bluuebunny/crossref_metadata_2025_split huggingface dataset:
Digitization of Drill Bit Inspections; User-Centered Design Methods to Automate Robotic Inspections
Authors: Ma Marrie , Murphy Jeremy , Salman Nader , Li Zhen , Chatar Crispin , Chatagnier Justin 
Published: September 2021

Abstract
One unique facet of digital technology is the merging of separate technologies for new workflows and products. Like other industries, energy is also doing this. This project will automate the bit inspection process and this system will reduce labor costs, increase product quality, and improve bit performance. The innovation center is working on various aspects of the project, which aims to join automation technologies with robotic capabilities.
Industrial robots are used extensively in traditional high-volume manufacturing applications. The high-mix, low-volume nature of oil and gas manufacturing operations has impeded deployment of automation solutions. Recent advances in sensors, computers, and machine learning now enable integrating robotics and automation technologies into these flexible manufacturing workflows. Driven by digital transformation, an automated inspection system for polycrystalline diamond compact (PDC) drill bits has been developed. The system uses high-resolution robotic 3D scanning, 2D imaging, and artificial intelligence to improve inspection efficiency and product quality. In our user-experience- (UX-) focused approach, we streamlined the user interface (UI) research methods to develop the robotic inspection UI and successfully tested the design with end users. This paper introduces the inspection system and improved workflows for the PDC bits, illustrates the innovative UX/UI development process, and targeted evaluation with the end users, which is crucial before deploying the system in production. We also concluded with some recommended improvements to guide future work.
Gas Lift Design Optimization Using Intelligent Gas Lift Valves a KJO Case Study
Authors: Al Qahtani Abdullah , Al-Aklubi Sultan , BenAmara Abdel , Faux Stephen 
Published: September 2021

Abstract
Gas lift is becoming a big consideration in most of oil field as an economic, sustainable means of artificially lifting weak/dead oil wells. This is especially considered in high volume wells. Gas lift is employed, by injecting gas into the well tubing through gas lift valves, to reduce the hydrostatic pressure of the produced fluid column in oil wells, leading to a lower flowing bottom-hole pressure. The increased pressure differential induced across the sand face from the in situ reservoir pressure, assists in lifting the produced fluid to the surface.
Optimizing the level of injected gas is important in maximizing the production, and hence the financial performance of the well. The challenge for most oil and gas producers is that they do not effectively maximize production with the most efficient use of gas lift resources. The challenge is that there is a lack of accurate and timely production data from the well tests. The optimal inject rate for a well is based on a ratio of injected gas rate to the liquid production rate. Under injecting the gas decreases the well production rate. The objective of optimization in gas-lifted wells is to achieve optimal production rate with minimal gas injection volume to spare gas for other wells, when the compression capacity is limited. Optimally allocated injection gas helps reduce unnecessary strain on your facility and maximize performance, this in turn enhances the life of production assets significantly.
This paper presents a case study from Khafji Joint Operation fields, utilizing the intelligent digital gas lift valve to optimize the design and performance of the gas lift wells. The case study demonstrates the value proposition by using the digital intelligent gas lift system to maximize well performance whilst reducing injected gas, in addition to acquired real-time data that help assess the process. That optimization was achieved on well level by optimizing the well parameters such as point of injection, injection rate, and injection pressure. All these aspects have been investigated and presented in this study by using field data and flow simulations. Results showed the potential added value of the system.
Toe Initiation Sleeve With Time-Delay Functionality Improves Operational Efficiency of Offshore NCS Wells
Authors: Mehus Cathrine , Keerthivasan Vijay Kumar , Koløy Tom Rune , Young Dustin , Sørheim Tore 
Published: September 2021

