The hot corrosion resistance of sprayed and atomized Fe‐40at.%Al, Fe40Al+0.1B and Fe40Al+0.1B+10Al2O3 intermetallic materials have been evaluated in molten Na2SO4 at 900 and 1000°C using polarization curves and polarization resistance measurements. The results are supported by electron microscopy and microchemical studies. The tests lasted 5 days. At 900°C the Fe40Al material had the lowest corrosion rate (0.03 mA/cm2), and the Fe40Al+0.1B+10Al2O3 exhibited the highest. At 1000°C, the Fe40Al+0.1B material, was the material that had the best corrosion resistance with less than 0.02 mA/cm2 in the first 50 hours, whereas the Fe40Al presented the worst corrosion resistance with 0.20 mA/cm2. The results are discussed in terms of the establishment of an Al2O3 layer that gives corrosion resistance to the materials and promotes an Al depletion in the FeAl matrix which allows the sulfides formation.
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.
TX 75083-3836, U.S.A., fax +1-972-952-9435. AbstractStimulation of oil wells is becoming more and more challenging every year. Wells easy to select are fast diminishing. Today's candidate for matrix acid stimulation have high water cut, close oil-water contact, marginal pay zone to stimulate and complex completion, raising more challenges. Combining coiled tubing pinpoint treatment placement with diversion method is crucial for such wells. Traditional chemical diversion like gelplug, VES, foam or nitrogen divert treatment fluid in the zone of broad permeability contrast.Interestingly, encouraging results were experienced when coiled tubing coupled with downhole rotary jetting tools were used to augment chemical diversion. For the first time these tools have been used to facilitate stimulation of openhole completed wells in carbonate reservoir of Ghawar field with outstanding result.Rotary jetting tool is useful mechanical mean to supplement coiled tubing pinpoint placement of stimulation fluids due to high power jetting and 360 degree rotation of the jetting tool. The high pressure drop across the nozzles is converted to high velocity flow which penetrates deeply and thoroughly inside the critical matrix and improves the quality of the treatment placement. Based on well conditions, proper nozzle size with optimized jetting power by speed-controlled rotating nozzle head is the key in this process. Significance of this system is to eliminate the domination of the high permeable zone on the treatment distribution by improved pinpoint jetting efficiency with proven results. It reduces the treatment fluid volume per foot of formation. Sustained gain is achieved as the treatment is more than acid wash. The system also replaces traditional jetting and wash-tools that are without rotating capacity. This paper evaluates the added value of high velocity downhole rotary jetting tools in pinpoint acid stimulation operations with all pros and cons. Case studies for both oil producers and water injectors will be discussed.
Iron sulfide (FeS) deposition is a ubiquitous phenomenon in sour oil and gas wells, especially for these producing from high temperature and high pressure reservoirs. Hydrogen sulfide (H2S) gas is highly soluble in water and readily reacts with carbon steel and dissolved iron once in contact, which leads to the formation of FeS scale. The surface deposition or bulk precipitation of FeS scale is detrimental to flow assurance, such as flow restriction, pitting corrosion and stabilized emulsion. Compared to the conventional carbonate and sulphate scales, the mitigation of iron sulfide deposition is notoriously difficult. It is essential to understand its root causes in order to develop a suitable strategy to manage the problem effectively. By combining laboratorial tests and model simulations, new progresses have been made on the FeS root cause analysis for high temperature high H2S gas wells. The iron sources were determined over different stages of well life from drilling, completion, acidizing to production. Results from this study demonstrate that the iron contributed by the sour reservoir connate water is limited and is not the major cause to FeS deposition on downhole tubular in sour gas wells. Carbon steel corrosion during production stage is one source of FeS deposition. However, the rate of iron sulfide deposition during production is minor and far less than the deposit observed in the field. Other sources of iron sulfide deposition should be further investigated. Another major source is the iron released from tubing due to acid corrosion during acidizing stimulation, which potentially leads to severe formation damage and associated deposition problems in the production tubing and equipment. In addition, the iron contamination in the drilling fluid could contribute to FeS scaling problem. This paper presents a fundamental study to understand the sources of iron for FeS deposition in high H2S sour wells producing from carbonate reservoirs. Appropriate mitigation strategies are recommended accordingly.
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