bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integrated Surface Facilities Management: Continuous Production Optimization
Authors: Di Sarra Andrea , Scaramellini Sara , Cerri Paolo , Pellegrini Simone , Viadana Giorgio , Bianco Amalia , Buongiorno Nicola , Masi Silvia 
Published: December 2014

Abstract
Production Optimization is one of the most complex and multi-disciplinary task in the oil & gas industry from an operational point of view. Optimization involves surface asset all along its production life and requires a continuous improvement process. Improvements, modifications, and temporary upsets in surface facilities during operation phase create the necessity to manage and optimize production scenarios with a more tight time-frame.
Technology improvements have enabled a widespread use of integrated simulation models for a better asset management to be fully combined with measured field data. This paper shows a dedicated workflow for surface facilities – gathering system and process plant - production enhancement and management using an advanced optimization technique based on a biogenetic algorithm.
The main feature of the proposed workflow is the ability to control many variables simultaneously according to the system constraints even with complex, conflicting, and non-direct interconnections and objectives to be reached. The workflow and the optimization approach are included in a wider integrated tool for production management, called rabbit™ - Risked Algorithm for Biogenetical Balance Integration Tool. Other features of this tool, such as transient phenomena and risk analysis evaluations, complete the ability of the tool to support the production and operation management. This paper will provide a useful description of how the tool can contribute in definition of field potential, production optimization and planning, minimizing production losses during planned/unplanned upsets as well as supporting debottlenecking activities.
It will provide some case studies of rabbit™ implementations on different oil and gas fields, both on-shore and off-shore, showing benefits on using the integrated workflow.
Monitoring and Confirming Full Activation of Hole-Enlargement-While-Drilling (HEWD) Tool using MWD Real-Time Data. A process developed by the Operation Support Center.
Authors: Al-Saadi Murad , Khambete Shreepad , El-Masri Hassan , Day Tim , Al-Awadhi Farhaad Khaled , Al-Hussieny H. , Karim Hassan Abdul 
Published: December 2014

Abstract
An operator in the Middle East planned to drill and perform a hole-enlargement-while-drilling (HEWD) operation in hard carbonate formations with an unconfined compressive strength (UCS) between 20,000 and 35,000 psi [138 to 241 MPa]. The main concern from the operator was ensuring that the hydraulic reamer was fully activated while drilling ahead.
Downhole logging-while-drilling (LWD) tools that provide real-time caliper data cannot be run above the reamer because of the operational requirements of both the reamer and the LWD caliper tools. The reamer requires a small plastic ball to be dropped through the inside of the drillpipe to activate the reamer and, consequently, placing a real-time caliper tool above the reamer would prevent the ball from reaching the reamer. Additionally, such a configuration would prevent electrical signal communication between the LWD tool and the real-time data transmission available at the measurements-while-drilling (MWD) tool. Hence, it was not possible to use real-time LWD data to confirm the reamer activation, and an alternate method had to be developed.
A new process was developed to monitor and confirm the full pad activation of the reamer. When the reamer is not activated, then 100% of the flow passes through the reamer, MWD tool, and drill bit. However, when the reamer is activated, then 20% to 30% of the flow is diverted through the HEWD tool to open the pads and cool and lubricate the cutters. The process ensures activation of the underreamer using the relation between MWD turbine RPM and flow. Alarms built into the monitoring software are triggered under certain conditions to alert the system operator to the expanded or retracted state of the underreamer. The operator can quickly check flow conditions and make adjustments to change the state of the underreamer. The process was used to perform a successful HEWD run with a BHA that included a rotary steerable system (RSS), MWD tool, an underreamer, and a 14.5-in. drill bit. The BHA delivered a high-quality in-gauge borehole and met all directional objectives, holding tangent at 19° inclination and 94° azimuth.
Pipeline Internal Damage Prediction by Deterministic Models and Neural Networks
Authors: Gabetta G. , De Masi G. , Gentile M. , Vichi R. , Scapin M. 
Published: December 2014

