bluuebunny/crossref_metadata_2025 huggingface dataset:
Cement Integrity Assessment Using a Hydration-Coupled Thermo-Mechanical Model
Authors: Moghadam A. , Loizzo Matteo
Published: September 2023

Portland cement is commonly used in wells to provide zonal isolation in the annulus. A damaged cement sheath can expose the casing to corrosive fluids and open a leakage pathway to shallow freshwater aquifers and atmosphere. The leakage can manifest itself as sustained casing pressure (SCP) or lead to gas accumulation in shallower formations. The impact of pressure and temperature variation on cement stress has been widely studied in the literature. However, the hydration reactions of cement are not usually included in the mechanical models. This leads to incorrect assumptions about the initial state of stress in cement immediately after curing.

In this work, we have developed a 3D well integrity model that incorporates the cement hydration process. The model is verified using laboratory experiments on cement stress evolution. The model calculates the water consumption during the hydration reactions to predict the pore pressure change in cement. The evolution of cement's mechanical properties with the hydration degree is captured using a homogenization model. A case study is designed to represent a typical low-enthalpy geothermal well in the Netherlands, using well designs and inputs from publicly available data. The cement stresses are tracked over the life of the well, to understand the magnitude of the stress cycles and to assess the potential long-term damage to the cement sheath.

The results show that the pore pressure drop due to cement hydration causes an increase in shear stress in the cement sheath. The pore pressure drop during hydration can debond the cement from the formation. The level of destressing in cement is a function of cement properties, formation stiffness, and the depth of the top of cement. When placed against softer formations, the stress drop in cement is more muted leading to a better seal. During the temperature cycles, the shear stress in cement changes in a cyclical manner. Depending on the magnitude of the stress cycles, damage can be accumulated in the cement sheath. The stress evolution in cement can also vary depending on the presence of external water (formation permeability).

The modelling technique presented in this work provides a robust methodology to estimate the magnitude of cyclical stresses in the cement sheath. This is a critical input to design cement recipes that can withstand load cycles throughout the lifetime of the well. The results of this work indicate the need to assess the integrity of cement at various depths and against various formations. It may not be possible to guarantee the seal efficiency against all formations, however risk analysis can be conducted using the presented model to assess the seal integrity of critical locations in the well profile.
Optimisation of Well Scheduling with Loading and Minimum Turn-Down Constraints
Authors: Jones Peter
Published: September 2023

Breagh, a moderately tight gas field in the Southern North Sea started production in 2013. Until compression is available, Breagh has been constrained by minimum turn-down constraints and the need to keep wells flowing above their loading rates leading to complicated well scheduling optimisation.

This paper describes a tool that makes hourly forecasts for cycling and non-cycling wells used to rapidly assess a proposed well scheduling for loading and minimum turn-down compliance.

The Breagh short term forecasting tool uses empirical equations to match historical pressures and production rates. Parameter values have been found for each of the existing nine flowing wells which match build-up pressures, predict the initial gas rate via a pseudo-PI approach and decline the gas rate over its flowing period. By matching the wells’ hourly rates over multiple months, these same parameters are then used to predict future well flows and display the results in a number of graphics for easy history matching and well scheduling assessments.

Due to the steep decline of the cycling wells, an hourly forecast was required. Excellent matches were obtained over multiple month periods. A single framework was found to be sufficient for both cycling and non-cycling wells, but with different sets of parameters: the Breagh short term forecasting tool was born and has proved to be very useful for: short term forecasting over a few months; rapid assessment of well schedules, including cases where a well issue has required a well to be closed in at short notice and alternative well schedules devised to enable uninterrupted production; and to assess the need for additional production tests to further lower minimum turn-down.

A new framework is provided for the performance forecasting of cycling gas wells, some with significant declines on an hourly basis, thus enabling rapid response times to well schedule optimisation issues. The following are the key findings:Hourly data rather than daily were required to make quality forecasts for cycling wells with extending a few months ahead.New potential well cycling schedules could be rapidly assessed, and more optimal schedules selected.The Breagh Short Term Forecasting Tool was one of three key contributors to returning Breagh from weekly cyclic to continuous production.
Flexible Pipe Riser Torsion Detection in Underwater Video Images
Authors: Cesar V. M. , Reis B. , Maia M. G. , Kelner J. , Sadok D. H. , Marinho J. M. T.
Published: September 2023