Abstract
A toe initiation sleeve is a tool installed in the toe of a completion liner and is used to establish a flowpath to the reservoir without the use of intervention. Conventional toe initiation sleeves require either intervention or increasing pressure to higher than the liner test pressure to activate. These methods have inherent cost and operational risks. This paper will present the development, qualification, and deployment of a multicycle, time-delay cementable toe initiation sleeve that allows for interventionless activation without exceeding the liner test pressure. This development greatly improves operational efficiency and eliminates risk associated with conventional toe initiation sleeves.
A major operator in the North Sea required an ISO V0 rated toe initiation sleeve to be developed and qualified. Design criteria for the tool was identified, and the design was developed based on field-qualified seal technology. Individual component and full-scale validation testing was performed to complete the product qualification, followed by field trials in 2019. With its unique time-delay feature, the newly developed ATS (Advanced Toe Sleeve) allows for an unlimited number of pressure cycles to be performed while also keeping the well V0 barrier in place, and activates at below liner test pressure.
This paper will discuss the technology development and implementation project, resulting in ISO 14998 V0-qualified cemented ATS being installed in nearly 40 wells in the same field. This paper will also provide insight into how the ATS provides unique benefits to the operator during various phases of the well's life.
Cementing: One moving part and opening sleeve isolated from the inside diameter (ID) allow for pumping darts through the ATS without the risk of opening Setting liner/testing liner: Time-delay features allow for setting liner and testing the liner at higher pressures than ATS opening pressure. Well cleanup/displacing to lower density fluid: Time-delay function allows for opening the ATS at lower pressure than the well has seen during previous operations. Completion: ATS design and qualification grade reduce completion steps and costs for the operator. Stimulation: ATS eliminates the need for intervention, reducing the operational steps and costs for the operator.
The advanced toe sleeve with built-in time-delay features maintains the liner integrity throughout the various well operations. The number of available pressure cycles can be predetermined, and the activation of the various cycles can be precisely controlled thereby also controlling when the tool is activated to achieve injectivity. This paper will present the development and field-wide implementation of the ATS technology, which has rapidly gained operator acceptance and resulted in significant time and cost savings.
Impact of High Resolution 3D Geomechanics on Well Optimization in the Southern Gulf of Suez, Egypt
Authors: Elkhawaga Mohamed , A. Elghaney Wael , Naidu Rajarajan , Hussen Assef , Rafaat Ramy , Baker Kareem , Radwan Ahmed , Heiland Julian 
Published: September 2021

Abstract
Optimizing the number of casing strings has a direct impact on cost of drilling a well. The objective of the case study presented in this paper is the demonstration of reducing cost through integration of data. This paper shows the impact of high-resolution 3D geomechanical modeling on well cost optimization for the GS327 Oil field. The field is located in the Sothern Gulf of Suez basin and has been developed by 20 wells
The conventional casing design in the field included three sections. In this mature field, especially with the challenge of reducing production cost, it is imperative to look for opportunites to optimize cost in drilling new wells to sustain ptoduction. 3D geomechanics is crucial for such cases in order to optimize the cost per barrel at the same time help to drill new wells safely.
An old wellbore stability study did not support the decision-maker to merge any hole sections. However, there was not geomechanics-related problems recorded during the drilling the drilling of different mud weights.
In this study, a 3D geomechanical model was developed and the new mud weight calculations positively affected the casing design for two new wells. The cost optimization will be useful for any future wells to be drilled in this area.
This study documents how a 3D geomechanical model helped in the successful delivery of objectives (guided by an understanding of pore pressure and rock properties) through revision of mud weight window calculations that helped in optimizing the casing design and eliminate the need for an intermediate casing.
This study reveals that the new calculated pore pressure in the GS327 field is predominantly hydrostatic with a minor decline in the reservoir pressure. In addition, rock strength of the shale is moderately high and nearly homogeneous, which helped in achieving a new casing design for the last two drilled wells in the field.
Bulk Modulus of Hydrocarbon Fluids After Injection with Supercritical CO2 at Reservoir Conditions
Authors: Kandil Mohamed Eid 
Published: September 2021