Abstract
Internal corrosion is a crucial issue for the safe operation of oil&gas pipelines. Corrosion in pipelines is due to interaction of several mechanisms and parameters, as for instance: electrochemistry, water chemistry, protective scales, flow velocity, steel composition, localized bacteria attacks, and more. The phenomenon is very complex and despite the large number of models proposed in literature, rarely can be reproduced and/or predicted for fit for purpose estimates.
In this paper, available corrosion models were examined and compared with field case data. The need for implementation with more parameters was pointed out, and an attempt to define a comprehensive approach was pursued. An ideal model shall be able to describe the evolution of a corrosion situation in time and in space (along the pipeline).
Fluid velocity and flow regime as a function of pipeline length were taken into account, and available Water Wetting models were also implemented. Model results were compared and calibrated with intelligent pig inspection results, corrosion rate and thickness measurements. To a better understanding and a more accurate prediction of the phenomenon, the implementation of more sophisticated mathematical analysis tools (ANN, Artificial Neural Newtorks) was also suggested. A first case study shows that a ANN based model can outperform the deterministic ones.
Success Case History of Well Pressure Balance Estimation based on Gas Trend in Ultra HPHT Wells
Authors: Tanaka Hisaya , Stuart Colin , Vigor Herve 
Published: December 2014

Abstract
Reducing pore pressure (PP) uncertainties during exploratory drilling operations remains a challenge especially with limited offset information available. Estimation of a pore pressure range while drilling based on gas trend is a recommended method for managing mud weight and to estimate margin of overbalance. Drilled and swab kicks still occur in HPHT wells with alarming frequency. Much can be done to reduce the chances of this occurring and in this paper we discuss some recently applied mud weight management techniques. While Managed Pressure Drilling is a significant advance in managing bottom hole pressure, there are surface equipment limits, and complex operations management controls to be defined. Therefore, in many future HPHT projects conventional overbalanced drilling will still be required. While maintaining attention on PP estimation is the focus of this paper, experience shows that minimum MW for borehole stability can sometimes be overlooked in HPHT wells if the sole focus is on well control aspects.
In the following example HPHT wells where downhole temperature exceeded 400degF and downhole pressure exceeded 10,000psi, drilling operations were carried out successfully by applying well pressure balance estimation based on gas trends. The key points and recommendations for this method are introduced in this paper. In the case study, three examples of gas trend interpretations with example data are described.
Increasing Depth of Penetration by Electrokinetic Driven Low-Concentration Acid IOR in Abu Dhabi Tight Carbonate Reservoirs
Authors: Ansari Arsalan A. , Haroun Mohammed , Rahman Md Motiur , Chilingar George V. 
Published: December 2014

Abstract
Conventional acidizing, though useful in increasing the effective permeability in the near well-bore region, has compatibility and operational issues such as limitation in depth of penetration and HSE issues to handle, transport and injection of high concentration of acid into the well. On the other hand, the application of electrokinetics (EK) has a number of economic and environmental advantages such as reduced oil viscosity, reduced water-cut, and no depth limitation. This paper presents recent research that demonstrates the impact of EK on matrix acid stimulation in carbonate reservoirs with varying acid concentrations and voltage gradients.
Core-flood tests were conducted by saturating core-plugs retrieved from Abu Dhabi oilfields with medium and light crude oil in a specially designed core-flood setup. Initially, EK was applied using acids of varying concentrations up to 1.2% HCl injected at the anode to cathode (producer) at 0.25ml/min. Experiments were also repeated with low concentration HCl stimulation without the application of EK.
Several correlations related to acid concentration, displacement efficiency and permeability enhancement are presented here at ambient and reservoir conditions on aged oil-wet core-plugs. The experimental results have shown that the application of waterflooding on the carbonate cores yields an average oil recovery of 60%. An additional 17-29% oil recovery was enhanced by the application of EK-assisted low concentration HCl-IOR (EK LA-IOR). In addition, EK LA-IOR was shown to enhance the reservoir's permeability by 32% on average across the tested core-plugs. It was observed that low acid concentration with application of low voltage EK, recorded a maximum oil displacement of 81% at reservoir conditions. Furthermore, this technique can be engineered to be a sustainable process in the presence of EK as the concentration and voltage gradient can be optimized to reduce the amount of acid injected and power consumption by 20-41%, further improving economic feasibility.
Optimal Waterflood Voidage Management Significantly Increases Oil Recovery with Minimal Incremental Cost
Authors: Vittoratos E. Steven , Zhu Zhouyuan , West C. C. 
Published: December 2014

