bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Ionic Liquid for Mercury Removal from Natural Gas
Authors: Abai Mahpuzah , Shariff Shahidah Mohd , Hassan Amiruddin , Cheun Kuah Yong 
Published: November 2015

Abstract
An increasing trend of contaminants in the oil and gas streams has been observed worldwide in the past recent years, and one of the eminent naturally occurring contaminant is mercury. Mercury has been found to be hazardous to health, safety, and environment as well as detrimental to process equipment at the oil and gas plants. The complexity in removing mercury is due to its existence in different species, mainly elemental, organo- and inorgano-mercury.
Most available technologies for mercury removal are located downstream of the acid gas removal and dehydration units and thus, leading to contamination of these units as well as mercury release to the environment. Besides its potential to be located upstream of these units to better protect the plant operations, the new technology is capable of treating the full range of mercury species by a single adsorbent or treatment step to meet the current targeted mercury level at outlet of mercury removal unit of less than 0.01 ug m-3. In addition, it can be applied to the existing mercury removal units without requiring any plant modifications or retrofitting.
A joint collaboration between PETRONAS and Queen's University Belfast has led to a development of a new technology that effectively removes mercury from oil and gas streams utilising ionic liquids. Efficient scrubbing of mercury vapour from natural gas streams has been demonstrated both in the laboratory and on an industrial scale, using chlorocuprate(II) ionic liquids impregnated on high surface area porous solid supports. This material has been tested for use within the petroleum gas production industry, and has currently been running continuously at a number of gas processing plants in Malaysia for more than three years. Since it was originally revealed, further innovative developments have been undertaken to improve its efficiency and performance for applications in liquid hydrocarbon streams. Recognitions and awards have also been received from various organisations including iChemE for the technology.
Since it was originally revealed, further innovative developments have been undertaken to improve its efficiency and performance for applications in liquid hydrocarbon streams.
Development of a Giant Carbonate Oil Field, Part 2: Migration from Pressure Maintenance Development to Sweep Oriented IOR Development
Authors: Nakashima Toshinori , Kumar Jitendra , Draoui Elyes 
Published: November 2015

Abstract
The studied field is a relatively homogeneous giant carbonate field composed of three stacked isolated reservoirs, having produced for nearly 50 years through a series of pressure maintenance methods. Chronologically, the implemented methods include gravity-driven dumpflood water injection, peripheral water injection and immiscible crestal gas injection. As the historical and on-going pressure maintenance oriented development is reaching its limitation in sustaining the oil production, it is necessary to move towards a sweep oriented development to further extend the plateau and increase final recovery.
A robust full field improved oil recovery (IOR) development plan is proposed with a smooth transition from pressure maintenance to sweep oriented development. The key questions to be answered in the IOR development are (a) when to migrate to sweep oriented development, (b) how to configure the pattern, (c) how to manage voidage replacement and decide the split between water and gas injection, and (d) how to resolve associated common issues with pattern water injection and crestal gas injection. The workflow includes dividing the field into three zones based on reservoir quality and current maturity to water flood. Dedicated sweep oriented strategy is defined for different zones respectively and its efficiency is evaluated through reservoir simulations by incorporating practical drilling campaign, well completion type, surface facility constraints and interference with historical development.
According to simulation results of the IOR plan, it can be concluded that the developed strategy (a) efficiently sweeps the oil without bypassed regions, effectively recovering down to residual oil saturation, (b) is quite robust with respect to the change of well count, (c) extends the plateau with efficient pressure support in the field and (d) is a reasonable approach towards yet undefined tertiary enhanced oil recovery (EOR) application.
This paper discusses the approach used to develop this IOR plan for the near and far future development of this giant carbonate field, focusing in particular on the solution of the above mentioned key questions.
Control Automation Technologies for Mega Project
Authors: Kulkarni N. V. , Musallam Khalaf 
Published: November 2015

Abstract
This Mega Project involves re-development of a producing oil field from 4 newly constructed aritifical islands. The new production facilities, well manifolds, pipe racks, buildings are being constructed in a modular form to reduce on site work activities. The project's main challenges included: Long field life (&gt;30 years)Aggressive phased development scheduleLarge capacity equipment / facilitiesLimitations on fabrication yard capacitiesRemote site working conditionsBrownfield construction environment (resulting from interfaces with an early production system)
Geostatistical Modeling of Complex Deltaic Reservoirs Integrating Production Data through Optimized History Matching
Authors: Caeiro M. H. , Soares A. , Demyanov V. 
Published: November 2015