When flexible pipelines are subjected to high axial loads and exposed to a mixture of CO2 and water, their metallic armor can corrode and crack, leading to a twisting deformation that, if left untreated, may cause collapse. Monitoring the entire length of the pipeline for twisting is crucial for early detection, but manual assessment is challenging due to the subtle nature of these anomalies and the analysis of video footage might take hours. This work aims to automate the inspection of flexible pipeline twisting by proposing an algorithm that processes video data obtained from standard pipeline inspection procedures and accurately detects sections of twisted pipelines. The algorithm was validated using simulated data and successfully detected twisting of a magnitude of 3mm on a 300mm pipeline. Results on real data were shown to be consistent with experts’ opinion, however further development is required to ensure reliability in the presence of other equipment and marine life.
Acquiring Accurate Real-Time Formation Fluid Properties to Provide In-Situ Fluid Analysis While Drilling
Authors: Cartellieri Ansgar , Schapotschnikow Philipp , Weinzierl Wolfgang , Denninger Johannes , Adams Alina
Published: September 2023

The composition of natural gas and crude oils specifies their calorific and commercial value. To determine required processing steps for intermediate and end products of the reservoir fluid and to define the layout of production facilities, an accurate fluid analysis is vital. Currently, the most reliable way of acquiring fluid compositional data is provided by recovering samples from the downhole environment with dedicated fluid sampling services for surface laboratory analysis. Specialized PVT (Pressure-Volume-Temperature) laboratories provide a detailed fluid characterization using advanced techniques such as gas chromatography (GC). This procedure is very costly and time consuming. Therefore, improved measurement systems and alternative methods with lower cost are commonly requested.

One way to hasten the analysis of reservoir fluids and to lower the cost is the introduction of sampling while drilling services. Even though, these products have been commercial for nearly a decade, most sampling jobs are still conducted with wireline services after the well has been drilled, delaying the acquisition, and incurring additional rig costs. One reason that has limited the application of logging-while-drilling (LWD) fluid sampling services is the reduced data resolution in real time. Whereas wireline services are able to transmit comprehensive fluid identification data in seconds, it takes minutes for a comparable LWD service to transmit the data even in significantly reduced resolution. The wireline data transmission rate is many thousand times higher than while drilling. A wired pipe application is available that can overcome this constraint, however, at much higher cost.

For a representative fluid evaluation and the selection of the optimal fluid samples for characterization in a dedicated PVT lab, an improved prediction of the fluid properties during pump-out, especially for LWD services, is required. Considering the limited real-time bandwidth available, the evaluation must be performed downhole. Therefore, new fluid type algorithms that combine multiple sensor readings into one model have been developed and implemented in the downhole electronics to provide a more sophisticated and thus conclusive in-situ fluid analysis.

This paper will discuss and present the most recent enhancements, achieved by adding machine learning algorithms and chemometrics to LWD fluid sampling services. Models are trained on data from multiple field studies and typical deepwater applications to simplify data interpretation and sample selection, resulting in comprehensive fluid type information being available at surface for real-time decisions and accurate in-situ fluid analysis.
Reducing Weight, Footprint, and Capital Cost of Sulphate Removal Units Using Modified Membranes
Authors: Garrote R. , Banham J. , Neculau M. , Hepp R. , Chaumien E.
Published: September 2023

Membrane suppliers manufacture RO (Reverse Osmosis) and NF (Nano Filtration) in spiral wound elements, being 8" the most common element size. The spiral wound element was developed in 1970 to package RO and NF material into compact, efficient, and usable unit. Over the last decades, optimization of the manufacturing processes such as robotic glue lines and automated rolling of the elements, provided incremental improvements in the ability to pack more active membrane area in the same limited available volume defined by the length and diameter of the 8" element; but as the technology became mature, the room for further packing improvements vanished and spiral element configuration has reached an optimal plateau. Available membranes in the market have mainly been optimized up to two standard offerings: a) the higher surface of 440 ft2 per element using thinner feed spacer of 26-mil, or b) the thicker feed spacer of 34-mil having 400 ft2 per element. System designers decide on either of the optimizations depending on the feedwater and pretreatment quality, being the high surface of 440 ft2 elements reserved for "good" feedwaters. This optimal plateau drove the market at least over the last decade where all new models launched offer improvements in either rejection, permeability, fouling resistant or robustness. However, all these new products have not varied in packing density that remained unchanged.

