bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improving Well Production Performance By Using Realtime Wash Desalting Planning Tool WDPT in the North Sea
Authors: Octaviano Ryvo , Hornstra Erik , Poort Jonah , Shoeibi Omrani Pejman , Linden Ruud van , Slot Harmen , Dechelette Benoit 
Published: November 2020

Abstract
Due to natural depletion many mature fields are currently suffering from productivity issues due to halite precipitation in the North Sea. Main actions to prevent or solve this type of scaling issues include increasing flowing pressures (topside choking or velocity strings), but often considered easiest and most economical are fresh water washes to dissolve downhole halite deposits. The main objective of this study is to increase production by optimizing washing sequences. Having an accurate washing schedules predicted allows to anticipate on production degradation and its mitigating actions.
To predict production decline due to halite, a virtual flow meter is developed combining a well model (Vertical Lift Performance, known as VLP curve), reservoir model (Inflow Performance Relation, known as IPR curve) and a dynamic model for the extra pressure drops due to deposition. The flow is calculated including the additional pressure drop. The virtual flow meter is calibrated using the last 3-6 months of production data. The Well Desalting Planning Tool (WDPT) makes real-time estimates of short-term pressure drops for each well and finally determines a date to water wash. It shows the schedule in the Planning Dashboard of the web-based WDPT tool. The software can be used to assist the operations department in prioritizing platform visits and optimize production. WDPT is developed as part of company Digital Oil Field (DOF).
Innovation in a New Normal – How Can the Upstream Industry Develop New, Fit-for-Purpose Technology?
Authors: Clegg John 
Published: November 2020

Abstract
The upstream oil and gas industry suffered an unprecedented dual shock in 2020. Suppression of demand caused by the global Covid-19 pandemic combined with oversupply caused by competition for production market share between major suppliers across the globe. Although the world that will emerge in 2021 is hard to predict, it is very likely that it will be different from the past. It is equally likely to change much more quickly, therefore needing new ways of developing and introducing new technology-based products and services. This paper introduces the dichotomies that will emerge. In particular the industry will need to be focused in order to deliver technology on time, at the same time being flexible in response to rapid changes. It can be challenging to meet both of these apparently conflicting requirements. By exploring the principles of innovation theory from a number of perspectives, this paper offers insights and suggestions to help the industry develop the highly efficient technological solutions it will need to thrive in 2021 and beyond in the face of significant restrictions on financial and other resources. It also describes the impact of stakeholder interests, including the pressures arising from environmental, social and governance (ESG) issues, which will not go away despite the shock to the industry that 2020 brought, and suggests how these may be met while developing effective new technology. The paper uses real-world examples, including examples from other industries, to describe strategies for product and service development, and business model adjustment. It concludes with a toolbox of ideas and techniques that should be broadly applicable across the upstream industry.
Physical Performance Testing of a Prototype Gerotor Pump Operating in Liquid and Gas-Liquid Conditions
Authors: Ejim Chidirim , Xiao Jinjiang , Oshinowo Lanre 
Published: November 2020

Abstract
Gerotors are positive displacement pumps and potential artificial lift options in the oil and gas industry. This study presents the performance characteristics from physical testing of a unique one-stage, equal-walled gerotor pump design operating in oil and oil-air mixtures. The pump was tested at various rotational speeds in a flow loop. The performance results were obtained to ascertain potential design optimizations of the pump before embarking on manufacturing and testing of the field prototype pump.
A physical prototype of a one-stage 400 series gerotor pump, suitable for application in a 5.5-inch casing, was designed, manufactured, assembled, and tested. Mineral oil and air were used as the operating media. For given pump outlet valve settings, the pump rotational speeds were set to 200, 250, 300, and 350 revolutions per minute (RPM). Gas volume fractions (GVF) at the pump inlet were varied from 0% to the maximum the current pump design could handle. For each test point, the corresponding pump parameters were measured. Dimensionless performance plots were established for obtaining pump performance at other flow conditions.
The results showed that pump flow rate decreased with increasing differential pressure, typical of positive displacement pumps. At 200 and 350 RPM, maximum pump delivery is about 190 and 330 barrels per day (BPD) of oil, respectively, at zero differential pressure. The pump can supply flow against a differential pressure of up to about 5.5 psi at 200 RPM and 15 psi at 350 RPM. For the 200-350 RPM speed range, volumetric efficiencies varied from 30% to 73%, whereas the electric power input varied from 145 W to 191 W. When pumping oil-air mixtures, the current gerotor pump design can handle 15% GVF maximum, at 250, 300, and 350 RPM. For certain pump outlet pressures, the total fluid flow rates decreased as the GVF increased to 15%. The volumetric efficiencies at 15% GVF varied from 32% to 53%, for the 300 to 350 RPM speed range, whereas the motor electric power input decreased with increasing GVF up to 15%. In conclusion, increasing the pump rotational speed improves the volumetric efficiency and gas-handling capability of the gerotor pump. These observations will aid in the required design optimization to enhance the performance of the future field prototype gerotor pump.
This study presents the capabilities of gerotors as potential artificial lift alternatives to handle liquid and gas-liquid mixtures for boosting applications in oilfield operations. The technology with additional design optimization can be readily integrated into oilfield equipment architecture. The mechanical simplicity of gerotors and their compactness provides a promising artificial lift substitute that may be implemented for downhole or surface production of liquid or gas-liquid mixtures in the oil and gas industry.
Pipe Strain Effects on Pumps - Case Study
Authors: Abdulelah Abdullah , Abdullah Abdulrahman , Ioannis Ioannis 
Published: November 2020