Abstract
The mechanical properties of hydrocarbon reservoirs significantly depend on the elastic properties of the fluids occupying the pore space in the rock frame. Accurate data and models for the mechanical properties of fluid mixtures in a petroleum reservoir containing supercritical CO2 should be available at the same reservoir conditions for reliable design of well-completion, maximizing reservoir productivity, and minimizing risk in drilling operations. This work investigates the change in the bulk modulus of the higher hydrocarbon fluid (decane C10H22) after the injection with supercritical CO2 at reservoir conditions. The isothermal bulk modulus βT of liquids under pressure, simply defined as the first-order derivative of pressure with respect to volume, is determined in this study from the derivative of pressure with respect to density. The density data were obtained from experimental measurements of mixtures of supercritical CO2 + C10H22 for a range of CO2 mole fractions from 0 to 0.73, at temperatures from 40 to 137 °C and pressures up to 12000 psi. The isothermal derivative coefficients of the pressure as a function of density are reported for each CO2 concentration measured in this work. Common fluid-substitution models, including the Gassmann model, which is only valid for the isothermal regime, have limited predictive power because most fluids are treated as simple fluids, with their mechanical properties only characterized by their densities. However, under different environments, such as when supercritical CO2 is injected into the geological formation, the fluid phase and its mechanical properties can vary dramatically. At high pressure, the density of CO2 can equal to that of the hydrocarbon phase ρ(CO2)/ρ(C10H22) ≈ 1, while the bulk modulus of CO2 remains as low as only βT(CO2)/βT(C10H22) ≈ 7 %. Excessive decrease in the bulk modulus can easily cause subsidence, although the pore pressure and the fluid mixture density remain unchanged, even at pressures up to 4000 psi.
Multiphase Flow Meter Health Monitoring Strategy: Maximizing the Value of Real-Time Sensors and Automation for Industrial Revolution 4.0
Authors: Al-Kadem Mohammad , Gomaa Mohammad , Al Yateem Karam , Al Maghlouth Abdulmonam 
Published: September 2021

Abstract
Metering with Multiphase Flow Meters (MPFMs) is a well proven Intelligent Field technology, which utilizes complex flow models and a radioactive detection mechanism to accurately measure multiphase flow (oil, gas and water) on a real-time basis. The major realized benefits of utilizing MPFM real-time sensor data technology are reduced maintenance costs, optimized maintenance schedules, and improved safety via minimizing visits and predicting well performance.
MPFMs also have the capability to perform comprehensive real-time test validation in a short period of time making them a valuable tool. Leveraging their capabilities, engineers can perform various production analysis scenarios remotely using continuous data streaming to reduce and ultimately eliminate reliance on operators and vendors in remote fields. Nevertheless, such MPFMs require frequent maintenance, which could be quite difficult to manage when having a large quantity of meters.
An in-house application was developed to support those objectives and to remotely monitor the health of all MPFMs on a real-time basis. The in-house analytics system comprises four modules, namely, Field Overview, MPFM Overview, Well Test Management, and Alarm Management with the steps used to avail this kind of solution to cover infrastructure requirements, visualization requirements, optimization and prediction. The solution was designed as the major interface for engineers to detect and prevent major MPFM component failures proactively and to highlight all types of projected MPFM component failures. It proactively harvests preset alarms, which leads to preventing internal MPFM parts from failing. These alarms are generated based on critical parameters measured by the MPFM such as rates, differential pressure, and radioactive measurements. Annual savings are realized due to utilizing the monitoring solution by minimizing costly offshore visits and optimizing the visits to be based on problematic MPFMs.
The authors will discuss a newly developed MPFM health monitoring strategy based on real-time solutions, driving a migration from a preventative to a predictive maintenance concept to reduce costs and optimize manpower time through eliminating unnecessary visits.
Forecasting Reserves Replacement Ratio RRR: A Method for Benchmarking the Ability of the Company to Mature Projects and Reduce Uncertainty
Authors: Salacz Dominique , Allam Farid , Mubarak Al Araimi Wadha , Al Mansoori Yousof 
Published: September 2021

