bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimising Oil Field Net Present Value with Produced Water Salinities and Tracers
Authors: Daramola Babalola 
Published: June 2021

Abstract
This paper presents case studies of how produced water salinity data was used to transform the performance of two oil producing fields in Nigeria. Produced water salinity data was used to improve Field B’s reservoir simulation history match, generate infill drilling targets, and reinstate Field C’s oil production.
A reservoir simulation study was unable to history match the water cut in 3 production wells in Field B. Water salinity data enabled the asset team to estimate the arrival time of injected sea water at each production well in oil field B. This improved the reservoir simulation history match, increased model confidence, and validated the simulation model for the placement of infill drilling targets. The asset team also gained additional insight on the existing water flood performance, transformed the water flooding strategy, and added 9.6 MMSTB oil reserves.
The asset team at Field C was unable to recover oil production from a well after it died suddenly. The team evaluated water salinity data, which suggested scale build up in the well, and completed a bottom-hole camera survey to prove the diagnosis. This justified a scale clean-out workover, and added 5000 barrels per day of oil production. A case study of how injection tracer data was used to characterise a water injection short circuit in Field D is also presented.
Methods of using produced water salinity and injection tracer data to manage base production and add significant value to petroleum fields are presented. Produced water salinity and injection tracer data also simplify water injection connectivity evaluations, and can be used to justify test pipeline and test separator installation for data acquisition.
An Independent Analysis of the Performance Characteristics and Economic Outcomes of the Liza Phase 1 Development Offshore Guyana Using Public Domain Data
Authors: Paul Simon , Dyall Kadija , Gabriel Quinn 
Published: June 2021

Abstract
An attempt was made to independently verify the proposed performance of the Liza 1 field using only data available in the public domain. The data used in modelling was sourced from news reports, company disclosures and the analogue Jubilee field in Ghana. Reservoir rock and fluid data from Jubilee Field was deemed an appropriate fit because of the corroboration provided by the Atlantic Drift Theory.
A major challenge in creating the model, was determining the aerial extent of the field. According to Yang and Escalona (2011), the subsurface can be reasonably approximated using the surface topography which is possible via the use of GIS software. Google Earth Pro software was used to estimate the coordinates and areal extent of the Liza 1 reservoir. A scaled image of the field location showing the Guyana coastline was re-sized to fit the coastline in Google Pro and then the coordinates for the Liza field and wildcat well locations were estimated. This was used to create the isopach map and set reservoir boundaries to create the static and dynamic models in Schlumberger's Petrel E & P Software Platform (2017) and Computer Modelling Group IMEX Black Oil and Unconventional Simulator CMG IMEX (2016).
The initialized model investigated the reservoir performance with and without pressure maintenance over a twenty (20) year period. The original oil in place (OOIP) estimated by the model was 7% larger than the OOIP estimated by ExxonMobil for Liza field. The model produced 35% of the OOIP compared to 50% of OOIP as forecasted by the operators. (See Table 1). The factors that strongly influenced this outcome were, the well positioning and the water injection rates. A significant percentage of the oil remained unproduced in the lower layers of the model after the 20-year period. Time did not permit further modelling to improve the performance of the model.
Table 1 Comparison of The Created Model and ExxonMobil's Proposal for Liza. Property ExxonMobil's statement on Liza field Modelled field Result Original Oil in Place (MMbbl) 896 967 Oil Recovery Factor (%) 50 35
Gas production from the model would be used as gas injection from three injector wells and as fuel for the proposed 200 MW power plant for Guyana. Even so, significant volumes of natural gas remained unallocated and subsequently a valuable resource may have to be flared.
Improving Production Forecasting in a Mature Onshore Oilfield Brownfield in Southern Trinidad by Making Use of Software Modeling
Authors: Paul Simon , Dukhoo Gerard , Phillip Murchison , Persadsingh Jediael 
Published: June 2021

