bluuebunny/crossref_metadata_2025_split huggingface dataset:
Shear Response of Rough Rock Discontinuities Subjected to Impact Loading: Experimental Study and Theoretical Modelling
Authors: Wang Feili , Wu Bangbiao , Wang Shuhong , Meng Fanzhen , Xiu Zhanguo , Wang Chonglang 
Published: April 2022

Abstract
The presence of discontinuities can significantly weaken rock masses, whose shear load-bearing capacity is always dictated by discontinuity failures. The shear response of rock discontinuity has been extensively studied under low loading rate conditions, while the effect of impact loading on its shear strength was unclear. To address this issue, rock discontinuity samples with quantified surface roughness were tested under six normal stresses (0%, 5%, 10%, 15%, 20%, and 25% of its uniaxial compressive strength) and different loading rates (varying from 100 MPa/ms to 700 MPa/ms) by a novel-designed impact shear testing system. Experimental results show that the impact shear strength is proportional to the loading rate and exhibits significant rate dependence. Moreover, the cohesion is clearly rate-dependent and the friction angle keeps constant during impact loading, which shows obviously different behaviors with those under static loading conditions. Considering the rate effect of the shear strength parameters, the shear strength criterion of rough rock discontinuity under impact loading was established. Furthermore, a statistical constitutive model was proposed by incorporating the Weibull distribution of the shear damage. The successful application of the theoretical model to the experimental data shows that the proposed models can well predict the shear strength and describe the shear damage of rough rock discontinuities under impact loading.
Tracing of Induced Heatwaves to Determine Well Inflow Distribution
Authors: Skogen Erik , Ottesen Tore , Mo Sjur , Moen Terje , Nyhavn Fridtjof , Johansen Stein Tore , Hjelstuen Magnus Blihovde 
Published: April 2022

Abstract
This paper introduces a novel wireless well inflow/outflow profiling technique and illustrates how operators may gain from its use. Results from well-scale multiphase flow loop tests are presented.
A system has been realized, based on tracing of heatwaves induced in the well fluid by wireless heat sources embedded in the completion string or otherwise deployed along the reservoir section of hydrocarbon-producing wells. The heatwaves are subsequently registered as temperature anomalies as they flow past one or more downstream temperature sensor(s). The data will be available through an existing SCADA system for real time analysis and interpretation.
Heatwave travel times and the Residence Time Distributions (RTD) in different parts of the well system are derived using flow models. This forms the basis for estimating "what is flowing where and how much?".
Extensive tests were carried out at SINTEF's flow laboratory. Single- and multiphase (oil-water) fluid compositions were produced through a well-scale horizontal flow loop with multiple inflow points, and across a range of flow regimes from laminar and up to fully turbulent regimes. Based on theoretical work and the laboratory results models were developed to accurately represent the transport of heat from heat sources to temperature sensor placed downstream. For the simplest case of turbulent single-phase flow, heatwaves are well defined for the whole tubing length and flow rates at various inflow points can be accurately determined. Also, for cases of multiphase and laminar flows, valuable flow information can be extracted from the downstream sensors. Models are being developed for all these cases.
A brief comparison to alternative monitoring techniques is made. The technique described in this paper is basically a tracer technique and similarities with flow monitoring by chemical tracers can be observed. Unlike traditional tracer technologies heatwave applications are not limited to production cases. It will also be a tool for water injector wells and wells for CO2 sequestration.
CO2 Caprock Threshold Pressure Measurements for the Northern Lights Reservoir
Authors: Zuta John , Vatne Kåre Olav , Askarhinade Reza , Iversen Jan Erik , Lohne Arild , Mousa Al-Noth Mohammed , Mehrabi Ali , Thompson Nicolas 
Published: April 2022

