The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
- Data Science & Engineering Analytics
The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
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Abstract The work we describe here was motivated by the sizable operational difficulties and capital expenditure associated with liquid surging or "surge wave instabilities" frequently encountered in gas condensate fields in late-life production. Predicting and managing surge wave instabilities is becoming increasingly important as the number of aging fields is growing. The observed surging for low production rates at the outlet of a 45-km gas condensate pipeline in the Åsgard Field was not captured by our dynamic multiphase flow simulator. The water content in the pipeline, as measured by a radioactive tracer, was also substantially underpredicted. To better understand these shortcomings, Equinor launched an extensive experimental campaign in their explosion proof (EX certified) test facility in Porsgrunn, Norway (PLAB), using "real" fluids designed to provide a better match with field conditions than typical model fluids: a methane-based natural gas, stabilized condensate sampled from the Troll Field (low-density, viscosity, and surface tension), and water with Monoethylene glycol (MEG) (high density and viscosity). The PLAB data provided the basis for the development of new closures for the high-definition stratified flow model. The total pressure drop, condensate, and water content for the Åsgard pipeline were well predicted with the updated multiphase flow simulator. Simulations based on a refined grid and some modifications to the simulator settings revealed rich dynamics with massive surges consisting of water/MEG only, pushing a large reservoir of condensate in front. The water/MEG surges started out relatively small close to the pipeline inlet and grew considerably in length until they reached roughly 4 km as they approached the riser base. The water/MEG surges carried all the water/MEG through the pipeline. There was no water/MEG transport between the surges. The simulation results agreed with the observations at the outlet of the pipeline, where the condensate arrived before the water and the water flow was zero between the surges.
Johnsen, Georg (Equinor ASA) | Solbjør, Kenneth (Oceaneering International) | Iversen, Arve (Oceaneering International) | Rouge, Nick (Oceaneering International) | Alsvik, Hallgeir Foss (TD Williamson) | Anderson, Gary (TD Williamson) | Craig, Stephanie (TD Williamson)
Abstract Pipeline isolation tools have long been used in decommissioning activities where continued production in connected pipeline sections is required. To reliably execute an isolation program, robust communication systems are required to load the isolation tool, track, activate and deactivate it, and monitor the tool during the isolation process. Historically, that has meant hard wiring or acoustically linking to the offshore platform or vessel. Typical subsea pipeline isolation projects are performed and supported by an ROV or diving vessel; however, advances in communication technology have changed that paradigm. Robust LTE and VSAT connectivity enable robust, dependable communications that support remote operations. Today, it is possible to execute the same types of pipeline isolation programs from globally located, onshore remote operations centers. Combining advanced pipeline isolation technologies with remotely operated resident ROV systems can transform operations by eliminating the need for costly vessel support and reduce the number of people required offshore. A recent pipeline isolation program used for the first time on Equinor's Veslefrikk Field in the Norwegian North Sea employed leading isolation technology and a resident, battery-powered, electric work-class ROV system remotely operated from shore, demonstrating that there is now a viable option to using an ROV or diving vessel for these types of subsea operations. This approach allowed key personnel to work as an interconnected team from an onshore base where they collaborated, controlled, and watched live operations rather than mobilizing offshore, enabling cost savings, reducing HSE risk, and increasing collaboration. By using the onshore remote operations center, the project team was able to ensure a successful campaign. The project was completed as planned, demonstrating not only the feasibility but the value and repeatability of this approach to pipeline isolation.
Equinor has entered into an agreement to divest 28% of its working interest in Statfjord area license PL037 to OKEA for 220 million plus a contingent payment element based on oil and gas prices over a 3-year period. The transaction has an effective date of 1 January 2023. "With this transaction, we continue to optimize our oil and gas portfolio, welcoming an industrial player with late-life expertise into the Statfjord partnership," said Camilla Salthe, senior vice president for field life extension, FLX, for Equinor. "This will contribute to diversification and high value-creation from the Statfjord area in the years to come." FLX is a unit within Equinor that is responsible for safe and efficient operations of late-life assets through new ways of working.
