bluuebunny/crossref_metadata_2025_split huggingface dataset:
Waterflooding Heavy Oil Reservoirs with Horizontal Wells: Field Examples from Canada
Authors: Delamaide Eric 
Published: October 2018

Abstract
Very few papers describe waterflood projects in heavy oil reservoirs, and even less that involve the use of horizontal injectors and producers. A few years ago, Beliveau presented a review of waterfloods in viscous oil in several pools mostly in Canada and demonstrated that excellent results can be obtained in most cases, but he mostly focused on pools with vertical wells. The purpose of this paper is to present results of several heavy oil waterfloods in Canada that use horizontal producers and injectors.
The production performances of eight heavy oil pools where waterflood has been implemented using horizontal wells have been studied. The pools are thin and bottom water is present in some of them; oil viscosity ranges from a few hundred to a few thousand centipoises. The overall performances of each flood will be discussed and compared to other heavy oil pools where waterflood is implemented with vertical wells. In addition, more detailed analyses will be performed in some patterns to better evaluate the impact of bottom water, well length, spacing and other factors on the flood performances.
As could be expected, water breakthrough is generally fast, within a few months from the beginning of injection; but more surprisingly, Water Oil Ratio can often remain stable for long periods of time. Ultimate recovery is expected to vary from a few percents OOIP to over 20%OOIP. Similarly, to waterfloods with vertical wells, a large portion of the reserves can be recovered while producing at high Water Oil Ratio.
This paper will present results of several waterfloods in heavy oil reservoirs in Canada which use horizontal wells. There are very few such field cases in the literature thus the information provided will be of interest to engineers who are considering waterflood as a follow-up to primary production in heavy oil reservoirs developed with horizontal wells.
Sand Prediction for a Cost-Effective Marginal Green Field Development
Authors: Mohd Hatta Siti Aishah , Zawawi Irzee , Gupta Anish , Ahmad Nadzri M. Safwan , Salleh Nurfarah Izwana , Jeffry Suzanna Juyanty , Sharif Natasha Md , Ishak Izza Hashimah , Maoinser M. Azuwan 
Published: October 2018

Abstract
Field B is a marginal green field located offshore Sarawak, Malaysia with formation depth of less than 1000 meters. The compressional sonic transit time range is from 100 – 115 μs/ft, which immediately triggered the possibility of using active downhole sand control as this range is assumed to be unconsolidated. However, the rock mechanical strength characterization tests from sidewall core indicated contradictory result of a consolidated formation. Since the field is considered as a small field, the cost of the well especially on downhole sand control device need to be extensively optimized. Hence, sand prediction study for a small green field development using field and laboratory measurements was performed.
Several methodologies of sand prediction were utilized to evaluate the optimum sandface completion and sand control management for the field. Empirical and analytical sand prediction based on the well logs, sidewall cores analysis, and sand prediction software are employed to evaluate the likelihood of sand production and the optimum well completion design for the field development. The available data from appraisal wells of Field B is also calibrated to the nearby brown field, Field A that has been producing for more than 30 years.
This paper will discuss on the sand onset prediction results between full perforation versus oriented perforation, and pressure depletion impact on the sand production. The study shows that the formation is not prone to sand production especially in the early part of the production life with high reservoir pressure and low watercut. The expected Critical Drawdown Pressure (CDP) generated from different methods show large variation of sand onset pressure if the sandface is completed using full perforation. Oriented perforation tremendously expands the sand free drawdown limit. Based on the results of the study, expected reservoir pressure depletion and watercut, the completion of the wells adopted Oriented Perforation with no other downhole sand control equipment.
This paper is beneficial for petroleum and well completion engineers especially on sand prediction part of well completion design in development stage. This will assist in ensuring the field meets the EUR and bring forward economic value as well as well integrity assurance.
A Case Study on Drilling Complicated Infill Horizontal Wells in Low Cost Environment: Challenges in Well Construction and Its Successful Mitigations
Authors: Singh Ankit , Goyal Abhinav , Hiregoudar Ashita , Tomar Gaurav , Sharma Anurag , Katre Anurag , Doodraj Sunil , Vermani Sanjeev 
Published: October 2018

