Visbreaking is a well-established thermal cracking process which is used in petroleum refineries for producing valuable products like Gas, Naphtha and Diesel from Vacuum tower bottoms. Maximization of yield of such valuable products from Visbreaking unit is limited by stability of its bottom product i. e Visbroken Tar which is generally measured by P-value (ASTM 7112). Typical conversion (weight % of Gas + Naphtha + Diesel) in visbreaker unit ranges between 15-20wt% and rest of the unconverted product goes to Fuel oil. Due to lower conversion, Visbreaker technology is becoming obsolete and need of hour exists to exploit different pathways for maximizing the profitability from existing Visbreaker unit. One such approach is by utilization of catalyst.
In the current work, different homogeneous catalyst formulations were developed in lab scale and experimental studies were conducted at different concentrations of catalysts with Vacuum residue feed. Based on promising results from the lab studies, one catalyst formulation was scaled-up to commercial level and effect of catalyst was demonstrated in a commercial visbreaking unit of 17000Barrels/day capacity which shows increase in conversion by 4.5wt% and thereby improving economics of visbreaking unit by 2 million USD.
Operational Readiness Assurance (ORA) is an iterative process to provide a readiness (measure of) assurance for the transition from a capital project to value-producing asset. Common issues are:
This paper will show as a current case study co-presented by Jacobs Consultancy with STAR Rafineri for their grassroots refinery in Turkey. We will examine how to address such issues on large projects and how to make an ordered structured transition.
The best way of promoting the unconventional gas is by adapting itself to the existing Value Chain model used for the conventional gas.
By overcoming the specific particularities that are derivative from the origin of the raw material, the extraction of the natural gas, the transmission system as well as the strategy followed for the development and maintenance of the infrastructures should not be differentiated.
There are three main reasons which justify this argumentation:
This is why the best way of promoting the use of the unconventional gas is through:
To summarize, the analysis of the value chain of the unconventional gas justifies the hey role of the international connections, traditionally associated to the conventional gas value chain, in order to promote a raw material that, even if it is not as known as the conventional one, it shall also be part of the energetic mix which guarantees the security of supply, the market integration and the economic competitiveness.
The proliferation of IoT endpoint technologies supporting the digital agenda in the oil and gas industry is increasing the attack surface of Critical Infrastructure networks and exposing organisations for more dangerous Cyber-Physical attacks. Accelerated digital deployments and deeper internet-based connectivity for remote operations management increases the likelihood of damaging Cyber-Physical attacks on field-based asset(s) and the control centre. These types of attacks can cause physical harm and result in safety hazards or worse a major control failing leading to loss of life, environmental damage or negative brand and financial impact. Such attacks can potentially go beyond damage to control systems, devices, equipment and network. They can actually pose risk to the entire supply chain and disrupt regional sector operations. This is the essence of Cyber-Physical risk, where oil and gas companies have to devote more focus on understanding the potential negative impacts new technologies can have on their business.
In this paper, we aim to analyse the importance of predictive techniques versus traditional methods of reactive security monitoring and response. We shall further elaborate on a parallel process of enhancing corporate response plans through development of organisational risk profiles and the adoption of relevant technology and digital roadmap as part of overall security architecture.
The US Department of Homeland Security mentions oil and gas as the most attacked industry. EY’s 2015 Global Information Security Survey showed that 41% of oil and gas organisations admit to inadequate cyber threat detection capabilities and 39% have no real-time insight on cyber threats. Our client interaction has also revealed that many companies were unaware that cyber penetration testing was necessary, which is especially critical given the deeper connectivity between OT and IT systems.
One of the big issues for the development of extra heavy crude oil is transportation from the well head to the refinery or shipping facility. Conventionally, dilution is applied to reduce density and viscosity and diluted heavy oil is transported through pipelines. However, if diluent is not available at low cost or in substantial quantities, such oil fields are not developed from an economic point of view.
Therefore, alternative methods, such as heated pipelines and partial upgrading technology to reduce the density and/or viscosity are expected as economic transportation methods rather than simple dilution. However, these methods also have advantages and disadvantages; heated pipelines may result in higher operating costs due to high electricity costs or higher capital costs in remote areas. Partial upgrading technology is also developed by several companies, but no matter what thermal technology is used for heavy oil conversion, the cracked products obtained may be unstable and they are not acceptable to the refineries.