Thanks to innovation in materials science, a new generation of RO and NF elements has been developed using unique New Thin-membrane technology. This unique technology allows for significative improvement in the packing density, offering the possibility of taking advantage of the combination of both forementioned optimizations in the same membrane element, that is the high active surface area of 440 ft2 and the 34-mil feed spacer. Alternatively, the technology allows to keep the thinner 26-mil feed spacer but boosting the active membrane area up to 510 ft2 per membrane element. This new technology has already been marketed and since 2020, several systems have been in service with the new generation elements. In this paper we discuss the advantages of using the new generation elements as experienced in the replacement of older generation elements used for Sulphate Removal in FPSOs in Brazil and other regions.
Pre-Installed Cable Protectors Will Save Time and Improve Safety While Running Completions
Authors: Bibby J , Brodie A , Fiorucci J
Published: September 2023

This paper will demonstrate the improved safety advantages, rig time savings and the associated cost reductions available by using pre-installed cable protectors during run-in-hole (RIH) operations for completions where downhole cables are at risk of damage. Pre-installed cable protectors can greatly reduce the number of personnel operating in the ‘red zone’, eliminate costly shipping logistics and reduce the amount of time needed installing cable protectors on the rig floor, thus providing safety benefits and improving RIH timing.
Acoustic Sand Detector Virtual Calibration: Methods and Validation
Authors: Barton N. , Constable K. , Nysaeter K. , Syslak H.
Published: September 2023

Acoustic Sand Detectors (ASDs) have been widely used on topsides and subsea flowlines to measure sand production for the last 25 years. Essentially, ASDs are filtered microphones, strapped onto a bend or tee, that detect ultrasonic noise generated by impacting sand.

ASDs are typically used either to detect the presence of sand or to quantify the sand rate. In the former case the well will typically be choked back when sand is present. This approach has the disadvantage that production may be curtailed even when sand production is too low to be problematic. Alternatively, the ASD could be calibrated by means of a sand injection. Once calibrated the ASD can output the sand rate in grams per second, allowing the operator to judge whether the sand rate justifies choking back the well. This strategy can significantly boost production rates. However, sand injection is not always feasible for topsides ASD installations and has never been done subsea (to our knowledge).

This paper summarises work that attempts to address this limitation. A correlation was developed that calculates ASD calibration coefficients without the requirement to perform a sand injection. It works on the assumption that sand noise increases when fluid noise increases, with additional corrections for various multiphase flow effects. The correlation was developed using historical data from laboratory tests and from offshore sand injections. It was then validated against additional historical topsides injection data from platforms in the North Sea. In this initial assessment the correlation was validated against approximately 800 data points.

One of the main potential applications of the correlation is to help estimate sand rates using data from subsea ASDs. Unfortunately, no suitable subsea data was available that could confirm the validity of the correlation, but it was shown that ASDs respond differently when installed subsea. Subsequently, laboratory flow loop testing was performed with ASDs installed on a pipe submerged in a pool. This confirmed that the correlation has a similar accuracy for both topsides and subsea ASD installations. The correlation is currently being trialed by an operator with a view to using it as a tool within their overall sand management strategy.

ASDs are widely installed, but their output is often poorly understood or misused. This paper outlines the correlation methodology and identifies the possibilities and limitations of other approaches. The validation and testing exercises also flag a range of other issues when using ASDs; the effects of poor installation; how subsea acoustic attenuation affects ASDs; and important considerations when performing sand injection calibrations.
Mechanical Umbilical-Less Installation of Tubing Hangers
Authors: Hansen F. N. , Saelen C.
Published: September 2023

Operators with subsea developments on the Norwegian Continental Shelf have the last 20 years aimed for better efficiency and reduce equipment and personnel needed on the rigs in relations with subsea completions. Drivers have been reducing HSE risk, reduce need for modifications on the rigs to accommodate for subsea related equipment such as reels and workover control systems, and reduce cost, rig time and emissions. Many measures have been implemented such as removing need for landing string and wireline operations with deep-set pump-open or disappearing barrier plugs, installing Intervention and Workover Control system (IWOCS) to operate all systems suppliers’ tools from same unit, use of ROV Workover Control System (RWOCS) subsea HPUs to control the Xmas Tree (XT) to remove the tree running tool (TRT) umbilical, developing a hydraulic-electric remote operated control system communicating on wired drill pipe to the tubing hanger running tool (THRT) to remove the need for THRT umbilical and IWOCS, to mention some.

This paper describes one of the last inventions; a mechanical tool for installation of tubing hangers (TH) that also removes the need for remote communication and hence dramatically reduces complexity and potential for faults. The mechanical tubing hanger running tool is called THRUT and has been developed by CCB Subsea in cooperation with Equinor. First umbilical-less subsea completion ever run with a THRUT was successfully conducted on the Equinor's Heidrun field on well E-2 from the Transocean Encourage drilling rig in March 2022. Following the first well, the THRUT has been run on 8 more wells for Equinor and 3 wells for Norske Shell. The tool concept is accommodated to interface to any kind of subsea horizontal XT (HXT) systems delivered by either Aker Solutions, TechnipFMC, OneSubsea, BakerHughes, or other system suppliers. And also, the tool is operated offshore by the subsea system supplier in charge of the subsea completion, no extra personnel from CCB Subsea is required offshore. Result is an efficient and robust tool with profile of low risk, low cost and less personnel needed.

