bluuebunny/crossref_metadata_2025_split huggingface dataset:
Compressor Computerized Performance Monitoring System CPMS
Authors: Goryachikh Vadim , Alghamdi Fahad , Takrouni Abdulrahman 
Published: December 2021

Abstract

Background information
Natural gas liquid (NGL) production facilities, typically, utilize turbo-expander-brake compressor (TE) to generate cold for C2+ separation from the natural gas by isentropic expansion of feed stream and use energy absorbed by expansion to compress residue gas.
Experience shows that during operational phase TE can exposed to operation outside of design window that may lead to machine integrity loss and consequent impact on production. At the same time, there is a lack of performance indicators that help operator to monitor operating window of the machine and proactively identify performance deterioration.
For instance, TE brake compressor side is always equipped with anti-surge protection system, including surge deviation alarms and trip. However, there is often gap in monitoring deviation from stonewall region. At the same time, in some of the designs (2×50% machines) likelihood of running brake compressor in stonewall is high during one machine trip or train start-up, turndown operating modes.
Also, typical compressor performance monitoring systems does not have enough dynamic parameters that may indicate machine process process performance deterioration proactively (real-time calculation of actual polytrophic efficiency, absorbed power etc.) and help operator to take action before catastrophic failure occurs.
In addition, typical compressor monitoring systems are based on assumed composition and fixed compressibility factor and do not reflect actual compositions variations that may affect machine performance monitoring.
To overcome issues highlighted above, Hawiyah NGL (HNGL) team has developed computerized monitoring and advisory system to monitor the performance of turbo-expander-brake compressor, proactively, identify potentially unsafe conditions or performance deterioration and advice operators on taking necessary actions to avoid unscheduled deferment of production.
Computerized performance monitoring system has been implemented in HNGL DCS (Yokogawa) and utilized by control room operators on day-to-day basis.
Real-time calculation, analysis and outputs produced by performance monitoring system allow operator to understand how current operating condition are far from danger zone. Proactive deviation alarms and guide messages produce by the system in case of deviation help operators to control machine from entering unsafe region. Actual polytrophic efficiency, adsorbed power calculations provide machine condition status and allow identifying long-term performance deterioration trends.
A New Viscosity and Density Sensing Platform for Drilling Automation
Authors: Gonzalez Miguel , Thiel Tim , Gooneratne Chinthaka , Adams Robert , Powell Chris , Magana-Mora Arturo , Ramasamy Jothibasu , Deffenbaugh, Max 
Published: December 2021

Abstract
During drilling operations, measurements of drilling fluid/mud viscosity and density provide key information to ensure safe operations (e.g., maintain wellbore integrity) and improve the rate of penetration (e.g., maintain proper hole cleaning). Nowadays, these measurements are still performed manually by using a calibrated funnel viscometer and a weight balance, as stipulated by current American Petroleum Institute (API) standards. In this study, we introduce an automated viscosity/density measurement system based on an electromechanical tuning fork resonator. The system allows for continuous measurements as fast as several times per second in a compact footprint, allowing it to be deployed in tanks or pipelines and/or gathering data from multiple sensors in the mud circulation system. The streams of data produced were broadcasted to a nearby computer allowing for live monitoring of the viscosity and density. The results obtained by the in-tank system in five wells were in good agreement with the standard reference measurements from the mud logs. Here, we describe the development and testing of the tool as well as general guidelines for integration into a rig edge-computing system for real-time analytics and detection of operational problems and drilling automation.
Field Experience of an Innovative Downhole Energy Harvesting System
Authors: Arsalan Muhammad , Fellinghaug Jarl André 
Published: December 2021

Abstract
Downhole power harvesting is an enabling technology for a wide range of future production systems and applications, including self-powered downhole monitoring, downhole robotics, and wireless intelligent completions. This paper presents the field experience of an innovative energy harvesting system that was successfully deployed and tested in the harsh downhole conditions of an oil producer.
There is a critical need for robust and reliable downhole power generation and storage technologies to push the boundaries of downhole sensing and control. This paper provides an analysis of available ambient energy sources in the downhole environment, and various energy harvesting techniques that can be employed to provide a reliable solution. Advantages and limitations of conventional technique like turbine are compared to advanced energy harvesting technologies. The power requirements and technical challenges related to different downhole applications have also been addressed. The field experience of the novel flow-based energy harvesting system are presented, including the details of both the lab and field prototype design, deployment and testing.
Field Application of Reaming-While-Drilling Technology in the Super Deep Composite Anhydrite-Salt Layers of Kuche Mountain Front in Tarim Oilfield
Authors: Xu Zhixiong , Teng Xueqing , Li Ning , Liu Hongtao , Zhao Caiting , Zhou Bo , Zou Bo , Yu Wei 
Published: December 2021