Equinor has awarded contracts for the use of semisubmersible drilling rigs Transocean Encourage and Transocean Enabler. The Encourage will mainly be used on a drilling campaign in the Norwegian Sea, while the Enabler will work in the Johan Castberg field. The rigs have been on 8-year contracts with Equinor that expire on 1 December 2023 and 1 April 2024, respectively. This will be the first contract extension since the rigs were built, as so-called Cat D rigs, specialized for Norwegian conditions. The drilling program in the Norwegian Sea comprises nine wells to be drilled on the Tyrihans, Verdande, Andvare, and Vigdis fields located in the Tampen area of the North Sea.
Abstract Reservoir simulation studies of the Troll field, from the start with single realization full field simulation models and well simulation models in 1991 until today's complex and large ensemble models, have given important input to the Troll field development, reservoir management and well planning. The main focus in this paper is on Troll Oil simulation model. The effects of hardware and software technology developments are discussed. This includes challenges due to field size, geology, communications, thin oil zone, horizontal wells, gridding, numerics, CPU etc. Troll reservoir simulation has always pushed the limits of the hardware and the software, and this has initiated new solutions in modelling and simulators. The following topics are addressed: General information about the Troll field Troll Oil – how did it start Model size, grid resolution and hardware capacity – pushing the limits Grid construction Well modelling Geological reservoir model From Reference Model to Multiple Realizations
Nilsen, Simen Jøsang (Equinor ASA) | Obrestad, Hanne Undheim (Equinor ASA) | Kaarigstad, Håvard (Equinor ASA) | Mansurova, Nadia (Equinor ASA) | Solvoll, Tom Are (Equinor ASA) | Løchen, Johan (Sinomine Specialty Fluids) | Howard, Siv (Sinomine Specialty Fluids) | Abrahams, Ben (Sinomine Specialty Fluids) | Busengdal, Christian (Sinomine Specialty Fluids)
Abstract This paper describes how high-density cesium/potassium (Cs/K) formate fluids were successfully utilised from reservoir drilling to upper completion installation in five productive Martin Linge high-rate gas wells. Four wells were completed with openhole gravel pack and one with standalone sand screens. The gravel packing operation marks what is considered to be the highest density carrier fluid openhole gravel pack successfully completed worldwide, with SG 2.06. A complex operation under near-high-pressure/high-temperature (HP/HT) conditions, including managed pressure drilling (MPD), overbalanced screen running and openhole gravel packing, was simplified by utilising the same fluid throughout the operation. Cs/K formate reservoir drilling fluid and screen-running fluid were designed with biopolymeric additives and minimal calcium carbonate bridging particles. Clear Cs/K formate brine (i.e., without biopolymeric additives and particles) was chosen as gravel pack carrier fluid. The use of Cs/K formate fluids for all stages of the operation reduced the complexity of transitioning between the operational stages. In addition, the reservoir was only exposed to one filtrate without application of damaging weighting solids. The drilling fluid contributed to successful MPD and delivered wells with very good hole quality in the reservoir, which consisted of interbedded sandstone, coal stringers and shale. The shale stabilising properties of concentrated formate brine–based fluids provided acceptable conditions for extended openhole time and allowed additional logging runs, including pore pressure measurements, under near-HP/HT conditions before running the screens. One bottom-up cleanout was conducted before the screen-running fluid was circulated in and the screens installed. The spurt and seepage losses were low throughout the drilling and screen running phases. No breaker treatment was required in any of the wells. All wells have proven to have good initial productivity and high well productive efficiency as expected. The record-breaking openhole gravel pack operations performed with the high fluid densities required in Equinor's Martin Linge field have set a new standard for completing in challenging high-pressure environments.
Abstract The objective of this case study is to share essential learnings from the planning and execution of the first drilling and completion campaign in the Valemon field throughout the period of 2012-2017 with a total delivery of 17 wells. The case study will give an overview of the Valemon field, geology of the area and well design. The development of well trajectory became longer and more challenging as the geology targets moved farther away from the platform. Several major challenges and learnings were experienced during execution such as enabling one run strategy in 17-1/2" section, updating well path strategy to improve borehole stability, managing overburden gas responses in 12-1/4" section, and section target depth strategy for 12-1/4" section. Continuous learnings from sessions such as Improve Well on Paper (IWOP), Drill Well on Paper (DWOP), Subsurface Action Review (SAR), Subsurface After-Action Review (SAAR), operational procedures after action review, experience reports, and post well meetings enabled the project to reduce the time and cost per well. It took 160, 111, and 166 days respectively to complete the first three wells. The last well was delivered in 62 days. By the end of the campaign in November 2017, the Valemon project delivered four (4) extra wells compared to the original plan of thirteen (13) wells, while spending 500 million NOK-2017 (Norwegian Kroner with 2017 currency) or 60 million USD-2017 (United States Dollar with 2017 currency) less than the planned budget. Moreover, the entire drilling campaign was completed without any well control incidents.