Abstract
Assessing the representative threshold capillary property of a reservoir formation is very important in the context of reservoir production, basin modeling and geological storage. The long-term safety of CO2 storage is highly dependent on the permanent sealing capacity of the cap rock.
As part of the Northern Lights CO2 storage project, Equinor with partners Shell and TotalEnergies, in Q1 2020 drilled well 31/5-7 in exploitation license EL001 southwest of Troll A in the northern part of the North Sea. The objective of the well was to investigate whether the formations in the Lower Jurassic Dunlin Group (Cook and Johansen storage formations and Drake Formation cap rock) are suitable for storage of CO2.
In this work, laboratory experiments were used to determine the CO2 cap rock threshold pressure for reservoir core material from well 31/5-7. The experiments were performed at reservoir conditions, 260.5 bar and 83.5°C. Prior to the tests, the permeability to water was measured to be in the nano Darcy range. The dynamic method for measuring the threshold capillary pressure relies on establishing a flow of water through the plug before CO2 reaches the plug's surface. Due to the low permeability of the plugs, the amount of water that must be displaced before CO2 contacts the plug's surface was kept low from the inlet. Thus, if CO2 contacts the plug's surface at a pressure below the threshold value, the water production should stop. The onset of water production from the outlet will define the threshold pressure, as CO2 will flow into the plug once the threshold pressure is exceeded. The CO2 pressure was gradually increased stepwise up to a maximum of 360.5 bar over 4 weeks.
The capillary threshold pressure for CO2 was measured for three plugs and was in the range 30 - 50 bar above the pore pressure of the reservoir at reservoir conditions. However, should the aquifer pressure exceed this value, the containment of CO2 below the Drake formation is ensured by its very low permeability (few tens of nD) that will preferentially drive the CO2 horizontally within the storage formations rather than vertically through Drake formation. No values were obtained within the time frame of the experiments for the two remaining plugs. The plugs were exposed to an injection pressure of 360 bar, 100 bar above the pore pressure, and no entry was observed. Thus, the minimum capillary pressure is expected to be greater than 100 bar for these two plugs.
Overcoming Subsurface Challenges to Develop a Thin Oil Column - A Case Study from the Five Decade Old Gekko Discovery in the Alvheim Area
Authors: Tveiterå Leif Kristian , Fismen Morten , Bang Asgeir , Chatterjee Amitabha , Osvoll Ivar Frøland 
Published: April 2022

Abstract
The Alvheim field has been on production since 2008 through the Alvheim FPSO. While the FPSO has produced more than twice the initial Alvheim area production estimate of 250 mmboe, the ambition is to produce a billion barrels from the area via continuous infill drilling and near-field exploration and developments. An example of the latter is the joint Kobra East and Gekko (KEG) tie-in. This paper describes the various anticipated subsurface challenges, risks and proposed solutions in developing the Gekko field, discovered in 1974 (25/4-3) and subsequently appraised in 2003 (25/4-8) and 2018 (25/4- 13S&A), revealing a thin oil column (6.5m) between a gas cap and a large aquifer.
The Gekko reservoir is of Late Paleocene age and consists of turbiditic sand deposits of the Heimdal Formation. Two subtle four-way closures (Gekko North and Gekko South) define the trap. Reservoir properties are excellent with high porosities and multi-Darcy permeabilities.
The technical challenges associated with producing a thin oil column sandwiched between the gas cap and a strong aquifer led to the field being viewed initially as a gas discovery and not included in the Alvheim development.
New appraisal wells and additional seismic data sets, advances in seismic techniques and a new area petrophysical study helped to improve the subsurface understanding. Development of the thin oil column has been evaluated using detailed reservoir simulation models to determine optimal well placement and completion solutions, resulting in a well design comprising of horizontal tri-lateral wells of approximately 4000 m reservoir lengths. New completion technologies such as autonomous inflow control devices (AICD), independent inflow control valves (ICV) installed in each lateral and downhole water cut meters are expected to play a pivotal role in unlocking the development potential.
The work done has resulted in a successful PDO submission (June 2021) for the KEG development. Four tri-lateral wells will be drilled during 2023, with first oil expected in 2024. This development represents the largest ongoing tie-in project to Alvheim, adding reserves of approximately 40 mmboe.
Producing a thin oil column such as Gekko presents significant subsurface challenges. Such a development will require targeted technologies and multi-disciplinary coordination. Successful development will reinforce the near-field development strategy for the Alvheim FPSO and add to its production volumes and production life. To be able to finally develop the field fifty years after it was discovered can also serve as a benchmark for future stranded developments of similar scope and complexity.
ECalc - A Computationally Efficient Tool for Emission Forecasting
Authors: Skjerve Kari Børset , Martinsen Frode , Solbraa Even , Espelid Øystein 
Published: April 2022

