervention costs. Several corrosion studies in the past have been conducted to understand the properties of water and the effect on the precipitation and deposition of ferric salts in order to devise a predictive model for onset of corrosion which is related to tubular lifetime with a view of establishing a reliable corrosion preventive strategy which precludes expensive monitoring or remedial work-over operations. In the past, produced water collected at surface was analyzed for chemical composition and PVT analysis but such results are inherently inaccurate due to the change in the chemical/composition and physical state of the water from downhole up to the surface. Hence there has been more focus on collecting "representative bottom-hole water samples". Memory based PVT samplers do offer this opportunity but suffer from the disadvantage of having to collect the samples "blind", quite often obtaining samples from the sump or coming back empty. This paper presents a novel technique and engineering accomplishment which enhances the PVT and water sampling capabilities at in-situ conditions on gas producers in combination with full production logging stack deployed on electric line, offering real time control of the sampling operation. The volume captured is adequate for proper broad fluid analysis; lesser quantities generate uncertainties which ended incorporated into the results. Field case studies are presented based on the early stage successful deployment of this technology and its impact on facilitating the recovery of representative formation fluid samples. Results of the fluid analysis have demonstrably improved the understanding of true water chemistry, which is a significant departure from earlier theories and contaminated measurements. Wells were sampled in order to carry out the risk assessment for corrosion and scaling tendency. The impact of the study on developing more effective well integrity and well intervention programs are also presented.to maintain the continuity of operations.