Abstract
This paper presents a case study of drilling of three horizontal wells, drilled as a part of fifteen wells onshore in-fill drilling campaign in a highly dense field, with 300+ wells in a span of 14 sq. km. The well design aspects, directional planning and implementation of innovative parameter monitoring tool for efficient drilling operation and accurate well placement is discussed in detail. Additionally, paper discusses in detail, re-engineering and limit extension of cold-stacked 1000 HP drilling rig to achieve the drilling objectives.
"Measure & Manage" approach was practiced at each and every stage while planning these wells to make them "drillable" utilizing the existing resources. To drill these complicated horizontal wells, a 1000 HP drilling rig which was in cold-stack condition was the only available option. The rig was made fit for successfully drilling these complicated horizontal wells by planning and optimizing the utilization of rig equipment viz. mud pump, rig tubulars, top drive etc. within its safe working & endurance limits. The well path was finalized after multiple iterations to ensure the well trajectory is free of collision threats from nearby drilled wells and also geological objective of draining the zone of high oil saturation is achieved hand in hand. Detailed Torque and Drag (T&D) and hydraulics model was prepared and analyzed for each operational step and every hole sections to identify the correct boundary line parameters for each operation. Based on these analyses bottom hole assembly (BHA) and bits were selected to deliver best possible ROP & directional control. All the drilling parameters critical to the operation were measured and monitored using"drilling parameters dashboard" to ensure that they are within the boundary limits as defined while planning the well. Friction factors were modelled, calibrated and measured on every trip to judge the hole condition for subsequent operations. Geo-steering was implemented while drilling the drain hole section of the wells for accurate well placement into the reservoir.
As a result of detailed step by step planning, accurate measurement and meticulous approach the three horizontal wells, which appeared practically undrillable with the available drilling rig & associated resources on first look, were drilled successfully. The actual time taken to drill these wells was within the planned time and within the allocated budget.
Risk Factors Affecting Delays in Upstream Natural Gas Mega-Projects: An Australian Perspective
Authors: Basak Munmun , Coffey Vaughan , Perrons Robert K. 
Published: October 2018

Abstract
The rapid expansion of the Australian gas industry has seen massive investment in mega-projects, but benefits from this have been impeded by the impact of severe project delays. Risks causing delays in upstream mega-projects are high, leading to frequent cost and schedule overruns. However, the absence of research concerning delays during this complex phase of mega-projects provides the opportunity to critically examine underlying challenges experienced by various project participants involved in upstream gas projects in Australia.
Data was gathered through an extensive literature review, interviews with industry experts, and a survey. A list of risk factors extracted from the literature was checked with industry experts for relevance in upstream mega-projects, and missing risks were added. The survey was circulated to a random sample of people working within the natural gas projects domain, including clients, consultants, and contractor organisations. Using Likert-style five-point scales, participants rated the frequency of occurrence and severity of each of the risks impacting delays.
A total of 70 risk factors were identified, which were then traced back to 10 risk sources that impact delays in upstream gas projects. The findings reveal that 72% of participants believe that the average delay in gas projects is between 10% and 30% in Australia. Moreover, 93% of participants mentioned that schedule slippage in the upstream phase causes severe challenges in attaining "first gas" and results in overall project delays. Based on the frequency of occurrence and severity indices, the magnitude of risk factors and sources was used to ascertain critical risks causing major delays. Kruskal-Wallis and Mann-Whitney U tests were applied to check the differences in perception of risk criticality influencing delays among the participants, who differed depending on work experience, job position, and the type of participants’ company. These tests indicated a good association in such perceptions. Key risk factors causing major delays included frequent change orders being issued by clients, unrealistic time schedules imposed on contracts, and poor organisational structures.
Risks in mega-projects cannot be eliminated completely. However, a more precise identification and prioritisation of risks causing major delays, along with differences in risk perceptions of various project parties, will provide an informed and broader perspective to industry practitioners and stakeholders in managing risks more effectively to reduce upstream gas project delays.
Structured Approach in Qualifying Cement Isolation Through the Use of Cementing Scorecard and Post-Job Execution Data
Authors: Heu Tieng Soon , Wee Anson , Combe Caroline , Mohd-Radzi Razif , Zhang Ting-Ting 
Published: October 2018