Abstract
eCalc is the name of a software tool for high-quality emission forecasting. eCalc allows integration of subsurface and operational knowledge and calculates emission forecasts directly relating drainage strategy to operational strategies and equipment. Emissions directly relating to reservoir drainage (CO2 in particular) vary with the reservoir production rates and pressures, and the process assumptions. Emissions from drilling, flaring and mobile vessels may be included for integrated bookkeeping. eCalc is a holistic asset prognosis tool for calculation of the total emissions allowing break-down into single emission sources.
eCalc has integrated energy functions to be used for modeling the energy usage of various process equipment such as pumps, compressors, generators, and turbines. The energy functions are models that relate input variables to energy consumption. The input variables are typically rate and pressures. For the compressor models, it uses compressor curves and thermodynamical models to calculate the shaft work needed for the predicted compression work through a single or a series of compressors. Also, it has built in models for future low-pressure projects, for less mature tie-in projects and new builds where vendor data is not available. In addition, there is also support for energy functions based on tables generated by external software (e.g. Unisim, Hysys).
The flexibility of the software allows evaluating varying subsurface drainage strategies combined with process modifications in an integrated calculation. The tabulated energy functions, or likewise thermodynamical calculations, allow for a fast and easy to use calculation tool that can be used in multi-realization systems like the fast model update environment. eCalc is batch callable in Unix and can thus be easily integrated in workflows. eCalc also allows integration with external software, like for example numerical optimizers.
eCalc uses process knowledge to mimic anti-surge and minimum flow without needing iterative solvers. Depending on where the operating point is relative to the chart, eCalc implements control strategies to automatically mimic process control. Eg if the operating point is in the surge domain, eCalc adds mass rate to the rate input to move to a point on the control line.
A forward model results which is at the core of the calculations. It is not intended to replace the commercial process simulation software but allows subsurface personnel access to simplified process calculations and therefore opens the possibility for a better cross-disciplinary working environment.
The integrated tool makes mutual information exchange between operations, subsurface and sustainability disciplines easy. The engineering approach with real physical models, capacities and data provides a high-quality emission forecast suitable for the long term. eCalc has been implemented on nearly all Norwegian installations (Espelid et al, 2022) and three generic examples are included in this paper.
Implementation of a Safe, Efficient, and Robust Whipstock System
Authors: Gregurek Philip Matthew , Eidem Morten , Nguyen Tuan Anh , Grindhaug Gaute , Ferdin Valerie , Ali Mohsen , Hern Greg , Munir Waqas 
Published: April 2022

Abstract
The whipstock system has successfully improved on operation efficiencies by reducing the total operational time by up to 50%. This is achieved by the system's ability to bypass the upfront cleanup / gauge run, on site assembly, and limitations on running speed. The absence of personnel in the red zone decreased the associated risk during deployment of the system. Even when met with faulty draw works, poor well conditions, and ovality in the casing the system was deployed without issues. Flawless execution of the system was demonstrated by setting the whipstock on the first attempt. The quality of the window was verified with the passing of a rotary steerable drilling assembly. No additional trips were required to ream or polish the casing exit window.
The mill to whipstock interface delivers on improved safety, robustness, and efficiency of a casing exit operation. This connection provides a positive impact in the reduction of carbon emissions by effectively decreasing the required time to perform a casing exit. The redundant set anchor prevents additional runs due to its redundant activation feature and its ability to be reset and reoriented if required.
This system delivers on improved safety, robustness, and efficiency of a casing exit operation by providing a positive impact in the reduction of carbon emissions. From multiple aspects, decreasing the required time to prepare the well and perform a casing exit.
Smart Well Foundation, the Cost Efficient and Environmental Choice for Field Developments
Authors: Mathis Wolfgang , Holen Ole Kristian , Bjørvik Trine Lise , Strand Vidar , Witting Fredrik 
Published: April 2022

Abstract
Conventional subsea satellite production well design requires the well to be drilled and completed with the drilling rig before flow line and umbilical are installed with other specialized vessels. This causes a time delay between well drilling/completion and production start-up, amounting to several weeks. By installing a well foundation with integrated conductor, manifold, pipeline and umbilical tie-in points, this costly time delay can be reduced, and facilitate instant or accelerated production.
The CAN® (Conductor Anchor Node) technology is the structural foundation for the well construction. Smaller marine vessels can be used for installation and recovery. Instead of drilling a 36 in. or 42 in. hole, running the conductor, and cementing operations, a vessel is used to install the well foundation ahead of rig arriving. The technology also offers unparalleled load capacities for satellite production wells, mitigating operational risk by preventing mobilization and handling of spud BHA and conductor handling equipment on the rig, preventing conductor as well as cementing failures, excellent inclination control and many more technical, cost, and environmental benefits.
In summary these advantages result in increased efficiency, shorter project execution time, faster time to first oil, reduced operational risk and lower cost ultimately lowering the CO2 footprint (21-44% reduction, or 400-600 mT of CO2) of the top-hole section of any well, development as well as exploration wells.
Field Validation of a Full Transient Hydraulics Model Leveraging Digital Twin and Real-Time Rheology Technology, Case Studies from North Sea Continental Shelf
Authors: Starostin Alexander B. , Forshaw Matthew J. , Aragall Roger , May Roland , Dahl Thomas G. , Macpherson John D. 
Published: April 2022

