Iron sulfide, as one of the main products of sour corrosion in oil and gas production systems, has become a focal point for flow assurance research. The formation of iron sulfide can cause many production problems such as the malfunction of downhole devices which can lead to a significant decline in oil production. Once iron sulfide forms in the production system, it is difficult or impossible to remove chemically and costly to remove physically. Accurate prediction models for iron sulfide formation at reservoir conditions are currently lacking in the industry and are necessary to help control scale and improve flow assurance. Solubility product (Ksp) of iron sulfide is the key parameter to make accurate scale predictions. However, research towards iron sulfide including precipitation, dissolution, inhibition, and removal are notoriously difficult not only due to the complexity of iron sulfide phases and their transitions but also due to the involvement of hydrogen sulfide in the gas phase. Tomson Technologies has developed new technologies to simulate realistic field downhole conditions for scale research. A reliable flow-through apparatus has been customized to perform mineral solubility studies under xHPHT (up to 1720 bar and 250 °C). In order to simulate the strictly anoxic environment and prevent dissolved ferrous iron from oxidizing, dissolved oxygen in the test solutions has been reduced to far less than 1 ppb. This paper is the first to examine the solubility of iron sulfide under these realistic downhole conditions with temperature up to 250 °C, pressure up to 1720 bar in 1M and 3M ionic strength solutions, under a strictly anoxic environment (<< 1 ppb dissolved oxygen). Under the HPHT and high salinity conditions studied, iron sulfide tends to form pyrrhotite (Fe1-xS) and troilite (FeSt) phases instead of mackinawite, the metastable phase (FeSm), which is most common at lower temperatures. Phase transition between pyrrhotite and troilite at elevated temperatures was observed during the solubility experiments. Solubility of iron sulfide decreases with increasing temperature and increases with increasing pressure which is consistent to previous reported results (Kharaka, et al., 1988). Experimental details and major findings from this research will be discussed.
Scale control in ultra-deepwater under high temperature, high pressure and high total dissolved solids (TDS) is critical for efficient and safe oil and gas production. With the continued development of offshore production in ultra-deepwater, more and more wells are exposed to extremely high temperature (>150 °C) and pressure (>15,000 psig) under anoxic condition. However scale testing, prediction and control under these extreme conditions is often challenging due to the limitation of testing equipment to accurately simulate these environments. The dynamic tube blocking test is a widely applied test approach for evaluating scale risk and scale inhibition efficiency in the laboratory. However, little information has been reported for studying control and inhibition of siderite (FeCO3), a major product from corrosion. Furthermore, very few studies assess the scaling risk of iron oxides under extremely high temperatures. In this research, the kinetics of siderite nucleation and precipitation has been studied in the absence and presence of scale inhibitors including sulphonated polycarboxylic acid (SPCA), polyvinyl sulphonate (PVS), carboxymethyl inulin (CMI) and sodium citrate. Scale inhibitors have been evaluated at high temperature (up to 250 °C) to determine if they are applicable for siderite (or iron oxide) inhibition. Inhibition of iron oxide precipitation under 250 °C and 600 psig was observed. All solutions used in this research are strictly anoxic with ≪ 1 parts per billion (ppb) of dissolved oxygen and in the absence of added reducing reagents, that might alter the reaction. This strictly anoxic condition is critical for evaluating inhibition efficiency and degradation of scale inhibitors due to the interferences and reactions between dissolved oxygen and scale inhibitors.
Polymeric scale inhibitors used for scale squeeze treatments to control downhole inorganic scale don't perform well when pumped into the reservoir due to the poor adsorption properties on the rock surface. However polymeric inhibitors are more temperature stable than phosphonates and have higher tolerance to elevated cation compositions in the water. Therefore, a new chemistry composed of metal nanoparticles coupled with a polymeric scale inhibitor was developed to improve the squeeze life. The use of nanoparticles in the oilfield has increased in recent years; this development shows how nanoparticles can be used to increased surface area and retention of scale inhibitor in the reservoir. Metal nanoparticles were selected because of their low environmental toxicity and low formation damage potential during injection and flowback. A fast and efficient synthesis method was developed to create a novel chemistry that couples nanoparticles with polymeric inhibitors to produce a product that it was hoped would have excellent squeeze properties in multiple rock permeabilities and compositions. Core flood experiments were conducted on intact core under onshore Permian conditions of temperature pressure and brine composition as well as conditions simulating an offshore conventional field (results will be reported separately). The experimental results will be presented to show the extended squeeze lifetime of the new product in comparison to a traditional polymeric scale inhibitor retained by adsorption and also will give insight into the mechanisms by which the nanoparticle/scale inhibitor enhances squeeze life, both by increased adsorption as well as prolonging release of scale inhibitor. The product developed is able to significantly increase the squeeze life of polymeric scale inhibitors by up to 10x depending on the minimum inhibitor concentration required. The retention of the inhibitor into the rock is significantly increased, while the release is controlled at above minimum effective concentration for extended periods. The theoretic explanation for this is a metal-inhibitor bond, proprietary to the product that allows for continuous release of inhibitor into the solution, without release from the rock. Traditional squeeze returns have a Freundlich isotherm, this product also follows a similar return curve, however does not suffer from the high concentration release at the beginning of the treatment flowback. These results show that nanoparticles can be used in the oilfield to enhance existing scale inhibitors as well as create new combination products that can improve performance. Use on nanoparticles in the oilfield is an evolving topic that has significant room to grow and expand into multiple areas of oilfield chemistry. This study showcases the application of nanoparticles to enhance performance of polymeric scale inhibitors for squeeze application while maintaining a cost effective product that is environmental responsible.