The paper describes the philosophy and requirements for the system design, the device functioning, and method for mechanical umbilical-less installation of TH in subsea HXTs, and also summarizes the most important results and operational experiences with regards to the advantages related to HSE, time, cost, personnel need, logistics and rig interface.
Biocatalysis Approach for Affordable and Sustainable Green Hydrogen Production
Authors: Laddha Chetan
Published: September 2023

Green Hydrogen is widely acknowledged as one of the important pillars for decarbonisation of hard-to-abate sectors and to transition the global economy to Net Zero. The current priority in the energy sector is to rapidly establish and scale a green Hydrogen based energy value chain that meets three core objectives: affordability, sustainability and security of supply, also referred to as ‘Energy Trinity’. Green hydrogen is produced from electrolysis of fresh water through technologies such as alkaline electrolyser, PEM (proton exchange membrane), and SOEC (solid oxide electrolyser). The production of green hydrogen from water is an energy intensive process, due to the high thermodynamic stability of water molecules. The cost of producing green hydrogen at scale is large proportional to the cost of renewable electricity. This requires green hydrogen production basins to be located close to regions/ geographies with access to surplus and low-cost renewable electricity, such as Australia, Middle East, Norway, Scotland and Chile.

The current cost of green hydrogen in the UK has a 5-10 times cost premium as compared to fossil fuels.

The primary inputs from green hydrogen production through electrolysis technologies are renewable electricity and freshwater. There has been an increasing concern globally on the availability and preservation of water resources. There are publications from water companies in the UK citing that the supply of constant fresh water supply for industrial applications such as green hydrogen production cannot be guaranteed under rapidly changing scenarios of climate change. There is a potential to set up large scale desalination plants to meet the fresh water for hydrogen production, however the large quantities of discharge water with high brine concentration might pose environmental hazards to marine habitat.

This calls for alternate technologies to be developed which addresses the freshwater dependence for green hydrogen production and the significant green premium on cost structure.

The paper describes a novel biocatalysis approach for production of green Hydrogen from wastewater, without requiring electricity input.
LOHC Business Models in Real-Life Trials – Reducing Cost and Risk in a North Sea Context, in Particular Through Repurposing Existing Infrastructure
Authors: Gilmore K. A. , Iliffe M. E.
Published: September 2023

The need for deep decarbonization has never been more evident or urgent than right now. The world is far off the Paris Agreement's commitment to limit global warming to well below 2 degrees Celsius. Countries representing more than 70% of global GDP have committed to reaching net zero, and there is increasingly consensus that hydrogen will play an important role in the decarbonisation of multiple sectors, including heavy goods vehicles, industrial feedstocks and high-grade industrial heating – applications for which there is no other decarbonization solution at present. There are also opportunities to use hydrogen to balance electrical energy systems, and to transport energy globally in a way that is not currently possible with electricity. Given these high potential applications, hydrogen is estimated to provide between 12-22% of the world's final energy demand by 2050.

However, there are significant commercial gaps currently in the hydrogen value chain, in particular the lack of a solution for large scale storage and transport of hydrogen. Hydrogen as an energy carrier has a relatively low volumetric energy density. A solution for transporting hydrogen at scale between global low-cost production and demand centers is therefore needed.

The growing hydrogen economy represents a major opportunity for energy producers - many of whom have existing skills and infrastructure which can be repurposed for this sector.
Lessons for Successful Digital Twin Implementation in Operations
Authors: Kennedy R.
Published: September 2023

With significant excitement about digital twins in industry, there is often far too much emphasis put on the technology – overlooking the fact that it is just one ingredient in a successful digital transformation. This paper will present an approach to planning, implementing, and sustaining operational digital twins, that is designed to maximise the asset owner's return on investment by putting the necessary focus on the people, process, and data elements, as well as addressing the technology.

A review of project lessons and industry findings will be presented to outline common challenges experienced during digital twin projects. Based on this, a structured digital twin methodology for operating assets has been designed to help address and overcome these challenges. The approach will enable asset owners to take a more holistic view of digital transformation using digital twins, enabling them to maximise the return on existing investments and drive lasting change – and value – through their asset operations. The digital twin methodology is delivered in three stages: advisory, implementation and value realisation.

During the advisory phase, the vision, business outcomes, objectives and value drivers are defined. Working closely with operations teams, use cases for the digital twin are identified, screened, and grouped to form strategic initiatives. Initiatives are then developed to define the required investment and forecast return, before being prioritised and sequenced on a strategic roadmap.

The implementation phase is performed using an agile, value-driven, and user-centric approach, which utilises a design-thinking process. Through each step, the people, process, technology, and data aspects are specifically considered and evaluated.

