|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Tropical storms severely affect oil and gas production in the Gulf of Mexico, especially during the storm season from June to December. Offshore well managers often need to shut down operations and evacuate the facility because of storm alerts. Furthermore, if the storms have a more-severe effect, facilities may need to be repaired before production restarts. The purpose of this paper is to determine the effect of storms on production by quantifying metrics such as downtime days and downtime percentage after the storm has passed and whether a facility's platform type affected these metrics. Oil and gas production at offshore facilities (Figure 1) are severely affected, especially in the Gulf of Mexico, by frequent storms.
The International Gas Union's (IGU) recent report on world LNG markets found that the trade increased by only 1.4 mt to 356.1 mt compared to 2019 supported by increased exports from the US and Australia, together adding 13.4 mt of exports. Asia Pacific and Asia again imported the most volumes in 2020, together accounting for more than 70% of global LNG imports. Asia also accounted for the largest growth in imports in 2020--adding 9.5 mt of net LNG imports vs. 2019. While 20 mtpa in liquefaction capacity was brought on stream in 2020, all in the US, startup of several liquefaction trains in Russia, Indonesia, the US, and Malaysia were delayed as a result of the pandemic, according to the report. The only project that was sanctioned in 2020 was the 3.25-mtpa Energia Costa Azul facility in Mexico, and in early 2021 Qatar took final investment decision (FID) on four expansion trains totaling 32 mtpa.
Abstract LNG shipments are nothing new in the face of technology. The first tanker shipment of LNG took place from Lake Charles, LA bound for Canvey Island in the UK in 1958 aboard the experimental vessel, the Methane Pioneer. So, why do people focus on this subject so much since mid 2000's? One of the key factors is technology, that reduced costs of LNG trades. More and more countries see that as a chance to diversify their imports. In 2023 Poland wants to cover over 35% of annual consumption with 7,5 bln cubic meters in LNG shipments. With this strategy there is a big chance for Poland to stop being dependent to Russia in 2023. Main forces that drive the interest for LNG shipments are: The growing concern for traditional supplies in the face of growing consumption, The effects of technology on cost reduction making previously uneconomic trades attractive, Environmental concerns, in some countries gas will replace coal in energy mix, Increasing liquidity in the global gas market, LNG trade gives new opportunities for both seller and buyer. It enables importing markets to shift trading directions thus gain energy independence as well as avoid supply shortages. Liberalization of market - influencing changes in contracts align with spot transactions drain the prices, making LNG even more attractive. On the other hand, the sellers experience completely new trading opportunities. Companies are able to engage in markets that were previously unavailable and escape adverse stockpile abundance. Aim of the research is to identify major trends in LNG industry. Forecast main course and future role of LNG and natural gas in the energy mix. Model global supply and demand 2020 - 2030. Analysis also covers incoming investments and check their potential. Research based on the available resources from GLE investment database and similar resources from other regions. Data broaden by other documents from energy companies and local statistic ministries. Model with trusted available data adjusted by current news and energy trends in Europe and in global gas industry. LNG market is expected to grow at around 1.3% annually. Global demand could increase from its current level of about 406 million tons per annum to 430 MTPA in 2025. For now natural gas is supported by policies to reduce air pollution and greenhouse gas emission and it will partly replace coal in energy mix in European countries. Today's challenge is to create liberal gas market and LNG is the answer on how to connect american, arab and european gas markets.
Shentu, Junjie (China University of Petroleum, Beijing) | Lin, Botao (China University of Petroleum, Beijing) | Jin, Yan (China University of Petroleum, Beijing) | Shi, Can (China University of Petroleum, Beijing)
In the deep-water hydrocarbon recovery, the over-pressured sand originating from fast sedimentary compaction brings about difficulties in well control during drilling practices. When encountered by a drill bit, the sand section will generate shallow water flow (SWF) that could substantially jeopardize the integrity of the drill string and the associated equipment, eventually leading to drilling failure. The SWF hazard has been one of the predominant geological hazards in the deep-water drilling operation nowadays. Therefore, it is crucial to accurately identify the SWF hazard, estimate the risk, and take the appropriate measures to minimize the engineering and economic losses. In this study, a set of experimental facility and workflow were proposed, in order to investigate the flow failure behavior of the over-pressured sand section. The experimental findings indicated that the initial overpressure was one of the principal factors of the SWF hazard. Accordingly, a discrete element method-computational fluid dynamics (DEM-CFD) coupling approach and was proposed to model the process of the SWF hazard. The results of the numerical simulation were verified by the behavior of sand transportation disclosed in the laboratory experiment. The simulation showed that the sand production of a specimen increases with three influence factors, including the initial overpressure, the porosity and the sand grain size. Some critical points were discovered and studied in the investigations of each influence factor, and the rising tendency of the curve tended to undergo a dramatic increment at the critical point. Finally, the SWF risk prediction chart was proposed for the fast and convenient identification and evaluation of the SWF risk.