Abstract
Empirical data, laboratory experiments, and mathematical simulation methods indicate that for many heavy oil waterfloods the optimal voidage replacement ratio (VRR) is less than one. Many more recovery mechanisms are activated with VRR&lt;1 than with VRR = 1. Some are readily understood with existing conventional reservoir engineering concepts, while others invoke emulsion & foamy oil multiphase flows that are activated under changing reservoir conditions. Not all the consequences of VRR&lt;1 are positive for recovery. In aggregate, however, as displayed in empirical observations, VRR&lt;1 can result in a significant increase in reservoir oil recovery, particularly for the heavier oils.
This paper focuses on the quantification of the relative importance of the mechanisms activated by VRR&lt;1 in saturated or nearly saturated reservoirs. The absolute value of the VRR&lt;1 depends primarily on the oil quality and its associated properties, whereas the optimal time evolution of the VRR depends on the well spacing and the reservoir heterogeneity of the depositional environment. Numerical simulations have ranged from simple 1D models to a detailed fluvial depositional environment model. The role of relative permeabilities are demonstrated by the 1D model. The 3D field models of increasing geological complexity are useful for quantifying the incomplete waterflood sweep, and the role of VRR &lt; 1 in activating solution gas drive to deplete the ‘cul-de-sacs’ of bypassed oil. We also propose here a numerical model to incorporate emulsion flow behavior into heavy oil water flooding, calibrated using data from a large scale (‘big can’) experimental waterflooding study of a heavy oil prone to emulsion formation. The methodologies developed in this study show that for heterogeneous heavy oil reservoirs the incremental recovery expected from an optimized VRR &lt; 1 process is similar to that of other commercial IOR processes such as polymer flooding, but with very little incremental cost.
Microporosity: Characterization, Distribution, and Influence on Oil Recovery
Authors: Fullmer Shawn M , Guidry Sean A , Gournay Jonas , Bowlin Emily , Ottinger Gary , Al Neyadi Abdulla , Gupta Gaurav , Gao Bo , Edwards Ewart 
Published: December 2014

Abstract
Microporosity is very common in limestone reservoirs globally and is especially significant in many large Mesozoic reservoirs in the Middle East. Despite its common occurrence there is:
Wide variation in its definition, Uncertainty around characterization, genetic controls, and distribution A rudimentary understanding of its influence on reservoir performance and hydrocarbon recovery.
The results of this study, based on a global survey of microporosity and specific Middle Eastern case studies, provide clarity on each of these topics.
One volumetrically significant type of microporosity occurs between micron size subhedral crystals of low magnesium calcite in matrix and within grains. This micro-pore system is very homogenous in terms of pore size distribution with 90% of pores between 1 and 3 microns in diameter. Pore throat radii range between 0.1 and 1.5 microns. Porosity, permeability, and capillarity relationships reflect this homogeneity for rocks dominated by microporosity. Rocks with less than approximately 80% microporosity exhibit a marked increase in pore system heterogeneity.
A pore geometry characterization approach incorporating digital image analyses of petrographic thin-sections was developed and provides a very effective means of rapidly characterizing and quantifying the total pore system, including microporosity.
The lateral and stratigraphic distribution of microporosity is systematically related to the distribution of depositional facies and the regional extent of burial diagenetic processes. Factors that inhibit burial diagenesis, such as hydrocarbon charge, also have a strong influence on the nature and distribution of microporosity.
Remaining oil saturation in microporous limestone, as measured from centrifuge capillary pressure and steady state (SS) core flood experiments, is negatively correlated with the percent fraction of microporosity. Due to the homogenous nature of the micro-pore system, rocks dominated by microporosity have more favorable oil recovery than rocks with mixed pore systems. In the specific cases studied here, water provides more favorable recovery than gas. These results have implications for resource assessment, field development planning and optimization of ultimate recovery in limestone reservoirs with significant microporosity.
Rotating Sand Screens to TD in Korchagina ERD wells
Authors: Valisevich A. , Zvyagin V. , Wilson K. , Bayanova A. , Shapovalov A. , Huseynov M. , Moen T. , Jaruga P. , Hansen S. , Hanley P. 
Published: December 2014

