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.

One of the major challenges of corrosion and scaling management in sour gas wells is to effectively monitor corrosion and scaling under real-flow regime conditions. It is very difficult to simulate the actual environment and flow conditions in laboratory experiments to study downhole corrosion and scale formation. Understanding the corrosion and scaling mechanism under downhole conditions is very important in order to develop effective prevention and mitigation strategies in a timely manner. An advanced downhole corrosion and scale monitoring (DCSM) tool has been designed and developed to monitor corrosion and scale formation in sour gas wells. This monitoring system represents significant improvements over the current industrial technology by directly measuring corrosion and scale deposition in real downhole conditions using exchangeable coupons with identical metallurgy as the downhole completion tubing. A slick line with a retrievable high-expansion gauge hanger was used to deploy and anchor the DCSM downhole at the desired depth. The tool was retrieved after 3 months exposure to the reservoir conditions for post-laboratory analysis. Advanced analytical techniques were carried out to understand the corrosion and scaling mechanism, including SEM, EDS, XRD, and surface profile measurement besides quantifying the weight changes. The results showed that a thin layer (~3-4 μm in thickness) of iron sulfide scale was deposited on the surface of coupon. It served as a protective layer to prevent and reduce further corrosion and scale buildup. To understand the mechanisms of scaling, the surface scale deposit was removed by corrosion inhibited acidic solution. The surface profile measurement showed localized pitting corrosion which appeared on the surface of coupon, which indicates that corrosion happened first followed by scale layer deposition on metal coupon surface. The newly developed DCSM tool has an advanced design which allows direct corrosion and scaling monitoring under downhole conditions. Post-laboratory analysis on retrieved coupons can provide corrosion and scaling mechanism for specific metallurgy under real downhole conditions. Proper corrosion and scale management programs could be designed to minimize the effects of corrosive gases. The developed tool can be used to monitor the effectiveness of the corrosion treatment and can be deployed in sweet gas wells, oil wells and water supplier wells.

Summary Thick deposits of various types of mineral scales are presently forming in the tubulars and formation of gas producers drilled in Saudi Arabian carbonate reservoirs. These mineral scales precipitate when ideal thermodynamic conditions combine with dissolved minerals present in formation waters. Without remedial action over time, these deposits can grow thicker and end up plugging tubulars and the reservoir. Thick deposits of mineral scales have recently begun to appear in gas producers in certain areas of the field. A comprehensive study was conducted to ascertain the nature of the precipitation mechanism and identify potential solutions to the problem. This paper details how laboratory analysis data, well production history, reservoir geology and petrophysics, and reservoir description were analyzed and used with sophisticated computer software to identify the formation-damage mechanism and the different scale types precipitating in the wellbore and formation. Extensive simulation work was conducted as part of the study to forecast the type and amount of mineral-scale precipitation that can be anticipated at varying reservoir and producing conditions. The study also evaluated the most cost-effective and feasible ways to remove different types of scale deposits. The future scale-inhibition and -removal strategies to be implemented in existing and future gas producers are being derived in large part from the results of the study described in this paper.

Iron sulfide scale deposition in sour gas wells is a corrosion induced flow assurance issue. Corrosion inhibitor batch treatment is one of the techniques used to mitigate corrosion and iron sulfide deposition on downhole tubing. The objective of this study is to introduce the newly developed Downhole Corrosion and Scale Monitoring tool (DCSM) to evaluate the performance of batch treatment of corrosion inhibitor under real downhole conditions. An advanced DCSM tool has been designed and developed to monitor and evaluate the performance of the corrosion inhibitor batch treatment in a sour gas well under actual downhole environment and multiphase flow regime. The tool was retrieved after 3-5 months of exposure to the reservoir condition for post-laboratory analysis. The retrieved coupons were thoroughly characterized to assess the performance of corrosion batch treatment and to understand the mechanisms of corrosion and scaling. X-ray diffraction (XRD) was used to analyze the mineraological composition of the surface scale deposition. Scanning electron microscopy (SEM) and energy dispersive x-ray spectroscopy (EDS) analyses were performed to characterize the morphology and elemental analysis of the surface deposition. A surface profilometer was used to quantify the size/depth of the general or localized corrosion, as well as the surface deposition. To evaluate the performance of the corrosion inhibitor batch treatment, two sets of trial tests were conducted in a selected high-temperature sour gas well. One set of the coupons was retrieved after three-month exposure without corrosion inhibitor batch treatment; the other one was retrieved after five-month exposure with corrosion inhibitor batch treatment. The results showed that a very thin layered iron sulfide scale was formed on the surface of test coupons in both cases. General and localized pitting corrosion were found which indicates that corrosion happened first followed by scale layer deposition on metal coupon surface. Less harsh general and localized pitting corrosion were observed in the presence of corrosion inhibitor batch treatment. The corrosion inhibitor treatment did reduce the general corrosion and localized pitting corrosion under scale deposit at a certain level. The newly developed DCSM tool is an advanced design which allows direct corrosion and scaling monitoring for metal coupons under downhole conditions. Combined with post-laboratory analysis, it provides corrosion and scale mechanism, evaluation on the performance of mitigation, and proper corrosion and scale management programs to minimize corrosion and scale. The DSCM tool can also be deployed and applied in sweet gas wells, oil wells, and water supplier wells to monitor the corrosion and scale under real downhole conditions.

Iron sulfide is one of the exotic scales formed in the oil and gas fields, particularly for those deep sour gas wells producing from high temperature and high pressure (HTHP) reservoirs. Compared to the conventional carbonate and sulphate scale, the mitigation of iron sulfide deposition is notoriously difficult. To develop a suitable mitigation strategy, it is essential to understand the formation mechanisms of iron sulfide in the given production system. In this work, we combined laboratorial tests, thermodynamic modelling, and field monitoring for the understanding the source of iron and the mechanisms of iron sulfide deposition in the sour gas well during acidizing treatment and production stage. Study results indicate that iron sulfide deposition in sour gas wells is a corrosion induced scaling problem. During acidizing treatment, high concentration of iron is released from tubular due to acid attack, despite corrosion inhibitor is used in the stimulation fluid package. Large amount of iron sulfide can precipitate when spent acid mixes and reacts with H2S in the reservoir and potentially causes severe formation damage. During the production stage, the iron released from tubular due to corrosion in produced water under high temperature and high pressure is the major contribution of iron sulfide deposited at the surface of tubing. These iron sulfide deposits, although appeared as porous layer, can protect the downhole completion from the highly corrosive fluids, which leads to the unexpected long service lives of mild carbon steel tubular in many wells. However, accelerated corrosion can occur when the protective iron sulfide film or deposit is disturbed or partial. This paper presents a fundamental study to understand the root cause of iron sulfide deposition in sour gas wells. Study results demonstrate that effective corrosion inhibition is key to mitigate the iron sulfide deposition problem in the sour gas wells.