bluuebunny/crossref_metadata_2025_split huggingface dataset:
Real-Time Operation: Game Changer Towards Effective and Collaborative Drilling Operation
Authors: Atemin Azizul , Iskandar Farah Farhana , Abd Aziz Amir 
Published: November 2017

Abstract
PETRONAS has adopted drilling operation digitalization and formed real-time drilling operation center; which is also known as WELLS RTC since a decade ago, in conjunction with the company’s recent theme – Collaboration, Pace and Going Digital. Traditionally, a real-time drilling operation center has always been perceived as a monitoring center only for quick decision making to reduce Non-Productive Time (NPT). However, over the years the centre has evolved and not only has proven how the real-time operation center has allowed real – time problem solving, but it has actually brings so much additional value to the company as a whole. It has been the centre of drilling process and workflow efficiency transformation, the knowledge transfer and the collaborative discussion between multiple disciplines team that involved in drilling planning and operation.
Prior to the existence of WELLS RTC, communications were made via emails and phone calls. Delayed decisions and miscommunication occurred along the way. WELLS RTC which operates 24/7 acts as collaboration center that provides avenue for the subject matter experts (SME) to discuss and make real time decision when needed. Collaboration & discussion is not confined to just Drilling Engineers, but includes and not limited to the Geological and Geophysical (G&G) team who are working on the well. Real-time data is now being stored in PETRONAS data center allowing the company to have full access to their own data.
A direct impact of having a real-time operation center is the improved communication between each personnel who are involve in the drilling operation. Tough decisions are now easier to be made especially when the SMEs are sitting together under one roof looking at the real-time data transmitted from the rig site.
Also, having full access to PETRONAS historical data allows the employee to search for the lesson learnt and best practices on the previous wells/fields allowing them to make more educated judgment (when needed) based on existing data. This data can be made available immediately for case study purposes. Software environments that are able to connect data between multiple servicing companies using the Wellsite Information Transfer Standard Mark Up Language (WITSML) format has resulted in increased accuracy of data communication which is needed for collaborative discussion.
This paper will describe and explain the benefits of having a real-time drilling operation center via case studies studies on collaboration between multiple work groups contribute to the success of multiple drilling projects delivery and the technology used to setup this center.
Formulation of Inhibitive Water Based Mud System with Synthesized Graft Copolymer: A Novel Approach to Mitigate the Wellbore Instability Problems in Shale Formation
Authors: Kumar Saket , Sundriyal Priyanka , Kumar Nitesh 
Published: November 2017

Abstract
This research paper discusses about the evaluation of carboxymethyl starch-grafted-polyacrylamidecoplymer as a potential drilling mud additive for the drilling of reactive shale formations. The graft copolymer was synthesized via carboxymethylation and free polymerization technique and it was characterized by FTIR, and SEM. Then, it was processed in the development of the WBDMS. Its effect on the rheological and filtration control properties of the formulated mud system was analyzed thoroughly as per API standard procedures. In addition, the shale inhibition properties were investigated with shale recovery test. Further, Core flow tests were carried out to study the formation damage caused by formulated WBDMS. The obtained results revealed that synthesized graft copolymer had shown superior shale inhibition property. The synthesized CMS-g-PAM along with other additives in the developed system had shown remarkable rheological and filtration characteristics. It also exhibited low formation damage, and high shale recovery than the PHPA polymer in the formulated WBDMS. Hence, this synthesized graft copolymer may be used as a potential mud additive in the formulation ofwater based drilling fluid system for drilling the reactive shale formations.
A New Facile Approach to Estimate EOR Polymers Thermal Stability at Harsh Reservoir Conditions
Authors: Zhang Xuan , Han Ming , Fuseni Alhasan , AlSofi Abdulkareem M. 
Published: November 2017

