bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improved Field Recovery and Drilling Costs in Agiba Using ESP Reversed Y-Tool Dump-Flood Solution
Authors: Al-Kady M. , Selim A. , Omar A. , Ginawi I. , Bahgat A. , Abdelmotaal H. , Botros K. 
Published: September 2016

Abstract
Managing a waterflooding project always has its sets of challenges and associated costs. The use of advanced completions can aid in minimizing such costs, while increasing the field recovery. This study highlights the deployment of an advanced completion in a waterflooding project in a newly developed field located in the Egyptian Western Desert.
Initially, a specific area of the field started to experience a decline in reservoir pressure. The operator decided to drill a new injection well to provide the required pressure support in this area. Unfortunately, the amount of water produced by the field wells was not sufficient to feed an additional injection well. Several solutions were explored to tackle this issue. The most straightforward, but costly, solution was to drill a new water source well. Another proposed method was to rely on a natural dump flood, by perforating both the injection and production zones within the same wellbore. The pressure difference should create a "natural injection" effect. However, the study showed that this method would not provide the required injection rate.
Finally, a novel solution was selected to provide the required injection rate with the aid of an advanced completion. The flow was assisted with an electrical submersible pump (ESP) to control the injection rate. The pressure support was successfully provided by producing water from the producing zone to be reinjected into the target injection zone, all within the same wellbore. The effectiveness of the solution was confirmed with the aid of a real-time monitoring and surveillance system. Later, this aided in optimizing the production of other nearby wells.
Bitumen and Tar Deposition and Tar Mat Formation Accounted for by Multiple Charging, Trap Filling and Fluid Geodynamics
Authors: Mullins Oliver C. , Primio Rolando Di , Uchytil Steve , Zuo Julian Y. , Dumont Hadrien , Mishra Vinay , Pfeiffer Thomas , Achourov Vladislav 
Published: September 2016

Abstract
Deposition of organic solids high in asphaltene content (tar, bitumen) in reservoirs from natural processes is a routine occurrence around the world. Nevertheless, there is a bewildering array of deposition characteristics as shown in recent case studies. Sometimes this tar or bitumen (both are really the same material) is at or near the crest; sometimes it is on interlayers within a heterolithic sequence (baffles) or at the base of the reservoir which can be tens of kilometers away from the crest. Sometimes the bitumen deposition is such that the corresponding formation remains permeable; sometimes the tar zone is totally impermeable. Sometimes the tar at the base of the reservoir represents a more or less continuous increase in asphaltenes from the oil immediately above the tar; sometimes there is a sharp, discontinuous increase in asphaltene content from the oil to the tar. And particularly for upstructure bitumen, sometimes the bitumen is deposited throughout the entire producing interval (in a well); at other times the bitumen deposition is only at the base of the producing interval. This paper shows that ALL of these variable tar or bitumen characteristics can be understood within simple concepts that treat the dissolved asphaltene in crude oils and the deposited asphaltene within the same framework. This framework utilizes simple chemical solution characterisitcs that are formally expressed in the Flory-Huggins-Zuo Equation of State for asphaltene gradients with its reliance on the Yen-Mullins model of asphaltenes. Multiple charges of incompatible fluids lead to asphaltene deposition. The extent of slow, diffusive destabilization from density stacking charge fluids versus rapid destabilization from a secondary lateral fluid front controls much of the characteristics of deposited asphaltene. Consequently, the proximity of the well to reservoir charge points as well as petrophysical parameters of the formations are very important parameters. The ideas herein enable projection of the nature of asphaltene deposition away from a wellbore to other locations in the reservoir. This capability greatly assists the ability to understand the impact of asphaltene deposition on production.
First Autonomous Inflow Control Valve AICV Well Completion Deployed in a Field Under an EOR Water & CO2 Injection Scheme
Authors: Kais Ransis , Mathiesen Vidar , Aakre Haavard , Woiceshyn Glenn , Elarabi Amr , Hernandez Ricardo 
Published: September 2016