During the value realisation phase the technology, data and associated business processes are maintained, and users are engaged to guide continuous improvement and future use case development. The ongoing benefits are tracked to support continued investment.

Two detailed case studies will be presented to illustrate the digital twin methodology in practice, detailing the challenges faced, and the outcomes achieved.
Developing a Strategy for Site-Level Methane Emissions Monitoring to Meet OGMP2.0 Level 5: A Case Study
Authors: Heggo D. , Balcombe P.
Published: September 2023

The voluntary Oil and Gas Methane Partnership (OGMP) 2.0 framework requires companies to improve their methane measurements and reconcile between source-level (bottom-up) monitoring and site-level (top-down) measurement campaigns. This study presents an analysis to develop a multi-site strategy for meeting level 5 OGMP2.0 standards. The framework involves a series of site assessments based on the available bottom-up emissions estimates, local weather data that impact measurement conditions, and emissions dispersion modelling. To demonstrate the developed framework, two site-level methane monitoring techniques (drone A and B) were selected for analysis of suitability on 6 gas assets, both offshore and onshore.

Firstly, bottom-up emissions estimates are collected for each site and assessed for data quality. The distribution of emissions for each source is used to develop a Monte Carlo simulation that analyses the benefit of conducting increased numbers of site-level measurements for reconciliation.

Weather has a critical bearing upon the capacity to conduct many top-down measurements. High-resolution weather data was synthesized for each region to determine the likelihood of a successful site-level drone measurement on each day during the year-long study period. A dispersion model derived using computational fluid dynamics was used to integrate bottom-up and weather data to shed light on potential estimation uncertainties from conducting site-level measurements across different days in the year. The results show that weather plays a very important part in predicting the success of a measurement campaign and the technique selection, with some sites having particularly restrictive rain and wind patterns. Sites with lower emission rates and high winds will not suit a site-level technique that monitors at distances of >250m. The quality of the bottom-up emissions estimations is also a vital parameter in decision making and data analysis: where the time resolution of source data is poor, it is not recommended to conduct several site-level studies as there is little potential for reconciliation.
Impact of Environmental Conditions on Safe Depressurisation of CO2 Pipelines: A Discussion on Design and Feasibility
Authors: McKay C. , Stokes S. , Shirani F.
Published: September 2023

Designing pipelines for CO2 transport comes with unique challenges when compared to conventional oil and gas transportation systems. One of which is the proximity of the CO2-rich fluid phase boundary to typical operating conditions. There are also significant risks specific to non-routine, planned operations which cross this phase boundary - such as depressurisation. This paper discusses how changes in environmental conditions can impact the safe depressurisation of CO2 pipelines.

During depressurisation of a CO2 pipeline, cold temperatures are a risk due to the high Joule Thomson (JT) coefficient of CO2-rich gas. When the contents of the pipeline transition from dense to gas phase, heat will also be absorbed from the system's surroundings to supply the latent heat of vaporisation. The combination of these factors means that the surrounding ambient conditions can greatly impact the requirements for safe depressurisation. To investigate this impact, the depressurisation of three representative CO2 pipelines have been investigated using thermohydraulic modelling software, considering varying ambient conditions from Wood's project experience.

The results show that factors such as ambient temperatures, wind velocities/seabed current, and the thermal conductivity of the surrounding soil have a first order impact on the minimum temperatures expected during depressurisation. The properties of the soil, such as dryness and composition - rarely the focus of detailed environmental analysis - are noted to have a particularly high impact on the minimum temperatures expected. Depending on the minimum wall design temperatures and pipeline length, this can result in significant minimum durations required to safely depressurise CO2 pipelines. It should be noted that a reasonable and economical approach for depressurisation is to assume a constant heat flux. Such an assumption provides an order of magnitude estimate as a screening procedure to determine if a more detailed survey is needed. However, in reality, the depressurisation event would cause the temperature of the soil to drop, which impacts the heat transfer from soil to pipeline. This will be discussed on a high level, with reference made to the finite element method adopted by some industry leading software packages.

The case studies shown provide an understanding of how forecast conditions during these operations can determine system design margins and increase operational risks in very different ways depending on the installed pipeline environment. The outcome is an increased awareness on the importance of early project phase CO2 transport insights for transport assurance and asset integrity, and an appreciation of current best practice for CO2 pipeline modelling.
Hydrogen Storage in Depleted Gas Fields: A North Sea Case Study
Authors: Looijer M. , Ahmad I. , Kathel P. , Filomena C. , de Borst K.
Published: September 2023

This paper presents a case study on a near-shore gas field in the Dutch North Sea for a seasonal storage scenario. A subsea development was considered, connected by pipeline to an onshore processing facility. Reservoir simulations were carried out to model the mixing of the hydrogen with the in-situ natural gas and to estimate the composition of the back-produced stream and its variation during and between the individual cycles. The required sizing of the processing facilities was determined through process models, and the pipeline sizing through a hydraulic assessment. The development considered new wells, which were designed to deliver the assumed hydrogen production rate at the end of a production cycle when contamination is highest. The investment and operational costs of the complete facility were estimated as well as emissions of the storage operations.

