Norske Shell Research Articles

Barriers to the integration of digital twin technology in manufacturing

Industry over the last ten years has been characterized by a high level of digital transformation, affecting all layers of production and all areas of the economy. One of the key trends in the digitalization of industry is the digital twin – a system that combines a physical object, its digital model, and a continuous link between the two. However, the integration of such a complex technological solution is fraught with a number of barriers that arise in one way or another in the way of technology users. The authors of the article analyzed 100 examples of digital twin use in industry according to 7 criteria, among which the scope of technology application, the most problematic stage of its integration, key technological, organizational, ecosystem and economic barriers, as well as recommendations on overcoming these barriers, which have been applied or are in the process of application, were highlighted. The article contains a layer of statistical data and infographics that confirm the key conclusions about the main barriers to the integration of digital twins, among which the lack of devices and equipment with the necessary capacity, the lack of existing strategies for the technology implementation, the lack of standards for industry regulation and high initial investment are the main ones. Each block of barriers is accompanied by real examples (cases) of use of digital twin in the domestic and foreign industry, among which there are such companies as KamAZ, UEC-Klimov, Tesla, Volvo, Norske Shell and others.

E&P Notes (April 2021)

E&P Notes (April 2021)

World's Longest Electrically Heated Flowline Allows HP/HT Field Tieback to Existing Host

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 161572, ’HP/HT Field Development Tied Back to an Existing Host,’ by Trevor Crowe, Shell, and Jean-Paul Koninx, SPE, and Crispin Slater, A/S Norske Shell, prepared for the 2012 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 11-14 November. The paper has not been peer reviewed. The Linnorm gas/condensate field in the Norwegian Sea is technically challenging. The high-pressure/high-temperature (HP/HT) reservoir contains gas with CO2, H2S, and traces of mercury. Although the gas is relatively lean, the associated condensate has waxy properties. Although there are production facilities within 30 to 70 km, this discovery was initially seen as “stranded” gas because of the absence of an export route with available capacity. The wells and subsea concepts would push the limits of existing technology and require some world-first solutions for what will be the highest-temperature subsea field development on the Norwegian continental shelf with the world’s longest electrically heated flowline. Introduction The Linnorm gas discovery was made during the first half of 2005 in the Haltenbanken area offshore Norway. Well 6406/9-1 found a 180-m net column of lean gas in a gas-down-to situation in three Jurassic reservoir zones, all under HP/HT conditions (180°C, 800 bara). Two reservoir zones were production tested, both with good results. The field was further appraised by Well 6406/9-2 in 2007, successfully determining the gas/water contact in the key reservoirs. Several follow-up exploration wells all proved dry. This meant that the projected hub development for the Halten South area was no longer feasible. The likely way forward for Linnorm then was in the åsgard pipeline became available (currently estimated to occur later than 2020). The project was put on hold in 2007 because Linnorm was not expected to be developed before the 2020s. In summer 2008, an opportunity to accelerate the development of Linnorm was identified by making use of potential ullage in the newly commissioned onshore gas-processing plant at Nyhamna, built to process gas from the giant Shell-operated Ormen Lange field. This would require a new 200-km trunkline, the cost of which made the development commercially marginal. The solution was found by entering a new joint venture, the Norwegian Sea Gas Infrastructure project. The next challenge was to select an option for gas processing. Rather than an expensive new-build platform on Linnorm, the choice was made in mid-2011 for a subsea development with a tieback to the Shell-operated Draugen oil platform. In December 2011, the development concept was confirmed as a two-template, five-well subsea development, with a 55-km directly electrically heated (DEH) flowline tied back to Draugen, and 15 million m3/d of gas-processing capacity installed on Draugen (Fig. 1). Subsurface Uncertainties An extensive wireline formation-sampling program showed that the dis-covered gas is generally fairly dry, with high CO2 content, some H2S, and, on average, 50 Μg/std m3 of mercury. The condensate/gas ratio (CGR) varies per reservoir, with evidence for vertical compartmentalization in up to six different reservoir layers. Reservoir quality is variable, with some very good sands but also large sections with lower-quality tight sandstone. The high variability in reservoir quality across the reservoir leads to a number of specific challenges.