Abstract
To extend areal coverage for maximum reservoir contact from a single offshore platform, Korchagina oil field is developed with Extended Reach (ER) wells with MD up to 8km, TVD 1.5km. The main target of Korchagina field is Neokomian sandstone formation with large gas cap that necessitates field development with horizontal ICD sand screen completions to minimize early gas breakthrough.
In 2011 a task was set to work out set of solutions that would convey ICD sand screens to TD in Korchagina ER environment, with openhole coverage up to 5000m, and to design completion elements around these solutions.
At planning phase industry expertise – completion practices in projects operating in similar ER environment was reviewed, and existing to date technologies to complete ER wells were analyzed.
Existing technologies and practices did not provide sufficiently robust and flexible solutions for Korchagina ER environment. Hence, innovative solution was proposed – Rotating sand screens to TD, with contingency to run in stages if rotation limit is expected to be exceeded based on drilling results.
Further, design of completion equipment was reviewed to accommodate high torque and rotation capability: direct wrap sand screen media with proven sand retention performance in high torque; integral centralizers, to transfer rotational motion at contact points to reduce drag; high torque connections. Paper discusses in details the solutions proposed and design of completion equipment.
In 2 years 11 ERD wells were completed with TD reaching 7996m MD at 1565m TVD and openhole coverage up to 4700m. Of these 11 wells, in 3 wells actual friction factors came low enough to allow completion run conventionally, in 8 wells rotation was required at 800m-3000m off TD. The results are presented in the paper.
Based on successful results of application, rotation is set as requirement for completion design for all the wells of current Korchagina field.
Journey of a Technology from Lab to Readiness for Field Application: Enzymatic CaCO3 - A Novel, Environment-friendly System for Conformance and Sand Consolidation
Authors: Bansal B. , Morkved M. , Javadi M. S. , Dorthe P. , Monberg J. , Bähring S. , Nielsen T. 
Published: December 2014

Abstract
Long horizontal wells are hydraulically fractured or acid stimulated to economically develop chalk reservoirs in the North Sea. To separate the zones and ensure conformance, each fracture or zone is separated by isolation packers and flow is controlled with a sliding sleeve. With time, conformance control capability of the lower completion may be lost if the sliding sleeve is stuck open or holes are eroded or corroded in the lower tubing. If a shortcut has developed between an injector and producer, either during stimulation or operation of the well, the consequence of losing conformance capability of the lower completion is more severe. Another scenario with serious consequences occurs when the well has been hydraulically fractured with proppant and the proppant is back-produced without a possibility to close off the zone.
To mechanically fix this conformance issue, it would require working over the well and replacing the lower completion. In an old (30-40 years) well, this is a challenge. A better solution is to solve the problem chemically by consolidating the sand in the fracture or plugging the fracture connecting the injector and producer. Recovery from the reservoir will then be optimized and the solution is likely to be cheaper than working over the well.
Enzymatic CaCO3 technology is a novel chemical system that can be used for plugging fractures and consolidates sand in propped fractures in horizontal wells. All chemicals used offshore in the North Sea need to be compliant with OSPAR regulations; the Enzymatic CaCO3 system is classified as environment-friendly. It also has predictable chemistry and is completely reversible. This paper discusses the process of maturing the technology from concept to readiness for field implementation covering lab testing, IP protection, chemical procurement strategies, environmental impact evaluation, and quality assurance process during field application.
Dolomitization of the Lacustrine Carbonates of the Toca Fm. (Kambala Field, Offshore Cabinda) and Quantitative Diagenetic Modeling
Authors: Frixa Alfredo , Maragliulo Chiara , Consonni Alberto , Ortenzi Andrea 
Published: December 2014

