bluuebunny/crossref_metadata_2025_split huggingface dataset:
Mechanism of Scaling Corrosion for Water Injection System and Its Solution through Nonmetallic Composite Tubing
Authors: Qiang Chen , Weiye Han , Shouzhi Huang , Tao Li , Qiang Sun 
Published: October 2017

Abstract
Water injection has been widely applied in tapping oil and gas resources underground, however scaling corrosion in the water injection system was a universal problem, posing a huge threat to the longevity of downhole tubing.
In this paper, SEM and XRED were employed to study the mechanism of scaling and corrosion in the water injection system, non-metallic composite tubing was developed and evaluated in terms of its ability to resist scaling and corrosion, field operation was carried out to testify this approach.
The results indicated that inorganic scale was formed as a result of Cl–, Mg+, Ca+ contained in the injection water, parameters including temperature and pressure played a role in this process, the scale could become highly corrosive in the weak acid environment; nonmetallic composite tubing was developed based on self-propagating high temperature synthesis technique, it was composed of three layers, ceramics inside, ceramic-metal combination middle, metal outside respectively, its scale rate was 1/70 compared to the conventional tubing, meanwhile the mechanical properties were better than its metal counterpart, field operation was performed in several oilfields, demonstrating strong scale and corrosion resisting characteristics, the statistic over 3years indicated that nonmetallic composite tubing guaranteed the smooth water flooding operation downhole, while conventional tubing was suffering from severe corrosion.
This paper contributed to better understanding the scale and corrosion in the water injection system and its prevention technique of nonmetallic composite tubing, through the pioneering example and profound insights we were able to explore new horizons and yielded more benefits to development of water injection operation.
Development of a High-Temperature Resistant Polymer Gel System for Conformance Control in Jidong Oilfield
Authors: Zhu Daoyi , Hou Jirui , Wei Qi , Chen Yuguang , Peng Kewen 
Published: October 2017

Abstract
The PG reservoir in Jidong Oilfield is at a depth of around 15,000 ft with an extremely high-temperature of about 300 °F. The average water cut has reached nearly 80%, but the oil recovery is less than 10% only after two years of water flooding process. It is of great importance to developing a high-temperature resistant plugging system to improve the reservoir conformance and control water production. An in-situ polymer gel system formed by the terpolymer and a new crosslinker system was developed, and its properties were systematically studied under the condition of extremely high temperature (300 °F). Suitable gelation time and favorable gel strength were obtained by adjusting the concentration of the terpolymer (0.4%-1.0%) and the crosslinker system (0.4%-0.7%). An increase of polymer and crosslinker concentration would decrease the gelation time and increase the gel strength. The gelant could form continuous three-dimensional network structures and thus have an excellent long-time thermal stability. The syneresis of this gel system was very little even after being heated for five months at the temperature of 300 °F. The gel system could maintain most of the initial viscosity and viscoelasticity even after experiencing the mechanical shear or the porous media shear. Core flow experiments showed that the gel system could plug the fractures and reduce the permeability in the higher permeability regions, and diverted the injection water flow to the lower permeability regions, and thus improve the conformance.
Differential Pressure Cone Meter as Meter Solution in FPSO's Facilities
Authors: Simatupang Ahmad Marzuki , Lalamentik Ruben 
Published: October 2017

Abstract
Demanding of oil & gas more increasing every year. However domestic production in Indonesia could not cover the demand, this phenomena resulting the deficit of oil & gas domestic stocks. Therefore, searching the new oil & gas sources shifting from onshore to the offshore and also deep water. FPSO development become the one important things to support exploration activities. One of the obstacles when design the production facilities in FPSO is limitation of space. All process equipment and instrument must be suitable with vessel space. Almost process instrument mainly in flow meter require upstream and downstream length to guarantee the accuracy of measurements.
In this paper will discuss about DP cone meter performance in support metering system in FPSO facilities. DP cone with size 2" and 6" will be tested. The beta ratio used in the testing are 0.45 and 0.75. The testing goals regarding the coefficient of discharge (Cd) curve performance doing in standard test and non standard test. In standard testing, each size of DP Cone meter connected with straight pipeline with 36D upstream length and 19D downstream length without flow disturbance element pipeline. Dp cone meter with size 2" tested with fluid which has Reynolds number 18,000 to 152,000 Re, and also Dp cone with size 6" tested with fluid which has Reynolds number 61,800 to 715,000 Re. In non standard testing, Dp cone meter directs connected with out of plane 90 degree elbow without requirement installation length in upstream and downstream and half of moon orifice plate with 3D upstream length and 5D downstream length. Maximum fluid Reynold number in the testing are 148,000 to 556,000 Re.
The results of testing showing that coefficient of discharge (Cd) Dp cone in standard testing and non standard testing do not change significantly. The curve showing good linearity and good performance. It verifies that Dp cone meter has resistance to swirl effect and poor flow profile. So, this flow meter more suitable with limitation space installation as FPSO
Remanufacturing Abandoned Tubing Based on Self-Propagating High Temperature Synthesis, Its Progress and Field Application Summary
Authors: Qiang Chen , Tao Li , Shouzhi Huang , Weiye Han , Qiang Sun 
Published: October 2017