Abstract
Reservoir modeling involves the characterization of the internal gridded petrophysical properties distribution and the simulation of fluid production. However, a common problem associated with reservoir modeling is the highly non-linear relationship between the distribution of the petrophysical parameters (frequently with a non-stationary character) and the fluid production. To tackle this problem, this paper presents a new methodology for integrated reservoir modeling by addressing a multiscale optimization approach applied for non-stationary geostatistical history matching of complex connectivity hydrocarbon reservoirs.
The methodology comprises a two staged procedure for multiscale optimization, which includes a global optimization stage followed by a local refining stage. The former consists of optimizing the geological spatial anisotropy trend by coupling the stochastic optimization over the anisotropy multiparameter space with an image generation algorithm - direct sequential simulation with local anisotropy correction. The latter aims at refining the small scale heterogeneity by performing the local optimization based on a regional image perturbation method. The local refining optimization is achieved by taking into account the best individual well production matches.
A complex deltaic reservoir case study is presented to illustrate the applicability of the proposed methodology. An ensemble of multiple optimized history matched models is obtained respecting both the production data and the geological settings. The results show that the deltaic complex channelized pattern is well reproduced and also that the multiscale optimization improves the match between the simulated fluid profiles and the observed production data. As such, optimization is performed at multiple scales: the anisotropy trend model accounts for larger scale variability of the structures, while consecutive local refining improves convergence to dynamic response around individual wells.
The contribution of this work to petroleum technology is the implementation of a novel methodology for the reproduction of the fluids production profiles through the perturbation of the subsurface petrophysical models while honoring complex geological constrains.
By-Pass Pigging Without or With Speed Control for Gas-Condensate Pipelines
Authors: Groote G. A. , van de Camp P. B. , Veenstra P. , Broze G. , Henkes R. A. 
Published: November 2015

Abstract
Pigging of a multiphase (i.e. liquid/gas) pipeline can result in a large "pigged" liquid slug when a normal (i.e. non-by-pass) pig is used. This requires a large separator or slugcatcher, or otherwise accepting production deferment during pigging. These problems can be avoided by using a by-pass pig, which means that part of the gas can by-pass the pig through holes, which reduces the pig velocity and in turn it also reduces the pig-generated volume. By-pass pigging is applied more and more often, but it remains difficult to select the right by-pass opening for the initial pig run. This paper describes a simple design tool, based on steady-state hydraulic pipeline simulation results, to determine the required fixed by-pass opening. Also field experience with a speed control pig for a gas-condensate pipeline is shown (i.e. the by-pass opening is adapted along the pipeline to maintain a constant pre-set pig speed).
The by-pass pigging design tool is based on steady-state hydraulic pipeline simulations. By-pass design has two main constraints: (1) too small an opening will create a large Pig-Generated Volume (PGV), and (2) too large an opening will create too little force on the pig to overcome the wall friction. The optimum opening is when the liquid surge will be minimum, to avoid having the risk that the pig gets stuck. The main uncertainty in the prediction is the friction between the pig and the pipe wall. The simple steady state by-pass pigging design tool is validated against both dynamic simulation results and field data. The tool provides a quick method to assess the right by-pass opening without the requirement of doing an extensive dynamic simulation study.
As the pressure decreases along the pipeline, the optimum by-pass opening also varies along the pipeline; the gas velocity and therefore the pig velocity will normally increase towards the outlet of the pipeline and a larger by-pass would be preferred at this point. However, a (fixed) larger by-pass can cause difficulties when launching the pig. A speed control pig consists of a variable by-pass valve which is controlled in such a way to maintain a constant pig velocity. For example, when the by-pass opening is reduced, the pressure drop across the pig increases and therefore the pig velocity increases as well. The speed control pig has been used several times for a 70 km long gas condensate pipeline, which has successfully reduced the liquid surge into the slug catcher. Field data demonstrate that the by-pass pig speed can be maintained almost at a constant velocity, when using a speed control pig for a gas condensate pipeline.
Industrial Cybersecurity Governance
Authors: Brouwer Riemer 
Published: November 2015

Abstract
Information Security Governance in the Oil & Gas Industry
Cyber-attacks against a wide variety of organizations are increasing rapidly, and it seems that almost every day a new attack is making the news. The United Arab Emirates (UAE) is unfortunately no exception. Recent attacks were focusing on the financial sector through widely published compromising of ATMs and debit card systems last year. The malicious hackers vary from individuals who are looking to obtain fame in the hacker scene, to professional organizations interested in industrial espionage. To make matters worse, political motivated hacktivism is posing an increasing threat in the Middle East.
Naturally, this also affects the oil & gas industry where a similar trend is taking place. Given the importance of oil & gas to the region and the oil producing countries such as the UAE, it makes the companies involved in oil & gas an attractive target. Traditionally, these companies were mistakenly thought to be secure because the systems they deployed, Industrial Automation and Control Systems, or IACS, were air-gapped and used proprietary technologies and protocols. However, more sophisticated attacks, and enhanced connectivity between industrial and corporate networks have increased systems vulnerability.
Reservoir Modeling and Uncertainties Evaluation of a Tight Carbonate Reservoir in Offshore Abu Dhabi
Authors: Al Khoury Philippe , Sinha Amit Kumar , Gueddoud Abdel Ghani , Serry Amr Mohamed 
Published: November 2015

