Liu, Wenyuan (China University of Petroleum – Beijing) | Hu, Jinqiu (China University of Petroleum – Beijing) | Sun, Fengrui (China University of Petroleum – Beijing) | Sun, Zheng (China University of Petroleum – Beijing) | Chu, Hongyang (China University of Petroleum – Beijing) | Li, Xiangfang (China University of Petroleum – Beijing)
Hydrates generation-blockage in submarine natural gas pipelines has always been related to the safety of deepwater natural gas production and transportation. However, the current hydrate formation risk prediction in subsea pipelines is still immature. In this paper, a model for evaluating the risk of hydrate formation in submarine natural gas pipelines has been established. The model has been applied and the sensitivity analysis of typical factors has been carried out. The results show that: (a) owing to the low temperature of the seabed, hydrate formation region (HFR) often exists in submarine pipelines. Avoiding HFR by injecting inhibitors is the key to ensure the safe transmission.
There are many types of equipment failures encountered during the operation of oil-flooded twin screw natural gas compressors. Defining the failure modes of gas compressors mining sour gas is of primary importance for improving reliability. The failure modes for compressors operating with hydrodymanic journal bearings are different from compressors operating with rolling element bearings. Gas compressors operating in corrosive environments easily succumb to failures such as corrosion-pitting, hydrogen-assisted fatigue and chemical attack. Some common failure modes will be defined for each type of bearings used in rotary screw compressors. Identifying these failure modes assists in defining the problem so that new lubricants can be designed to extend the working life of the compressor.
The failure modes of roller bearing equipped compressors operating in sour and acid gases are primarily due to premature spall formation from hydrogen-assisted fatigue (i.e. hydrogen embrittlement) and sulfide stress corrosion. We have found that hydrodynamic journal bearings equipped compressors operating in sour gases will fail due to sulfide corrosion attack of the hydrodynamic bearings. A new additive system was developed to inhibit both types of failure modes. Laboratory corrosion tests were used to compare corrosion inhibition of new additive system to well-established compressor lubricants. When levels of corrosion inhibition were established, the experimental lubricants were field tested. Field tests of this experimental lubricant were carried out in compressors operating with both hydrodynamic bearings and rolling element bearings. The testing in this difficult natural gas field, demonstrated that CPI’s new experimental fluids have extended the operating time to failure, for compressors operating with both type of bearing systems, from about 2,000 hours to well over 10,000 hours. CPI has developed lubricant solutions that improve the reliability by extending the time to failure for oil-flooded twin screw compressors mining water-saturated natural gas streams with both acid gas and sour gas elements.
Up until recently, the monitoring of greenhouse gases with satellites had been limited to a regional or global scale. Because of the low spatial resolution of scientific satellites looking at gases, attributing emissions to specific facilities had so far not been possible. GHGSat changed that narrative with its first satellite GHGSat-D in June 2016, the first and only in the world specifically designed to monitor emissions directly from industrial sites, with a spatial resolution of less than 50m. The system makes it possible for oil and gas companies to keep a frequent eye on their facilities scattered across vast areas at the lowest cost possible since all measurements are performed remotely with no need to access the sites.
We present recent single pass measurements taken with our demonstration satellite in the Short-Wave Infrared (SWIR) band, showing evidence of point source emission plumes at facilities such as underground coal mine vents and oil and gas facilities.
The lessons learned from GHGSat-D in the last three years making over 4,000 measurements at hundreds of facilities around the world have been incorporated into our second satellite scheduled for launch in August 2019. As a result, GHGSat-C1 is expected to improve on the performance of its predecessor by an order of magnitude. We will present some of the first results from this second satellite.
Finally, we introduce some of the innovative products and applications we are developing using analytics, artificial intelligence and machine learning to better serve our customers with actionable insight and optimize the operation of our system. The ability of the technology to work together with other sources of data (such as other satellites, drones or ground measurements) in an effective tiered monitoring system will also be demonstrated.
This paper presents details of the development of the Middle East to India Deepwater Pipeline (MEIDP) providing information on the technical and commercial feasibility of the deepwater gas transportation system, which will reach a record water depth of 3450m, cross two continental slopes, an earthquake subduction zone (the Owen Fracture Zone) and outfall debris of the river Indus fan in 2500m water depth. High pressure trunk lines have proved to be the safest, cheapest way of transporting gas to market for short to medium distances up to 2,500 kilometers, making the proposed SAGE - Middle East to India Deepwater Pipeline the optimal solution for gas delivery to the Indian Subcontinent.