Abstract
In Trinidad's mature onshore oilfields, operators have traditionally forecasted the initial production rates back calculated from decline models. These rates, then reduced annually by a predetermined decline model has been used to evaluate financial feasibility. This method does not make use of the reservoir pressure. This paper demonstrates how software modelling, utilizing the reservoir pressure can reasonably forecast the performance of low rate oil producers and alert the operator of the need for artificial lift from the inception of the production cycle.
The objectives of the project were to determine remaining recoverable reserves, evaluate the potential for redevelopment (workovers and infill drilling) and to demonstrate that software modeling can be used to forecast production for an oil reservoir in a mature onshore oilfield in Southern Trinidad. Petroleum Experts Integrated Production Modeling (IPM) software suite was used for building all models. A comparison of the production forecasted by software modelling and the traditional method of forecasting initial production rates by back calculating from decline models was also undertaken.
Using the available data and net oilsand maps, the fault block bulk volumes, oil in place and the remaining reserves were determined. These results were then used to identify fault blocks with potential workover well candidates and infill well locations. Research of well files and well logs were used in evaluating zones for potential recompletions, reperforation or perforation of additional footage for production. Forecasting and comparison of the initial production rates and ultimate cumulative production for the proposed infill wells and recompletions using the traditional IP/Decline model method and computer modeling was then performed.
Form the data available, it was determined there were four blocks with remaining reserves that could be successfully recovered. The recovery methods proposed included the workover of two existing wells and drilling of two infill wells. Initial production rates and ultimate production volumes obtained by modeling of workover and new well performance had reasonably close agreement with those obtained by the traditional IP/Decline models. The results of the modeling, however indicated that all the wells required the use of pumping mechanisms (sucker rod/beam pumps) to sustain production over a ten-year period. The need for this important production mechanism would not have been realized from the IP/Decline method. An important distinction is that the modelling makes direct use of the reservoir pressure, whereas the IP/Decline model does not.
New Technology Allows for Hands-Off Intervention During Cementing Operations Increasing Safety and Operational Efficiency
Authors: Ramon Michael , Wooley Tony , Martens Kyle , Farrar Amy , Fadaol Seth 
Published: June 2021

Abstract
The culture of safety within the oil and gas industry has undergone an evolution since the advent of significant E&P operations in the late 1800s. The initial focus on safety was to protect property, not people. This mentality has shifted over time to include a greater focus on the safety of personnel, in parallel with technology developments that have pushed the limits of operators’ and service providers’ abilities to drill and complete more complicated wells. The safety efforts introduced to date have yielded results in every major HS&E category; however, falls and dropped objects continue to be areas in need of improvement.
During cementing rig up and operations there are still many manual activities that require working at heights in the derrick. New technological advances have allowed the industry to reduce the number of hands-on activities on the rig and operators have moved to eliminate these activities by automating operations. Man lifting operations are recognized as a high-risk activity and, as such, many rigs require special permitting. During cementing operations, not only are personnel lifted into hazardous positions, but they are usually equipped with potential dropped objects. Some of these objects, if dropped, reach an impact force that could seriously injure or, in worst cases, result in a fatality. During these operations, personnel are also hoisted along with a heavy cement line in very close proximity. This introduces other dangers such as tangling, pinch points, and blunt force trauma. These risks are heavily increased when working in adverse conditions, such as high winds or rough seas. By utilizing a wireless cement line make up device, along with wireless features on a cement head to release the darts/plugs/balls and operate the isolation valves, an operator can eliminate the need for hands-on intervention.
This paper will discuss current cement head technologies available to the operator that allow them to improve safety and efficiencies in operational rig time. Three field studies will be presented that detail running cement jobs with all functions related to the wireless attributes of the cement head. The field studies will present the operational efficiencies achieved by utilizing the wireless features compared to the standard manual method.
Before the recent introduction of a wireless cementing line make-up device, a wireless cement head still required hands-on intervention to rig up the tools, putting people in high-risk situations.
An Assessment of and Proposed Updates to the National Oil Spill Contingency Plan of Trinidad and Tobago Based on the Readiness Evaluation Tool for Oil Spills
Authors: Rudder Marc , Barzey Derval , Ramlal Amy , Gopie Shaleni , Alfred Ronald 
Published: June 2021

