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Two weeks after announcing a new discovery in the Barents Sea, Norway's Equinor is back with news that it has successfully found oil and gas at another location. Although it is significantly smaller than the previous find, the Skavl Stø discovery is well within tieback distance to the giant Johan Castberg field found just 3 miles to the north. Early data suggest that the Skavl Stø discovery contains a recoverable volume of between 5 to 10 million BOE. This compares to the estimated 37 to 50 million bbl of recoverable oil the majority state-owned operator announced it found in May at the Snøfonn Nord field. The back-to-back discoveries were made in locations separated by less than a mile.
Found about 3 miles from the southern edge of its giant Johan Castberg field in the Barents Sea, Equinor has made a subsea discovery that holds an estimated 37 to 50 million bbl of recoverable oil. Equinor is calling its new Arctic discovery the Snøfonn Nord field and said in its announcement that the field was made exactly 1 year after it found a slightly smaller oil field--the Isflak field--in the same area. Equinor added that the Snøfonn Nord field marks its tenth discovery in the Castberg license area which it shares with partners. Equinor holds a 50% ownership stake in the project with the remainder held by Vår Energi (30%) and Petoro (20%). The majority state-owned operator said the latest discovery may be developed with a tieback to its Johan Castberg floating production, storage, and offloading (FPSO) unit that was delivered to a Norwegian shipyard in April.
Abstract The near-linear relationship between anthropogenic CO2 emission and global warming is a major cause of concern among scientists. Achieving a low carbon future requires a new approach to providing energy solutions. This paper reviews the advancements in CCUS technology and actions of the oil and gas industry actively participating in Carbon Capture, Utilization and Storage (CCUS). CCUS has been identified to play a key role in achieving the goals of the Paris Climate Agreement. Oil and gas industry has been using CO2 Enhanced Oil Recovery (EOR) for many years which removes some CO2 permanently from the atmosphere. Currently there are more than 150 CO2 EOR projects in place worldwide. Additionally, the major oil and gas companies are stepping up to further remove CO2 from the environment through Direct Air Capture (DAC), Carbonate Fuel Cells etc. This paper discusses a few of the CCUS projects undertaken by some major oil and gas companies. Many companies are investing in startups, national research institutes and other ventures with proven viable technologies for carbon capture such as DAC and fuel cell technology. It is too early to say which of these technologies will emerge as the most superior one. Therefore, investing in different technologies and continuing with the established practices is the more fitting approach. The recent changes in 45Q tax credit in the USA is going to entice even more investors to approach CCUS as a commercially attractive venture. There is currently a lot of pressure from government and public to minimize CO2 emission in all industries and this will only increase with time. Oil and Gas industry is investing heavily on CCUS projects and are therefore best equipped to transition to carbon management companies. The end goal is to make the industry profitable while also safeguarding the environment.
Ragaglia, Simone (Vår Energi) | Carotenuto, Antonio (Vår Energi) | Napoleone, Luca (Vår Energi) | De Dominicis, Guerino (Vår Energi) | Sakharov, Sergey (Vår Energi) | Latypov, Artur (Schlumberger) | Newman, Robert (Schlumberger) | Guevara, Carlos (Schlumberger) | Rachi, Hakim (K&M Technology, Schlumberger) | Revheim, Kjell (Schlumberger)
Abstract To rapidly increase production from the Goliat Field without adding costly subsea equipment and infrastructure or mobilizing a high-end subsea construction vessel, an operator transformed two single-bore subsea wells into multilateral producers with independently controlled branches. A multidisciplinary team was assigned to perform a feasibility study for the introduction of multilateral wells. Work started with a reservoir geomechanics/wellbore stability review, based on which well construction/completion basis of design was made. The design and operations sequence were analyzed by a well engineering team. As a result, the main risks, uncertainties, and assumptions were clarified. Two candidate wells were identified, and then a multidisciplinary team was assigned to manage the project, finalize design, initiate procurement, and write procedures. Workshop preparation was closely monitored and reported on a weekly basis. The onshore team closely followed up and supported operational execution. The new laterals were added to the existing wells, and multilateral junctions were installed and tested. An intelligent completion was installed, and independent branch production started. In addition, the estimated reduction in generation of CO2 is estimated to be between 10 to 20 thousand metric tons per well as compared with drilling two new subsea wells and installing the associated infrastructure. The technology enables an exploration and production (E&P) company to introduce subsea reentry multilateral technology to increase production while minimizing costs. The process includes well candidate identification, planning, and execution. This practical example can be used for future reference by drilling and production-focused petroleum industry professionals to better understand the benefits and limitations of existing technologies.