Abstract
Water-soluble polymers have been widely used in chemical enhanced oil recovery (EOR) either independently or part of surfactant-polymer (SP) and alkaline-surfactant-polymer (ASP) processes. The polymer viscosifies the injected water thereby reducing displacing fluid mobility and sweep efficiency. Key to efficient sweep is attaining a sustainable mobility control (i.e. maintenance of sufficient viscosity during the propagation in the reservoir). Therefore, long-term stability is a crucial parameter in screening of appropriate polymers for EOR application, especially in high temperature and high salinity reservoirs. Generally, the evaluation of polymer solution's long-term stability is time-consuming process. Accordingly, there is a need to develop fast and reliable means to assess the feasibility of polymers from a long-term stability standpoint. Different from the methods in the literature, this paper presents a new facile approach to evaluate the polymers in powder form and identify their molecular decomposition. The approach is correlated and confirmed against conventional long-term stability results obtained on polymer solutions.
Thermogravimetric analysis (TGA) was used in this work to study the decomposition of polymers and their individual constituents. The derivative of TGA curve with respect to temperature is known as the DTG, which can clearly identify differences in decomposition rates of screened polymers. Furthermore, conventional long-term stability tests were performed on polymer solutions prepared in synthetic seawater with salinity of 57,670 ppm. The solutions were aged at a temperature of 95°C under anaerobic conditions and monitored by rheological measurements for viscosity loss, total organic carbon (TOC) analyses for material loss, and gel permeation chromatography (GPC) for molecular weight loss.
The thermal stability of 12 commercial water soluble polymers was tested in this work. The long-term stability results are consistent with the TGA results. The two polymers showing good thermogravimetric thermal stability exhibited significant viscosity retention in conventional long-term stability tests. TOC and GPC results further supported the TGA results. The developed and demonstrated method provides a fast approach to screen polymer candidates for high temperature and high salinity reservoirs.
Development of an Extended Delayed Oil Swell Packer for Deployment in Extended Reach Drilling Oil Wells
Authors: Mitchell Campbell , Urquhart Niall 
Published: November 2017

Abstract
This development, predominantly from four artificial islands, of a giant offshore field in the United Arab Emirates (UAE) requires lateral compartmentalization with open hole packers of the 6 5/8" horizontal lower completions with lateral lengths greater than 16,000ft and total well lengths greater than 30,000ft MD. Swell Packer technology has enabled cost effective compartmentalization in horizontal laterals and is the preferred OH packer solution for the development.
Deploying swell packers is regarded as being a simple solution to compartmentalizing any lateral where typically the deployment fluid differs from the fluids in which it will swell in; this application prevents the elastomer from swelling during deployment and swelling upon contact with produced or injected fluids. The use of an extended delayed oil swell packer with no delay systems in this particular application enables the packers to be deployed in a Non Aqueous Reservoir Drill in Fluid (RDFNAF) where the packer is required to delay its swelling during deployment, thereafter continue to swell once the packer is at final depth and the elastomer contacts the produced oil.
As lateral lengths have increased beyond 16,000ft and total well MD goes beyond 30,000ft these Extended Maximum Reservoir Contact (EMRC) wells require an oil swell packer to delay its swell time sufficiently to be ran to TD in RDF Non Aqueous Drill in Fluid, deploy a displacement string to swap out the drill in fluid to completion brines & breakers and not reach the 8 ½" dimension of the drilled open hole; thereafter continuing to swell on contact with the produced fluids, in this case oil, and swell out sufficiently to meet the required pressure differential between compartments at the wash out diameters of the drilled formation. At the time of the field development starting, there was a gap in the swell packer technology available globally such that this functionality could not be provided. The paper outlines the qualification process to develop and deploy a new swellpacker design meeting these functional requirements.
To date there have been three deployments with these delayed oil swell packers, with deployments consisting of 23 swell packers in a 6-5/8" production liner length of 19,000ft, with 35,835ft MD; 28 oil swell packers with a production liner length of 20,225ft, with 30,197ft MD; and a 6 5/8" production liner length of 18,905ft with 27,995ft MD.
The application of these delayed oil swell packers in the Giant Offshore Oilfield Abu Dhabi was a first of its type where extensive design and testing went into the swellpacker development. The use of this swell packer technology has presented a commercially viable solution to compartmentalize lateral sections over 16,000ft and wells with total measured depth beyond 30,000ft and is a key enabler to deliver cost savings associated with EMRC well designs.
Human Factors Analysis and Classification System
Authors: Akhtar Muhammad Adnan 
Published: November 2017

