bluuebunny/crossref_metadata_2025_split huggingface dataset:
E-line Milling of Isolation Valve Restores Well Access in the North Sea
Authors: Ngo Xuan Dong 
Published: April 2022

Abstract
Milling interventions can resolve a variety of issues related to downhole restrictions, and these extend beyond remediation of typical scale buildup. One such problem or challenge is that of downhole hardware becoming stuck or no longer functioning properly.
In early 2020, a North Sea operator experienced a significant increase in water cut from a horizontal producer and needed to investigate. Production logging found no evidence of scale, but the run did reveal a half-open formation isolation valve. An additional caliper log showed the valve had a clean shifting profile, but, after a failed open-close operation, the operator decided to mill the valve to make further logging and water shut off possible.
The e-line toolstring consisted of a tractor and a milling tool with a specialized milling bit. The function of the tractor was twofold, providing conveyance to target depth as well as countering the torque of the milling tool during the operation. A Power Suction Tool was also included as a contingency for potential fishing of milled hardware/debris. During the run, after tagging the valve, hardware milling was carried out in two three-hour stages. The valve was completely milled through, collected as two pieces (half-moons) in a single run.
The operation resulted in the removal of the restriction and enabled access to the section of the well below the isolation valve. With the operation requiring just 8.5 hours, the solution provided significant time and cost savings to the operator.
GOR Prediction from Advanced Mud Gas in Gas Flooded Reservoirs – A Simulation Study
Authors: Yerkinkyzy Gulnar , Yang Tao , Cheng Nan , Uleberg Knut 
Published: April 2022

Abstract
This paper presents a new approach to GOR prediction from advanced mud gas data for gas flooded reservoirs. This new approach predicts the GOR of the reservoir oil and/or gas while drilling in gas flooded reservoirs and makes real-time well decisions based on identifying the reservoir fluids. The method is currently under extensive verification in real field operations. The new method's potential is significant for accurately mapping resources for in-fill wells, boosting profitability, and lowering carbon footprint in gas flooded fields.
This study widens our previous machine learning model from advanced mud gas (Yang et al., 2019) developed for predicting in-situ reservoir fluid properties by extending the methodology to include gas flooded reservoirs. The methodology is verified by compositional modeling of a large field undergoing pressure depletion, water, and gas injection over 30 years. The compositional reservoir model is used to generate advanced mud data (light components C1 to C5) to predict fluid phase properties by machine learning. The predicted fluid properties are then compared to the actual model data. The data points represent different well locations and different times of the field development, i.e., initial state, water injection, gas injection, and pressure depletion.
To accurately predict the fluid properties using a machine learning model, the "training database" must contain a wide range of fluids that covers the "compositional window" in the gas injection process. To achieve this, we have introduced synthetic fluid samples into the machine learning fluid database. The synthetic data are generated through slim tube simulation by developing miscibility between original reservoir fluid composition and representative injection gases. We have verified the machine learning model by comparing the GOR from the reservoir simulation model against the predicted GOR at different depths during the different production stages of the field. The GOR prediction shows good agreement with the simulation results.
Utilization of Settled Barite as Permanent Well Barrier Element - Feasibility Study
Authors: Khalifeh Mahmoud , Muri Bø Eskild , Shahmoradi Mohammad Ali 
Published: April 2022