Dooply, Mohammed (Schlumberger) | Schupbach, Michael (Murphy Exploration & Production Co.) | Hampshire, Kenneth (Murphy Exploration & Production Co.) | Contreras, Jose (Schlumberger) | Flamant, Nicolas (Schlumberger)
Two of the most important parameters to monitor during a primary cementing job are the flow rate in and return flow rate measurements. To achieve optimum quality control of a primary cementing job, measuring annular return rates and comparing them with simulated data in real-time will provide better understanding of job signatures and result in the best possible top-of-cement estimation prior to running any cement evaluation log or taking decision to continue drilling the next section of the well.
The return rate job signature along with the wellhead pressure is essential to understand the behavior and discrepancies between simulated and acquired surface data. Therefore, to assess the risk of job issues, such as unsuspected washout and lost circulation among others, accurate measurements of the return rate are critical.
Historically, cement job evaluation has been limited by the fact that most drilling rigs do not have an accurate flow meter installed on the annulus return line, and a simple verification of mud tanks volumes versus pumped volume, as reported by drillers or mud loggers, more than often results in an unreliable assessment of the volume lost downhole, due to the unfamiliarity with the U-tubing effect and lack of data consolidation from the cement unit (flow rate in) and the rig (flow rate in & flow rate out).
This paper will review a solution developed to mitigate the lack of a direct flow rate measurement by computing and displaying the return rate using either a paddle meter measurement or the derivative over time of the volume observed in the rig tanks.
With advancements in technology such as horizontal drilling and hydraulic fracking, operators are able to pursue reserves in unconventional mudrock reservoirs. Brittleness, one of the many pre-screening considerations, is an important parameter because it determines whether a mudrock can be effectively stimulated via hydraulic fracking. The industry currently uses several geochemical signals (e.g. Si/Al and Si/Zr) to identify authigenic silica phases present in an unconventional reservoir. Cemented horizons are prime candidates for placing hydraulic fracks due to the strengthening effects of mineral cements on the rock frame. A similar geochemical method for readily indicating the occurrence of authigenic carbonate has not been identified. This study documents trace element geochemical differences between biogenic (detrital) carbonate phases and associated cements so that chemical proxies may be used to differentiate authigenic carbonate phases using bulk geochemical data. Both carbonate-rich formations (e.g. Eagle Ford and Niobrara) and argillaceous formations (e.g. Haynesville and Marcellus) are examined to gain insight into reservoir brittleness, using bulk and trace elements such as Ba, Mg, Mn, Fe, Sr, and Ca. The goal is to develop a technique that can be implemented real-time by the mudlogging unit at the wellsite and during the initial core analysis phase. This method will allow a more targeted placement of hydraulic fracking zones to increase permeability and hydrocarbon production in mudrock reservoirs.
Electron probe micro analysis (EPMA) on several types of carbonate was conducted on low (0.45 %Ro) and high (2.5 %Ro) thermal maturity Eagle Ford and Haynesville Formation samples, respectively. The EPMA reveals that Sr is the primary elemental signature of the authigenic carbonate phase within the low maturity Eagle Ford. The Haynesville EPMA reveals higher variability of Fe, Mn, Sr, Mg, and Ba trace element concentrations, however the dominant elemental signature associated with the authigenic phases is elevated concentrations of Fe and Mn. Utilizing XRF, Sr/Ca and Ca-Fe-Mg cross-plots can be used as proxies to identify authigenic carbonate in the Eagle Ford and Haynesville Formations respectively, and can be used to indicate brittle zones for target adjustments at the wellsite.
Taoutaou, Salim (Schlumberger) | Jaffery, Maimoon Fayyaz (Schlumberger) | Jain, Bipin (Schlumberger) | Abdelhamid, Essam (Total) | Szakolczai, Cyril (Total) | Lansot, Jean-Yves (Total) | Garnier, Andre (Total)
Cement sheath integrity under high-pressure and high-temperature (HPHT) conditions in the Maharaja Lela Jamalulalam (MLJ) field in Brunei is challenging to achieve because of the harsh downhole conditions. Pressures reach 15,000 psi [103 MPa], downhole temperatures rise to 165°C [330°F], and the narrow margin between the pore pressure and the fracture gradient makes mud removal and cement placement even more challenging.
In addition, pressure and temperature cycling during production means cement selection with right properties is essential to maintain long-term wellbore integrity. The cement system must deliver cement mechanical properties that can withstand the downhole stresses over time. Mechanical failure of the cement sheath would create a path for wellbore fluid migration that could result in sustained casing pressure (SCP) or interzonal communication.
This paper will discuss the challenges of cementing in the tight pore-to-fracture window in the MLJ field, and the design and placement of one of the world's heaviest (2.48SG [20.7 lb/gal]) flexible and expandable resilient cement systems.
Wells in the MLJ field reach into a deep reservoir (4500 to 5000 m true vertical depth, TVD) where the pressures can reach up to 15,000 psi with bottomhole static temperatures reaching 165°C. The well is drilled using 2.18 SG [18.2 lb/gal] mud weight, and the production string is pressure tested at 15,000 psi; during the drilling and completion, the temperature variation is on the order of 60°C [108°F].