Abstract
Hydrothermal dolomitization is one of the main diagenetic processes potentially affecting the petrophysical characteristics of carbonate reservoir rocks.
It's effect on Barremian lacustrine carbonates of Upper and Lower Toca Formations has been investigated through an integrated diagenetic study and simulated through a quantitative diagenetic modeling (RTM TOUGHREACT software), in order to understand the behavior of dolomitizating fluids in the carbonate reservoir rock. This approach is also useful in carbonate marine contexts.
Among the analyzed core samples, the best reservoir facies are represented by coarse Mollusk Coquina limestone and hydrothermal dolomite, which is the subject of this study.
Two types of dolomite have been recognized. A finely crystalline, likely early diagenetic dolomite, shows low reservoir properties, and a coarsely crystalline, likely late diagenetic zebra dolomite, with very good reservoir properties.
Dolomitisation is associated with strong silica precipitation in the Upper Toca Formation, pointed out by mineralogical and chemical analyses that also document, the presence of detrital palygorskite, typical of lacustrine environments under arid conditions and, in the Lower Toca Formation, of talc replacing ooids and indicating strong hydrothermal conditions.
The integration of different investigation techniques allowed to hypothesize a mechanism of dolomitization by hypersaline fluids probably mixed with modified hypersaline and fresh waters, interacting with crustal rocks, as pointed out by Strontium isotope analysis. High homogenization temperatures registered in fluid inclusions (100 to 140 °C) could be due to crustal thinning, while the hypersaline fluids (20 to 25 NaCl eq. %) could be migrated from the Aptian Loeme Fm. salt or be originally present in the deep water lake sediments.
The RTM TOUGHREACT software simulations pointed out that an important control on the results is exercised by the permeability field of the rocks. Dolomitization is directly proportional to the flow intensity, while temperature seems to exert less influence. From the sensitivity analysis water composition is very important for the process.
First Successful Hydraulic Fracturing in the Offshore Abu Dhabi: Part2—Overcoming the Operational Difficulties—
Authors: Al Ameri Fahed , Inukai Hisashi , Al Zarouni Asim , Al Kindi Mohammed , Kawamura Kazuhiro , Al Awadi Farhaad Khaled , Al Husseiny Afifi Hassan , Salman Mohamed Wajeeh , Moussa Khaled Abdel-Ghani 
Published: December 2014

Abstract
The first application of hydraulic fracturing in the offshore Abu Dhabi was executed safely and successfully. This achievement will be a valuable foothold to expand the field development target toward more challenging reservoirs such as deep tight sand in this region. There were huge amount of operational difficulties to carry out this hydraulic fracturing due to various operational restrictions, limited data availability and high-pressure & high-temperature (HP/HT) condition. Finally, these difficulties were successfully overcome by an intensive designing study on well completion, surface equipment, and operation associated with hydraulic fracturing for a tight gas reservoir.
In this paper (Part 2), the key factors that led this trial to the first successful hydraulic fracturing in the offshore Abu Dhabi are described against the difficulties from operational point of view such as well completion design, arrangement of fracturing and surface testing equipment and acquired lessons learnt. However hydraulic fracturing design optimization from subsurface point of view is discussed in the other paper described by Kuroda, et al. (2014) as Part 1. Well completion design and equipment arrangement were optimized to overcome an extremely wide range of pressure and temperature condition with multi stage fracturing. Fracturing and testing equipment of high specification were arranged on the limited space of both the off-shore jack up rig and the fracturing vessel, and then these well-prepared equipment contributed to safe and accurate operation. Acquired lessons learnt will contribute to other offshore tight-sand gas reservoirs development in the offshore Abu Dhabi. These outcomes will be especially applicable in this region to optimize offshore hydraulic fracturing for tight HP/HT reservoirs in order to enhance the well productivity and enable economical development of marginal fields.