Abstract
The Ministry of Energy and Energy Industries assessed the National Oil Spill Contingency Plan of Trinidad and Tobago (NOSCP, 2013) for its effectiveness as a preparedness and response mechanism. Using the Readiness Evaluation Tool for Oil Spills (RETOS™), the NOSCP attained a score of 42% in the Level A Assessment. Gaps were identified in areas including National Legislation, Risk Management, Logistics, Training and Exercises, and Operational Response. Further, lessons learned from past spills were examined to highlight deficiencies in oil spill response (OSR) planning and readiness. Proposed updates to the NOSCP include: designation of appropriate Lead Agency depending on the nature of the spill scenario, mandating Oil Spill Risk Assessments, and the use of SIMA as a decision-making tool for oil spill response; development of comprehensive guidelines for Dispersant Use, Oiled Wildlife Response and Oil Spill Waste Management. The NOSCP is being re-designed to facilitate a national response management system that meets best management practice for oil spill contingency planning. This will enable the efficient and effective deployment of the appropriate resources (equipment, expertise and oversight) to mitigate impacts to human health and the environment, and minimize production down time and socio-economic costs.
Development Features of Cold Production with Horizontal Wells in a Foamy Extra-Heavy Oil Reservoir
Authors: Yang Zhaopeng , Li Xingmin , Xu Xinxia , Shen Yang , Shi Xiaoxing 
Published: June 2021

Abstract
The block M as a foamy extra-heavy oil field in the Carabobo Area, the eastern Orinoco Belt, has been exploited by foamy oil cold production utilizing horizontal wells. The early producing area of block M has been put into production more than 10 years. And the development features of cold production in foamy extra-heavy oil reservoirs are different from the conventional oil field. It is necessary to investigate the development features of this kind reservoir and analyze its influence factors.
Combining the production data with the reservoir geological characteristics of the research area, the cold production features of foamy extra-heavy oil using horizontal wells are analyzed. Then numerical simulations were adopted to study the influence factors of cold production performance.
In the early stage of cold production, the oil production rate is high and the producing GOR is low. With the process of cold production, the reservoir pressure decreases gradually, the producing GOR increases gradually, and the oil production rate decreases gradually. When the bottom hole flowing pressure drops to below the bubble point pressure, the flow of extra-heavy oil in the reservoir can be divided into two zones: far well zone and near well area. In the far well zone, the pressure is higher than the bubble point pressure. The flow of oil is a single-phase flow, and the displacement mode is elastic driving. In the near well area, the pressure is lower than the bubble point pressure, and the oil flow is foamy oil flow, and the displacement mode is the dissolving gas drive driven by foamy oil. There exists many factors that influence the cold production performance of foamy extra-heavy oil, including reservoir depth, reservoir thickness, reservoir physical property and heterogeneity. The oil recovery factor per unit pressure drop can evaluate the cold production performance of foamy extra-heavy oil reservoirs. The effectiveness of cold production is closely related to reservoir parameters. Larger reservoir thickness, deeper reservoir depth and greater reservoir permeability will enhance the performance of cold production. Closer, larger and more interlayers above the horizontal well will hinder the performance of cold production.
This research provides certain guidance and reference for further development adjustment and new project evaluation for foamy extra-heavy oil reservoirs in the Eastern Orinoco Belt.
Using Machine Learning Methods to Identify Reservoir Compartmentalization in Mature Oilfields from Legacy Production Data
Authors: Ramcharitar Kamlesh , Ramdhanie Arti Kandice 
Published: June 2021