Abstract
Conventional ‘textbook’ primary cement job execution has always been associated with the combination of bumping top wiper plug, successful casing pressure test and/or no losses during the job. These criteria have been referenced by the general industry as positive indications and conveniently adopted as qualification for a successful cement job without considering other key parameters that contributes to proper cement isolation behind casing. In a deepwater development campaign offshore Malaysia, cement isolation behind the 9-5/8" production casing serves as critical barrier to ensure well integrity throughout the production lifecycle. To achieve this, the authors have deployed a structured approach focused on designing for success and optimizing a set of key performance indicators (KPIs) with pre- and post-drilled hole conditions. This paper outlines the approach based on the experience from the drilling campaign of nine oil producer wells.
Simple Numerical Simulations to Demonstrate Key Concepts Related to Coal Seam Gas Well Integrity
Authors: Rodger Iain , Garnett Andrew , Hurter Suzanne 
Published: October 2018

Abstract
Many stakeholders are concerned about the effects of Coal Seam Gas (CSG) developments on aquifers. Well integrity issues are often mentioned as potential leakage pathways which could lead to aquifer contamination or depletion.
This study involved the creation of simple models to represent the behaviour around a producing CSG well with a well integrity failure. A range of realistic scenarios were chosen, representing hypothetical well integrity failures at different stages of CSG production. Dynamic numerical models were built that represent each scenario, and simulations were run to forecast the flux of fluids around the wellbore. These models were parameterized based on data from literature related to well integrity studies, and should represent reasonable worst-case scenarios. The results of simulations using these models are then used to explain key concepts relating to well integrity in CSG wells in a manner which can be understood by interested parties from non-technical backgrounds.
The simulation results based on these simple models indicate that well integrity issues in producing (or previously produced) CSG wells are unlikely to have any significant impact on overlying aquifers.
Polymers and Their Limits in Temperature, Salinity and Hardness: Theory and Practice
Authors: Delamaide Eric 
Published: October 2018

Abstract
Polymer flooding is a mature Enhanced Oil Recovery process which is used worldwide in many large- scale field expansions. Encouraged by these positive results, operators are still looking at applying the process in new fields even in the context of low oil prices and are evaluating its feasibility in more challenging reservoir conditions: high salinity, high hardness and high temperature. Several solutions have been proposed to overcome the limitations of the conventional hydrolyzed polyacrylamide (HPAM) in these types of challenging environments: biopolymers such as xanthan or scleroglucan, associative polymers, or co- or ter-polymers combining acrylamide with monomers such as ATBS or NVP. Each of these solutions has its advantages and disadvantages, which are not always clear for practicing engineers. Moreover, it is always interesting to study past field experience to confront theory with practice. This is what this paper proposes to do.
The paper will first review the limits of conventional HPAM and other polymers that have been proposed for more challenging reservoir conditions. But more than that, it will focus on the field experience with each of these products to establish some practical guidelines for the selection of polymers depending on the reservoir and fluid characteristics.
One first result of this review is that the limits of conventional HPAM may not be as low as usually expected. Biopolymers appear very sensitive to biodegradation and their success in the field has been limited. Associative polymers appear better suited to near-wellbore conformance control than to displacement processes and some of the new co and ter-polymers are currently being field tested with some measure of success. It appears that the main challenge lies with high temperature rather than high salinity; some field projects are currently ongoing in high salinity (200 g/L) and hardness.
The paper will help set the current limits for polymer flooding in terms of temperature, salinity and hardness based on laboratory work and field experience. This will prove a useful guide for practicing engineers looking to pilot polymer injection in challenging reservoir conditions.
An Innovative Artificial Lift Technology for Severely Scaling Wells Applied Successfully in Asp Flooding in Daqing Oilfield
Authors: Chen Mingzhan , Cheng Jiecheng , Zhou Wanfu , Huang Youquan , Sun Xiaoming , Cao Gang , Han Song , Wang Guoqing , Jiang Tao , Li Ping , Wang Yanyan 
Published: October 2018