Abstract
The ADGAS plant facilities include three LNG trains (Trains-1 & 2 commissioned in 1977 and Train-3 commissioned in 1994), Offshore Associated Gas (OAG) and Integrated Gas Development (IGD) facilities along with utilities and other associated facilities such as storage tankage, jetties for export of the products, etc. The gas feedstock comes from various offshore oil and gas fields surrounding Das Island. The feed gas, delivered to the plant at different pressure levels is compressed through different stages and purified before liquefaction. The feed gas contains impurities like CO2 (Carbon Di Oxide) and H2S (Hydrogen Sulphide), which are removed by gas sweetening process. H2S removed by the sweetening process is converted into liquid Sulphur in the Sulphur Recovery Units. After sweetening, the hydrocarbon gas mixture is cooled in stages followed by fractionation and liquefaction to produce different hydrocarbon products ranging from LNG (a mixture of methane and ethane) to Paraffinic Naphtha.
ADGAS commissioned the OAG and IGD facilities in 2010 and 2013 respectively, enabling gas export from Das Island to onshore Habshan facilities through a subsea pipeline. The primary objective of OAG facility is to process additional quantities of LP Gases that has become available at Das Island from ADMA-OPCO, following increase in oil production. The process involves compression of LP Gases, Dehydrate and dispatch 211 mmscfd of Gas & Condensate through marine pipeline to GASCO facility at Habshan. OAG (two processing trains) processes about 200mmscfd gas whereas The IGD was commissioned in the year 2013. This comprises of three Trains capable of delivering 900 mmscfd of dry compressed HP Gas at 155 Bara through marine pipeline to GASCO facility at Habshan.
Use of Pilot Wells to Cost-Effectively Unlock Field Potential: Case Studies from the Jasmine Field
Authors: Yusuf Mukminin , Saifuddin Farid , Nuada I Nengah , Triandi Muhammad 
Published: November 2017

Abstract
The Jasmine Field is a mature stacked-sand oil field that has been on production since 2005. One of the biggest current challenges is to locate remaining oil accumulations. Seismic mapping, material balance and reservoir simulation studies provide pointers to promising locations, but can never guarantee accuracy. Pilot wells offer a means to appraise identified locations before committing to drilling horizontal wellbores.
A pilot well is often used in Mubadala Petroleum drilling campaigns as part of an overall strategy to extend the field's life by continuing to locate and tap remaining oil accumulations. Collaboration across subsurface teams leads to decisions on pilot well locations. In most cases the pilot well appraisal objectives will be to confirm the structural position, to identify fluid contacts or to assess depth uncertainty, especially in areas where there is no well penetration or in significantly updip locations. These appraisal objectives apply to shallower and deeper horizons as well as to the target reservoir itself, and in Jasmine there is a strong record of accomplishment of successfully locating remaining oil by means of such appraisal. It is critical therefore, that well planning is tailored so as to accommodate the appraisal objectives as well as the eventual production target.
Two case studies are presented, illustrating different approaches to using pilot wells prior to placing horizontal wellbores in Jasmine field. In the first case, the horizontal production wellbore was planned to develop an updip region of the target reservoir, to access remaining oil, with additional pilot well appraisal objectives in both shallower and deeper zones. The location for the new horizontal well was confirmed and this dual-role pilot/producer well not only succeeded in reducing depth uncertainty for the new horizontal wellbore, but also identified additional reserves in other reservoirs. In the second case an appraisal pilot well was used to investigate a downdip region of a depleted reservoir. Material balance assessment had indicated that the volume accessed by the updip producer was larger than suggested by the static model, which might have resulted in water encroachment from downdip, causing the appraisal location to water out. However, seismic imaging identified potential barriers between the updip and the proposed downdip appraisal location, which would have prevented water encroachment from downdip. The pilot appraisal well was required to distinguish between those two possibilities.
Moving Models into Reality: An Automated Workflow to Calibrate Forward Stratigraphic Modeling; Application to Hanifa and Arab-D in Central Saudi Arabia
Authors: AlQattan Hussain , Mezghani Mokhles , Hmoud Khalid 
Published: November 2017

Abstract
Forward stratigraphic modelling (FSM) is an evolving technology for understanding the geology between wells for the purpose of exploration and field development. As opposed to the use of geostatistics, this process-based modeling approach uses physical equations for key controls on deposition, such as initial bathymetry, eustatic sea level change, subsidence rate, wave energy, and other environmental conditions. The output simulation is a 3D cellular model with properties like lithology, porosity, and water depth.
FSM results do not honor the interpretation from the drilled wells. This means that the prediction accuracy from the generated model may not be high. The current process of calibrating forward stratigraphic models is time-consuming and tedious. In this paper, we propose an automated workflow to improve the accuracy of a forward stratigraphic model by automating its calibration to facies data from wells.
For our case study, we use an initial stratigraphic model of the Hanifa and Arab-D in central Saudi Arabia. The modeling area covers 430 km by 370 km, the cell size is 10 km, and the simulation time step is 100,000 years. In the resulting model, cells are assigned to seven index facies based on their lithology, wave energy, and water depth. Initially, we conducted a sensitivity analysis to identify the environmental parameters with critical influence on the final model. Subsequently, we ran several simulations with varying values for these critical parameters. To measure the match between the different simulation models and the observed well facies, we used facies from 16 wells. The simulation run with the highest match was used as the best forward stratigraphic model.
Uncertainty maps, based on superimposing several simulations, were generated to check which areas of the simulation are replicated more often than others, meaning they bear, relatively, the lowest uncertainty. This approach may be used to evaluate the risk of drilling new wells in specific locations, or to provide a measure of the uncertainty for subsequent reservoir simulations. In the future, we will use seismic facies and attributes, in addition to well data, for the model calibration.
The Importance of the Stability of Cement Sheaths: Interaction between Cement, Acid, Carbon Steel and Formation and Treatment Fluids
Authors: Alsaiari H. A. , Sayed M. , Reddy B. R. , Metouri S. , Al-Taie I. 
Published: November 2017