Abstract
Cost reduction has been a strong tendency in the petroleum industry recently, annually millions of tons tubing is abandoned in China, leading to a huge resource waste. Based on self- propagating high temperature synthesis, abandoned tubing could be remanufactured functionally equivalent and visually indistinguishable compared to a new one, its field application has been launched in the oilfields and significant economic benefits was secured.
This paper presented three parts, first the three-dimensional finite element model was employed to study the maximum stress and residual strength of abandoned tubing corresponding to its wearing depth, failure criterion for abandoned tubing was established; second the alumina ceramic layer was prepared at the inner-wall surface of abandoned tubing based on self-propagating high temperature synthesis and the ceramic-lined composite tubing was obtained, the microstructure, corrosion resistance, mechanical properties and bonding capacity of the remanufactured tubing were evaluated, and finally the field operation of remanufactured tubing in harsh downhole environment was summarized.
The results indicated that the abandoned tubing must meet the requirement of certain criteria before being subjected to remanufacturing technique, that is 1.5mm for the J55 tubing and 2.8mm for the N80 tubing respectively; the bonding force between the steel pipe and alumina ceramic layer was more than 30MPa, the maximum impact energy was 73J, the maximum bending radius was 11m, making the remanufactured tubing capable of working in the harsh downhole environment, field application demonstrated its values, the popularization of remanufactured tubing in the oilfield is taking place.
This paper contributes to better understand the remanufacturing engineering in the perspective of petroleum industry, through the pioneering example and profound insights we are able to explore new horizons and yield more benefits to the long term healthy development of petroleum equipment.
Successful Re-Fracturing Application Using Temporary Gelled Isolation System in a Vertical Well in China
Authors: Wheeler Richard , Mayor J. , Williams V. , Kotov S. , McDonald T. , Guo X. , Zhao Z. 
Published: October 2017

Abstract
To maximize return on investment, many operators choose to re-fracture existing wells as an economic alternative to drilling new wells. While it may improve ultimate recovery, re-fracturing of wells with multiple producing zones can be challenging. Several techniques are available in the market place; each having its own limitations and benefits. The technology discussed in this paper, already implemented in the Western Hemisphere, uses a guar-based gelled fluid for temporary zonal isolation in the annulus. The need for a cost-effective solution for re-fracturing, without using a packer or other downhole isolation tool was identified in the Changqing oilfield in China. The objective was to prove the concept of using a gelled annular isolation technology for re-fracturing in this oilfield for applicability in the Asia Pacific region.
Two candidate wells were selected for re-fracturing based on previously completed methodologies and observed production declines. A two stage vertical well was selected for proof of concept. The original completion used a 5 ½-in. casing, applying multi-stage sand jetting fracturing. The application of the gelled polymer system for re-fracturing utilized the 5 ½-in. casing as an outer tubing and implemented a 3 ½-in. inner string to create an annular space for isolation. The gelled fluid was pumped into the annular space between the inner tubing string and the original casing to isolate existing perforations in the two stages. After the re-fracturing treatment was completed, the gel was broken down and the inner string removed.
Before the job was pumped, laboratory testing and simulation concluded that the gelled fluid would be placed within the pump time of the job and hold for the expected time frame of the fracturing operations. This testing provided detailed operational guidelines on placement time, pump rate, fluid shear rate at bottom hole temperature within the constraints of the wellbore architecture before committing to pump the job. The fluid was successfully placed and maintained isolation during fracturing stages. The inner string was removed from the hole following the breaking of the isolation fluid.
The novelty of this work included the application of using a guar-based gelled fluid as a temporary annular isolation pill in a re-fracturing application in China. In addition, this work proved that an inner completion string could also be temporary and therefore removed after the job was completed to ensure that maximum access to the reservoir was achieved. Finally, this is the first cost effective and simple re-fracturing methodology introduced to this area of the Asia Pacific region.
A Comprehensive Preparation Study for Microbial Nutrient Injection of Microbial Enhanced Oil Recovery: Reservoir Screening and Laboratory Analysis – Case Study Bentayan Field
Authors: Astuti D. I. , Ariadji T. , Aditiawati P. , Purwasena I. A. , Persada G. P. , Ananggadipa A. A. , Dewi U. R. , Khendarsyah D. D. , Rizki R. , Abqory M. H. , Ardianto R. N. 
Published: October 2017

