The US Department of Energy (DOE) has announced the selection of six projects to receive approximately $30 million in federal funding for cost-shared research and development in unconventional oil and natural gas recovery. The projects, selected under the Office of Fossil Energy's Advanced Technology Solutions for Unconventional Oil and Gas Development funding opportunity, will address critical gaps in the understanding of reservoir behavior and optimal well-completion strategies, next-generation subsurface diagnostic technologies, and advanced offshore technologies. As part of the funding opportunity announcement and at the direction of Congress, DOE solicited field projects in emerging unconventional plays with less than 50,000 B/D of current production, such as the Tuscaloosa Marine Shale and the Huron Shale. The newly selected projects will help master oil and gas development in these types of rising shales. This cement will prevent offshore spills and leakages at extreme high-temperature, high-pressure, and corrosive conditions.
The Vega subsea field in Norway has been producing successfully using a continuous Mono Ethylene Glycol (MEG) injection, topped up with corrosion inhibition means. A topside reclamation process allows reuse of MEG, however, limits the possibilities to produce saline water. In order to manage wells producing saline formation water and to increase ultimate recovery, a new flow assurance and integrity philosophy without continuous MEG injection is considered. This paper describes the options on hydrate as well as integrity management and the modifications both on the subsea and topside facilities required to enable an operational philosophy change. This change of the operational philosophy appears feasible, using either timely depressurization or Low Dosage Hydrate Inhibitors (LDHI) as well as a film building corrosion inhibitor in the system.
The FPSO Kaombo Norte came on stream on July 27 2018, offshore Angola. When both its FPSOs will be at plateau, the biggest deep offshore project in Angola will account for 10% of the country's production. Kaombo reserves are spread over an 800-square-kilometer area. The development stands out for its subsea network size with more than 270 kilometers of pipeline on the seabed between 1500-2000m water depth, including subsea production wells more than 25km away from the production facility.
During the project phase, measures have been taken in order to standardize the subsea design overall including the thermal requirements. By necessity the insulation design of the subsea component is driven by the most stringent part of the development which is then applied throughout the complete system on Kaombo. This inevitably infers that certain parts of the system operate with a built-in margin regarding thermal performance. With an overall objective to optimize the OPEX the use of this margin on some assets generates added-value in the operational phase by reducing production shortfalls through reducing the number of preservations undertaken during life of field.
In order to improve the overall preservation sequence, crude abilities to delay hydrates formation and/or to transport hydrates have been studied on the coldest fields. It was found that studied crudes present interesting properties to delay hydrates formation. These tests have been performed with crude samples in lab conditions in order to assess the temperature and pressure when hydrates start to form. The results indicate that it is possible to extend the waiting period (i.e. time before launching preservation) well inside the hydrate thermodynamic zone and operating "safety" zones have been defined depending of the actual temperature and pressure.
An optimized preservation sequence postponing the decision point to restart or preserve was finally implemented thanks to:
An accurate knowledge of the full system thermal performance especially including the weak links The study of crude properties for the most penalizing fields vs. hydrates plug risk
An accurate knowledge of the full system thermal performance especially including the weak links
The study of crude properties for the most penalizing fields vs. hydrates plug risk
The methodology implemented is today already field proven and application of the extended waiting period was performed allowing reduction of shortfalls and smooth restart. A significant impact is expected for the full life of the field.
Gas hydrate resources in India are huge and potentially represent a global energy game changer if the technologies for production from hydrate reservoirs are techno-economically established. Several initiatives have been undertaken by NGHP in India for gas hydrate exploration in deepwater offshore. Fabián Vera, Baker Hughes, and Christine Ehlig-Economides, Texas A&M, explain transient well analysis and how it contributes to shale development. It may not matter whether the IOCs or the NOCs are in charge. The work to be done is the same and the same people will likely be doing it.
Natural gas hydrates are considered to store vast amount of natural gas trapped in the subsurface worldwide. However, gas hydrates are yet to be commercialized due to technical challenges in the production technology. As a compact source of energy which is widely distributed, natural gas hydrates can play a big role in meeting future energy demands. But producing them is not such an easy task. Gas hydrate resources in India are huge and potentially represent a global energy game changer if the technologies for production from hydrate reservoirs are techno-economically established.
As operators rely on longer subsea tiebacks, an upward trend in the number of plugs caused by paraffins and hydrates has been seen. New prevention and remediation methods are discussed to help solve these challenges. A former technical manager with Petrobras discusses the development of the company’s flow assurance philosophies and strategies.
The 9th International Conference on Gas Hydrates featured discussions on key advancements in flow assurance, including the concept of risk management and anti-agglomerates being applicable strategies in transient operations. By using a Bayesian network, a probabilistic graphical model, in their shale operations, companies might eliminate some of the hurdles they face in these areas, an expert said at the 2016 Unconventional Resources Technology Conference.
A computational fluid dynamics model is proposed to analyze the effect of hydrate flow in pipelines using multiphase-flow-modeling techniques. The results will identify the cause of pipeline failure, regions of maximum stress in the pipeline, and plastic deformation of the pipeline. The 9th International Conference on Gas Hydrates featured discussions on key advancements in flow assurance, including the concept of risk management and anti-agglomerates being applicable strategies in transient operations. A BP flow assurance manager explains a methodology for determining and mitigating flow assurance risks. A BP flow assurance engineer discusses the shift in hydrate management strategy from complete avoidance to risk mitigation for an offshore dry tree facility.
Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. In the context of hydrate control, anti-agglomerants are chemicals which prevent hydrate crystals from sticking together and forming a larger mass.
In natural settings, such as the ocean bottom, when buried organic matter decomposes to methane and dissolves in water, clathrates form at temperatures greater than 277 K (4 C or 39 F). Biogenically produced methane in dissolved water forms hydrates very slowly, because of mass-transfer limitations. Over geologic time, the total enclathrated methane in the oceans has been estimated at 2.1 1016 standard cubic meters (SCM)--twice the energy total of all other fossil fuels on Earth. The amount of hydrated methane in the northern latitude permafrost is relatively small (7.4 1014 SCM), within the error margin of ocean hydrate estimates. Figure 1 shows world hydrate deposits in the deep ocean and permafrost, most of which were determined by indirect evidence such as seismic reflections called bottom simulating reflectors (BSRs).