Abstract
Reserves Replacement Ratio (RRR) has been used as a Key Performance Indicator (KPI) for monitoring the ability of IOCs to replace their reserves through time. It provides valuable information about the expected long-term viability of the company and its ability to move forward with new projects. If this remains an important metric for investors and operators alike, it is worth understanding the key parameters behind this KPI. How should we realistically expect the RRR to behave in the future? What does it tell about the reserves and resources of the operator? The objective of this document is to investigate how a widely underused KPI can be analyzed and forecasted based on previous reserves and business plan submissions. We suggest a method to provide teams with relevant and realistic RRR, that can be expected based on the company portfolio.
This method was developed by reviewing the Reserves & Resources in hundreds of reservoirs for all projects, including No Further Activity (NFA) cases and all future development projects. Based on the future profiles, the evaluation of the RRR was forecasted for 10 years. The forecasts are being reviewed year on year to ensure that teams are provided with realistic KPIs based on hard data rather than biased expectations. The RRR is computed using (i) the amount of reserves added during the year, divided by (ii) the production of the company during the same year. This paper will focus on the reserves changes from one year to another, considering that reserves addition (or reduction), comes from two main sources:
Project maturation: as projects are maturing on the SPE PRMS vertical axis, they will eventually become commercial according to the PRMS definition and move from contingent resources to reserves. Project maturation is driven by the asset team and by the company's willingness to move forward with the development. Technical review: as more data becomes available, the reserves of the asset will change, up or down, within (hopefully) the range of uncertainty defined in PRMS. This is driven by the inherent uncertainty in the reservoir. The control that the company has on this parameter is very limited. This document emphasizes on the impact of the uncertainty captured by the asset team during the reserves evaluation exercise, and how it will (should) affect the KPI calculations. Finally, we will discuss what should be a reasonable KPI depending on the PRMS submissions, 1P, 2P or 3P.
Eventually, this method should provide a healthy middle ground between asset teams being too pessimistic in setting their KPIs, and managers who are keen to set challenging, and sometime unrealistic, targets
Designing Tools To Improve Rod Pumping Performance In Hostile Production Conditions
Authors: Fu Zhijun , Zhu kuanliang , Wang Lei , Xu Jingjing , Wang Qian , Wang Jinzhong , Wang Lingling , Liu Yufei 
Published: September 2021

Abstract
In oil and gas industry, it is inevitable that the developed reserve will gradually become exhausted. Under such circumstance, in order to stabilize oil production and meet increasing energy demand, we have no choice but to improve oil recovery from matured field as much as possible, since finding new large reservoir is quite hard in the future. For Jidong Oilfield in China, a lot of method can be used for improving oil production, one of which is deep pumping method by increasing pump setting depth, especially for depleted reservoir.
Deep pumping method can be helpful to lower bottom hole pressure and enlarge drawdown pressure between producing layer and downhole. Not only can this method generate more power to displace oil from reservoir to well and subsequently increase oil drainage area, leading to higher oil recovery, but also can boost pump fillage and finally obtain high production efficiency. Even though, this method still brings many disadvantages. In Jidong Oilfield, we sometimes set the 1.5in pump at over 3000m depth (in this paper, all well related are rod pumping wells), where varied problems happened as followed:
Novel Nano and Bio-Based Surfactant Formulation for Hybrid Enhanced Oil Recovery Technologies
Authors: Ma Qisheng , Xia Wenjie , Tang Yongchun , Haroun Mohamed , Motiur Rahman Md , Gibrata Muhammad , Rouis Lamia , Djanuar Yanfidra , Abdelhadi Eldali Magdi , Ijaz Rabbani Aneesa , Abubacker Ponnambathayil Jassim , Suboyin Abhijith 
Published: September 2021