CO2 Technology Centre Mongstad–Design, functionality and emissions of the amine plant

Abstract The CO 2 Technology Centre Mongstad (TCM) project is constructing two large post-combustion CO 2 capture demonstration plants near the Statoil operated Mongstad refinery, located at the Norwegian west coast north of Bergen. TCM’s partners are Gassnova, Statoil, Sasol and Norske Shell. This paper describes the amine plant. The amine plant is designed and constructed by the CO 2 capture technology provider Aker Clean Carbon (ACC) with specifications and additional generic functionalities defined by TCM. Several new technology elements will be tested and verified, including improved solvents. Monoethanolamine and a new ACC solvent will be tested during the initial 16 months of operations. Thereafter tests will be run by the TCM partners. The quality and quantity of the emissions from the absorber to air have become top priority. Currently they represent a health and environmental uncertainty, mainly due to the lack of reliable and accessible experimental data. While knowledge and experience of these emissions are rapidly increasing, an emission permit is being applied for. The amine plant is highly flexible and can combine several novel technologies. Due to its scale it will give valuable information on utility and space requirements, scale-up properties and contribute to reducing HSE risks and costs.

HP/HT Gas-Condensate Well Testing for the Shell Onyx SW Prospect

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 108665, "HP/HT Gas- Condensate Well Testing for Shell's Onyx SW Prospect," by Arild Fossa, Expro; Derek MacKenzie, SPE, Norske Shell; Odd Steinveg and Eric Henderson, Expro; and Bart van den Bosch, SPE, Halliburton/Shell, prepared for the 2007 Offshore Europe, Aberdeen, 4–7 September. Complex data gathering occurs over a shorter time with much stricter environmental and safety constraints than ever before. Coupled with increased needs for more-accurate reservoir data for prospect evaluation, emphasis is placed on upfront planning and improved technical performance together with extensive use of advanced fluid-data-gathering methodologies. The latest technologies in testing gas-condensate wells were used on this job. Experiences were used later as the basis for other gas-condensate prospects, including those in the Russian sector of the Barents Sea. Introduction Onyx Southwest (SW) exploration Well 6406/9–1 was the second well drilled under License PL 255 offshore Norway. The first well, Well 6406/5–1 in the Tott East prospect, was drilled in 2002 to intersect sands of the Middle-to-Lower Jurassic Garn, Ile, and Tofte formations. Well 6406/9–1, was planned as a vertical exploration well for a possible high-pressure/high-temperature (HP/HT) regime. Although the HP/HT conditions were marginal, the test was designed and executed as if under full HP/HT conditions. Maximum surface pressure with reservoir fluids to surface was considered to be less than 690 bar. Bottomhole static temperatures were anticipated to be in excess of 150°C. The main objective was to investigate the stacked Ile, Ror/Tofte, and Tilje formations by conducting a multizone drillstem test (DST), with each interval being tested separately. Testing of two zones with a third was planned as a contingency to cover formations of interest. Results from well logging narrowed the selection to a two-zone DST. Test Objectives For the Onyx SW exploration-well formations, the primary test objectives for each reservoir were to assess the productivity and to obtain representative fluid samples. Obtaining reservoir pressure and temperature; determining skin and permeability-thickness product, kh; and identifying possible reservoir boundaries and heterogeneities for the formations were secondary objectives of the well tests. These secondary objectives would aid safety and equipment selection for future wells, as well as provide the starting point for further reservoir analysis. The kh and skin could not be attained satisfactorily for HP/HT wells in any other way because alternative methods have poor performance under such well conditions. The kh and skin parameters were selected to further aid analytical reservoir-simulation work and to enable improved use of the productivity data. Detection of possible reservoir boundaries and heterogeneities was included as a secondary target for planning a future field-drainage strategy. To achieve the test objectives, a set of special requirements was established to obtain the desired data quality. These requirements were downhole shut-in, testing the well with seawater as the packer fluid, and use of downhole memory gauges and single-phase sampling.

Assessing the Feasibility of 4D-Seismic Reservoir Monitoring

This article is a synopsis of paper SPE 50666, "Assessing the Feasibility of a 4D-Seismic-Reservoir-Monitoring Project," by B. Blonk and R.W. Calvert, Shell Intl. E&P B.V.; J.K. Koster, Norske Shell A/S; and G. van der Zee, Shell U.K. Ltd., originally presented at the 1998 SPE European Petroleum Conference, The Hague, The Netherlands, 20-22 October.