Abstract
Scaling issue of artificial lift systems is the main bottleneck for ASP flooding, and has considerably negative influence in commercial stage. In the past decade, different anti-scaling technologies have been developed and applied in Daqing Oilfield. However, high pump failure still exists in severely scaling producers. This paper presents an innovative artificial lift method – a patented bailing pumping unit production system, which has been applied successfully in field test stage in Daqing Oilfield.
The system consists of soft plunger, special designed wire line, winch system and surface control. Produced liquid mixed with large quantity of scale particles is lifted to surface by the soft plunger connected to wire line. The plunger is made of high molecular materials and steel skeleton support which ensures good flexibility and reliability after long term of operation in abrasive environment. The wire line is specified designed and processed to enhance operation life. It connects downhole gauge and surface control. Down hole pressure can be monitored in real time, which provides references for adjustment.
This innovative bailing pumping unit production system has been applied in 80 wells in 3 ASP flooding blocks with severe scaling issue in Daqing Oilfield. The average running life was improved from several weeks to 710 days. Considerable benefits have been achieved by the 60% operation cost decline. It has been the premier artificial lift method for the severely scaling producers. Additionally, there is no need for flushing or acidizing treatment to deal with scale deposited in downhole pump, rod string, and tubing string compared with pumping unit production system in ASP flooding, which significantly reduces normal management intensity and cost.
Field test showed that this innovative bailing pumping unit production system has outstanding scale resistance capability for severe scaling wells in ASP flooding. It also provides a great reference for other oilfields in worldwide with similar issues both in ASP flooding and high salinity conditions.
An Improved Production Data Analysis Method for Shale Gas Wells
Authors: Pang Wei 
Published: October 2018

Abstract
Production data analysis (PDA) is a very useful methodology to conduct transient rate and pressure analysis for shale gas wells. However, frequent shut-ins as well as nozzle size changing and well interference often occur for shale gas wells in China. This leads to abrupt changes, fluctuation, or even loss of production data. The existing PDA methods are incapable of addressing this issue.
A new PDA method is proposed to solve the above problem. First, the model for shale gas wells is established and solved by Duhamel's principle and Laplace transform. The log-log curve curve for PDA is obtained. Second, the formation pressure distributions and the average formation pressures within the SRV area are calculated. Then, a virtual equivalent time is proposed by use of the average formation pressure. Thus, the production data with abrupt changes can be converted into several interconnected segments with known initial formation pressures. Numerical validations and field cases are conducted to verify the proposed method.
For the field shale gas wells with several abrupt rate and pressure changes, the history matching provided by the commercial software with a skin factor agrees with the field data before the first shut-in. However, the estimated pressure and gas rate start to deviate from the field data continuously since the first shut-in, and the deviation becomes greater over time. Particularly after the third shut-in, the deviation is too large to history matching. The offset is mainly caused by significant discontinuities and subsequent cumulative errors. On the contrary, the history matching of pressure and gas rate with correction by virtual equivalent time are both in good agreement with the field data. This implies that the issues caused by abrupt changes or significant discontinuities of production data are satisfactorily addressed. Therefore, the results interpreted from the PDA such as fracture half-length and SRV are more accurate and confident.
Where the Laterals Go? A Feasible Way for the Trajectory Measurement of Radial Jet Drilling Wells
Authors: Huang Zhe , Huang Zhongwei , Su Yinao , Li Weichang , Jiang Tianwen 
Published: October 2018