Northrop, Scott (ExxonMobil Upstream Integrated Solutions) | Seagraves, Jenny (ExxonMobil Chemical Limited) | Ramkumar, Shwetha (ExxonMobil Upstream Integrated Solutions) | Cullinane, Tim (ExxonMobil Upstream Integrated Solutions)
Development of sour gas reserves involves extraction, treating, and disposal steps that can be operationally complex. Historically, highly sour gas reserves are left undeveloped because of the technical challenges and high production costs. These reserves are now being reevaluated as potential sources of supply in areas with high demand for natural gas.
To address development challenges, ExxonMobil has applied a dual approach to advancing technologies. First, our broad experiences and well-defined best practices are used to select technologies that best meet the "routine" aspects of sour natural gas development and production. Second, ExxonMobil's industry-leading research capabilities are applied to create new technologies that make treating of difficult sour gas streams feasible.
ExxonMobil has over 70 years of experience in operating and developing technologies for gas treating. Relevant experiences will be described along with the efforts to develop and apply innovative technical solutions needed to develop these reserves. Examples include FLEXSORB™ SE solvent for acid gas enrichment and tail gas clean up, the Controlled Freeze Zone™ process for separating significant concentration of contaminants from natural gas, and cMIST™ technology for dehydration and selective H2S removal from raw gas. Each of these technologies will be discussed in some detail, as will our general experience with sour gas treating.
This paper illustrates how new technologies developed by one company can become part of the body of applied science that ultimately benefits the broader industry.
Kiss, Gabor (ExxonMobil Research and Engineering Co.) | Barckholtz, Timothy A. (ExxonMobil Research and Engineering Co.) | Blanco Gutierrez, Rodrigo F. (ExxonMobil Research and Engineering Co.) | Han, Lu (ExxonMobil Research and Engineering Co.) | O'Neill, Brandon (ExxonMobil Research and Engineering Co.) | Rosen, Jonathan (ExxonMobil Research and Engineering Co.) | Sutton, Clay R. (ExxonMobil Research and Engineering Co.) | Davis, Keith E. (FuelCell Energy, Inc.) | Dobek, Frank (FuelCell Energy, Inc.) | Geary, Timothy (FuelCell Energy, Inc.) | Ghezel-Ayagh, Hossein (FuelCell Energy, Inc.) | Jolly, Stephen (FuelCell Energy, Inc.) | Willman, Carl (FuelCell Energy, Inc.)
Electrical power generation facilities account for a large share of global CO2 emissions. Because they are stationary single-point emitters, power plants are an obvious target for reducing anthropogenic CO2 emissions by CO2 capture. Capture from Natural Gas Combined Cycle (NGCC) power generation has been much less investigated than from coal power generation, despite having approximately half of the CO2 emissions per electrical unity of energy produced as compared to coal-fired power plants. Furthermore, the majority of carbon capture R&D has been devoted to the development of amine scrubbers, a process which incurs a significant energy debit because of its steam consumption in the sorbent regeneration step. Molten Carbonate Fuel Cells (MCFCs) can be used for CO2 capture from NGCC facilities without a significant energy debit. They are modular, thus flexible in fitting the required capture capacity. When using MCFCs for carbon capture, additional power is created by the fuel cells keeping the total efficiency of the power generation system at or near the efficiency of the NGCC plant without CO2 abatement.
This paper summarizes the current status of MCFC carbon capture technology for low-CO2 emission abatement. We developed modeling tools and performed process simulations to optimize MCFC performance and to develop and assess integrated solutions for power generation with carbon capture. We also obtained proof-of-principle data at the bench scale, using small button cells and lab-scale single cells. Additionally, we carried out process demonstration tests using pilot-scale fuel cell stacks. Our results indicate that the technology is feasible and effective.
Liu, Wenyuan (China University of Petroleum – Beijing) | Hu, Jinqiu (China University of Petroleum – Beijing) | Sun, Fengrui (China University of Petroleum – Beijing) | Sun, Zheng (China University of Petroleum – Beijing) | Li, Xiangfang (China University of Petroleum – Beijing)
Hydrate formation and blockage in pipelines are serious problems in the oil-gas production and transportation. The current research is limited to the prediction of pipeline hydrate formation. However, the small hydrate generation often does not form obvious pipeline flow-barriers. Therefore, compared with hydrate formation, hydrate growth rate and deposition rate is equally important for the emergence of flow barriers. Based on the hydrate formation-growth-deposition mechanism and combined with the hydrate experiment in the flowloop, the characteristics of hydrate formation-growth-deposition in pipelines under different gas-liquid flow patterns was studied. The results show: Different flow patterns show different hydrate formation and deposition characteristics due to different phase distribution and interface distribution. The bubble flow, cluster flow and slug flow have some similarities in flow patterns. It can be seen that the gas phase in the flow system exists in the form of bubbles, and the occurrence of thin liquid film on the tube wall under these three flow patterns is relatively rare; accordingly, the similarity of laminar flow, wave flow and annular-mist flow shows that thin liquid film or gas-liquid-pipe wall three-phase interface will always appear in the flow process, which will make the hydrate formation and deposition risk of the latter three flow patterns significantly greater than the former three flow patterns. Comprehensive analysis shows that the hydrate risk of each flow pattern is in the order of annular-mist flow > laminar flow and wave flow > slug flow > cluster flow and bubble flow. The annular-mist flow is the most dangerous flow pattern for hydrate formation and blockage, which is quite common in the oil and gas industry. In this case, special attention should be paid to hydrate prevention and control.