Based on the above well conditions, advanced computer-based simulations were used to determine the cement mechanical properties required to withstand the pressure and temperature changes. To achieve the required mechanical properties, special blends were prepared with engineered particles to impart flexibility and expansion for a 2.48 SG cement system.
To manage the cement placement, state-of-the-art cementing design software was used to accurately simulate the bottomhole circulating temperatures and pressures during placement as well as to simulate pipe centralization; a 3D model for fluids displacement also proved valuable.
ABSTRACT The Gamma ray (GR), and Spectral gamma ray (SGR) measures the radioactivity value of the rocks and the Optical borehole imager (OBI) logs shows the faults and fractures of borehole wall. These logs were utilized to evaluate a mine prospect off-San Cristobal, Potosi, Bolivia. The lithology consists of Paleocene-Miocene shaly sandstone and pyroclastic rocks deposited in a lake depositional environment. The transgressive-flooding surface and the maximum flooding surface were identified with the GR log in three wells (named A, B and C) in order to construct a stratigraphic cross section. Processed OBI data produced rose diagrams of strike and dip direction of the geological structures and these are oriented WNW-ESE in the southern part and SW-NE in the northern part of the prospect area. During Pliocene, a dacite-porphyry intrusion took place and has created an epithermal system ore deposit. In the transgressive-systems tract there is an increase of Ag and base metals grades in the middle and upper parts where the radioactivity values are higher due to a more reduced environmental condition of "deeper wate" sediments. This makes the GR and SGR logs a good indicator of the presence of a mineral ore deposit. Presentation Date: Wednesday, September 18, 2019 Session Start Time: 1:50 PM Presentation Time: 2:40 PM Location: Poster Station 10 Presentation Type: Poster
Abstract Business Process Outsourcing can be aptly described as the process of forging a contractual relationship with external supplier for the provision of capacity that has been previously undertaken within an organization. In the global oil and gas industry, Business Process Outsourcing (BPO) has emerged in contemporary times as a potent tool in their operational mix. This is particularly hinged on the imperatives to find a delicate balance between rising global demand, diminishing reserves in some of the world's major oil fields, while managing distribution and operating costs. The collapse of crude oil prices from US$100.00 in May 2014 to about US$30.00 and even below in early 2016 has reinforced outsourcing. Empirical studies reveal that outsourcing of non-core activities may result in 25% cost saving associated with on-/near-site operations and as much as 50-75% for offshore operations compared to the cost of engaging in same activities in-house. Apart from cost-cutting, other benefits associated with BPO include a stronger focus on core competencies; improved regulatory conformity and compliance; as well as access to a larger talent pool and novel technologies. The oil and gas industry has emerged as the cornerstone of Nigeria's economy, accounting for about 70% of annual government revenue and more than 90% of the nation's foreign exchange reserves. Since the 1990s, outsourcing has assumed an increasing dimension in the nation's oil and gas industry. Empirical studies reveal, for example, that up until the early 1990s, employees in the oil industry comprised about 70% and 30% of permanent and temporary employees, respectively. The temporary employees were initially focused on non-core activities. However, in recent times core activities are increasingly contracted to service providers, reversing the structure of employment in the industry by 2010, with 40% of permanent employees, while 60% were permanent employees. The increasing replacement of permanent employees with temporary ones has fueled concern in the industry, led by labour unions, which have expressed concern about the sub-standard welfare of contract workers. This development has led the Federal government of Nigeria to issue guidelines on staff contracting and outsourcing in the Nigerian oil and gas industry.
Abstract One of the primary energy sources, natural gas is widely used for power generation, industrial production, transportation, commercial buildings, and households. The industry is a capital intensive one for all stages from exploration to delivery. Two types of supplies: pipeline and Liquefied Natural Gas (LNG), recently have faced a direct intra-industrial competition. Physical nature of methane and associated transportation costs lead to domination of so-called "natural monopolies" or "national champions" and strict government regulation, which postponed the development of free trade and competition. After decades of technical innovations and cost curve improvement in LNG sector, increasing global energy consumption, shale boom in the USA, and demand for supply diversification reformulated the role of gas in the global energy balance. While the pipeline sector remains to be in the hands of large corporations and a subject of strategic interstate and international agreements, LNG provides more diversity and flexibility of trade. However, even after a long history of LNG shipment since the late 1950s, this market is still regional with high spreads between countries and terms of delivery. The paper presents the evolution of business models in the natural gas industry, focusing on the primary drivers as government regulation, technologies, and regional markets trends on the way to liberalization and cointegration. Thus, our primary objective is to show relative influence power of these drivers. This analysis also defines the competitiveness of corporate business model under conditions of asymmetric information in regional gas markets, deregulation trends, fast-growing production technologies and downstream infrastructure (specifically in the LNG sector). We also enclose the analysis of the most globally competitive gas projects. We analyze changes in value chain change and trading contracts. Our methodological approach poses model-based principles, including option and contract models, jointly with game theory elements.