Abstract
Radial jet drilling (RJD) is an unconventional drilling technology to drill multiple radial laterals by using a high-pressure liquid jet. It is a cost-effective alternative to bypass damage zones near the wellbore, restimulate the production of old wells and develop the unconventional reservoirs. However, due to the structure of the deflector and the diameter of the radial laterals, traditional well-trajectory measuring tools cannot be applied in the RJD wells. It hinders the conduct of some significant operations. The unknown trajectory is a crucial limitation to further development and field application of the RJD technology.
In this paper, except an introduction of RJD technology, a measuring system and a mini-tool were proposed for the attitude measurement and motion state recognition. Based on the navigation theory, a reckoning method of the trajectory was established. After that, an experiment study was carried out to test the performance of the measuring tool and the reckoning method. As results of the experiments, the average errors of the measured lateral length, inclination and azimuth are 8.12%, 5.10% and 5.10% respectively.
Study on Wax Removal During Pipeline-Pigging Operations
Authors: Li Weidong , Huang Qiyu , Wang Wenda , Ren Yijie , Dong Xue , Zhao Qi , Hou Lei 
Published: October 2018

Summary
Widely used as it is, pipeline pigging still holds ambiguities in its mechanisms. In this paper we explore the nature of the wax removal process with a unique pigging facility. Solid wax content, yield stress, viscoelasticity, and microscopic characteristics of wax samples are thoroughly studied with differential-scanning-calorimetry (DSC) trials, rheological tests, and microscopic observations. We found that the relative solid wax content is approximately linearly dependent on temperature, and yield stress can be well-fitted with wax content in an exponential format. An investigation on wax-breaking force indicates that it increases with solid wax content. Wax removal efficiency increases with wax thickness and pipe-wall temperature, decreases with a wax-mixing ratio and solid wax content, and it varies irregularly vs. the scraping-element hardness in the pig. Furthermore, a prediction model of wax removal efficiency was developed on the basis of nondimensional analysis. The absolute average deviation of verification experiments against this model is 5.22%. This model might benefit in estimating the wax-scouring capacity of the wax-in-oil slurry and, therefore, helps to avoid wax blockage and to arrange the pigging program.
Advantages of TiO2/carbon nanotube modified photocatalytic membranes in the purification of oil-in-water emulsions
Authors: Veréb Gábor , Kálmán Viktória , Gyulavári Tamás , Kertész Szabolcs , Beszédes Sándor , Kovács Gábor , Hernádi Klára , Pap Zsolt , Hodúr Cecilia , László Zsuzsanna 
Published: October 2018

Abstract
For the effective purification of emulsified oil contaminated waters advanced treatment methods have to be applied, such as membrane filtration, which is able to eliminate macro-, and even nanoscale oil droplets, however, membrane fouling is still a major problem, which prevents economic utilization. Therefore, fouling mitigation is one of the most important aspects in the field of membrane separation developments. In the present study, solely TiO2 and TiO2/carbon nanotubes (CNT) composite modified PVDF membranes were prepared and used to purify oil-in-water emulsions. Achievable fluxes, reversible and irreversible filtration resistances, fouling models, filtration efficiencies and photocatalytic activities were compared in case of different nanomaterial covered and unmodified PVDF membranes. Applying either solely TiO2 or solely CNT coating resulted in the significant reduction of total filtration resistance in both cases, but the combination of the two components (TiO2 with 1 wt% CNT) resulted in by far the highest flux and lowest resistance, meanwhile, the enhanced photocatalytic efficiency of the composite was also achieved. To the best of our knowledge, this study demonstrates the beneficial effects of the combination of TiO2 and CNT nanomaterials for the first time in the field of membrane separation of oil-in-water emulsions.