Abstract
Despite long production histories, operators of mature oilfields sometimes struggle to account for reservoir compartmentalization. Geological-led workflows do not adequately honor legacy production data since inherent bias is introduced into the process of allocating production by interpreted flow units. This paper details the application of machine learning methods to identify possible reservoir compartments based on legacy production data recorded from individual well completions. We propose an experimental data-driven workflow to rapidly generate multiple scenarios of connected volumes in the subsurface. The workflow is premised upon the logic that well completions draining the same connected reservoir space can exhibit similar production characteristics (rate declines, GOR trends and pressures). We show how the specific challenges of digitized legacy data are solved using outlier detection for error checking and Kalman smoothing imputation for missing data in the structural time series model. Finally, we compare the subsurface grouping of completions obtained by applying unsupervised pattern recognition with Hierarchal clustering. Application of this workflow results in multiple possible scenarios for defining reservoir compartments based on production data trends only. The method is powerful in that, it provides interpretations that are independent of subsurface scenarios generated by more traditional workflows. We demonstrate the potential to integrate interpretations generated from more conventional workflows to increase the robustness of the overall subsurface model. We have leveraged the power of machine learning methods to classify more than forty (40) well completions into discrete reservoir compartments using production characteristics only. This effort would be extremely difficult, or otherwise unreliable given the inherent limitations of human spatial, temporal, and cognitive abilities.
Experiments and Simulation on Integrated Approach of CO2 EOR and Storage in Mature Reservoirs
Authors: Wang Rui , Lv Chengyuan , Liu Xuan , Tang Yongqiang , Cui Maolei , Yang Zhaopeng 
Published: June 2021

Abstract
CO2 storage mechanisms in an EOR process in mature reservoirs are measured to determine three types of storage factors, which are introduced into compositional numerical simulation. The hybrid objective function coupli ng the oil recovery factor and the CO2 storage ratio is proposed to optimize the injection and production parameters in CO2 flooding. Three storage factors of the oil and water partition coefficient, the permeability change coefficient and the CO2 retention factor are measured in a laboratory, which is utilized to modify the grid properties of oil, brine, rock in compositional numerical simulation. The restart procedure is automatically adopted to consider these storage mechanisms in CO2 EOR. The bi-objective function of the oil recovery factor and the CO2 storage ratio is used to optimize the injection and production parameters for CO2 EOR, which concludes the design principles on CO2 EOR and storage. The oil and water partition coefficient defined as the ratio of the CO2 solubility in the oil phase and the brine phase is a constant for a specific reservoir condition. The permeability change coefficient caused by the mineral dissolution effect of carbonate water decreases slightly in the early stage and increases gradually with the long term injection. The CO2 retention factor that is induced by the relative permeability hysteresis decreases with the pressure and the permeability. These equivalent treated methods that modify fluids and rock in the real-time are inserted into the procedure of compositional numerical simulation to take into account the storage mechanisms in CO2 EOR. The results show that the effect of the storage mechanisms on EOR is evident. Furthermore, the bi - objective optimization indicates that the injection rate should be reduced largely in the medium and the later stages to control gas channeling as the EOR scenario is focused. And the bottom wellhole pressure of producers should be decreased to the lower level to maximize oil recovery. As the storage scenario is concentrated, the injection rate is required to be slightly controlled. As the producers are shut off, the injection rate must be increased significantly to maximize CO2 storage. The storage mechanisms in the CO2 EOR process have not been understood thoroughly. The methodology of numerical simulation coupling CO2 EOR and storage is not mature, which is still not taken into account in commercial software. The results above provide a way to optimize CO2 EOR and storage simultaneously, which is significant for the large scale storage after CO2 EOR in mature oilfield.
Short-Term Outcomes of Laparoscopic Versus Open Liver Resection for Hepatocellular Carcinoma in Elderly Patients: A Propensity Score Matching Analysis
Authors: Monden Kazuteru , Sadamori Hiroshi , Hioki Masayoshi , Ohno Satoshi , Takakura Norihisa 
Published: June 2021