Abstract

Objective
Developing tight reservoirs is a challenge, it becomes more challenging when the reservoir is not well known and uncertainties remain in its description. This paper presents how this challenge has been addressed for an offshore tight carbonate reservoir.

Methods
A workflow is followed to obtain an optimized development plan for a tight reservoir and to evaluate the effect of uncertainties on field production. Evaluation of uncertainties uses response surface technique; it shows the most influential parameters and supports the data gathering plan to reduce uncertainties.

Results
The reservoir is generally thin with thickness variations across the field and with general thickening toward the north. The porous section of the formation is present in the northern eastern part.
This reservoir is characterized by variable porosity values and low average permeability. Well tests show a saturated oil reservoir with a gas cap.
The field development challenges are to identify a sweet area attractive for field development through representative static and dynamic models. The static model is built using log data from wells penetrations in the porous body. Very few core data are available to build correlation between porosity and permeability. The use of these data was maximized in order to populate the simulation grid with properties. Available dynamic data are used to describe pressure and fluid saturations in the porous zone where most likely fluid contacts values were evaluated and their uncertainty ranges were defined.
As a conclusion of this study, P10, P50, P90 oil production profiles were obtained and the impact of uncertainties was evaluated.
Finally with response surface technique a ranking of the uncertainties based on their effect is obtained. This ranking supports a data gathering plan and helps prioritizing actions needed to reduce the uncertainty in the estimated oil production profile.

Novel/Additive Information
Through this work, an example of an optimized development plan for a tight reservoir is presented and response surface technique is used to evaluate uncertainties effect and support the data gathering plan.
Breakthrough in Drilling Automation Saves Rig Time and Safeguards Against Human Error
Authors: Abrahamsen Egill , Bergerud Ronny , Kluge Roald , King Matthew 
Published: November 2015

Abstract

Objectives/Scope
The world's first deployment of an automated drilling control system on a Statoil rig in the North Sea helped the rig in saving up to 10% rig time per well through safeguarding and optimizing manual operations and through automating repetitive drilling activities such as tripping, pipe filling, connections and pump start up. Advanced modelling of well conditions, combined with closed loop control of the drilling control system provided safeguards for pressure, rotary and hoisting velocity.

Methods, Procedures, Process
The drilling instrumentation, surface- and downhole sensors are coupled with robust real-time and fully transient hydraulic, mechanical and thermodynamic models that continuously evaluate the current downhole conditions. These models determine all possible combinations of drillers' actions (string accelerations, velocities, rotation, pump start-ups and flow rates) that will cause the dynamic downhole pressure to reach or exceed upper and lower well stability- and geo-pressure prognosis. These results are actively used to safeguard both manual and automated sequences. For example should the driller attempt to pull the drill string at a velocity that would cause the downhole pressure to fall below the Pore Pressure or Collapse Pressure at any depth in the open hole section, the drilling control system will intervene and limit the upward velocity to a safe value based on the dynamic model.

Results, Observations, Conclusions
The models effectively calculated and communicated current limits to the drilling control system, allowing the control system to safeguard the well against human error during manual operations and to automate various repetitive operations. Statistics after 3 wells proved an overall time saving of 4% per well through automated repetitive sequences (such as pump start-ups and friction tests) while another 2–8% time savings per well were realized through optimized manual operations (active safeguards and safety triggers) and other improvement initiatives by the rig. Although the system was originally developed to eliminate human errors and avoid major incidents (including technical side-tracks), the daily efficiency gains indicate that the system also avoids minor issues that otherwise would have slowed down the operation without being seen as downtime or Invisible Lost Time. This indicates that the system works as intended and that the system should be able to avoid major incidents when the relevant conditions arise.