Abstract
The implementation of drilling technique for multiple lithology interbeds and high-pressure anhydrite-salt in the complex Mountain Front area has been completed. The plastic creep of the anhydrite-salt layers, the losses of the low-pressure sandstone, the overflow of the high-pressure salt-water, the narrow mud density window and frequent pipe-stuck occurrence are significant issues, which trigger significant engineering challenges downhole. This study presents the application of the reaming-while-drilling (RWD) technology which has led to minimize the downhole non-productive time (NPT) and achieve successful results. The RWD technique was applied in the composite anhydrite-salt formation of the Kumugeliemu group. Through optimized combination of the RWD tools, bits, reaming blades, and the mechanical analysis the drill string with shock-absorbing design and hydraulics optimization to guarantee the bit and the reamer blades have the proper pressure drop, hydraulic horsepower and flow-field distribution, the RWD was used with the vertical seeking tool drilling technology, resulting in minimum vibration and/or stick-slip, and achieving the expected rate of penetration (ROP) as well as target inclination. It improved the operation efficiency significantly while avoiding the downhole complexities at the same time. Since the geological structure of the offset well Keshen X (no RWD) is similar to Keshen XX (RWD technology was applied), a comparison between the two wells was performed. The reaming meterage in the composite anhydrite-salt layers in Keshen XX was 791 m, spending 15 days, average ROP is 3.73 m/hr. There was no overflew or loss during the drilling. It was smooth, no pipe sticking when checking the reaming effect during the wiper trip and the tripping out. On the other hand, Keshen X spent 29 days with average ROP of 1.35 m/hr to drill the 449 m composite anhydrite-salt rock. Moreover, it was difficult to trip in and trip out during the drilling, and the pipe sticking happened frequently, back-reaming frequently as well. There were losses during both the drilling and the casing running. Due to the unsmooth wellbore, this well increased additional 3 runs of reaming after drilling operation and 4 clean-out runs. 13 days later after the reaming operation, the anhydrite-salt rock creep was checked and found that the hole was still smooth, no pipe sticking existing. Hence, RWD technology has accomplished both goals of preventing the downhole complexities and speeding up drilling. The novel RWD technology can be well illustrated by presenting all the details of its application in salt-base formations.
Identifying Producing Horizons in Fractured Reservoirs a Far Field Acoustic Approach
Authors: Hati Samhita , Chawla Hemlata , Ghosh Arnab , Guru Udit , Guru Rakesh 
Published: December 2021

Abstract
The present study attempts to use 3D slowness time coherence (STC) technique to characterize the far-field fractures based on the reflector locations and attributes such as the dip and azimuth of fractures. These, in integration with the rest of the available data are used to accurately characterize the producing horizons in fractured basement reservoirs.
The first step of the workflow involves the generation of 2D image to see if there are evidences of near and far wellbore reflectors. Since this is subjective in nature and does not directly provide quantitative results for discrete reflections, a new automated sonic imaging technique – 3D slowness time coherence (STC), has been incorporated to address this challenge. This method complements the image by providing the dip and azimuth for each event. The 2D and 3D maps of the reflectors can be readily available to integrate with the interpretations provided by other measurements, to better correlate and map the producing horizons.
A field example is presented from the western offshore, India in which a fractured basement reservoir was examined using 3D STC technique to provide insight to the near and far field fracture network around the borehole. Few of the interpreted fractures from the resistivity image and conventional sonic fracture analysis coincide with the far field 3D STC reflectors, indicated by significant acoustic impedance. Further, the zones where the near and far field events coincide, represent a producing horizon.
Comparing the near wellbore structures from the borehole images with the reflectors identified through the far field sonic imaging workflow provides necessary information to confirm the structural setting and characteristics of fractures away from the borehole. For the present case, it indicates the continuity of the fracture network away from the wellbore and explains the possibility of high production from the reservoir horizon.
This study opens new perspective for identifying and evaluating fractured basement reservoirs using the sonic imaging technique. As more wells are drilled, it will be possible to better correlate and map the producing horizons in the field. This will allow better planning of location of future wells and help in optimizing field economics.
A robust, automated and synergistic approach is used to locate and characterize individual arrival events which allows a more reliable understanding of the fracture extent and geologic structures. The 2D and 3D visualizations/maps can be readily integrated with the interpretations provided by other measurements.
A Coupled Model of Temperature and Pressure for Managed Pressure Cementing in Deep-Water Region
Authors: Wang Xuerui , Hao Feng , Sun Baojiang , Wang Zhiyuan 
Published: December 2021