Abstract
Striving to achieve high level of plant's reliability, and realizing the wide impact of piping misalignment on rotating equipment premature failures, Oil & Gas industry has come up with many standards and best practices aiming to eliminate or minimize to the possible extent the effects of pipe strain on rotating equipment. Pipe strain is considered as one of the most frequent reasons causing rotating equipment to fail. It occurs when there is a misalignment between the piping and the equipment's suction and/or discharge flanges. A case study of a vertical crude charge pump at Saudi Aramco plant, experiencing high vibration and repetitive mechanical seal failures due to piping misalignment and subsequent pipe strain effects will be considered in this paper, highlighting the corrective actions adopted following the relevant investigation and troubleshooting conducted by Operation, Maintenance and Engineering (OME) team. Moreover, a Finite Element Analysis (FEA) model will be presented, demonstrating the significant impact of pipe strain on the pump's shaft behaviour and the potential modes of failure in case pump-to-pipe flanges misalignments are not seriously considered.
Dealing with EPC Project Management Problems and Challenges A Case Study on Petrochemical, Oil and Gas EPC Projects in Middle-East
Authors: Akhtar Mujahid 
Published: November 2020

Abstract
Project schedule delay and cost overrun have become a normal matter to witness and at a certain point, it textures almost likely that it would be an inevitable result. Such result could be avoided if we identify the causes of delay and try to mitigate the challenges early phase in the project. An effective Project Manager manages all aspects of EPC project and he must understand the causes of problems. This case study aims to explore problems faced in EPC projects that lead to cost overrun and schedule delay, and to explore good practices to minimize impact on overall project.
The methodology adopted consists of survey, interviews and case study approach. A survey was used to collect the common causes of EPC Project delays and cost overrun. An interview approach used to find out significant delay and success factors together with effective management practices collected from survey. Later, case study approach is used to validate the information gathered previously and to understand the relation and consequences of each factor. The interviewee were project managers, project controls manager, construction manager, discipline engineers, subject matter experts and client representatives, etc. from several EPC contractors and clients.
There are several causes of EPC projects delay and cost overrun and every project may have its own challenges but many found to be common among projects. Sometimes, it may be a single trigger event that leads to delays or a combination of events. The case study reveals that major factors contributing to schedule delay and cost overrun are mostly related to project complexity, aggressive unrealistic schedule, weak or poor planning and control, inherited bidding inaccuracies and estimation mistakes, ineffective leadership and poor decision-making, absence of project management practices, etc. Also, design changes, delay in placing POs, lack of team competency, late client approvals, late vendor information, delay in PTW issuance, inadequate construction resources, quality issues and reworks, and ignoring previous project's lesson learned. Further most, poor risk management, poor interface management between project stakeholders contributes to cost overrun and delays. This case study findings may be helpful to EPC contractors, clients, project sponsors, project managers, construction managers and other stakeholders to understand the major factors, causes and problems that they may face during EPC project lifecycle and how to overcome such challenges effectively.
This case study can be viewed as a lesson learned approach. This study will guide them in developing and adopting necessary effective and efficient project management practice to complete the EPC projects within budget, on schedule with good quality, and safety. Stakeholders’ awareness about causes of delay give them more options and improve capability in problem-solving throughout the project life-cycle.
Decision Tree Regressions for Estimating Liquid Holdup in Two-Phase Gas-Liquid Flows
Authors: Almashan Meshal , Narusue Yoshiaki , Morikawa Hiroyuki 
Published: November 2020