The study enhanced the understanding of the technical scope and technology gaps; as well as the economic, environmental, and energy performance of underground hydrogen storage. It highlights main cost drivers and delivers insights into the re-purposing potential of the existing infrastructure. An example insight gained from the study was that the disposal (or utilization) of the waste stream from gas separation could pose a real challenge particularly in an offshore environment, given its intermittent character, the highly variable and partly unpredictable composition, its large flow rate, and its near-atmospheric pressure when using a Pressure Swing Adsorber for separation.
Selection of CO2 Mixture Composition for Flow Assurance Analysis
Authors: Pierre B. , Wright D.
Published: September 2023

Transported and geologically stored CO2 contains several impurities that depend on its source and associated capture technology. Impurities in anthropogenic CO2 can have damaging impacts on the different elements of a CCS system, which must be considered when developing a CO2 specification (Table 1). Thus, characterising all the impurities and determining the required purity of the CO2 mixture is critically important for the safe design and operation of CCS transport and storage systems.

It is important to note that CO2 specifications relate to normal operations. Short-term excursions outside of the recommended maximum concentrations for each impurity may be permissible provided they do not lead to health and safety risks and / or risks to the mechanical integrity of the asset.
Creating New Economic Reserves Using Enhanced Oil Recovery Within a Mature Offshore Field
Authors: Johnson G. , Neal A. , Lugo N. , Farthing D , Fordham A.
Published: September 2023

The offshore Captain Field was discovered in 1977 in the UK sector of the North Sea, it was brought online in 1997 and initially developed using field-wide waterflood using long horizontal wells and artificial lift with produced water re-injection. The reservoirs are large and homogeneous sandstone reservoirs with high porosity and permeability, and around one billion barrels of medium to high viscosity oil at 18-21° API gravity. figure 1 (a) below shows the Captain offshore facilities, with the Wellhead Protection Platform (WPP) and the Bridge-Linked Platform (BLP). The map figure 1 (b) below shows the UK sector of the North Sea, with the Captain location highlighted.
The Use of VR Technology for MAH Awareness Training
Authors: Luoma Christine , Wardrope Martin
Published: September 2023

This paper aims to demonstrate how Virtual Reality (VR), a technology that gives the user an immersive 3D experience, is being used successfully as part of major accident hazard (MAH) awareness training and how this has been sustained to provide an innovative, powerful method of ongoing workforce engagement.

In the VR scenarios designed by DNV, the user carries out a typical operational task, but an error then leads to a loss of containment and fire, or explosion. The realism of the scenario creates a memorable experience and helps users remember key safety messages from the VR and the training programme they are embedded in. The immersive learning environment, which is engaging and fun, has proved to be a highly effective method of learning. Direct learning points include hazards and SECEs that are specific to each scenario, risk assessments and incorporation of the IOGP process safety fundamentals and lifesaving rules, but the discussions that can be had around the VR have proven to be equally valuable.

Like the majority of the 10 operators currently using the MAH VR, Harbour Energy have tailored their MAH awareness training around the virtual reality, which has played a critical role in engaging the workforce and facilitating training around the consequences if mistakes are made. The result of the VR technique and planned deployment by Harbour has been further improvement in MAH engagement across the whole company. In a clear demonstration of this success, Harbour Energy have recently won the IChemE Training and Development Award in 2022 for Fostering Process Safety Culture Through Innovation, for their VR programme.

The use of VR is a novel method for MAH awareness training, which gives the industry a new approach to this. Harbour's application has shown how to keep this live and engaging over a number of years. It is a safe, cost effective and interactive method that could revolutionise training. In collaboration with Harbour Energy and other Operators, DNV are looking for even more novel ways to develop and use the VR technology.
More than just Rules! Safety as a Universal Language- Transition to Industry Life-Saving Rules Embedding Human Performance in Practice
Authors: Abbasi Shariq , Hobbs Marie , Yildiz Gokhan , Bryden Robin
Published: September 2023

Goal Zero underpins Shell's strategic ambitions and Life-Saving Rules are a proven enabler in achieving Goal Zero. Shell has embraced the opportunity of transitioning from twelve Shell Life-Saving Rules to nine industry Life-Saving Rules (IOGP) in pursuit of eliminating Serious Injuries, Illness and Fatalities (SIFs). This is not just a simple switch from one set of Rules to another. It is part of a multi-year journey to strengthen the mindset and behaviours of ‘Who we are’ in Shell and deepen our commitment to Human Performance. This paper explains the context of the Life-Saving Rules, why Shell decided to transition, an overview of how we managed this large-scale change, and the impact so far and remaining dilemmas in the journey.