Abstract
The narrow density window in deep-water environment brought great challenges to well drilling and completion by causing well control issues. Managed Pressure Cementing (MPC) is a new technology developed from Manage Pressure Drilling (MPD), which can precisely control the annular fluid pressure profile. Accurate calculation of wellbore temperature and pressure is the key to MPC. This paper focus on coupled models of temperature and pressure for MPC in deep-water region.
The well cementing process can be divided into two stages: fluid displacement stage and cement setting stage, which displays different characteristics. During the cementing displacement stage, the cement is in a flowable slurry state and is circulated into the annulus. During this process, the rheology of fluids if effected by temperature in wellbore. On basis of the fluid rheology model, a coupled model of temperature and pressure in wellbore is established considering the transient flow characteristics during cementing displacement stage. During cement setting stage, the cement slurry stops flowing and the significant cement hydration reaction starts. A large amount of hydration heat and obvious pressure reduction can be observed. On basis of the cement hydration kinetics model, a coupled model of temperature and pressure in wellbore during cementing setting stage is established.
Based on the models established in this paper, a series of numerical simulations are conducted using a deep-water well. Simulation results show that neglecting the complicated interactions between temperature and pressure can cause a big error. During the cementing displacement stage, higher temperature in the deep part of wellbore reduces the fluid viscosity, which leads to a smaller friction. On the contrary, larger friction is observed near seabed as a result of the low temperature in deep-water environment. The pressure in wellbore changes frequently due to the coexistence of multiple fluids in wellbore. Therefore, a frequent control of annular fluid pressure is required using the MPC technology. During the cement setting stage, an obvious temperature increase is observed as a result of cement hydration heat. The pressure decreases with the depending of cement hydration. An addition back pressure at wellhead has to be added using the MPC technology. The transient temperature and pressure have impact on the rate of cement hydration in turn. Cement in the deep part of wellbore have a faster rate of cement hydration. The low temperature at mudline slows the cement hydration process.
Considering the complicated interactions between temperature, pressure, cement hydration and fluid rheology, coupled models between temperature and pressure based on hydration kinetics during well cementing in deep-water region is established in the manuscript. The new model established in this paper plays an important role in the MPC technology.
The Measurement of Tortuosity of Porous Media Using Imaging, Electrical Measurements, and Pulsed Field Gradient NMR
Authors: Elsayed Mahmoud , Kwak Hyung , El-Husseiny Ammar , Mahmoud Mohamed 
Published: December 2021

Abstract
Tortuosity, in general characterizes the geometric complexity of porous media. It is considered as one of the key factors in characterizing the heterogonous structure of porous media and has significant implications for macroscopic transport flow properties. There are four widely used definitions of tortuosity, that are relevant to different fields from hydrology to chemical and petroleum engineering, which are: geometric, hydraulic, electrical, and diffusional. Recent work showed that hydraulic, electrical and diffusional tortuosity values are roughly equal to each other in glass beads. Nevertheless, the relationship between the different definitions of Tortuosity in natural rocks is not well understood yet. Understanding the relationship between the different Tortuosity definitions in rocks can help to establish a workflow that allows us to estimate other types from the available technique. Therefore, the objective of this study is to investigate the relationship between the different tortuosity definitions in natural rocks. A major focus of this work is to utilize Nuclear Magnetic Resonance (NMR) technology to estimate Tortuosity. Such technique has been traditionally used to obtain diffusional tortuosity which can be defined as the ratio of the free fluid self-diffusion coefficient to the restricted fluid self-diffusion coefficient inside the porous media.
In this study, the following techniques were used to quantify hydraulic, electrical, and diffusional tortuosity respectively on the same rock sample: (1) Microcomputed Tomography 3D imaging (2) Four-Electrodes resistivity measurements (3) Pulsed-Field Gradient Nuclear Magnetic Resonance (PFG NMR). PFG NMR is very powerful, non-invasive technique employed to measure the self-diffusion coefficient for free and confined fluids. The measurements were done based on two carbonate rock core plugs characterized by variable porosity, permeability and texture complexity.
Results show that PFG NMR can be applied directionally to quantify the pore network anisotropy created by fractures. For both samples, hydraulic tortuosity was found to have the lowest magnitude compared to geometric, electrical and diffusional tortuosity. This could be explained by the more heterogeneous microstructure of carbonate rocks. NMR technique has however advantages over the other electrical and imaging techniques for tortuosity characterization: it is faster, non-destructive and can be applied in well bore environment (in situ). We therefore conclude that NMR can provide a tool for estimating not only diffusional tortuosity but also for indirectly obtaining hydraulic and electrical tortuosity.
Bahrain LNG Import Terminal Project (BLNGIT) - 1st LNG Commissioning Cargo and Integration of Imported RLNG with Domestic Khuff Gas in the Existing Network
Authors: AlKhunaizi Fawaz A. Aziz , Prudhvi Muni Shankar , Mohamed Anwar 
Published: December 2021