In this study, the economic evaluation of the transportation methods for extra heavy crude oil is addressed. Capital costs and operating costs for the dilution method, heated pipeline and partial upgrading are compared with respect to several factors, such as distance from the well to the refining facility or diluent cost.
Technical evaluation of partially-upgraded heavy oil is also addressed. Compatibility with other crudes, desalting operation, refinery fouling and hydrotreating were examined to address refinery processing of partially-upgraded heavy oil. JGC is operating a 5 bpd upgrading facility at Western Canada. Its operating experiences are applied for the economic and technical evaluations.
It is well known that refinery-petrochemical integration has the potential to optimize assets and sustain profits during oil demand cycles. For the same reason, it is also an important factor to reduce investment risk in new enterprises. Nevertheless, Brazilian oil refining facilities have never been effectively integrated to petrochemical units due to the chemical industry development model adopted in this country decades ago. However, there are still several integration opportunities that can lead to reduction of chemicals import, supply security and profitability increase.
This paper presents some interesting R&D initiatives related to refining-petrochemical integration, several of which are Brazilian particular issues an others with worldwide application.
Although some Brazilian refineries are able to produce MTBE using isobutylene from the FCC C4 cut, the majority of oil refining facilities in this country sell butenes as LPG. So, the use of butenes to produce chemicals rather than fuels has the potential to increase refineries profitability substantially. At Petrobras’ R&D centre, two projects are focusing on this subject: the use of butenes and fatty acids methyl esters to produce long chain linear olefins via metathesis, aiming the production of detergents, and the production of C12 olefinic compounds, from C4 oligomerization, for the formulation of synthetic-based drilling fluid, which can reduce/eliminate expensive chemical imports for Petrobras’ oil & gas production area.
Other refinery-petrochemical integration related projects, also being developed by Petrobras and university partnerships, aims propylene production and use, having a worldwide application character. An interesting initiative is the development of a propane/propylene facilitated transport membrane separation module, which can allow a substantial increase in the C3 splitter capacity. Also promising is the development of a high selectivity catalyst system to produce propylene from propane via oxidative dehydrogenation and the use of impure propylene to produce solvents.
Pietraszsek-Mattner, Sarah (ExxonMobil Exploration Company) | Barron, James W. (ExxonMobil Upstream Research) | Myers, Rodrick D. (ExxonMobil Upstream Research) | Moreton, David J. (ExxonMobil Exploration Company) | Sempere, Jean-Christophe (ExxonMobil Upstream Research)
With the recent downward pressure on oil and gas prices, the oil and gas industry is operating in a reduced capital environment and is optimizing expenditures throughout the lifecycle of an oil and gas asset. In order to stay competitive, successful companies need to develop the next generation of technologies to enhance their abilities to be more selective in exploiting the reservoirs that underpin a project. In the past, the evolution of 3D and 4D seismic acquisition and enhanced seismic imaging techniques reduced exploration risk through the remote sensing of trap geometries, reservoir properties, and fluid presence, where favorable conditions existed. In higher-risk plays, such as those that depend on the existence of connected natural fracture networks to achieve economic flow rates, the ability to predict the presence, orientation, extent, and relative intensity of these fracture systems is necessary to improve the overall success in intersecting the highest natural fracture density and most productive reservoirs.
Traditionally, the impact of natural fractures on reservoir performance has been analog-based and scaled to match production data. A new process-based numerical modeling technology has been developed that predicts the formation of natural fracture networks from structural history and geomechanics. This prediction is then calibrated to fracture data collected from image logs, core and dynamic wellbore performance data. Utilizing this field-wide spatial distribution of fracture connectivity can narrow investment uncertainty by optimizing the number and position of future appraisal, production and injection well locations. This new approach, enabled by advances in numerical modeling, high-performance computing and innovative laboratory methods, illustrates how technology continues to drive our ability to unlock value from complex reservoirs.
