Chapter 13 - Dynamic simulation of gas processing plants

Chapter 16 - Human Factors and Ergonomics

This paper describes a vapour phase method for cleaning and decontamination of a slug catcher in a gas processing plant. Corrosion and heavy metal losses required the slug catchers to be replaced. Safe decommissioning demanded the elimination of H2S, LEL and pyrophoric iron. Compromised integrity made traditional cleaning methods like circulation or pressure jetting unfeasible. The proposed method significantly reduced decontamination times and the associated effluent. The vapour phase method using degassing chemicals entrained in steam lowered H2S and LEL levels to substantially zero and also neutralized the pyrophoric material. The entire cleaning process was conducted with a temporary H2S scrubber due to unavailability of the process flare. This method did not require the system to be liquid filled or subject to high jetting pressure, making it possible to limit the treatment pressure to below 2 barg, thus minimizing the stress on the structural integrity of the slug catcher. In addition, the slug catcher weak zones were fortified externally in preparation for decontamination. This technique of using steam as a medium to distribute and apply the degassing chemicals throughout the slug catcher has proven to overcome the limitations of conventional cleaning methods. It further provided a viable solution to reducing the time and resources required to achieve substantially zero H2S, LEL and pyrophoric content by half. With traditional cleaning methods, the effluent generated would be substantial, necessitating additional logistical support for transporting the waste from the offshore location. Decontamination in a steam saturated vapour phase reduced the amount of effluent generated significantly, to only one third in comparison. This resulted in a solution that was more economical and environmentally friendly. Effective decontamination eliminated the risk associated with the presence of hydrogen sulfide (H2S) gas and pyrophoric materials, ensuring the slug catcher was decommissioned safely and successfully. For heavily compromised systems and for locations with water supply, waste management or schedule constraints, the vapour phase decontamination process has distinct advantages over conventional methods. The resultant savings in time and resources makes this an attractive option for mainstream oil and gas processing facilities as well.

The major sources of gas flaring and air contamination in the natural gas processing plants: A case study

Digital Twin (DT) technology has rapidly matured from pilot projects to integral components of advanced asset management and process optimization in the oil and gas (O&G) industry. This review provides a structured synthesis of the current state of digital twin frameworks, with a focus on offshore and topside gas-processing systems, such as those found on Floating Production Storage and Offloading (FPSO). Emphasis is placed on high-fidelity process simulations and scalable architectures integrating real-time data with advanced analytics. Drawing on over 85 peer-reviewed sources and industrial frameworks, the paper outlines modular DT architectures, encompassing steady-state and dynamic process simulations (e.g., Aspen HYSYS), reduced-order and hybrid machine learning models, co-simulation environments, and advanced equation-of-state packages (e.g., GERG-2008). Special attention is given to compressor map integration, Equations of State (EOS) selection, ISO/IEC standard compliance, and digital thread continuity. Additionally, the review explores economic and sustainability-driven DT implementations, including flare and methane mitigation, ISO 50001-aligned energy optimization, and lifecycle/decommissioning strategies. It concludes with a technical and economic assessment of DT maturity for gas compression facilities, identifying research gaps in standardization, long-term validation, and cybersecurity integration. The insights provided are intended to support decision-makers, engineers, and researchers in deploying scalable, auditable, and high-impact DT solutions across the O&G value chain.

The experimental work has been carried out on range of spigot diameters and two hydrocyclone sizes. The slurries used were mixtures of ball clay and silica which have been used as models for industrial slurries. Variations in the rheological properties were effected by varying the concentration of each of the components and with the use of viscosity modifiers. Viscosity modifiers were employed to significantly reduce the yield stress in the slurry, which led to an increase in the separation efficiency and improved the sharpness of cut significantly. A correlation for the prediction of hydrocyclone performance was developed. An agreement exists between the prediction and the experimental data. These results are very important for industrial processes involving separation of concentrated mixtures of particulate flows as they provide information for the design and operation of mineral processing plants in the mining industry.