Abstract
BackgroundThe number of elderly patients with hepatocellular carcinoma (HCC) requiring surgical treatment has been continuously increasing. This study aimed to examine the safety and feasibility of laparoscopic liver resection (LLR) versus open liver resection (OLR) for HCC in elderly patients at our institution in Japan.MethodsBetween 2010 and 2018, LLR and OLR were performed in 80 and 138 elderly patients (aged > 70 years) who were diagnosed with HCC, respectively. Propensity score matching (PSM) analysis with covariates of baseline characteristics was applied. Intra- and postoperative data were evaluated in both groups.ResultsAfter PSM, 56 patients who underwent LLR and OLR, respectively, were compared. No significant differences in demographic, clinical data, and operative times were observed. Blood loss (OLR: 327 mL, LLR: 50 mL [P < 0.001]), length of postoperative hospital stay (OLR: 12 days, LLR: 7 days [P < 0.001]), and time to start oral intake (OLR: 2 days, LLR: 1 day [P < 0.001]) were significantly lower and shorter in the LLR group than in the OLR group. The incidence of complications over Clavien-Dindo class IIIa was similar between both groups.ConclusionsOur results suggest that advanced age alone is not a contraindication, and LLR can be a treatment option for elderly patients with HCC.Trial registration: retrospectively registered
The application of the strength reduction shortest path method to the stability analysis of shallow buried tunnel
Authors: Wang Wei , Zhang Jiaqi , Liu Ao 
Published: June 2021

Abstract
In order to improve the theoretical analysis of surrounding rock stability of shallow buried tunnel. The strength reduction shortest path theory is applied to the stability analysis of shallow buried tunnel surrounding rock, combined with the ultimate equilibrium strength reduction theory. We discussed the influence of the depth and span ratio of tunnel, cohesion, and internal friction angle on the shortest path of the strength reduction, and studied the effects of various factors on shallow buried tunnel safety relationship by using strength reduction factor of safety and the shortest path of the shallow buried tunnel surrounding rock and the grey relational analysis theory. The results show that: In the analysis of shallow buried tunnel in strength reduction, the approximate distribution obeys parabolic between reduction path length and the reduction ratio. When the strength reduction of cohesion is the shortest path the reduction rate is greater than the internal friction angle. The internal friction angle and cohesive force have a great influence on the stability of shallow tunnel under the method of shortest path of strength reduction. Finally, the comprehensive safety factor of shallow buried tunnel calculated by the finite element strength reduction shortest path method is greater than that calculated by the limit equilibrium method.
A Liquid Chromatographic Method for Determination of Acetamiprid and Buprofezin Residues and Their Dissipation Kinetics in Paddy Matrices and Soil
Authors: Majumder Sujan , Mandal Somnath , Majumder Biswajit , Paul Anindita , Paul Tarun , Sahana Nandita , MONDAL PRITHUSAYAK 
Published: June 2021

Abstract
The present study was conducted to investigate the residue status of two insecticides (acetamiprid and buprofezin) and their dissipation kinetics in three matrices viz. paddy grain, straw and soil. The extraction protocol for residues of these two insecticides was executed using acetonitrile solvent. The analytical method was validated, which showed good linearity with the limit of quantification (LOQ) value of 0.01 and 0.02 mg kg− 1 for acetamiprid and buprofezin respectively. The recovery range was 79.67–98.33 % concerning all the matrices in both the insecticides. Acetamiprid (20% SP) and Buprofezin (25% SC) were applied separately in the paddy field in two doses: single dose (recommended dose) and double dose along with untreated control throughout the experiment. Residue analysis of these two insecticides in paddy (grain and straw) and soil was accomplished employing high-pressure liquid chromatography (HPLC) with a UV detector. The dissipation data showed that acetamiprid exhibited higher dissipation in comparison with buprofezin. However, their persistence was found slightly higher in soil. The dissipation dynamics in the rice and soil were discussed with biological half-lives of both the insecticides. Consumer risk assessment study was also made considering its fate to the consumers.