Abstract
Enhanced oil recovery (EOR) schemes utilizing CO2 and water injection often experience significant problems and challenges with short circuiting of CO2 gas and water between injectors and producers, thereby leaving significant oil behind. Presented herein is the description and results of a field trial of new downhole flow control technology designed to provide autonomous inflow control of produced fluids from each zone in multi-zone wells.
The new technology deployed involves integrating an autonomous inflow control valve (AICV) and a conventional (passive, non-autonomous) inflow control device (ICD) into a unique 3-position "sliding sleeve", shifted by coil tubing, to allow performance comparison between the two different inflow control devices as well as multiple flow control settings of each type. The AICV was designed (and lab tested) to selectively choke back or shut off flow of free CO2 gas and also high watercut (&gt;99%), thereby significantly improving reservoir sweep and yielding higher oil production. The AICV opens or closes autonomously depending on sensed properties of wellbore fluids. Prior to installing the advanced completion, the multi-zone (vertical) trial well was extensively characterized using PLT and other log data, which was then inputted into a commercially available computer model to help design the AICV and ICD settings. The field trial was designed to evaluate the use of flow control in the EOR scheme over a wide range of flow rates and also to compare the two different flow control technologies at different settings within the same wellbore and reservoir condititions.
This paper presents the results of the world's first field trial of the AICV in a Water and CO2 injection scheme, and the world's first comparison with conventional ICD technology in the same well. In addition to lab tests, the early field trial results of the advanced flow control completion are compared with historical production and PLT data where the zones were comingled (without any downhole flow control). A performance comparison of AICV versus conventional ICD, along with conclusions, implications for other wells in the same field and other fields, and lessons learned, are all presented herein.
Leak Detection and Self Healing Pipelines Using Twin Balls Technology
Authors: Chalgham Wadie , Seibi Abdennour , Lomas Matthew 
Published: September 2016

Abstract
Healing leaks is always a priority in the oil and gas industry and plays a major concern to human safety. The time required to fix any leak has a direct relationship in determining the damages caused to the environment, industry and most importantly the number of lives lost caused by catastrophic pipe failures. Detecting leak size and location in pipelines with higher accuracy present major challenges to operators. This paper presents an innovative solution to detect leaks or potential future leaks and heal them instantly using Twin Balls Technology. The solution is based on establishing a relationship between leaks and its associated sound level. Knowing those sound levels precisely and how they propagate with respect to time from the leak source will help build the solution with higher precision. The solution consists of inserting two flowing smart balls into the pipeline. The first smart ball will be receiving acoustic data thanks to the sensors inside of it. Once the threshold of sound level is surpassed, designed thanks to multiple experiments, the smart ball will send a signal immediately to a second flowing ball responsible of ejecting a healing fluid. The healing fluid will flow towards the leaking outlet and close it instantly, preventing any further damages. Also, the first ball will alert instantly the supervisors via wifi monitoring and text messages describing the leak size and location. Twin Balls Technology could be used in pipelines of different sizes and flowing fluids.
A Pigging Model for Wax Removal in Pipes
Authors: Huang Qiyu , Wang Wenda , Li Weidong , Ren Yijie , Zhu Fangda 
Published: September 2016

Abstract
Pigging is widely used in pipelines for wax removal. However, pigging operation relies heavily on "rules-of-thumb." Because of its complexity, rather limited pigging models were presented to predict the wax removal mechanics in past decades. This work aims to develop a pigging model for wax removal in pipelines. A unique experimental facility was designed and constructed for simulating pigging operation for wax removal in pipelines. This facility comprises five main parts: an experiment system, a wax casting system, a motor and control system, a measurement and data acquisition system, and a special designed pig system. The mixture of crude oil and field wax deposit was cast inside the test section to carry out the pigging experiments with disc and cup pigs. It was found that hardness of the scraping element in pig has a profound effect on wax removal, and this effect depends on the wax thickness on the pipe wall tightly. A pigging model, which could well explain the effects of wax thickness, wax hardness, pipe diameter, pig geometry as well as hardness of the scraping element in pig, was established based on the experimental findings. To the best of our knowledge, this is the first time to incorporate the effect of hardness of the scraping element in pig on wax removal into a pigging model. 17 sets of pigging experiments were used to verify the developed pigging model with an average relative error of 10.69%. The pigging model developed in this work could be a practical tool in designing economic and safe pigging programs.
Managing Competency in a Low Oil Price Environment: SPE Offers an Expanded Competency Management Tool to its Members
Authors: Jain Alok , Donohue Bradford R. 
Published: September 2016