Some lessons from thermal-runaway incidents

Due to the limited quantitiesand high cost of energy resources, the task of reducing their consumption at existing gas processing plants is crucial. One of the methods to save energy is to optimize the distribution of heat flows at a process unit. The most energy-consuming unit in natural gas processing plants isademethanizer, so the decision to optimize the operation of this unit is practical.To this end, the article discusses the existing options of layout for the stripping section of the unstabilized gas condensatedemethanizer at natural gas processing plants with deep extraction of C2+hydrocarbons.The peculiarities of equipment layout for the stripping section of the demethanizer in all the considered options have been studied in detail. The positive and negative sides of each option have been revealed.A proprietary design is proposed for a shell-and-tube heat exchanger with a phase interface that performs the function of a stripping section for the demethanizer. A comparative analysis of using a horizontal thermosyphon evaporator and a shell-and-tube heat exchanger with a variable vapor-liquid ratio under the same operating conditions is given. As a result, it was revealed that the total weight of equipment and overall dimensions of the steel structure in the first option are greater than in the second one. It is established that the latter solution will simplify the layout of the demethanizer unit and improve the process performance of the plant, providing an advantage over the existing technology solutions. Besides, the design of this equipment makes it possible to use it in gas processing plants with low-temperature processing of natural gas.

Improvement of integrity management for pressure vessels based on risk assessment - A natural gas separator case study

THE RELEVANCE. The gas processing industry is quite energy intensive and requires significant energy costs to carry out its activities. Finding ways to improve the energy efficiency of enterprises in this industry is a necessary and urgent task. THE PURPOSE. Identification of opportunities to improve the energy efficiency of the operation of existing industrial furnaces of a gas processing enterprise with the development of energy-saving measures.METHODS. To achieve this goal, a study of existing industrial furnaces of a gas processing enterprise was conducted for the possibility of useful use of low-potential heat of outgoing flue gases. A feasibility study of the proposed energy-saving measures has been carried out.RESULTS. The analysis of the enterprise revealed a low efficiency of technological furnaces. The reasons for the low efficiency are the overestimated excess air coefficient and the high temperature of the exhaust flue gases. The following directions for improving the efficiency of furnaces are proposed: utilization of the thermal energy of flue gases and maintenance of the excess air coefficient at the regulatory level.CONCLUSION. The calculated energy saving potential with a decrease in the temperature of outgoing flue gases to 160 ° C was 82348.8 Gcal, and with a decrease in the excess air coefficient to the standard 5% - 8986 Gcal. In total, this amount will amount to about 23% of the total heat generation by industrial furnaces. The proposed energy-saving measures will make it possible to utilize the thermal energy of flue gases and reduce the excess air coefficient in order to achieve a standard fuel/air ratio. The effect of the proposed measures will amount to 79694 Gcal, which is about 20% of the total heat generation by industrial furnaces.

The study outlines the evolution undergone by the gas industry in the Russian Far East and reviews the main features of its resource base, transport infrastructure, and processing facilities. We analyze the goals of the Eastern Gas Program and its results achieved. We reveal that for two decades, the development of the industry was carried out in an extensive way and was subordinated to the pursuit of national interests. We consider three configurations of the gas industry in the region. The configurations are related in such a way that to arrive at the next configuration the preceding one is complemented by production facilities representing the next link of the process chain. The gas industry in its first configuration includes natural gas production and transport companies; in the second configuration - gas processing facilities; in the third configuration - gas chemical facilities. Based on the analysis of structural shifts, we show that the gas industry in the first configuration underwent development in the region at an advanced pace but remained an enclave in the structure of the economy. Estimates of the effects of sectoral superstructures in the format of the second and third configurations are projections, since the projects to build the Amur Gas Processing Plant and the Amur Gas Chemical Complex are still underway. We used an input-output model to obtain estimates of regional GRP growth rate in the case of development of these industries. It was found that the emergence of gas processing in the region's economy will increase the GRP by 11.2% compared to 2015, and the emergence of gas processing and gas chemical industries will provide a total increase in the GRP by 13.9%. According to the results of calculations based on the dynamic model of economic interactions FrEEDM, given that all process lines of the Amur Gas Processing Plant are put into operation, the above increase in the GRP can be achieved by 2030.