Abstract
Settled barite is a flexible material which can be compared with unconsolidated sand slurry barrier materials. It is consisted of different particles with density of 4.2 sg and in combination with additives in drilling fluid (e.g., bentonite, xanthan gum, cuttings) can create a seal barrier.
Initially, 402 wells were reviewed, which 307 of them were wells with slot recovery. Among them, 102 wells had cut reported below top of solid, and only 72 of them had circulation pressure data. Acceptance criteria were defined to sort out the final wells to be considered in this study. Finally, 22 wells possessed the requirement for being studied. Our data mining process shows that one can divide the fluid above cement into three zones: light, heavy and consolidated. Engineers are interested to find depth of heavy fluid and conducting cut & pull operation. However, these data shall not be used for studying potential utilization of settled barite as annular barrier. Operational data and experience show barite can be compacted and in combination with other ingredients present in drilling fluid, providing consolidated material. Analysis of 77 field circulation through settled barite shows that settled barite adheres to casing and formation.
The initial experimental result, on simple water base fluid, show that settled barite could hold pressure slightly higher than its hydrostatic pressure. One should note that these experiments were conducted in long transparent plastic pipes with least friction. The well data and initial experimental measurements indicate that settled barite may have the potential to act as barrier similar to unconsolidated sand slurries.
The objective of this paper is studying prospective utilization of settled barite as annular barrier by reviewing well data from wells drilled in the North Sea and conducting experiments.
Real-Time Fiber Optics: A Door Opener for the Wellbore Environment
Authors: Bakka Håkon Sunde , Dümmong Stefan , Haavik Kjetil Eik , Li Qin , Olsen Per Atle 
Published: April 2022

Abstract
Distributed Fiber Optic (FO) sensing is a novel technique that allows for continuous monitoring of the entire wellbore. Two of the most common techniques are Distributed Temperature Sensing (DTS) and Distributed Acoustic Sensing (DAS), which allow for measurement of temperature and strain, respectively (after Johannesen et al., 2012). Both have a large range of applications, but accessibility has often been a limiting factor due to large data amounts and slow data transfer rates (e.g., Schuberth, 2020, and Schuberth et al., 2021).
For the Johan Sverdrup asset, Equinor has developed a data streaming solution that allows for real-time processing and interpretation of FO data. The system has been operational for more than a year. In its current state it processes approximately 500 terabytes (TB) of data each week, with insights made accessible to the end user through a web-based front-end solution. This streaming solution has been designed to give a flexible and scalable framework that enables real-time information exploitation of the fiber optic data, as well as allowing for automated monitoring.
We will illustrate some of the benefits of this system, and how it can provide new understanding of well conditions and processes. Over the past year, the potential of this data has been illustrated through several prototype applications, providing automated insights ranging from downhole valve monitoring to real-time inflow profiling (e.g., Schuberth at al., 2021, and Dümmong, 2021). It even opens the door to harsh environments such as wellbore clean-up, where monitoring in the past has been a challenge.
The real-time fiber optic system on Johan Sverdrup has been developed over the course of just two years. In its current state it processes 500 TB per week but is designed to handle up to 300 TB per day, which will be put in use as more interrogators are added to system. As data acquisition is continuous, the amount of information and therefore possible application space keeps growing day by day.
Grane Case Study: From Data and Model Ensembles to Actionable Insights Using a Cloud-Based Innovation Toolkit
Authors: Barkved Olav , Haukås Jarle , Kochetygova Anastasia , Monastyrev Konstantin 
Published: April 2022

Abstract
Assessing and improving subsurface models is an integral part of any field development project. Scanning through a multitude of data and models to look for opportunities to improve is a challenging task that can be very complex and time consuming if done manually. On the other hand, successful automation of the process typically requires field-specific customization. To address this challenge, a cloud-based innovation toolkit has been developed.
The toolkit is a set of Python modules that automate the key steps in comparing reservoir model predictions to various types of observation data, including production data and time-lapse seismic data. The toolkit enables users to create customized images that highlight important aspects of data and models, helping the team to decide how to proceed. Images that drive decisions are referred to as actionable insights. The toolkit is also used to create customized mismatch metrics, combining, for instance, production data mismatch and time-lapse seismic mismatch per region, per time interval, or overall. Ranking a set of reservoir models according to selected mismatch metrics is automated. For improved efficiency, the toolkit is built on top of a data management system for simulation models, which makes access to the models and results stored in the cloud quick and seamless.
The innovation toolkit was used in a case study in the Grane Field to assess time-lapse seismic data, production data, and two ensembles of 200 and 100 reservoir models, respectively. An important element of the project was the customized co-visualization of gas migration observed from time-lapse seismic data and production data, vs. simulated gas thickness and gas production from the reservoir model ensembles. These images allowed the team to quickly identify a region where changes to the top reservoir structure could reduce the mismatch between model predictions and production and time-lapse seismic observations.
As a final step of this study, an updated ensemble was generated that allowed the team to test and confirm several hypotheses about structure, contacts, and in-place volumes of the selected region of the Grane Field. The short time spent for this study vs. the amount of data processed highlights an important advantage when it comes to the need for continuous well maturation in the Grane Field.
Cloud access to data, models, and new digital tools enable new opportunities for automation and improved efficiency. The novelty of the presented work is the combination of automation and customization, enabling domain knowledge to drive automated workflows.
Sealing Performance of Geopolymer for Plugging and Abandonment; Apple-to-Apple Scenario
Authors: Gomado Foster Dodzi , Khalifeh Mahmoud , Kamali Mohammadreza , Saasen Arild , Aasen Jan Aage 
Published: April 2022

