The formation of CaCO3 mineral scale is a persistent flow assurance problem in the oil and gas industry. It deposits at various locations with different levels from reservoir to topside flowline. It could restrict well intervention, block flowline and reduce production. To make an effective mitigation strategy, it is essential to understand the location and severity of scaling, and the performance of scale inhibitor under specific operation conditions. In the work reported herein, the dynamic scale loop tests were performed to evaluate the severity of scale deposition at different locations from the reservoir to transport flowline in the absence and in the presence of scale inhibitors under dynamic conditions. The tests are carried out at various temperatures (20-130°C) and pH (6.0-8.3), which are major factors contributing to calcium carbonate formation and representative of the operating conditions at different locations from reservoir to topside flowline. The results showed low calcium carbonate risk from reservoir to wellhead under tested conditions. Although the high reservoir temperature favors calcium carbonate formation in downhole, the low pH reduces the risk of calcium carbonate formation at downhole conditions. Harsher calcium carbonate deposition is evaluated at the conditions of phase separator/degasser units due to the higher pH of produced water after released CO2 from fluid. Calcium carbonate scale can also deposit in transport flowline, especially at high temperature during summer in the desert area, along with higher pH of the produced water. Calcium carbonate scale prevention and mitigation treatments are required to inhibit scale deposition. The tested phosphonate scale inhibitor provides low dose rate to effectively inhibit calcium carbonate formation at high temperature. The corrosion inhibitor could have a negative impact on the performance of scale inhibitor, and this must be considered when designing the scale inhibitor treatment. This paper gives a comprehensive study of scaling risk evaluation from downhole to topside flowline in the absence and in the presence of scale inhibitor. It contributes to the understanding of calcium carbonate formation and inhibition in the whole production system and recommends effective scale mitigation strategies.
Iron Sulfide deposition in production facilities is one of the flow assurance issues in oil and gas industry. It can cause tubing blockage, interfere well intervention, and reduce production in both sour oil and gas wells. Mechanical descaling is currently applied, but it is time consuming and costly. Dissolvers based on concentrated hydrochloric (HCl) acid have high dissolving power, but with a limited applicability due to overwhelming drawbacks such as corrosion and H2S generation. Low corrosive, non-acid chemical dissolvers were developed. However, the dissolution rate is low and is not comparable to concentrated hydrochloric (HCl) acid performance. Following the development of the iron sulfide dissolver presented in ADIPEC 2017, this work focuses on the improvement of the kinetics of iron sulfide dissolution, the kinetic factors of the dissolution rate. The non-acidic iron sulfide dissolver was used in lab dissolution tests. The effect of dissolution temperature, particle size, agitation, and ratio of volume of dissolver and mass of scale, were studied. Scale dissolution tests at temperature between 40°C and 125°C were carried out to evaluate the dissolution rate of pyrrhotite scale particles of sizes between 10 and 80 mesh. The ratios of volume (ml) of dissolver and scale particles (gram) were tested from 10:2 to 20:1. The agitation was from static to 160 rpm. The tests lasted for 6 hours. The dissolving amount was calculated by weight difference between the initial and final solids. The results show that the kinetics of pyrrhotite dissolution can improve significantly at high temperature due to the increase in the thermodynamic of dissolution, and by reducing the particle size to increase the contact surface area of scale particles. The increase of volume ratio of dissolver with the mass of scale particles and increasing agitation have limited effect on the kinetics of scale dissolution under the test conditions. This study provides and ranks the kinetic factors for iron sulfide dissolution. It gives a guideline to improve iron sulfide dissolution during field application using non-acid based iron sulfide scale dissolver.
Excessive water production affects profitability of oil and gas. It reduces hydrocarbons production rates. In addition, it leads to corrosion, scale formation, and extra costs in constructing large water handling facilities. One of the key issues is to correctly identify the source of the excess water and develop the appropriate treatment.1 The targeted reservoir of this study is a naturally fractured carbonate reservoir that displays super K which are areas of extremely high permeability that can produce substantial volumes of both oil and water. Super K zones can significantly enhance recovery per well, however, these zones present significant challenges at the onset of water production because they can dominate the flow in the wellbore resulting in high water loading. One chemical method to deal with the excessive water production problems is the use of Relative Permeability Modifiers (RPM). It reduces water cut of the produced fluids without significantly damaging hydrocarbon production. Unfortunately, most of the developed RPMs are suitable for Sandston reservoirs rather than carbonate ones. There have been no successful applications of materials that display a relative permeability modification in reservoirs of this type. It is estimated that carbonate reservoirs contain more than 60% of the world’s remaining oil reserves so the development of new technologies that enable these reserves to be tapped are extremely worthwhile.2 The development of novel materials which could tackle excess water production in carbonate wells would represent a radical, and much needed step-change technology for the extraction of the significant reserves trapped in reservoirs of this type. This paper describes a comprehensive review of different chemical methods for water control and reports on lab tests to examine the performance of several commercially available RPMs to reduce water-cut in carbonate cores. An advanced work to create and develop a relative permeability modifier (RPM) to control water production in naturally fractured carbonate fields with super K permeability is also described in this paper.
Calcium sulfate scale is one of the challenges that face production stability in the oilfield industry as it is one of the most challenging scales to manage. Sulfate-scales are very hard to dissolve because of their low solubility-product. This work studies the dissolution capacity of different chemical additives and recipes on calcium sulfate scales. In this work, the maximum dissolution capacity (gram of scale/mole of chelating agent) of various chemical additives and recipes will be studied to evaluate the efficiency in the dissolution of Calcium Sulfate scales. Several experiments were conducted at multiple doses, pH, and in-presence of a catalyst. Potassium Carbonate was used as a catalyst in the dissolution of Calcium Sulfate scales. The performance of each additive was studied in a catalyzed and non-catalyzed pathway and with various. A Series of experiments conducted showed that parameters such as the additive-dose, pH, and a catalyst affect the dissolution efficiency. The dissolution performance efficiency of each additive (Lactic Acid, Citric Acid, L-Glutamic Acid-N, N-diacetic Acid (GLDA), and Gluconic Acid) was compared to the additive performance efficiency under a catalyzed pathway in a formulated recipe. The outcome of this work will contribute to the economic value added by finding the most efficient and cheap recipe to remove Calcium Sulfate scales from the wellbore.
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