Abstract
The stability of cement sheaths during well workover, production and intervention is an important element for well integrity and operational safety. Cement sheaths support casing, provide zonal isolation, seal off annuli, and protect casing from corrosive fluids. Understanding the interaction of the cement with the production and intervention fluids under reservoir conditions is essential to prevent unexpected operational problems.
This paper provides a systematic study on the interaction between the cement and many oilfield elements including fresh acid, corrosion inhibitor, carbon steel, hydrogen sulfide, and carbon dioxide. A series of laboratory experiments were conducted by exposing set cement to various fluids at temperatures ranging from 50 up to 200 °F. Both fresh and aged cements were evaluated.
Cement degradation during production in sour environments could be severe and consequently provide a source of iron- and calcium-related deposits. The severity of the problem depends on the level of degradation and production conditions. The degradation process can also maximize the exposure of casing surfaces to corrosive fluids leading to an increased concentration of dissolved cations in produced fluids, thus, increased potential for inorganic deposits and water-oil emulsion formation. Severe cement degradation can exacerbate the potential of creating easy pathways for toxic gases to the surface.
Several advanced analytical techniques including X-Ray Diffraction (XRD) and Inductively Coupled Plasma (ICP) were used to evaluate the condition of the cement before and after the fluid exposure in our experiments. The results indicated that, unlike what has been reported in the literature, acid can significantly degrade a major portion of the exposed Class-G cement within less than two hours if the exposed cement surface area to acid is considered. The exposure to hydrogen sulfide and carbon dioxide did impact the cement degradation, but not significantly. The degradation was found to be a function of acid concentration, fluid additives, and environment conditions. To determine whether cement catalyzes the corrosion process, the average corrosion rates were also calculated. The results were in agreement with field observations and beneficial to optimize the cement stability and to minimize the related operational problems.
Advanced Reservoir Characterization in Vaca Muerta using Chemical Tracer Technology
Authors: Panichelli Patricio , Martínez Joaquín Ramírez , Crespo Pablo , Noguera Iván Lanusse , Chatterjee Monalisa 
Published: November 2017

Abstract
The selection of the objective target in unconventional shale formations is a determinant factor on the productivity of wells. In thick unconventional formations, as is Vaca Muerta, the operators are looking for new ways of quantifying the production of each stage of hydraulic fracturing executed in the well.
It is of vital importance for the operators to be certain that every section of the well that has been stimulated is effectively contributing to the well production, and that the clean-out of all stages has been correctly carried out.
Other challenges, such as optimal spacing between clusters, stages and wells, which in turn allow to optimize drilling & completion costs, maximizing ultimate recovery (EUR), appear amongst the main preoccupations.
One of the techniques that the industry has developed to answer those questions has been the use of chemical tracers during the stimulation process. Since 2013, the use of chemical tracer technologies to simultaneously tag water, oil and gas has gained great acceptance in unconventional players in USA, with more than 30,000 stages tagged using this technology. In Argentina, Shale operators are quickly gaining experience too.
This paper describes the technique used on site to apply chemical tracers in a multi-stage horizontal well with 15 stages, in Vaca Muerta formation, Argentina. The paper also comments on the data interpretation and necessary steps to obtain the oil and flowback water production profile during the first 60 days following well startup.
Chemical tracer results showed evidence of zones with higher oil production, and higher stimulation water flowback, as well as confirming the complete cleaning of the well.
A production monitoring tool with long term reach, as are chemical tracers, offers the operator the possibility to correlate operational changes (e.g. choke changes) with the individual response of every stage. It is possible to identify which stages are contributing to the incremental oil production, after each operative change.
Finally, it was observed that the information generated with chemical tracers, geological interpretation, and microseismic results collected during the stimulation along the horizontal section of the well, showed a high level of correlation. This helped the Reservoir Engineering team to explain the differences in productivity of each of the fractured stages of the horizontal interval of the well.