Abstract
This paper demonstrates a comprehensive preparation study of field injection microbial nutrient starting from a quite extensive screening to select a field and wells, followed by a series of laboratory experiment seeking an optimum nutrient for the in-situ microbes through some oil properties examinations after giving the treatment. The laboratory examines many combination of nutrient to formulate an optimum nutrient, and compares oil sample compositions before and after treating at the optimum nutrient. The general screening evaluates field candidates based on the remaining oil in place, average porosity and average permeability for many fields in Indonesia. Having the field candidate is then followed by an Enhanced Oil Recovery screening that is a combination of Aladasani and Bryant methods. Hence, Bentayan Field is chosen and two wells were selected BN-38 and BN-81. We are confident that this field is possibly unfavorable for most EOR methods other than the MEOR. The laboratory experiment observed total bacteria number during the incubation period that was conducted every 7 days with method of Total Plate Count (TPC) on Nutrient Agar (NA) medium for aerobe facultative bacteria and Reinforced Clostridial Medium (RCM) for anaerobe bacteria. The results can be summarized and concluded that the optimum nutrient composition consists of molasses, nitrogen salts of (NH4)2PO4, and phosphate salt of NPK for BN-38 well is different from the one for BN-81 well, especially, the concentration of molasses. The oil composition after the treatment observed by GC/MS, clearly indicates becoming a much lighter composition then the previous to the extent that the heptane plus is degraded up to more than 30%. This irreversible mechanisms consequence to the viscosity reduction of up to 43.68% and 47.83% for BN-38 and BN-81, respectively. In addition, the imbibition experiment using synthetic core samples yield results of ultimate recovery factor of 56% at an optimum soaking time of 7 days for BN-81. Finally, a schematic diagram of field implementation the injection is presented that is much simpler than the microbial injection since does not need a cultivation tank at the surface.
Retention of Silica Nanoparticles in Limestone Porous Media
Authors: Al-Anssari Sarmad , Nwidee Lezorgia. N. , Ali Muhammad , Sangwai Jitendra S. , Wang Shaobin , Barifcani Ahmed , Iglauer Stefan 
Published: October 2017

Abstract
Nanofluids (dispersion of nanoparticles in a base fluid) have been suggested as promising agents in subsurface industries including enhanced oil recovery. Nanoparticles can easily pass through small pore throats in reservoirs formations; however, physicochemical interactions between nanoparticles and between nanoparticles and rocks can cause a significant retention of nanoparticles. This study investigated the transport, attach, and retention of silica nanoparticles in core plugs.
The hydrophilic silica nanoparticles were injected into limestone core as nanofluid of different nanoparticles size (5 nm, and 20 nm), concentration (0.005 – 0.1 wt% SiO2), and base fluid salinity (0 – 3 wt% NaCl) at different temperatures (23, and 50 °C). Deposition and transport of nanoparticles were measured via nanoparticle concentration of effluent fluid, and energy distractive spectroscopy (EDS) measurement on the limestone core.
It was found that silica nanoparticles dispersed in brine (NaCl) solutions are increasingly retained in limestone core as the solution ionic strength increases. On the other hand, less significant retention was measured when the nanoparticles were dispersed in DI water. The EDS measurements also reported the same trend of increased nanoparticles retention with salinity due to larger aggregates that result from the screening effect of the electrolyte on repulsive forces between nanoparticles. Thus, the observed change in surface wettability from oil to water-wet and the increase in oil production that reported in many core flooding laboratory studies are mainly related to the high adsorption rate of hydrophilic silica nanoparticles on carbonate surfaces.
Improve Production in Unconventional Oil Wells Using Artificial Sump Pumping System
Authors: Elmahbes Reda , Quintero Regulo 
Published: October 2017