Abstract
Sealability of barrier material is required for successful plug and abandonment operations. The emergence of geopolymer as a green alternative to ordinary Portland cement presents an option for well abandonment in a more environmentally friendly manner. Sealability of geopolymer in terms of hydraulic and shear bond strength (key factors in evaluating the interfacial properties of the cement-casing interface) is compared to that of API Class G cement at 25°C and at a pressure of 34.5 bar (500 psi). The hydraulic sealability was measured with a custom-made setup, which allows the measurement to be taken continuously from the curing stage of the various cementitious materials with eliminating any pressure and temperature shocks. Thus, mimicking downhole conditions for the hydraulic sealability behavior of the cementitious materials used in our study. In addition, the push-out test was used to characterize the shear bond strength between the casing-cement interfaces. The volume shrinkage behavior was studied for both materials. The volume shrinkage of the Neat G cement was found to occur very quickly during and after the hydration reaction resulting in a total shrinkage of 2.4% whiles that of the geopolymer undergoes a shrinkage of 2.2%. The shear bond strength of the geopolymer lesser than that of the Neat G cement, it was able to match the Neat G cement in terms of the hydraulic bond strength. This is reveals that the rock-based geopolymer can be an alternative for zonal isolation as well as revealing that hydraulic bond strength and hydraulic sealability should be the main factors for barrier qualification.
Materials for Well Integrity – Rheological Behavior Study
Authors: Kamali Mohammadreza , Khalifeh Mahmoud , Saasen Arild , Delabroy Laurent , Godøy Rune 
Published: April 2022

Abstract
Ordinary Portland cement has been the prime material used for well cementing and permanent well- abandonment. Occasionally, the properties of the Portland cement can be inadequate to fulfil the necessary requirements. Hence, alternative barrier materials have been suggested for use in primary cementing and permanent well-abandonment. Among these, geopolymers, expansive cement, pozzolan based material, and thermosetting resins can be good alternatives.
This article presents the fluid properties and rheological behavior of the above-mentioned alternative materials. API neat class G cement is used as a reference material to compare the obtained results. Through this study, the bottom-hole circulating temperature (BHCT) and bottom-hole static temperature (BHST) are selected to be 65 and 90°C, respectively. The pressure is 2500 psi. These conditions are representative for most wells on the Norwegian continental shelf. The initial results include viscosity profile at BHCT, the effect of pressure on thickening time, and intensity of static fluid loss.
Our results show that the barrier materials have their pros and cons. One material might be good for an application such as a squeeze cementing job while the other one may not fit this application. The viscosity measurements showed all the candidate barrier materials to be shear-thinning to some degree. Except for the pozzolan based sealant, all other selected materials presented right angle set and pressure- dependent consistency.
Virtual Field Trips: Experience from a Global Pandemic and Beyond
Authors: Buckley Simon John , Howell John Anthony , Naumann Nicole , Pugsley Jessica , Vanbiervliet Joris , Ringdal Kari , Lewis Conor , Tong Bowei , Chmielewska Magda 
Published: April 2022