Abstract
In keeping with its mission to provide its members with opportunities to enhance their technical and professional competence, SPE launched a Competency Management Tool (CMT) in partnership with IHRDC in October 2014. In order, to gauge membership interest, this initial release of the CMT included a limited number of key operating company technical jobs. By June 2015, some 1,000 members had used the tool and provided very positive feedback. Encouraged by this response, SPE decided to expand the number of jobs in the tool such that a larger cross-section of its members could benefit from it. This meant expanding CMT's operating company-focus to include drilling contractors, EPC contractors, integrated service companies and the student community. The expanded CMT was launched in late September 2015. It now includes 41 job competency models, 9 disciplines (Production Engineering & Operations, Project and Facilities Engineering, Well Engineering, Health, Safety, and Environment, Subsurface, Business Development - Operating Companies, Business Development - Service Companies and Contractors, Supply Chain, and Entry level Engineers), 308 competency units and over 1,200 training resources. The basic features of the tool have also been enhanced to provide quicker assessment results and easier navigation. Since September 2015, some 1,900 users have accessed the tool, 1,263 of them have started a self-assessment and 210 have completed the self- assessment. It is encouraging to see that the composition of the users adequately represents the broad geographical spread of SPE's membership, and all of the job models are being used, although a higher percentage of users are concentrated in only four or five disciplines. The paper describes how using the CMT will add value for students, young professionals, mid-career or senior professionals, and also for companies that do not have an in-house Competency Management System. The user feedback over the past 18 months has been critically analyzed to develop insights about the use of the tool and whether SPE is meeting its key objectives in introducing the tool. While the overall usage numbers are lower than expected, it is believed that that is a result of lack of awareness about the tool rather than its usefulness. The usage data clearly shows that a higher percentage of users are young professionals and career professionals, the two categories that SPE was specifically targeting for accelerating competency development to address the industry concerns about the "experience gap" stemming from a large-scale exodus of older professionals. As the industry recovers from the oil price shock, the availability of the CMT as a low-cost alternative (free for SPE members) to develop and manage a competent workforce should serve it well to get back quickly on its feet.
Multiphase Flow Meter Performance Evaluation Using Live Hydrocarbon Flow Loop Mimicking Real Field Conditions
Authors: Benlizidia I. , Al Jarri A. S. , Al Anazi M. A. 
Published: September 2016

Abstract
Over the last two decades, multiphase flow measurement (MPFM) has become accepted by the Oil & Gas industry worldwide. Nevertheless, the operators are in a pressing need to assess the measurement performances of each MPFM technology. Generally, this is performed through field trials of one or several MPFM technologies against typically a conventional test separator.
In this paper, we will describe an accelerated new and cost effective methodology to evaluate the metrological performance of a multiphase flow meter in specialized facilities with live hydrocarbons mimicking the real field conditions.
In this methodology, multiphase flow loops are used to reproduce real field conditions with live hydrocarbons fluids where pressure is the key parameter when attempting to mimic real multiphase flow in such controlled environment. Associated with proper test procedure design, these facilities have offered a framework to evaluate multiphase flow meters using live Hydrocarbons under comprehensive conditions in terms of flow regimes, flow rates, phase fractions distributions, salinity, pressure and temperature, ensuring good stability and very high level of accuracy in the reference measurement. The paper guides the reader through the technical considerations required to identify the flow loop test conditions and requirements and set standard procedures from an operator point of view to perform a successful performance evaluation. It also provides case studies where the performance benchmarking obtained in the flow loop has been confirmed and verified in real field conditions.
Using a live hydrocarbon multiphase flow loop for evaluating and quantifying metrological performance specifications for multiphase flow meters has shown to be a very powerful and cost effective tool when associated with proper testing procedure design. This new approach also provides results that are translated to an expected and verifiable performance for real field applications with all their associated complexities.
This paper provides a new testing methodology for any multiphase flow measurement technology where the conventional ways of testing may fail; it also provides valuable insight to multiphase flow meter performance measurement evaluation and specifications definition from an oil operator point of view.
De-risking Polymer Flooding of High Viscosity Oil Clastic Reservoirs - A Polymer Trial in Oman
Authors: Anand Adi , Ismaili AbdulRahman 
Published: September 2016

