Cycle efficiency is one of the critical parameters linked to the success of implementing a Supercritical Carbon Dioxide (sCO2) power cycle in a Concentrating Solar Power (CSP) plant application. Ambient conditions often change rapidly during operation, making it imperative that the efficiency of the plant cycle be optimized to obtain the maximum power production when sunlight is available. Past analyses have shown that operating the cycle at the critical point provides the optimum efficiency for dry operation. However, operation at this point is challenging due to the dramatic changes in thermophysical properties of CO2 near the critical point and the risk of the fluid having a two-phase, gas-liquid state. As a result, there is a high likelihood that liquid can form upstream of the primary compressor in the sCO2 power cycle. This paper explores the potential for liquid formation when operating near the critical point and looks at the influence of liquid on the compressor performance. The performance impact is based on industry experience with wet gas compression in power generation and oil and gas applications. Options for mitigating liquid effects are also investigated, such as upstream heating, separation, or compressor internal controls (blade surface gas ejection). The conclusions of the paper focus on the risk, estimated impact on performance, and summary of mitigation techniques for liquid CO2 entering a sCO2 compressor.
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Wet Gas Compression (WGC) continues to be an important topic as oil and gas production is driven further out into the ocean and moves critical equipment to the ocean floor. In the last year, significant milestones have been reached for WGC by the installation of the first wet gas compressor off the coast of Norway. Even with this achievement, there is a lack of understanding of the physics behind WGC and there are deficiencies in the ability to predict the compressor performance. Understanding the two phase flow structure inside the compressor is important for validating WGC simulations and being able to predict compressor performance. This paper reviews the results from a test program focused on characterizing the flow inside the compressor by using flow visualization. An open impeller centrifugal compressor was outfitted with windows to view the flow inside the compressor at the inlet, inside the impeller and in the diffuser section. Testing was conducted with an ambient suction pressure at various compressor speeds, flow rates, and liquid volume fractions. Images and videos were captured at the different conditions in order to observe the two phase flow structure. The general patterns and trends that characterize wet gas flow are discussed in this paper.
Foams have been used as hydraulic fracturing fluids to reduce water usage and minimize the potentially deleterious impact on water-sensitive formations. Traditionally, carbon dioxide (CO2) and nitrogen (N2) have been used as the internal phase in these foamed fluids. Hydraulic fracturing with natural gas (NG) is a relatively inexpensive option, particularly if NG produced from the wellhead can be used without significant processing. In an ongoing program sponsored by the US Department of Energy (DOE), an alternative fracturing process is being developed that uses NG-based foam. Previously, the optimal thermodynamic pathway was identified to transform wellhead NG into pressurized NG suitable for use as the internal phase in a foamed fracturing fluid. Recent work has focused on preparing a NG-based foam at surface conditions typically encountered in hydraulic fracturing and measuring the stability and rheological properties of the foam. In addition, the transient response of the foam during fracture initiation was simulated using a fast-acting solenoid valve. A single base-fluid mixture was prepared by combining a commercially available viscosifier and foaming surfactant with water. The base fluid was then injected into a tee using a water pump. Simultaneously, liquefied natural gas (LNG) was pressurized using a cryogenic pump, vaporized using a heat exchanger, and injected into the tee to mix with the base fluid and generate foam. The foam then flowed through approximately 300 ft of 0.312-in. inside diameter (ID) tubing equipped with pressure transducers at several locations. The test fixture included a sight glass to visually inspect the quality of the foam. This paper reports on findings related to foam stability and rheology and compares these results to previous studies on foamed fracturing fluids.
Hydraulic fracturing treatments are used to produce oil and gas reserves that would otherwise not be accessible using traditional production techniques. Fracturing treatments require a significant amount of water, which has an associated environmental impact. In recent work funded by the Department of Energy (DOE), an alternative fracturing process has been investigated that uses natural gas as the primary fracturing fluid. In the investigated method, a high-pressure foam of natural gas and water is used for fracturing, a method than could reduce water usage by as much as 80% (by volume). A significant portion of the work focused on identifying and optimizing a mobile processing facility that can be used to pressurize natural gas sourced from adjacent wells or nearby gas processing plants. This paper discusses some of the evaluated processes capable of producing a high-pressure (10,000 psia) flow of natural gas from a low-pressure source (500 psia). The processes include five refrigeration cycles producing liquefied natural gas as well as a cycle that directly compresses the gas. The identified processes are compared based on their specific energy as calculated from a thermodynamic analysis. Additionally, the processes are compared based on the estimated equipment footprint and the process safety. Details of the thermodynamic analyses used to compare the cycles are provided. This paper also discusses the current state of the art of foam fracturing methods and reviews the advantages of these techniques.
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