Novel/Additive Information
This paper demonstrates how automation reduces invisible lost time and allows drillers to focus on other activities while repetitive tasks are controlled by software. Furthermore, rig safety is significantly enhanced since the closed loop drilling control system prevents users from exceeding the dynamic limits calculated by the drilling control system.
Correctly Allocating Injected Gas to Targeted Zones by Integrating Data from Spectral Noise and Temperature Logs
Authors: Alabd Khaled Mohamed , Riza Faizal , Al Nuaimi Nawal , Fawzy Ahmed , Moussa Mohamed , Shnaib Fathi , El Sheshtawy Mohamed , Volkov Maxim , Nagimov Vener , Vorozhikhin Sergey 
Published: November 2015

Abstract
Gas Injection alone, or in Water Alternating Gas (WAG) mode to improve oil recovery (IOR) has been widely applied since the late 1950s. The incremental oil recovery attributed to IOR has been generally estimated at 5 – 10% over Secondary Recovery (water injection alone), primarily due to preferential sweep under gravitational effects. Theoretically, water and gas injection tend to have preferential sweep due to gravitational effects and formation characteristics. In practice, however, it is an operational challenge to obtain a uniform sweep across the reservoir.
One of the biggest challenges in understanding the injection behavior in gas injection wells using the conventional production logging approach is to identify the exact entry points, and to determine a representative injection profile to the actual injection volumes. Mechanical spinners provide inflow profiles within the borehole that in many cases doesn't reflect the actual gas behavior inside the addressed layers beyond the entry point.
Gas containment in the reservoir and within the targeted zone is one of the biggest hurdles. Unlike pilot projects, in full field application, channeling, cross flows, out of zone injection and premature breakthrough often occur, resulting in wasting gas, delayed response, and lower than expected recovery.
Effective reservoir management requires active & efficient reservoir surveillance in order to optimize well & reservoir performance. It is, therefore, critical to design a proactive program for data acquisition, integrating that data into a knowledge data base and to transform that knowledge into valuable information to guide future operations for remedial work, recompletion, infill drilling, and further development programs.
This paper discusses in detail how the injection profile geometry was described, and injected gas volumes were correctly allocated to targeted zones in one of the giant onshore oil fields in Abu Dhabi, UAE operated by ADCO, using integrated HPT (High Precision Temperature) and SNL (Spectral Noise Logging). Data from HPT and SNL logging package was integrated to successfully monitor water injection, identify cross-flows and locate casing leaks in injection wells for the past 2-3 years. Based on the performance, reliability, and accuracy of this advanced logging technology, ADCO has decided to use the same tools and temperature simulation to track gas injection, gas flow profile behind pipe, and to monitor any communication with any extraneous thief zones.
New Rotary Steerable Drilling System Introduction in the UAE for ADCO Delivers High DLS Capabilities While Improving ROP and Providing Extensive Formation Evaluation Data
Authors: Tipu Imran , Al Jasmi Shurooq Abdulla , Al Shamsi Juma Sulaiman , Danche Ali M. , Muhammad Javid , Nurzai Jehanzeb , Biscaro Enrico 
Published: November 2015

Abstract

Objective
One of the recent concepts in the industry promoted by a super major is the Limiter Re-designTMphilosophy where the performance limiters are addressed one by one to incrementally improve performance. This paper focuses on the limiter aspect of the new High build up rate RSS (HBR RSS) and the elimination of controlled ROP as a goal in a given field for a UAE operator. The paper analysis the success of redesign by comparing the controlled footage drilled before and after redesign.

Process
Drilling of directional wells is conducted by using Motor or Rotary steerable systems. Both of these systems provide directional capabilities peculiar to the system being used. BHA design defines the geometrical limits of achievable dogleg while the formation capability provides the second important element in drilling a directional well. Horizontal or highly deviated wells with high curvature provide the maximum exposure to pay zone and minimize the missed interval due to landing of well. With all else being constant a well with highest curvature during landing will have the maximum reservoir exposure as compared to other wells. This however, introduces the practical limitation of drilling wells with high dogleg, especially when in conjunction with formation evaluation LWD suites.
During drilling of challenging directional well profiles it is frequently required to control rate of penetration to achieve aggressive build-rates or compromise with the data acquisition program. This is a common practice with different rotary steerable systems in the market. As this was identified as a limiter that adversely affects ROP and geosteering capabilities a new design of RSS with higher dogleg capability was conceived, developed and deployed.

Results
The new RSS system was designed to give geometrically higher dogleg capability while still able to withstand the increased bending stresses. This high build rate RSS system was successfully able to eliminate the controlled ROP as a limiter for the given application which resulted in 39% ROP improvement. In addition the development of high build rate RSS provided multiple benefits such as: elimination of ROP and LWD limitation, increased curvature capabilities and higher reliability of RSS system with respect to high bending related issues. It also challenged the bit manufacturers to design bits capable of taking full advantage of the given RSS system.

Additive Information
This paper describes the improvement that was made in one field by eliminating a limiter. While this process was done for the given field, the applications of this process are universal. Similar issues exist in other fields around the world and additional capabilities can address limiters in ROP, Reliability or removing additional BHA Runs.