Equinor has awarded contracts for concept studies to advance the Wisting project development toward concept selection by mid-year 2022, and ultimately a final investment decision by the end of 2022. The operator has tapped Aker Solutions, KBR, Sevan SSP, and Aibel related to the floating production storage and offloading (FPSO) vessel, and Aker Solutions, TechnipFMC, OneSubsea Processing, IKM Ocean Design, and Kongsberg Maritime for the subsea production and processing equipment, umbilicals, risers, and flowlines . The Aker Solutions contract covers front-end engineering and design of the FPSO. Valued at around $40.3 million, the study includes an option for engineering, procurement, construction, and installation valued at $922 million to $1.38 billion, according to Equinor. The Wisting field is in the Barents Sea and is estimated to hold close to 500 million BOE.
Tao, Mo (Consortium for Electromagnetic Modeling and Inversion, University of Utah, and TechnoImaging) | Jorgensen, Michael (Consortium for Electromagnetic Modeling and Inversion, University of Utah, and TechnoImaging) | Zhdanov, Michael S. (Consortium for Electromagnetic Modeling and Inversion, University of Utah, and TechnoImaging)
Accurate interpretation of salt structures plays an important role in hydrocarbon exploration. Over the years, several methods have been applied to mapping salt structures, including seismic, gravity and magnetic. The gravity and magnetic methods in particular have the advantages of low cost, efficiency, and ability to map the salt flanks and base of the salt, which are critical in oil and gas exploration. The salt diapirs are characterized by diamagnetic properties which makes a standard magnetic inversion for susceptibility difficult to apply. In this paper, we apply a recently developed method of total magnetic intensity (TMI) data inversion for magnetization vector instead of susceptibility. The magnetization vector can change its orientation within the inversion domain, thus indicating different types of magnetic properties of the rocks. The 3D inversion for magnetization vector, however, becomes very complicated due to the increased non-uniqueness of the inverse problem. To address this ambiguity, we use a joint inversion of gradiometry and TMI data based on a joint focusing stabilizer. This novel approach is illustrated by the case study of mapping the sea-bottom salt structures in the Nordkapp Basin of Barents Sea.
The Nordkapp Basin in the Barents Sea is considered an underexplored basin with limited amount of good quality seismic for exploration. The salt diapirism is prolific with diapirs penetrating all the way up to the seafloor. The basin has only 4 key wells of which 3 of them tested salt flank prospects. In order to image the very complex salt flanks, accurate 3D velocity models for imaging is required. Experience from TopSeis acquisition both in the Barents Sea and the North Sea has provided sufficient evidence to continue a similar acquisition setup for recording of the seismic wavefield. In addition to a high quality seismic wavefield, a high-resolution 3D velocity model is required to image around and up against the irregular salt bodies. This can be achieved by deploying Ocean Bottom Seismic (OBS) nodes on the seafloor. Recent Full Waveform Inversion (FWI) technology can obtain very accurate models to high frequencies even from very sparse node geometries. A split-spread source-over-streamer acquisition geometry using six wide-tow sources in addition to a long offset FWI front source will be used to acquire 3700 km of high-quality data. Seafloor nodes in a sparse grid of 1200 × 1200 m will be deployed to record the necessary low frequencies and long offset full azimuth data required to build an accurate velocity model.
Geophysical studies for offshore exploration have long been dominated by seismic methods. With the frontier areas of hydrocarbon exploration moving to more challenging geological settings, decisions based on seismic methods alone could be risky. Independent information from alternative geophysical methods integrated with seismic data becomes essential and necessary in this challenging situation. We consider an approach of integrating the complementary information of different geophysical methods to obtain self-consistent geophysical models based on using joint focusing stabilizers in regularized joint inversion of multiphysics data. The method enforces strong coupling between different models and promotes the sharp boundaries of the targets. The practical effectiveness of the developed methods is demonstrated by the case study of integrating and imaging electromagnetic (EM) and full tensor gravity gradiometry (FTG) data collected in the Nordkapp Basin in Barents Sea, Norway.