Techniques used in the exploration of turbidite reservoirs in a frontier setting – Helland Hansen licence, Vøring Basin, offshore mid Norway

Following the award of operatorship in the frontier Vøring Basin. Norske Shell embarked on the 3D seismic evaluation of a new play in the Upper Cretaceous. Integration of regional geology with various geophysical techniques is shedding light on the lithological and depositional model in this uncalibrated area. The current interpretation is that of a deepwater fan, with deposition of reservoirs in sheet layered geometries. The first exploration well is scheduled for drilling early in 1998.

The First Long-Term Horizontal-Well Test in the Troll Thin Oil Zone

Summary An 11-month horizontal well production test was performed offshore Norway inthe giant Troll gas field to prove performed offshore Norway in the giant Trollgas field to prove possible thin oil zone reserves. The oil column in the testarea possible thin oil zone reserves. The oil column in the test area is only 22 m, and the 500-m horizontal well was positioned 4 m from the water zone and18 m from the gas zone. The well, tied into production and testing ship Petrojarl 1, was put on production in production and testing ship Petrojarl 1, was put on production in Jan. 1990, The initial oil rate from the horizontalwell was more than four times higher than that of a vertical well in the samearea, Test results show that horizontal wells represent a viable technology foreconomic oil production from the thin oil zone in the Troll field. Introduction The Troll field, located below 300 m of water offshore Norway (Fig. 1), contains 0- to 26-m-thick oil rims sandwiched between a large gas cap and anactive aquifer. In the westernmost fault block of the field, the Troll West oilprovince, the oil zone is the thickest, 22 to 26 m. The oil in place (OIP) ofthis province is estimated to be 121 × 10(6) stock-tank m3. The oil in the Troll West oil province is located in high-quality sands withpermeabilities from 3,000 to 10,000 md. The oil production is limited by gasconing, resulting in rapidly production is limited by gas coning, resulting inrapidly decreasing oil rates. Developments by vertical wells therefore haveconsistently exhibited marginal economy. Horizontal wells are known to improve well productivity and to reduce water-and gas-coning problems. The Helder field, offshore The Netherlands, wasredeveloped in 1987–88 with 10 horizontal wells. Results show improvedvolumetric sweep, reduced water coning, and productivities up to 20 timeshigher than for vertical wells. In the Prudhoe Bay field in Alaska, manyhorizontal wells have been drilled. A 5-mm-long horizontal well in this fieldyielded productivities 1.5 to 3 times that of vertical wells. The wells alsoare successful in reducing gas coning. In the Troll field, pretest simulation studies indicated that developmentbased on 500-m horizontal wells could offer an economically attractive oildevelopment. Because of the 300-m water depth, highly unconsolidated reservoirrock, and a thin oil column, however, development with horizontal wells wasconsidered a high-risk project. To confirm the horizontal-well potential and long-term behavior, and therebyreduce the risk involved, a decision was made in June 1989 to perform an8-to-12-month production test with a 500-m horizontal well in the oil zone ofthe Troll West oil province. province. The well, operated by Norsk Hydro A.S., was completed in Dec. 1989, and production from the test ship began in Jan.1990. When the test concluded after 11 months, the well had produced 1 043 000stock-tank m3 of oil and the water cut had stabilized at about 35%. Background The Troll field covers 700 km2. The estimated gas in place (GIP) and OIP are1670 × 10(9) std m3 and 615 × 10(6) stocktank m3, respectively (Fig. 2). Twomain north/south faults divide the field into three provinces: Troll West oilprovince, Troll West gas province, and Troll East (Fig. 2). The Troll West oilprovince is province, and Troll East (Fig. 2). The Troll West oil province isinto the Southern and the Northern oil provinces (Figs. 3 and 4). Concession Block 31/2 (Fig. 2), operated by A/S Norske Shell, was awarded in1979. Blocks 31/3, 31/5, and 31/6 were awarded in 1983 with shared operatorshipbetween Norsk Hydro A.S., Den norske Stats Oljeselskap A.S., and Saga Petroleum A. S. Phase 1 of the Troll development, as proved in 1986, calls for gas Phase 1 of the Troll development, as proved in 1986, calls for gas production to startfrom Troll East in 1996. Before the horizontal test production to start from Troll East in 1996. Before the horizontal test well, 26 exploration wells hadbeen drilled within the four blocks; hydrocarbons were encountered in 22 wells. Two-dimensional seismic surveys Cover all four blocks. To select the horizontalwell location accurately, a 3D seismic survey was carried out during the summerof 1989. Reservoir Description The Troll field is contained within three easterly tilted fault blocks(Figs. 2 and 3). The reservoir interval is of Middle to Upper Jurassic Age, andthe reservoir sediments consist of clean, medium to coarse sand interbeddedwith micaceous and silty, very fine to fine sand. These sediments are generallyvery poorly consolidated. A typical feature of the reservoir sediments in the Troll field is thenumerous calcite-cemented layers occurring in all lithologies in all wells. There are two classes of calcite-cemented layers: extensive (up to severalkilometers) wide sheets found at the boundaries of the geological zones and theless extensive (1 to 100 m) calcite-cemented layers located within thegeological zones. JPT p. 914