Equinor has made an oil and gas discovery with its Røver Sør well nearby the Troll field in the North Sea. The operator said it is the seventh discovery in this area since the autumn of 2019. According to preliminary estimates, the size of the discovery is between 17 and 47 million bbl of recoverable oil equivalent, of which the majority is oil. The two exploration wells were drilled by semisubmersible Transocean Spitsbergen. Equinor is operator of the production license with partners DNO, Wellesley Petroleum, and Petoro.
As the industry enters a new era in offshore oil and gas development, operators are looking for ways to realize returns from new investments faster and optimize utilization of their existing assets. In addition to ensuring returns-focused performance, operators are simultaneously tasked with doing so in a way that reduces the carbon footprint. The offshore industry is looking to electrification as a means to reduce the amount of carbon emitted per barrel produced while enabling greater performance. Subsea processing systems have offered electric equipment for decades. Over a 20-year period, more than 30 multiphase pumps have been successfully deployed worldwide, including the industry's first all-electric-actuated boosting system, recently installed in the Vigdis Field in Norway.
Sinha, Supriya (Halliburton) | Walmsley, Arthur (Halliburton) | Clegg, Nigel (Halliburton) | Vicuña, Brígido (Halliburton) | Wu, Hsu-Hsiang (Mark) (Halliburton) | McGill, Andrew (Equinor ASA) | dos Reis, Téo Paiva (Equinor ASA) | Nygård, Marianne Therese (Equinor ASA) | Ulfsnes, Gunn Åshild (Equinor ASA ) | Constable, Monica Vik (Equinor ASA) | Antonsen, Frank (Equinor ASA) | Danielsen, Berit Ensted (Equinor ASA)
With the introduction of ultradeep azimuthal resistivity (UDAR) logging-while-drilling (LWD) tools toward the beginning of the last decade, the oil and gas industry went from real-time mapping of formation boundaries a few meters from the wellbore to tens of meters away. This innovation allowed early identification of resistivity boundaries and promoted proactive geosteering, allowing for optimization of the wellbore position. Additionally, boundaries and secondary targets that may never be intersected are mapped, allowing for improved well planning for sidetracks, multilaterals, and future wells. Modern tool design and inversion algorithms allow mapping the reservoir in 3D and exploring the sensitivity of these tools to the electromagnetic field ahead of the measure point for look-ahead resistivity. Improvements in the technology over the past decade have changed the way wellbores are planned, drilled, and completed, and reservoir models are updated. This paper presents a case study summarizing the advances in UDAR measurements and inversions over the last decade. The case study presents the whole workflow from prejob planning, service design, and execution of one-dimensional (1D) and three-dimensional (3D) inversion in addition to the future potential of look ahead in horizontal wells. Prewell simulations provide a guide to expected real-time tool responses in highly heterogeneous formations. This identifies how far from the wellbore 1D inversions can map major boundaries above and below the well. A fault was expected toward the toe of the well, and UDAR was used as a safeguard to avoid exiting the reservoir. Standard 1D inversion approaches are too simplistic in this complex geologic setting. Thus, 3D inversion around the wellbore and ahead of the transmitter is also explored to demonstrate the improvements this understanding can bring regarding geostopping toward the fault and reservoir understanding in general. Successful geosteering requires personnel trained to handle complex scenarios. Geosteering training simulators (GTS) could be efficient tools for training to interpret inversions where the “truth” is known from realistic 3D model scenarios. The team can learn how to best exploit UDAR technology and inversion results within its limits and not extend the interpretation beyond acceptable uncertainty levels. It will also be addressed how the understanding of inversion uncertainty could be updated in real time in the future. The continued future success of UDAR technology and 1D to 3D inversion results for look-ahead and look-around applications will depend heavily on uncertainty management of the inversions to avoid wrong decisions and potentially reduced well economy.