Abstract In this paper, we present a mathematical programming approach to evaluate the conceptual study of regional integrated development for Alta-Gohta discoveries in the Barents Sea. Two alternative scenarios are investigated, the first considers to tieback Alta-Gohta to a field that is 60 km away, Johan Castberg, and the second to tieback the field to Goliat, another field at 100 km further. A sensitivity analysis in terms of CAPEX and OPEX is performed to assess the trade-off between selecting the host to be Johan Castberg or Goliat. The results indicate that the profitability and host selection for a tieback development plan of Alta-Gohta is highly dependent on the start time and the costs of the project. Introduction The planning of offshore field development is complex and time-consuming as it involves several disciplines such as drilling, infrastructure location, processing capacity, wells scheduling, production planning, among others. This paper addresses conceptual studies from DG1 (feasibility) to DG2 (concept selection) of regional integrated field development alternatives of real-world fields. In this work, the feasibility and profitability of two different business concepts are assessed through a mathematical-programming based approach. The Barents Sea is the largest sea area on the Norwegian Continental Shelf (NCS) and with the largest potential for finding oil and gas reservoirs. Field development in the Barents Sea is challenging due to stricter safety and environmental regulations, Arctic weather season limitations and a lack of mature facilities and infrastructure as only a few fields are currently in production there. The Snøhvit (gas) and Goliat (oil) fields came on stream in 2007 and 2016, respectively. The oil field Johan Castberg is another field in the area currently under development and has the first oil planned to 2023. Gohta and Alta, two nearby offshore oil discoveries in 2013 and 2014, respectively, are currently under consideration for being developed. Recently, the operator reported that a standalone development of Alta and Gohta is no longer considered to be commercially viable, Staalese (2020). The main reason is that the deployment of new host facilities in the Barents Sea is too costly, and the recent fall in oil prices.
Bravo, Maria Cecilia (Schlumberger) | Blanco, Yon (Schlumberger) | Firinu, Mauro (Vår Energi) | Gianbattista, Tosi (Vår Energi) | Martin, Eriksen (Vår Energi) | Erik, Brondbo (Vår Energi) | Paul, Scott (Schlumberger) | El-Khoury, Jules (Schlumberger) | Horstmann, Mathias (Schlumberger) | Haq, Shahid (Schlumberger)
Abstract In complex and sensitive environments such as the northern Barents Sea, operations face multiple challenges, both technically and logistically. The use of logging while drilling (LWD) technology mitigates risks and assures acquisition of formation evaluation data in a complex trajectory. All data gathering was performed in LWD and provided the kernel for interpretation; alternate scenarios utilizing pipe conveyed wireline elevated risk factors as well as higher overall costs. Novel technology was required for this data acquisition, including fluid mapping while drilling (FMWD) that allows fluid identification with the use of downhole fluid analysis (DFA) using optical spectrometry as well as the retrieval of downhole fluid samples and a unique sourceless multifunction LWD tool delivering key data for the petrophysical evaluation. This paper presents a case study of the first application of a combination of FMWD and a petrophysical LWD toolstring in the Barents Sea. An excellent contribution to the operator of the PL229 that have pushed the boundaries of the formation sampling while drilling and set the basis to challenge the potentiality of this technique and improve the knowledge of the methodology that are the ultimate goals of this paper. Methods, procedures, process Hydrocarbon exploration, production, and transport in the Barents Sea are challenging. The shallow and complex reservoirs are at low temperature and pressure, potentially with gas caps. The Goliat field is the first offshore oil development in this environment, producing from two reservoirs: Realgrunnen and Kobbe. As part of the Goliat field infill drilling campaign with the aim of adding reserves and increase production, PL229 license operator drilled a highly deviated pilot hole to confirm hydrocarbons contacts in the undrained Snadd formation, which lie between two producing reservoirs. A successful data acquisition would not only provide information on the structure of the reservoir but would also assess the insitu movable fluid: type of hydrocarbon or water. FMWD allowed insitu fluid identification with the use of DFA, enabling RT evaluation of hydrocarbon composition as well as the filtrate contamination prior to filling the sampling bottles for further laboratory analysis. All data was acquired while drilling and using a comprehensive real-time visualization interface. Results, observation, conclusion Extensive prejob planning was conducted to optimize the operation. Dynamic fluid invasion simulations were used to estimate the required cleanup times to reach low contaminations. Simulations showed there was significant advantage in cleanup times when sampling soon after drilling. Honoring the natural environment, a unique sourceless multifunction LWD tool was used to acquire data for petrophysical evaluation-GR, resistivity, radioisotope-free density and neutron porosity, elemental capture spectroscopy, and sigma. Fluid mapping in a single run was key to efficiently resolve the insitu fluid type and composition. Critical hydrocarbon samples were collected soon after the formation was drilled to minimize mud filtrate invasion and reduce cleanup times. Multiple pressure measurements were acquired and six downhole fluid samples at low contamination (∼3% confirmed by laboratory) collected at several stations in variable mobilities. One scanning station was done at a zone were a physical sample was not required to confirm absence of gas cap. The DFA capabilities and ability to assess composition and control the fluid cleanup from surface allowed critical decisions to complete the acquisition program in this remote complex environment, all while drilling. In conclusion, FMWD results facilitated the placement decisions of the horizontal drain in this reservoir. This green BHA is unique in the LWD world. It eliminates radioactive source-handling and all related environmental risks to provide a comprehensive reservoir characterization. FMWD contributes formation pressure and fluid characterization and enables the physical capture of fluid samples in a single run. The combination of these two technologies completed the formation and fluid evaluation needs in this remote and environmentally sensitive area while drilling.