Abstract
Unconventional oil wells represent a combination of challenges to electrical submersible pump (ESP) systems and can limit the production potential for those types of wells. Unconventional wells with steep decline curves and high amounts of free gas challenge the operating envelop of current ESP systems to economically and reliably produce these wells. The challenges that unconventional wells present for all forms of artificial lift forms are: (a) highly deviated wellbore; (b) high gas-to-oil ratio (GOR); (c) gas slugs; and (d) tight casing. When a large amount of free gas is present in the production fluid, the gas enters the ESP pumps and drastically affects its performance. In many cases the gas can lock the pump, leading to a production cut. This paper discusses a case history for an unconventional field where traditional ESP methods were used as the primary form of lift. The challenges in using this form of lift to economically produce from those wells are also discussed.
The use ofan artificial sump pumping system in unconventional oil wells with steep decline curve and high amount of free gas has a proven record of operating reliably and economically under unconventional wells challenges. Artificial sump pumping systems are configured and designed to fit inside 7-in. casing and bigger to tight casing sizesof 5½ in.through the use of slim-line ESP systems. The artificial sump pumping system uses an inverted shroud to naturally separate gas and block it from entering the pump. This blocking actionprevents the pump from experiencing gas lock due to unpredicted gas slugs. In addition, the system is equipped with a recirculation system to continue cooling the motor during gas slugs, enabling the ESP to continue producing efficiently during slug events. Moreover, a capillary tube could be installed with the system to enhance system run life for wells where corrosion and scale are issues.
This paper presents a comparison between the use of conventional ESP methods and artificial sump systems in unconventional, conventional, and mature fields where free gas and gas slugs are a challenge. The results shows how an artificial sump system improves production from those wells and how it significantly improves ESP run life operating under unconventional challenges. In addition, the benefit of using this system for protecting the motor lead extension during installation especially for deviated well and wells with high DLS. This paper discusses how the system reduced the number of failures and enhanced the run life for wells where corrosion and scale-related failures are an issue.
Fueling Our Future with Gas through End-to-End Integrated Optimisation of LNG Supplying Gas Fields
Authors: Chuah S. M. , Khor Y. Y. , Borhan N. A. , Baghdadi F.. , Adillah B. J. 
Published: October 2017

Abstract
In a complex offshore gas network covering both green and mature fields' production to LNG plants, end-to-end integration is essential in building a portfolio that can maintain output. Often in the course of identifying conceptual development opportunities by individual field, this aspect isoverlooked in the broader context of regional optimization. To provide assurance of production sustainability to meet commercial agreement, it is imperative to formulate a development plan that integrates subsurface and surface elements to accurately quantify the remaining reserves and thus the value of the asset. As such, this paper will focus on the methodology of formulating this optimized development plan to incorporate subsurface and surface network modeling and demonstrate the importance of this system for excellent asset management and future development.
A series of reservoir evaluations has been performed on a simple one-dimensional model and three-dimensional model depicting the gas reservoir performance. The analysis is further enhanced by using subsurface and surface production network modeling. The key advantages of this workflow compared to the conventional field development plan (FDP) approach is that the field capacity is derived based on pressure interface and existing production constraints to capture any backpressure effects for anyinfill drilling or upgrading projects.
In this field example, the integrated network model has resulted in a simpler yet more reliable technical proposal where synergistic opportunities and the associated potential production challenges can be identified.Higher level goals on production attainment and cost avoidance can be achieved through circumventing the potential production hiccups for new development. A detailed analysis workflow using real time data will be discussed as part of technical assurance.The key benefits include full field optimization and opportunities identification,and generation ofa representative business case in a timely manner to meet the demands of managing a dynamic gas system.
Closed Loop Speed Control System of ESPCP with Capillary Tube
Authors: Zhu Shijia , Hao Zhongxian , Wang Quanbin , Zhang Lixin 
Published: October 2017

Abstract
The ESPCP is a new rodless artificial lift, which completely gets rid of rod tubing wearing problems. Because of the higher efficiency of the system, the advantage of energy saving makes the new system used more and more widely in low production wells in CNPC. However, the working condition of system at the bottom of the well is hard to monitor. The pump and the motor are in danger of burning out when the dynamic liquid level is lower than the inlet.
In this paper, we introduce a closed loop control system with capillary tube to solve these problems. The system can monitor the pressure at the bottom of the well, and calculate the dynamic liquid level using downhole pressure and wellhead casing pressure. The system can adjust the speed of the motor according to the dynamic liquid level. In this way, it achieves the closed loop speed control of the motor. The pressure measurement cylinder was located above the pump preventing sand burial. The cylinder and the tube were filled with nitrogen, so the pressure was transmitted through a capillary tube to the sensor on the ground.
We have tested the capillary tube measurement system in the lab, the results of the experiments showed that the error of the measured pressure value was less than 5%. In this design, there is no semi-conductor device at the bottom of the well. So the measurement no longer suffered from the temperature drift of the sensors and the expensive price of high temperature resistance electronic devices. We have used this measurement system with ESPCP in Jilin and Jidong oil field in two wells. The results of the field experiments showed that the system can monitor the downhole pressure continually and it has been running for 4 months. Moreover, we could get two key parameters, downhole pressure and dynamic liquid level, by using this measurement system. It would be helpful for further system failure diagnosis.
The capillary tube downhole pressure measurement system was a cost-saving and stable system. It achieved the closed loop control and prevented the evacuation problem in low production wells. Also it makes contribution to the popularization of Electronic Submersible Progressing Cavity Pump (ESPCP). This paper will present the details of this design and experiments.