Excessive water production from hydrocarbon-producing wells can adversely affect the economic life of the well. It was estimated that an average 3.0 barrels of water is produced for each barrel of oil worldwide. Unwanted water production can unfavorably affect well economics owing to handling of the produced water, reduction of hydrocarbon production, and environmental concerns. Naturally, fluids tend to follow in paths of least resistance which, are often created by the heterogeneous nature of the rock. The use of nanosilica based fluid system was developed for water shut-off application. Two sets of experiments were conducted to examine nanosilica treatment process and its ability to withstand an elevated temperature. A core flooding tests were conducted to evaluate the efficiency of this chemical system using super-K, fractured and wormholed cores plugs. An analytical study, (ESEM) and X-Ray techniques were applied to characterize untreated and chemically treated core plugs. The core flow testes indicate significant drops in water production for all core plugs including: High permeability, fractured and wormholed formation. When chemical treatments were placed, the Nanosilica system was able to withstand the differential pressures at 300°F and did not allow the flow of water in wormholed core, high permeability core and fractured core. The ESEM results showed the presence of SiO-rich compounds filling the secondary porosity. This suggests that the chemical treatment of the core plugs is resulted in some of the used nanosilica product is blocking fractures and pores. Nanosilica system expected to control water production through high permeability streaks and large pore openings. This system can be injected in porous media without plugging tendency due to their low viscosity. Nanosilica can enter deeper inside formation matrix before it gelled up. This work provides significant insight using nanosilica as an alternative chemical treatments intended for use in large openings.
Resources of 800 TCF and 27 BBO estimated for unconventional shale reservoirs together with more than 50 TCF of gas associated with tight rocks have generated great expectation in Argentina. Actually, the country is very active in developing this type of reservoirs. The formations are located in six main hydrocarbon-producing basins covering a surface of approximately 545,000 km2known as Paleozoic, Cretaceous, Cuyana, Neuquén, Golfo San Jorge and Austral. The associated source rocks are eleven, all of them with potential to be unconventional shale reservoirs. Five are marine in origin while the others were deposited in lacustrine environments. Ages range from Late Devonian to Early Cretaceous. Average TOC are in between 0.5 to 11 (wt%) with variable thicknesses up to 2,000 meters. Vertical wells targeting these objectives range in depths from 2,000 to 5,000 meters. In the particular case of Vaca Muerta Formation, a world class example and the most important unconventional shale reservoir currently being developed, horizontal wells can reach up to 2,000 m long with 20 fracture stages at a cost that varies from U$D 20 MM to 10 U$D MM. More than 650 wells drilled during the last 5 years are currently producing 50,000 bbls/d. Regarding tight clastic and carbonate reservoirs, there are at least eight formations, being the most important in the Neuquén basin. Average vertical wells have 12 fracture stages and cost U$D 9 MM. Tight gas reservoirs represent 20% of the total gas production of the country. Different scenarios consider that unconventional reservoirs could cover 50% of the country hydrocarbon´s demand in 15 years. The current stage of the projects suggests a promising future considering the favourable geological, engineering, political, environmental and social conditions. Consequently, the most important challenge focuses in optimizing operations, services and logistics with substantial cost reductions through time.
Moyano, Juan Miguel (ARPEL) | Sanchez Thorin, Ana Cristina (Equion) | Grosse, Francisco (Tecpetrol) | Milazzo, Pietro (Weatherford) | Wharton, Stephen (Tecpetrol) | DHuteau, Emmanuel (YPF) | Nardone, Gonzalo Lopez (YPF)
Between 2005 and 2015, the Latin American and Caribbean region experienced a growth of its Gross Domestic Product of approximately 3.5% per year. This economic growth was accompanied by an annual increase of 2.2% and 4% consumption in oil and natural gas respectively. Unconventional hydrocarbons offer a historic opportunity to supply to the region the energy and resources required to continue along this continually growing path.
ARPEL and its member companies published a document developed by a multidisciplinary group of oil and gas companies with operations in Latin America. The document proposes alternatives to make unconventional oil and gas projects technically and economically viable under a sustainability framework, addressing key issues related to supply chain management, social and environmental management and operational guidelines. Also, the document makes regulatory proposals to foster the sustainable development of unconventional resources, taking into consideration their particularities concerning the investments required, the production profile, logistics and technology applied.
In order to provide technical rigour, alternatives derive from an international review of best practices described in a wide range of scientific reports and policies published by governmental and inter-governmental organisations, as well as by industry associations that support the implementation of sustainable practices in oil and gas companies.
Unconventional hydrocarbons represent a significant fraction of total energy resources in several countries of Latin America and the Caribbean. Therefore, the sustainable development of these resources will ensure an additional source to diversify the energy matrix and accompany the efforts of States to achieve increasingly higher levels of prosperity.
This paper –based on the ARPEL document- provides a comprehensible technical background that can assist governments and the hydrocarbon industry, as well as other stakeholders, to develop the basis for a sustainable development of unconventional resources and a lasting benefit for the Latin American and Caribbean States.