Abstract
A long term polymer injectivity trial has been conducted in a medium-high oil viscosity field in Oman, with a suite of objectives to assess the feasibility of the high viscosity polymer concept, evaluate alternative polymers and de-risk the low-salinity polymer hybrid for field implementation.
An integrated analysis of this injectivity trial is presented. Performance in the field during injection of low and high molecular weight (MW) polymer in hybrid with low salinity water is analysed along with interpretations of the intermediate water injection, shut-ins, pressure fall-off and step rate test at the end.
The analysis is based on simulation models to history match the pressure response in the injector during the polymer trial. Key realizations focusing on two aspects – polymer rheology and wellbore/reservoir fluid propagation mechanism – are presented that were used to history match baseline water injection, low and high MW polymer injection, low salinity water injection and polymer low salinity water hybrid. Other sources of information – step rate test and pressure fall-off tests conducted during the trial – were interpreted to validate the conclusions from the HM model.
The study highlighted the risks of either inducing fractures or reactivating an existing fracture network in the reservoir during the polymer injection. Different sources of data indicated fracture pressure lower than anticipated. The dynamic characterization of the fractures – propagation and shrinkage – depending on the injection rate, injection fluid type and viscosity are found critical to explain the entire polymer trial response. The study also highlighted that capturing the polymer rheology adequately in the model, based on laboratory data, helps to explain the trial response. Changing well conformance has been found another important parameter in explaining the trial response. Finally, using the baseline water injection to ensure the permeability field is adequately modelled constitutes another step in understanding the polymer trial.
Experimental and Theoretical Study of Water-Solute Transport in Organic-Rich Carbonate Mudrocks
Authors: Padin A. , Torcuk M. A. , Katsuki D. , Kazemi H. , Tutuncu A. N. 
Published: September 2016

Abstract
The objective of this research is to determine the physicochemical processes underlying water and solute transport in organic-rich source rocks. Experiments were performed on Eagle Ford shale samples composed of organic-rich, low-clay carbonates using a high pressure triaxial assembly with novel design. Experimental results were successfully matched with a numerical chemical transport model. The mathematical formulation of this model relies on the chemical osmosis principles driving low-salinity brine into high salinity core samples. The results of this research should be beneficial for design of EOR processes in organic-rich shale.
A custom designed experimental apparatus was constructed to conduct flow tests. The apparatus is capable of maintaining core samples at reservoir pressure, temperature and confining stress. In addition, a new mathematical model was formulated to simulate flow into the core as a porous medium rather than as a molecule-selective membrane. This new model is based on the following principles: (1) the solvent (low-salinity water) selectively enters the pores by diffusion mass transport and (2) the dissolved salt molecules (which are ionized) are restrained by internal electrostatic forces from diffusing in the opposite direction of the low-salinity brine molecules entering the pore network.
The mathematical model closely matches the experimental results and, more importantly, only very few assumptions were made in matching experiments. For instance, the critical model input data, such as permeability, porosity and rock compressibility, were obtained from flow experiments on twin cores, and the diffusion coefficient was chosen by history matching. The strengths of the numerical simulation include: (1) the mathematical model is based on the mass transport fundamental principles, (2) the model does not require the use of the ambiguously-defined membrane efficiency term, and (3) the chemical potential gradient is the reason for the low-salinity brine entering the high-salinity brine cores to generate osmotic pressure within the cores. The latter implies that osmotic pressure is the consequence of water entering the cores, not the cause.
Stress Dependent Permeability of Carbonate Rock
Authors: Hamid Osman , Osman Haytham , Rahim Zillur , Omair Ahmed 
Published: September 2016

Abstract
Permeability is one of the most important parameters in formation evaluation, reservoir characterization, and hydrocarbon production. There are many methods in the industry to model in-situ permeability, but it is also critical to know that permeability decreases with the increase of effective stress as has been reported in many case studies i.e. permeability is sensitive to changes in stress and pore pressure. In this study, a relationship between permeability, porosity, velocity and effective horizontal stress is developed for carbonate reservoirs using both core and field data.
In-situ horizontal stress is related to permeability for several reservoirs around the globe. This paper addresses fundamental controls on stress dependent permeability, as identified through analysis of core samples. The model developed provides a description of effective stress and explains the dynamic impact of geomechanical stresses on key production parameters in an effective way. This will lead to a more robust simulation model and history match for the life of the reservoir.
Core plug samples from carbonate formation were tested for conventional measurement (porosity, permeably, and grain density), while acoustic slowness is obtained by wireline and/or LWD measurement to create empirical correlations between permeability, porosity, velocity and effective stress. The correlations show a good agreement with available data that are commonly used in the industry for carbonate.
The developed workflow is presented to improve evaluation and enhance the productivity and management of stress-dependent reservoir, also predict sweet spots, optimize completion and predict production that will help in the development of both conventional and unconventional reservoirs.