Abstract
In producing oil and gas wells, two-phase flow of gas and liquid is inevitable. Gas density is lighter than liquid density, as a result, gas travels faster than liquid, leaving the liquid phase to build up in pipe segments. The amount of liquid occupying each pipe segment varies. This phenomenon is called liquid holdup, which is defined as the ratio of the liquid volume in a pipe element to the volume of the pipe element. Liquid holdup presents challenges in calculating mixture physical properties and two-phase flow pressure drop. Estimating liquid holdup is the first step to investigate production wells problems. Early detection and identification of liquid holdup (HL) in oil and gas wells is needed to reduce the maintenance downtime and thus increase production. This is significantly crucial in designing oil and gas facilities. Consequently, many studies on predicting liquid holdup have been carried out in the past, considering different flow conditions, resulting in a large number of empirical correlations with various degrees of accuracy.
Machine learning approaches in predicting liquid holdup in multiphase flows have been recently studied to improve the prediction accuracy compared to the existing empirical correlations. However, these approaches ignored the heuristic feature importance of the input parameters to the predicted HL values. In our study, a machine learning predictive model, boosted decision tree regression (BDTR), is trained, tested and evaluated in predicating HL in multiphase flows in oil and gas wells. Decision trees are considered as non-parametric machine learning models. The datasets used in training and testing the predictive model are experimental and they were collected from literature (111 data-points). Air-kerosene and air-water mixtures were used in obtaining the 111 experimental data-points.
Results show that, the proposed BDTR model outperforms the best empirical correlations and the fuzzy logic model used in estimating HL in gas-liquid multiphase flows. For the built model, the most important input feature in estimating HL is the superficial gas velocity (Vsg). The empirical correlations developed in the past for identifying HL in the multiphase flow phenomenon can only be applied under certain flow conditions by which they were originally developed but this machine learning model does not suffer from this limitation.
To the best of our knowledge, the present study is the first work that shows how the decision forest regression predictive models can accurately predict HL. Using the BDTR model with its interpretable representation, one can clearly determine the heuristic feature importance of the input features used in building the model. Heuristic feature importance can help in having a better insight of the issues associated with the HL studies, such as the liquid loading phenomenon.
Well Portfolio Optimization: Rapid Screening of Production Enhancement Opportunities
Authors: Sinha Rajeev Ranjan , Songchitruksa Praprut , Holy Ralf , Vadivel Karthick , Ramachandran Sreekrishnan , Martinez Henry 
Published: November 2020

Abstract

Objectives/Scope
A system providing a standardized and automated approach to rapidly screen and rank large well count assets (hundreds or thousands of wells) in a fraction of the time and repeatably, is proposed. The solution enables the proactive management of existing wells by keeping the production enhancement opportunity pipeline full and expediting potential candidates through the Opportunity maturation process (OMP) in an integrated and collaborative framework.

Methods, Procedures, Process
The solution is based on a hybrid and automated decision-support system anchored in a knowledge-based framework. Hybrid refers to the integration of (1) petroleum engineering analysis methods and best practices with (2) advanced machine learning algorithms for autonomous well performance signature identification, and (3) the operator's business logic driving the economics of the field. Automated alludes to a continuous running workflow requiring minimal interaction, utilizing machine learning approaches such as neural networks, bayesian belief network models, logistic regressions, advanced optimization, etc.

Results, Observations, Conclusions
The application of the proposed solution led to workover and intervention candidate evaluations now routinely performed on a weekly basis (compared to the previous bi-yearly approval review and approval process across almost 200 well completions, with engineers confirming and validating the system-generated opportunities before escalating them for approval. Moreover, in its early evaluation, the new system has provided 89% in time savings in both the identification and review of intervention candidates and 88% in cost savings resulting from the elimination of manually tedious and routine work.

Novel/Additive Information
Asset teams are entrusted with proposing enough well production opportunities on a regular basis. The identification of potential workover candidates remains a manual, tedious and repetitive process consuming several weeks of engineers’ time in every iteration. With the addition of the proposed solution in the existing body of literature, asset teams can proactively manage opportunities in their fields.
Geomechanical Laboratory Studies to Mitigate the Wellbore Instability Problems in Nahr Umr Shale Formation in Offshore Abu Dhabi
Authors: Shaver M. A. , Yudhia D. P. , Al Ameri S. M. , Couzigou E.. , Al Marzouqi A.. , Mahgoub F.. , Vican K.. , Koronfol S.. , Martin J. W. , Muniz E.. 
Published: November 2020