Abstract
Traditionally, field geology and the use of outcrop analogues have been crucial to aid subsurface understanding, with fieldwork and excursions playing an important role in the training and continued professional development of multidisciplinary geoscientists. The COVID-19 pandemic caused a major disruption to industry training programs and university geoscience courses as travel restrictions and lockdowns created the need for digital alternatives. Although virtual field trips (VFTs) had been gaining traction prior to the pandemic, the sudden need to replace physical field activities has driven a rising interest to allow geologists and geoscientists to keep in touch with the rocks. In this contribution we present the state of the art of virtual field trips, covering the process of conceptualizing and building a VFT, as well as delivery methods available. We argue that VFTs have an important place in geoscience education, not as a replacement for physical field trips, but as a complement to assist participants’ orientation prior to a course, retention of learning outcomes post-trip, as well as an enabler of accessible and non-discriminatory experience of field geology to a wider group of people than those conventionally given the opportunity for physical excursions.
Central to the successful creation of virtual field trips is the availability of 3D virtual outcrops and other geospatial data to populate a VFT. Databases of virtual outcrops, such as SAFARI and V3Geo, make it efficient to create a high-resolution framework for a field trip, which is then used to integrate conventional field or subsurface data. Finally, the VFT leader adds their narrative and learning process around the 3D virtual environment and delivers the content to participants. A VFT can be organized by topic (e.g. depositional environment or structural setting) rather than restricted to a limited geographical area. In addition, a VFT can be created to fit any available timescale, from a tour lasting minutes to look at a particular geological feature, through to a multi-day agenda mirroring a conventional field trip. We illustrate our contribution using example VFTs designed for different audiences and geological topics.
Effects of Well Placement on CO2 Emissions from Waterflooding Operation
Authors: Angga I. Gusti Agung Gede , Sutoyo Handita Reksi Dwitantra , Bellout Mathias , Bergmo Per Eirik Strand , Slotte Per Arne , Berg Carl Fredrik 
Published: April 2022

Abstract
Water injection provides efficient pressure support and increases oil recovery in field developments worldwide. The success of water injection comes from its cheap and simple application. However, waterflooding is an energy intensive operation. Typically, more than one third of total energy use in offshore platforms is allocated for water injection. Since many offshore platforms still rely on gas turbines as their main energy source, waterflooding thus accounts for a substantial portion of total CO2 emissions. The quantity of CO2 emitted depends on the injection strategy being adopted; both on the well placement and on the injection rates and pressures during production life. Traditional optimization of drainage strategies has given little heed to the cost of emissions. In this work this emission cost will be an integral part of the injection strategy optimization, as we will include the cost of emissions into our optimization objective.
We formulate the optimization objective (net present value) so that it incorporates the cost of CO2 emission: Our augmented objective function includes not only revenue and cost of production, but also carbon tax proportional to CO2 emitted. Moreover, we introduce a scheme for quantifying CO2 emissions corresponding to a particular injection strategy. This scheme is based on an integrated subsurface-topside model and utilizes reservoir simulation results for calculating the energy spent by the water pump and treatment systems. This energy is then used to estimate the fuel consumption for water injection and the corresponding CO2 emissions.
We conduct the optimization study using a two-dimensional numerical reservoir simulation model. In addition, we optimize over a range of CO2 tax rates and investigate how the different tax regimes affect the optimal solution and associated carbon emissions. Our results indicate that the optimal well placement is dependent on the CO2 tax rate. A higher CO2 tax rate moves the optimal injection location towards higher permeable zones. This leads to lower oil production and lower emissions. However, the relative reduction in emissions is larger than the relative reduction in oil production.
Ensuring Well Safety and Integrity Through Risk Identification, Job Planning and Gas-Tight Multistage Cementing Tools in the Norwegian Martin Linge Field
Authors: Hrabovsky Brett , Zapata-Bermudez Fernando , Karlbom Therese , Fliss Andreas 
Published: April 2022