LPG production from a gas processing plant was experiencing gradually decreasing LPG production in spite of having feed gas rich in heavier hydrocarbons. The process involves dehydration of feed gas, cooling the gas in a propane based chiller to condense heavier hydrocarbons, processing the liquid in a De-ethanizer column to separate C3+ components and further separate the C3/C4 (LPG) and C5+ components in a De-butanizer column. To understand the above phenomenon, a steady state model of the plant was developed using licensed commercial process simulation software. The crucial process parameters required for efficient recovery of LPG are then identified and their optimum values established through simulations. Further experiments were carried out during plant operation to identify the bottlenecks in maintaining the parameters at optimum levels. From simulations it was observed that De-ethanizer pressure, De-butanizer reflux condenser outlet temperature and De-butanizer reboiler temperature have the major effect on LPG components loss. From real time monitoring of operations, it was observed that there was difficulty in maintaining De-ethanizer pressure and De-butanizer temperature profiles at the optimum levels. It was concluded that an ineffective air cooled condenser, a passing manual valve and an improperly tuned temperature controller were the root causes behind sub-optimal operation. Accordingly, recommendations were made for rectifying the problems and the same have been accepted by the plant engineers for implementation which will result in LPG production gain by 20 %.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Construction of unenclosed gas processing plants is suitable for cold processing plants is suitable for cold weather operation provided appropriate winterizing procedures are followed. The result should be a safer operating plant with less investment. plant with less investment Introduction Hudson's Bay Oil and Gas Company Limited is a producing company employing 875 people. It was formed through an agreement between what is now Continental oil Company in the United States and the Hudson's Bay Company Limited. The Hudson's Bay Company was incorporated in 1670 under a charter given by King Charles II. It is the oldest company in existence in North America. Hudson's Bay Oil and Gas operates seven sour gas plants and one sweet gas plant in Alberta. These vary in size plant in Alberta. These vary in size up to our largest, the Kaybob South Gas Processing Plant which is designed to Processing Plant which is designed to produce 2080 long tons of sulphur, produce 2080 long tons of sulphur, 25,000 bbls. of condensate and 6,800 bbls. of LPG per day. This plant is located on 54.5 degrees North Latitude and is subject to severe winter conditions. It is this plant and our Edson Gas Plant, about 60 plant and our Edson Gas Plant, about 60 miles south of the Kaybob South Plant, which will be discussed in this paper. Discussion Winter temperatures in North Central Alberta will drop to 60 degrees F below zero on occasion. Minimums of 40 degrees F below are expected. Unless proper design precautions are taken, temperatures at this precautions are taken, temperatures at this level can make a plant inoperable. One of the first decisions to be made in plant design is the extent of housing for the plant. The plants being considered in this paper are basically unhoused. only process pumps containing water, compressors, firing ends of boilers and other small equipment containing water are housed. One major reason for this decision is safety. The gas we handle contains up to 17% hydrogen sulphide, which is extremely poisonous. poisonous.

Unique Challenges in the Design and Operation Philosophy of Solar Thermal Power Plants

A study of offshore production units with large fluids processing capacity is presented, focusing in ultra deep water scenario (higher than 2,000 m) and the production of light oil, with high Gas Oil Ratio (GOR) and CO2 contamination. This situation fits to some exploratory and production areas offshore Brazil. Taking a regular size FPSO as the comparative base, analysis explored the impacts of different processing capacities on energy demand, weight and footprint requirements. The evaluation considered two gas processing plants: the first is less complex, without CO2 separation from the produced gas, reinjecting the whole produced gas into the reservoir; the second is more complex, with CO2 removal and a more flexible plant, capable of exporting treated gas and reinjecting rich CO2 stream or the whole gas. As the driving force of CO2 separation by membranes is the pressure drop between feed gas and the permeated rich CO2 stream, the second option leads to a lower processing capacity, mainly due to the increase in compression and power demand. The risks and benefits of large production systems are also evaluated from the reservoir drainage and gathering systems point of view. One of the main constraints is the indication that for high GOR oil, considering or not CO2 separation in the processing plant, its capacity would have to be limited due to maximum topside dry weight and deck footprint that could be installed on a converted hull or a new built unit. Additionally, constraints related to maximum power generation must be taken into account. If CO2 is not removed, and the gas is reinjected with no export, a higher processing capacity could be achieved. The design of higher capacity plants shall also consider reservoir aspects, flow assurance through long tie back wells, operability, maintainability and increase in difficulty to purchase high capacity equipment, such as vessels, valves, pumps, compressors and other.

Simulation of mercury distribution in an offshore natural gas processing platform