Abstract
This investigation presents laboratory and field deployment results that demonstrate the potential candidacy utilizing Nano and bio-technologies to create superior chemicals for novel applications to increase oil recovery from both onshore and offshore reservoirs. Nano-technology is gaining momentum as a tool to improve performance in multiple industries, and has shown significant potential to enhance hydrocarbon production. The laboratory analysis and specifically designed coreflood results indicate there are beneficial interactions at liquid-nano solid interface that increase oil mobility. This will increase the surface activity of chemical surfactants and thereby make them the dominant agents to mobilize and recover oil from oil-bearing reservoirs. Advances in biotechnology offer another rich resource of knowledge for surface active materials that are renewable and more environmental-friendly. In addition, our studies also demonstrate that bio-surfactants are well-suited to provide superior performances in enhancing oil recovery.
Nano-particles and biosurfactants may be included with synthetic surfactants to create novel and more efficient surface active agents for enhanced oil recovery. These formulations can promote better flow back of the injected stimulation fluids and additional mobilization to extract more oil from the matrix and micro-fractures. Laboratory experiments demonstrate that the specialized surfactant formulations created, interact with mixed or oil-wet low permeability formations to produce additional oil. Furthermore, this investigation also compares the total production on a candidate field with respect to typical water flood and the novel formulated surfactant approach. For each surfactant treatment, the overall designed injected fluid volume is 1500 m3 (~ 396,000 gallons) with 4 gpt (gallon per thousand unit) of surfactant concentration. Results indicate improved oil production with longer exposure time of the key surfactants within the reservoir. Enhanced surface wetting and super-low interfacial tension (IFT) at lower chemical concentrations are recognized to be the main mechanisms. The novel surfactant also shows stronger sustainability and endurance in keeping rock surface wettability over traditional surfactant system up to 5 times for an 8 PV wash. Furthermore, this can assist to identify and initiate the optimization of the identified mechanisms for potential applications within other compatible reservoirs.
A number of successful field applications of EOR with special formulated nano and bio-based surfactant formulation are discussed in this paper. This unique study bridges the gap between the field realized results and lab optimization to enhance feasibility as a function of time and cost.
Fault Rock Property Prediction On Jurassic Clastics Of The Barents Sea/Norway
Authors: Schuller Volker , Zamolyi Andras , Stueland Eirik , Dunkl István , Kettermann Michael , Schleder Zsolt 
Published: September 2021

Abstract
We analysed the fault rocks of a compartmentalized field in the Barents Sea, in an area with several tectonic elements, which formed at different tectonic events. Standard Fault Seal Analysis (FSA) was conducted to predict the shale content of the fault rock (SGR). A static cellular model based on well data, seismic data and geological concepts served as input. The fault rock calibration workflow required various data acquired by different methods. We analysed the Mid-Triassic to Upper Jurassic clastic deposits to reconstruct the tectonic history. Apatite fission track and (U-Th)/He thermochronology were used to determine the maximum burial depths and exhumation history. The results of high-resolution shale ductility analysis (BIB-SEM), a compaction trend study, kinematic analysis and structural modelling (section balancing) served as additional input constraints for fault rock calibration.
The evaluation of the results helped to reconstruct the following tectonic evolution: The orthogonal faults of the analysed area developed at an early stage, during Late Triassic to Early Jurassic times at relatively shallow depth, below 1000 m. Ongoing subsidence created accommodation space for Upper Jurassic to Cenozoic deposits with a maximum burial depth of 2000 m for the analysed Mid-Jurassic rocks. Exhumation of the area started around 10 Ma and continued through to Quaternary times.
The calculated values for fault rock permeability show a wide range when using poorly constrained input for fault rock calibration: 10 to 1000 mD for SGR values around 0.08 at reservoir/reservoir juxtaposition. Fault rock calibration using above described results concluded in reliable values for fault rock permeability and ultimately, for transmissibility multipliers. The reason for the sensitivity of the fault rock calibration is a combination of multiple factors: highly permeable reservoir sandstone, shallow depth of initial faulting, maximum burial depth and low shale content at the primary reservoir level.
The study shows that an accurate reconstruction of the geohistory provides essential parameters for fault rock calibration and fault rock permeability calculation. The range of values can widely scatter if preconditions are not acknowledged. Well-constrained fault rock calibration reduces the uncertainty on possible flow scenarios, increases the reliability on production forecasts and helps to determine the most efficient drainage strategy.