Abstract
In order to meet the country's future energy requirements, and in particular the increased demand for electricity and water in addition to major industrial growth, Bahrain's National Oil and Gas Authority (NOGA) has taken the strategic decision to import Liquefied Natural Gas (LNG) to supplement existing local gas supplies as a long term energy policy.
NOGA and the National Oil and Gas Holding Company B.S.C (c) (NH) signed project agreements in 2015 for the development of an LNG Receiving and Regasification Terminal in the Kingdom of Bahrain with an international consortium.
The purpose of this paper is to shed light on this ‘first-of-its-kind’ project development in the Kingdom of Bahrain in order to highlight (i) the challenges and management of such challenges, (ii) the ultimate project/operational objectives and successful results, and (iii) lessons learnt.
A Single Artificial Neural Network Model Predicts Bubble Point Physical Properties of Crude Oils
Authors: Al-Marhoun Muhammad 
Published: December 2021

Abstract
Reservoir fluid properties at bubble points play a vital role in reservoir and production engineering computations. Ideally, the bubble point physical properties of crude oils are obtained experimentally. On some occasions, these properties are neither available nor reliable; then, empirically derived correlations or artificial neural network models are used to predict the properties.
This study presents a new single multi-input multi-output artificial neural network model for predicting the six bubble point physical properties of crude oils, namely, oil pressure, oil formation volume factor, isobaric thermal expansion of oil, isothermal compressibility of oil, oil density, and oil viscosity. A large database comprising conventional PVT laboratory reports was collected from major producing reservoirs in the Middle East. The model input is constrained mathematically to be consistent with the limiting values of the physical properties. The new model is represented in mathematical format to be easily used as empirical correlations.
The new neural network model is compared with popular fluid property correlations. The results show that the developed model outperforms the fluid property correlations in terms of the average absolute percent relative error.
Implementing Remote Mudlogging Solutions to Support a Deepwater Project in the Caribbean: A De-Manning Case Study
Authors: Smith Evan 
Published: December 2021

Abstract
Today's oil and gas industry is a global endeavor. With technological advances in data management and transfer, the ability for experienced engineers to receive, interpret, and make decisions from all over the globe in near real-time is not only achievable, but is becoming more desirable. Provoked by downturns and reduced personnel numbers, methods of increasing efficiency and cost reduction has gradually moved engineers away from the rig site, while still undertaking the same roles and responsibilities. This paper examines one case for an operator in the Caribbean.
One major client drilling in the Caribbean was forced to explore reduced staffing options on one of its deep-water drilling rigs after flight cancellations, border closures, and isolation/quarantine procedures were implemented due to the COVID-19 pandemic. This made getting experienced data engineers and sample collection personnel to the rig site impossible. Two data engineers, two mud loggers, and two sample catchers are on the rig during normal operations, but with the above-mentioned challenges, only two mud loggers remained on site. The mudlogging service provider proposed intercompany collaboration with a region experienced in remote operational support, and a remote monitoring station was set up and manned with experienced data engineers to support real-time operations. A focal point between the remote engineers and the rig team was designated, and was responsible for communicating roles and responsibilities, linking the two teams. A robust communication protocol was established between the mudlogging crew, the remote personnel, the drill floor, and the company man which outlined specifics of which events would trigger communication between parties.
Two intermediate hole sections were successfully drilled, without any interruption or delay. The remote engineers successfully participated in the rigs well control drills, calling directly to the rig when needed. During drilling, the experienced remote personnel were able to provide topic specific guidance to the less experienced engineers at the rig site, which accelerated their on-the-job training. This guidance encouraged and allowed for decreased reliance on the remote support over the course of drilling. The operator considered the implementation of the remote engineers a success and looked to implement additional remote resources from other service lines and providers.
Development of additional remote support opportunities directly reduces risk and cost of personnel at the rig site throughout all aspects of the oil and gas industry. Reduction of personnel on site reduces overall exposure to the hazards associated with the rig site and would decrease the probability of incident. Recent improvements in technology and communication have made it possible for this to be a viable solution to de-manning the rig site in an evolving industry.