Since Shell introduced 12 Life Saving Rules in 2009, the Rules have helped to save many lives and prevent life altering events. Shell decided to transition to industry nine Life-Saving Rules across whole company due mainly to a) inclusion of Line of Fire Rule; b) strong desire to standardise based on the pull from our major suppliers; c) rolling out ‘I-statements’ instead of ‘dos & don'ts’.

Preparations for the transition began in early 2020 for a global launch on Safety Day 2021 (an annual dedicated engagement session with all staff and contractors about safety led by leaders across Shell). The "I statement’ language of the new Rules empowers individuals to figure out with their peers how to comply and encourages peer-to-peer intervention to enable compliance throughout the work task. This means the Rules are more than just Rules; they help create the environment in which people feel safe and responsible to speak up triggering conversations about what can make compliance difficult, resolving any dilemmas before work starts.

When failures do occur, how leaders respond matters. Leaders must engage to understand how context drove behaviour and encourage people to speak up with their improvement ideas. People are the key to solutions, when leaders respond productively the whole system is improved and learnings reach those at the point of risk. In Shell we now call this Fair Event Handling.

After a successful launch of the industry Life-Saving Rules on Safety Day, we recognise there is still a long learning journey ahead. We share the content of the paper as a means to encourage further sharing as we all strive to overcome dilemmas in what makes work difficult and together make compliance easier.
Decarbonisation on the UKCS a Comparative Study of Electrification Options West of Shetland
Authors: Milne A , Dodd M , Joyce A
Published: September 2023

Meeting the Paris Agreement targets and rapidly transitioning towards renewable energy are critical. Despite significant renewable energy growth, projections indicate fossil fuels will meet almost half the UK's energy demand by 2050. The oil and gas industry is facing increasing decarbonization mandates due to environmental concerns and the need for a sustainable energy future. However, the UK is unlikely to completely achieve its Nationally Determined Contribution (NDC) target.

Offshore oil and gas industry emissions are primarily due to energy-intensive processes that could be significantly reduced by shifting towards more sustainable practices and electrifying these processes. The West of Shetland region holds strategic significance in energy security, economic contributions, and potential for further exploration.

The rapidly evolving offshore wind power sector and technological innovations in this field present a promising path towards a sustainable energy future. However, the electrification of oil and gas assets in the West of Shetland area will encounter challenges relating to grid connectivity, wind intermittency, environmental impact, and potential large-scale wind power generation elsewhere in the UK.

Three key network design options are suggested for supplying required offshore electricity: a coordinated approach, an individual approach, and a local supply approach. There are three key groupings in the West of Shetland region: the Clair grouping, Schiehallion-Lancaster-Solan, and Rosebank-Cambo. Each has potential for electrification, but also unique challenges to be addressed.

The adoption of renewable energy and energy storage technologies for oil and gas facilities in the West of Shetland area involves a variety of factors. Initial costs can be substantial, especially offshore, but these could be offset in the future due to tightening emissions regulations and carbon pricing. Older assets nearing their end of life may not be worth electrifying. Overcoming these challenges necessitates a collaborative strategy among industry players, the government, and regulators. Norway is leading in electrification, while the UK North Sea is moving much more slowly. A coherent energy policy for the West of Shetland area addressing oil and gas developments alongside renewable energy developments appears essential.
The Impact of Dynamic Wettability Alteration and Phase Behavior on the VES Flooding Recovery at the Pore-Scale
Authors: Ahmed M. Elmuzafar , Sultan Abdullah S.
Published: September 2023