It is hoped that the research in this paper can provide some theoretical guidance for field construction and related researchers.
Pipelines are the most economically viable mode of transportation for oil and gas. Every pipeline is monitored 24×7 using meters distributed across the pipeline. Flow, temperature and pressure meters are the most common and essential for continuous and efficient operation of pipelines. Like any other instrument these meters also have uncertainty and prone to error due to irregular calibration, drift, gross error and other such events. The overall accuracy of pipeline metering increases as the distance between consecutive meters decreases. It is also affected by the placement of meters at critical locations like pipeline tapouts, tapins and consumers points. Economics do not allow pipeline operators to install beyond a certain amount of metering assets.
The complexity to efficiently calculate the product in and out of a gas pipeline is more compared to a liquid pipeline. It arises due to the high compressibility of gases compared to liquids. Gas pipelines operate at much higher pressure than oil pipelines. The trapped gas inside a gas pipeline can be called line pack of that pipeline. The line pack is very sensitive to two natural factors pressure and temperature of the pipeline. Oil pipelines carry one fluid at a time. Gas pipelines on the other hand carry several gases as a mixture. Unlike oil, gas billings are calculated as the energy the gas mixture carries to the consumer. Due to the mixture, gas composition is another essential factor to accurately calculate energy of the mixture.
This paper discusses the challenges of calculating various transport factors and phenomena in gas pipelines and how methods like gross error correction and machine learning can be used to increase the accuracy. The results and conclusions are derived from the applications of these methods to natural gas transportation pipeline. Some of most important conclusions obtained were Understanding the pattern of on-field meter data with ideal meter provides insights in the root cause of the problem. e.g. sudden spike in temperature leading to error in line pack. Creating digital twin of all metering assets allows faster isolation of pipeline sections having calculation errors. e.g. by monitoring the difference between field and ideal parameters. Having a central meter diagnostics system that combines the data from meters of different make and models improve the pattern recognition and error detection ability. Gross error detection isolates the meters inducing error. The feedback can be provided to the machine learning algorithms for root cause analysis.
Understanding the pattern of on-field meter data with ideal meter provides insights in the root cause of the problem. e.g. sudden spike in temperature leading to error in line pack.
Creating digital twin of all metering assets allows faster isolation of pipeline sections having calculation errors. e.g. by monitoring the difference between field and ideal parameters.
Having a central meter diagnostics system that combines the data from meters of different make and models improve the pattern recognition and error detection ability.
Gross error detection isolates the meters inducing error. The feedback can be provided to the machine learning algorithms for root cause analysis.
Note: This paper only covers the gross error of meters. There are methods used to reduce other meter errors namely random, limiting and systematic not covered in this paper. Readers are requested to read relevant material to understand the complete scope of errors in metering systems.
Comstock Resources has entered into a definitive agreement to sell its oil and gas properties in and around Burleson County, Texas, to an unnamed company for approximately USD 115 million, subject to adjustments. The properties being sold are producing approximately 1,900 BOPD and 5.5 MMcf/D of natural gas. At the end of last year, Comstock's proved reserves included approximately 3.7 million bbl of oil and 3.9 Bcf of natural gas related to the interests being sold.
Production and drilling activities in offshore installation are one of the most necessary activities of human society. To drill a subsea well and raise the crude oil to a platform, by itself, presents a series of risks. Associated with this activity, when the crude oil reaches the topside of the platform, there are a number of operations that prepare the oil and gas to be exported to land by pipelines or oil tanker vessels, which involves equipment and process that take high temperatures, high pressure and high flow rates. Understanding the dynamics of the factors that can affect the interaction of operators with all these offshore complex systems is critical, because the loss of control of these systems can cause serious accidents, resulting in injuries to workers, environmental damage, loss of production and geopolitical crises. Accidents in the oil and gas offshore installations, such as drilling rigs and FPSOs, can have tragic consequences and all efforts should be targeted to prevent its recurrence. Therefore, from the perspective of current technological developments, it is essential to consider the influence of Human Factors in the risk management of offshore industrial plants.