Prediction and prevention of scale and corrosion at extreme high pressure and temperature (xHPHT) is important to reduce environmental risk, improve human safety, and for production security for Gulf of Mexico (GOM) ultra deepwater (UDW) oil and gas production. In order to develop the methodology and prediction models needed for xHPHT corrosion, scale formation, inhibition, and the next generation of fluid modeling, this research was funded by RPSEA to study corrosion and scale at extreme pressure and temperature. This paper presents the corrosion experimental work conducted at xHPHT and high total dissolved solids (TDS) conditions in both a static autoclave reactor and a flow-through apparatus. The corrosion behavior of different alloys used for deepwater production tubing in two types of synthetic brines which simulated two UDW well conditions were studied. Reliable and feasible apparatus and procedures were developed for the corrosion study at extreme pressure, temperature and TDS conditions. Vertical scanning interferometry (VSI) was explored and found to be a powerful tool for localized corrosion analysis of different surface shapes (e.g., flat or curved).
In hydraulic fracturing, large amounts of water are pumped at high speed down the wellbore. To reduce pump pressure and costs, a friction reducer is added to the stream. There is currently no unified performance criteria for selection of friction reducers. This work outlines the methodology for producing such a unified method of comparing performance between any friction reducer chemical additives, both liquid and dry powder. A 0.5 inch stainless steel high-flow low-shear flow loop pumping at ranges between three and twenty gallons per minute was custom-built. The loop uses a Coriolis flow meter, two absolute pressure transducers, and one differential pressure transducer to accurately determine the friction reducer additive performance in any given fluid by measuring pressure drop across a section of developed flow. This paper utilizes over 400 in-house flow loop tests to establish a novel unified ranking system for the evaluation of friction reducers’ performance. The ranking is independent of the type of friction reducer used and quality of water. Produced waters, fresh water, treated produced waters, and synthetic waters were all used to validate the methodology and ranking system to create a unified criteria to compare performance of any friction reducers. Tomson Technologies created a standardized metric for assessing and ranking friction reducer performance. This standardization was achieved through the use of an unique performance scale comprised of the weighted average of the most important friction reduction parameters of a friction reducer in any produced water: (1) inversion time (InvT), (2) maximum percent friction reduction (Max% FR), (3) time to sustain maximum percent friction reduction (RetT@%Avg.FRmax), and (4) the percent friction reduction at the end of 500 seconds (% FR@500s). 500 seconds is used because fluid during hydraulic fractures travels from the pumps to the reservoir in 500 or fewer seconds in almost all cases. This scale is measured in a new unit called "Friction Reducer Units" (FRU), which ranges from 0 to 10. FRU has been used to rank and correlate the performance of different classes of friction reducers in various types of waters, resulting in a comprehensive results database and is used to show applicability of the overall metric.
With the continued development of offshore production in deepwater wells, a greater understanding of scale formation and corrosion under extreme high pressure and temperature (xHPHT) is needed. In order to better predict scale formation and scale solubility, knowledge of the thermodynamic and kinetic properties of these mineral systems under xHPHT conditions is important. Research to expand the amount of data and models for different types of scales at these conditions will reduce offshore production risk and improve human safety in ultra-deepwater (UDW) production. A novel flow-through apparatus has been developed to perform a scale solubility, dissolution, and precipitation study of minerals under high pressure (up to 24, 000 psig), high temperature (up to 250 °C), and high total dissolved solids (TDS, up to 360, 000 mg/L). This part of research will focus on the solubility study of magnetite and siderite. Studying dissolution and precipitation will improve understanding of the formation of passive layers (Fe3O4 and FeCO3) and their phase transitions as temperature increases, as has been observed in corrosion research. In this work, effects of reaction conditions, including temperature, pressure, pH, and brine composition on solubility of magnetite, have been investigated. Reduction potential is an important parameter which will affect magnetite solubility dramatically and is sensitive to brine composition. Details of the experimental setup and preliminary results of this research will be presented.
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