Wettability plays a crucial role in the recovery of hydrocarbons as it governs the adhesive forces between oil and rock samples, directly influencing the efficiency of the displacement process. Numerous research efforts have focused on modifying rock wettability to a more favorable state. Typically, the contact angle measurement with smoothed rock discs has been employed, but this experimental design has limitations in reflecting reality since the wettability effect occurs within the pores. The coverage area of a single drop is substantial, encompassing a wide range of pore and grain spaces, introducing uncertainties regarding the validity of the measurement. In this study, we delve into the pore-scale level to observe the actual process of contact angle alteration during flooding, utilizing microfluidic technology. Three different concentrations of Viscoelastic Surfactant (VES)—specifically, 0.5%, 0.75%, and 1.25% vol%, prepared using 57K ppm synthetic seawater—were employed. The microfluidic model initially underwent saturation with formation water and was subsequently displaced by oil to establish the initial oil saturation. The microfluidic setup encompassed a precise pump for flood control and a high-speed microscope to capture images, which would later be analyzed using image processing software to obtain the real contact angle. To ensure the reliability of our data, we divided the pore space into twenty divisions and measured the contact angle through image analysis. The contact angle was measured at various injection stages to observe the dynamic changes from the initial state to the final state and the resulting recovery from each fluid system. Additionally, we analyzed the in-situ generated emulsion to establish a link between phase behavior, wettability alteration, and recovery. The results demonstrated that using 0.5% VES altered the wettability from slightly oil-wet to slightly water-wet, resulting in a 55% recovery of the original oil in place (OOIP). Conversely, employing 1.25% VES did not significantly alter the wettability but yielded a recovery of 52% OOIP. The 0.75% VES altered the wettability from slightly oil-wet to extremely water-wet; however, this alteration did not translate into higher recovery. Instead, a water breakthrough was observed, which diminished the sweep efficiency, resulting in a recovery of 47%. This pore-scale investigation successfully demonstrated the effectiveness of utilizing VES solutions to modify rock wettability and enhance oil recovery.
Remote Monitoring and Separation of Unmanned Solids Producing Assets to Improve Oil and Gas Production
Authors: Nilsson O. , Taylor S. , Greenland S.
Published: September 2023

Energy companies need access to reliable and continuous sand production information to improve their understanding of sand-producing wells. Removing sand directly downstream of the wellhead while also monitoring the separated sand in real-time enables quantified sand data to be transformed into valuable insights on the well production and provides an understanding of reservoir behaviour. With the increase in the deployment of Normally Unmanned Installation (NUI) and satellite platforms by energy companies, it is becoming increasingly important to have remotely operated systems that traditionally have been manually operated.

This paper introduces a system for optimizing production through remote monitoring and quantifying offshore sand production in an "industry-first" case study. The operation was conducted in 2022 on a NUI in the North Sea. The asset was anticipated to produce more than 4 000kg of clay/proppant mix solids with the potential for producing Benzene and Naturally Occurring Radioactive Material (NORM). Typically, wells producing solids are kept closed in, but in this case, a desander with a closed-loop system was utilized to enable production and avoid personnel exposure. Project results included stable production, remote monitoring of sand production, POB (Personnel On Board) and emissions reduction compared to a conventional operation while preserving the operator's process safety requirements.

With continuous measurement and solids removal, the operator could continue operations without personnel onboard. The desander provided data directly to production engineers. It gave them access to information that enabled fact-based decisions, ensuring a holistic methodology for production and integrity for the asset without needing personnel offshore.

New ground breaking technology is shared in this paper to help more energy operators manage sand-producing wells. With the increased focus on POB, remote solutions are part of the solution. This paper shares a project with documented success.
Wireline Formation Tester Multi-Probe and Packer-Probe Pressure Transient Tests in Dry Gas Reservoirs
Authors: Alan Cihan
Published: September 2023

Most of interpretation and analysis procedures developed for pressure transients acquired by multi-probe and packer-probe wireline formation testers (WFTs) are used to conduct are based on the slightly compressible fluid of constant viscosity and compressibility. Hence, these interpretation and analysis procedures apply for oil and water bearing formations. There is a concern that the interpretation/analysis methods based on the assumption of slightly compressible fluid may not be applicable in the case of testing a single-layer or a multi-layer gas zone(s) with the effects of nonlinear gas properties including non-Darcy flow for multi-probe or packer-probe wireline formation testers. In the literature, to the best of our knowledge, there is no a comprehensive study investigating the validity of the above stated assumption for the interpretation of WFT pressure transient data in gas zones.

In this work, variety of cases considered for investigating the effect (or sensitivity) of non-linear gas flow on the pressure transients from multi-probe and packer-probe wireline formation testers (WFTs). These effects include gas gravity, variation of gas viscosity and compressibility with pressure, non-Darcy flow, position of active (flowing) and observation probes, mechanical skin and radius of skin (or invaded) zone, and reservoir heterogeneity in the vertical direction. A three-dimensional r-θ-z single-phase-gas fully-implicit finite-difference model for a limited-entry vertical well has been developed for the purpose of this investigation. The results show that for multi-probe wireline testers, the sink (or the flowing) and horizontal probe pressure responses are highly affected by the effects of the non-Darcy flow and invaded zone, while the vertical probe pressures are mainly influenced by the properties of the uninvaded zones with non significant non-Darcy flow effect. For packer-probe testers, similar results are obtained. Both synthetic cases are presented to confirm the theory and procedures developed in this work.