Abstract
Poor management of annular pressure regimes, or inadequate transport of drilled cuttings from bit to surface, results in significant non-productive time (NPT) and invisible lost time (ILT). On average one in three North Sea continental shelf wells requires the technical sidetrack of a section, pushing drilling projects over authorized expenditure (AFE). Insufficient control of real-time hydraulics is a significant contributing cause.
Pre-well planning applications and real-time (RT) engineering applications have used, for decades, steady state hydraulics models. In recent times, this modeling has been augmented with transient hydraulic models which have improved the capability, especially in real-time. Our advisory and control system maintains a digital twin with tools and environment, updates the digital twin state from measurements and transient wellbore flow modelling, and assists range of operations.
This paper details the features of a one-dimensional multi-phase transient model of wellbore flow capable of comprehensively resolving the temporal and spatial course of pressure, cuttings concentration in suspension, and those in static beds along the wellbore. The model considers local variations in rheology, cuttings slip, cuttings deposition, and cuttings mobilization. The cuttings concentration uses a drift-flux model, populated with coefficients from high-resolution 2D and 3D CFD simulations. The numerical solution is designed for effective real-time execution.
A comparison of simulation outputs with measurements demonstrates the accuracy of the model: equivalent circulating and static densities (ECD & ESD) and standpipe pressures are compared to their measured counterparts from surface and downhole pressure sensors; simulated outlet cuttings mass is compared to measured skip weights.
The evaluation also demonstrates that accuracy is a function of input data availability and quality: how RT rheological sensor data, providing a constant feed of Fann-75 data to the model, impacts simulation results.
Results clearly show the superiority of a real-time transient hydraulic model, obtaining a 10-20% tighter correlation with measured ECD & ESD, and a simulated mass out of the wellbore within 4% of the measured skip weights during both drilling and section clean-up operations.
Simulation results using input low-resolution bob-and-cup measured mud density and rheology have less accuracy than those supplied with a continuous feed of real-time density, rheology, and temperature from an automated measurement system. A sensitivity analysis on input variables serves to identify which fluid properties are the most essential to measure automatically.
The paper will conclude with an overview on the implementation of the physics-based models in a SCADA style drilling advisory and automation system.
Novel Workflows to Model Fishbone Wells and Generate Reliable Production Forecasts, Employing an Economic Optimization Procedure
Authors: Dousi Niek 
Published: April 2022

Abstract
In the last years it has become technically- and economically feasible to drill productivity enhancing fishbone wells in tight and/or thin formations or in areas where hydraulic fracturing is not permitted due to local environmental regulations. Modeling of fishbone wells is complex and currently very time-consuming. A fully integrated workflow has been developed to model fishbone wells, using dynamic models to generate reliable production forecasts. This novel workflow comprises of the implementation of pre-defined well trajectories and number of needles in a box- and/or full-field dynamic model. Subsequently, the number of needles and number of wells to be drilled is optimized using a workflow driven by project economics.
The workflow comprises the ability to generate forecasts for different well configurations, such as horizontal well length, well depth, number of needles and needle lengths. The needles are modeled explicitly as multilaterals. The needles cannot be oriented during drilling. To obtain a reliable prediction of the recovery of the fishbone wells, a so-called "needle rotation randomizer" has been developed. The orientation of the needles is important in the prediction of future production, as the ratio between the horizontal- and the vertical permeability (KvKh) can be significant in tight formations.
The attractiveness of different well- and needle configurations, as well as the number of fishbone wells is assessed as part of the workflow. This paper addresses how different scenarios, including variation of the number of needle stations (subs) and wells impact project economics by applying a simplified Net-Present-Value (NPV) calculation. Modelling results highlight that more subs will lead to a higher production rate, with corresponding higher NPV's. However, too many subs will lead to lower NPV's, as recovery increase becomes more marginal. It will be demonstrated how modelling can be used to optimize the number of subs. With further full-field dynamic modeling the production forecast can be enhanced by varying well numbers and their spacing the using the optimized number of subs. This paper will showcase how, a fully optimized full field development plan, applying fishbone wells can be generated using the applied workflow in a very short timeframe.
The novel workflow involves the generation reliable production forecasts for fishbone wells, employing a "needle rotation randomizer". Secondly, the new workflow enables optimizing the number of subs and wells, using an efficient economic optimization assessment.