Abstract
Wellbore instability challenges encountered while drilling the Nahr Umr Shale include, but are not limited to, hole collapse leading to hole enlargement. Wellbore instability leads to huge cost increases in the drilling process and in rare cases well abandonment. Observations from drilling data suggest that wellbore stability varies with different wellbore deviations and azimuths, especially in areas of highly laminated formations and anisotropic in-situ field stresses. Accurate information on the rock strength and rock failure behavior in shale has a major impact on the improvement of drilling efficiency. Knowledge of the mechanical properties of shale is essential to implement any 3D shale anisotropy borehole instability model (Crook AJL, et. al., 2002).
Shale mechanical properties were evaluated from laboratory tests. Well-preserved core samples retrieved from the Nahr Umr Shale were put through several tests to describe the mechanical characteristics related to rock strength and in-situ stresses with the aim to determine the effect of the anisotropy and plane of weakness in drilling high-sailing angle trajectories. Strength anisotropy was assessed using the plane of weakness model (Jaeger, J.C., & Cook, N.G.W., 1979) which assumes that the heterogeneous media is composed of a matrix rock and a plane of weakness (e.g., bedding/laminations, interface between lithotypes or laminations). Shear failure occurs once the shear stress acting on the plane of weakness exceeds its shear strength. Laboratory tests include both extremely slow triaxial tests and multistress path testing performed on three orientations. Failure envelopes were created to develop the plane of weakness model to predict the orientation of the weakest plane and determine the magnitude of the strength reduction. Elastic anisotropy data from plugs is combined with advanced sonic logs, enabling a more robust evaluation of the formation anisotropy to improve both stress predictions and the allowable mud-weight windows during wellbore stability assessment.
Impact of WAX on Asphaltene Deposition under Jet Pump Operation as Revealed by Asphaltene Inhibitor Field Test
Authors: Yoshimoto Tatsuya , Kurosawa Masaharu , Fukuda Jun , Yonebayashi Hideharu , Murakami Yuji 
Published: November 2020

Abstract
In a Japanese oil field, which applying jet pump (coiled tubing running, standard flow type, produced oil as power fluid containing asphaltenes and waxes) since 2014, unstable power fluid injection pressure has been observed since 2016 due to asphaltene deposition on jet pump nozzle area, which limited power fluid rate and therefore production rate. The objective of this study was to achieve high oil production rate by overcoming the pressure fluctuation due to asphaltene deposition problems.
Asphaltene inhibitors (AI) from various suppliers were tested to measure asphaltene deposition amount as a laboratory screening. The best AI candidate was implemented in a field trial test during which, asphaltene deposition amount in strainers were measured, production oil was collected to measure asphaltene deposition rate under stock tank condition, and operation data was monitored and analyzed. To confirm the new AI efficiency, these data were compared with the ones during the original AI before starting the field test.
This paper presents specific features which were found in the field test. Selected AI was efficient at dispersing asphaltenes. It achieved stable injection pressure and reduced asphaltene deposition amount in production oil sample. However, it became worse again within one month. The main reason was that the new AI worked as dispersant to delay asphaltene deposition so that asphaltenes finally accumulated under jet pump production system which is semi-closed loop. Asphaltene deposition amount on strainers increased during winter, especially shut down periods, because process temperature was close to ambient condition. This temperature-dependent observation means asphaltene deposition was highly influenced by wax deposition. A follow-up laboratory test revealed the asphaltene deposition amount decreased by adding paraffin inhibitor (PI). This field test result revealed the asphaltene and paraffin interaction in field scale.
Design of Thermoresponsive Polymers to Selective Permeability Reduction in Porous Media
Authors: Maddinelli Giuseppe , Bartosek Martin , Carminati Stefano , Moghadasi Leili , Manfredini Nicolò , Moscatelli Davide 
Published: November 2020

Abstract
A critical issue in waterflooding operations is determined by reservoir heterogeneity, which generates preferential flow through high permeable paths limiting contact with oil bearing zones. The use of Thermoresponsive Polymers, a novel type of chemicals, has been evaluated as a method to improve the oil displacement by better addressing water flow through un-swept regions. The placement of chemicals able to impair the high permeable layers, blocking water and diverting flow to richest oil zones could improve the final oil recovery. We describe a method based on novel, water soluble polymeric materials characterized by thermoresponsive properties, inducing reversible viscosity variation. This type of temperature stimulated co-polymers are molecules subjected to a reversible transition in correspondence to a certain "lower critical solution temperature" (LCST). Below such critical temperature, the molecules are completely soluble in water (low viscosity), while in the range over the LCST, a phase transition occurs, creating a gel-like structure with a consistent increase of the solution viscosity. This phase transition could be exploited to decrease consistently the permeability of the area occupied by the fluids. These products have the potential, by proper tailoring of the chemical structure, to design the range of working temperature to match the reservoir peculiar conditions.
After a first screening of different polymer properties by bulk tests, the final performance evaluation was done by core-flooding experiments. Clashach sandstone was selected as reservoir rock analog. The injectivity performance of the polymer solution (2% w/w), was measured by differential pressure monitoring. The permeability reduction, due to transition over the critical temperature (typically, 70°C in our experiments), was evaluated by permeability to brine measurements before and after the polymer treatment. The results obtained in terms of injectivity and permeability reduction are positive and promising for a field application. The polymers studied represent a novel class of products, sensitive to temperature, suitable for conformance control application. It allows a precise tailoring of their features, i.e. the transition temperature from low to high viscosity, adjusted to the temperature and permeability of the reservoir. These parameters need to be carefully estimated, before running the treatment, through a tracer campaign and reservoir simulation.