Palynostratigraphy and palynofacies reconstruction of the Upper Jurassic to Lowermost Cretaceous of the Draugen Field, offshore Mid Norway

In 1984 Norske Shell discovered the Draugen Field with well 6407/9-1 at the edge of the Trøndelag Platform, offshore Mid Norway. The discovery was made in the offshore marine bar sands of the Upper Jurassic Rogn Formation. Based on the palynological assemblages observed in the Rogn and the overlying Spekk Formation four zones and seven subzones can be recognized. They range in age from Mid Oxfordian to Late Ryazanian. Furthermore, four palynofacies have been recognized, characteristic of different offshore marine environments: from lower offshore with stagnant bottom conditions to upper bar washover deposits. Integration of palynofacies data with the stratigraphic framework shows that in the Mid Oxfordian to Early Kimmeridgian the highest energy and the source area lay to the south and the southwest. During the later part of the Kimmeridgian the highest energy sequences (upper bar with washover deposits) are found in the north-central and south of the area. During the Portlandian to Late Ryazanian waterdepth increased rapidly resulting in a lower offshore environment with stagnant bottom conditions. From the depositional history it may be concluded that the Rogn bar could develop in the Draugen area because the uplifted faulted margin of the Trøndelag Platform created the right energy conditions for development and preservation of the bar.

People and Organizations Interacting.

Foreword Introduction A Way to Look at Things The 'Project With the Long Breath': Organizational Change in a Tanker Company Organization Change on a North Sea Project From Vertical to Horizontal: New Organizational Principles in a Refinery Redesign in Research: Participative Redesign of Work Organizations Organization Development on the Shop Floor Evolution, Revolution, and the Battle for Survival Organization Design in Canada: Sarnia Chemical Plant Development in Norske Shell's Organization Working Life in Japan A Group in Transition The Cultural Perspective Managing Diversity Index.

INTERPRETATION OF AEROMAGNETIC DATA FROM THE NORWEGIAN SECTOR OF THE NORTH SEA*

AbstractTotal magnetic intensity contour maps for the study region (between 2°E to 10°E and 56°N to 60°N) were digitized and converted to a regular grid of 285 × 285 points. The study area measures approximately 444 km × 444 km and the grid spacing is thus 1. 56 km. The International Geomagnetic Reference Field for 1975 was gridded for the above‐used net, and from the two data sets a further grid of the ▵T field was generated. A large number of profiles were constructed which were suitable for depth determinations. The regular grid ▵T data is also convenient for the computation of the second vertical derivative. Using the method of vertical prisms of Vacquier et al. (1963), a large suite of curvature‐depth indices was measured to complement the depths obtained from the intensity slopes and from boreholes which reach the crystalline basement. The depth to the magnetic basement has been contoured, and the resulting map is shown to be in good agreement with what is known about the deeper geology of the study area.The work reported here is part of a research project supported by Amoco Norway, BP Petroleum Development Ltd, Elf Aquitaine, Esso Exploration and Production, Norwegian Gulf, Norsk Hydro, Mobil Exploration Norway, Norwegian Petroleum Directorate, Royal Norwegian Council for Scientific and Industrial Research (NTNF), Norske Shell, and Statoil.