Abstract
Despite advances in cementing technology, annulus integrity is one of the major challenges facing the industry, both in terms of frequency and impact. Using tailored solutions for cementing a well is of great importance in oil and gas wells to secure an optimal annular barrier in complex conditions when traditional techniques done with single stage cementing are not sufficient. High-performance multistage cementing solutions are used to provide flexibility to operators to solve their new challenges and go beyond the conventional cementing techniques.
Operating in the Norwegian Martin Linge field, near the border to the UK sector in the northern part of the North Sea, with a target of deep gas formations brings additional challenges. When encountering shallow oil-bearing formations that require annular production barriers in conjunction with adjacent formations that have shown a propensity for breaking down during conventional cementing, choosing a solution that maximizes annular seal integrity and overcomes the shortcomings of previous stage cementing technology is a must have.
Even if possible, through conventional single stage cementing, to mitigate losses, the length of the section still posed significant risk to meet the overall objectives. A subsequent second stage cement job allowed the operator to avoid any additional intervention work to remediate poor isolation from primary jobs allowing them to deliver the well on time and on budget.
Therefore, this paper demonstrates how through risk identification, job planning and the selection of effective gas-tight multistage stage cementing tools, the enhancement of well safety and integrity can be achieved across multiple wells to ensure barrier objectives are met and future production can be optimized.
Ram Performance and Hydraulic Modeling of Subsea Blowout Preventer Control System
Authors: Párraga Quispe José Luis , Zhu Lei , Estefen Segen F. , Lourenço de Souza Marcelo Igor 
Published: April 2022

Summary
A subsea blowout preventer (BOP) system is critical in providing safe working conditions for drilling activities in deepwater oil exploration. However, performance evaluation of the shear ram BOP is still a challenge for the industry. In this paper, two aspects of BOP shearing capability are studied: The required shear force to cut the pipe inside BOP successfully and the time it takes to shear the pipe and close the well. A finite element model is used to calculate the maximum shear force of a typical drillpipe, while an analytical hydraulic model is proposed to calculate the BOP closing time. A case study is presented for estimating the emergency disconnect sequence time in a deepwater offshore scenario. It is assumed that the BOP control system is activated from the surface, employing an electrohydraulic multiplexed control device for closing the BOP and rapidly disconnecting the lower marine riser package (LMRP), thus preventing damage to both riser and wellhead.
Observations of CO2 Corrosion-Induced Carbonate Scale Formation and Inhibition on Mild Steel
Authors: Li Wei , Dai Zhaoyi , Wang Xin , Ko Saebom , Paudyal Samiridhdi , Yao Xuanzhu , Leschied Cianna , Shen Yu-Yi , Pimentel Daniel , Kan Amy T. , Tomson Mason 
Published: April 2022

Summary
Aqueous CO2-containing environment is ubiquitous in oil and gas production. Carbonate scales (e.g., calcite) tend to form in such an environment. Meanwhile, the CO2 corrosion of mild steel infrastructure may result in corrosion-induced scales including siderite (FeCO3). Previously, siderite was generally treated as a corrosion problem rather than a scale problem. However, the relationship between the corrosion-induced scale and other metal carbonate scales on the steel surface is unclear. For example, how does siderite influence calcite deposition on the mild steel? In this study, the mild steel corrosion and mineral carbonate scaling behaviors were investigated simultaneously in the presence of various cations such as Ca2+ and Mg2+. We observed a two-layer scale structure on the mild steel surface under simulated oilfield conditions. The inner layer is an iron-containing carbonate scale such as ankerite or siderite, while the outer layer is calcite. In addition, calcite deposition at a very low saturation index was observed when the inner layer was present. Furthermore, a common scale inhibitor [diethylenetriaminepentakis(methylenephosphonic acid) or DTPMP] can effectively mitigate calcite, siderite, and ankerite formation on the steel surface, but meanwhile, aggravate the steel corrosion because of the absence of protective scale layers.