bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enhanced Core Analysis Workflow for the Geomechanical Characterization of Reservoirs in a Giant Offshore Field, Abu dhabi
Authors: Noufal Abdelwahab , Germay Christophe , Lhomme Tanguy , Hegazy Gehad , Richard Thomas 
Published: November 2015

Abstract
This paper is focused on the integration of two laboratory centimeter-resolution logs of mechanical properties (strength and compressional elastic-wave velocity Vp) into an enhanced core analysis workflow for the geomechanical characterization of unconventional reservoirs in a giant field in Abu Dhabi, where fracking is the cornerstone for producing the unconventional oil. The design and placement of hydraulic fratures rely strongly on the a-priori knowledge of the stress profile and brittleness index, which were estimated via a mechanical earth model constructed from wireline logs and correlations based on US shales analogues. With most of the stratigraphic column in the Abu Dhabi field composed of carbonates, the calibration of the mechanical earth models was found critical as the US shales based correlations would otherwise not have been suitable to the geomechanical characterization of these tight carbonate reservoirs.
With this case study we illustrate:How the combination of the continuous profiles of rock strength UCS (Uniaxial compressive strength) and P-wave velocity measured directly on dry cores with the scratch tests contributes to the identification of different Geomechanical Facies,How the mapping of several Geomechanical Facies enables the building of a simple yet robust relationship between the UCS measured directly on cores and properties such as the total porosity and acoustic velocities of sonic waves, obtained from wireline logs, andHow the centimeter-resolution profiles of strength and elastic wave velocities measured on dry cores enable the proper upscaling of geomechanical properties measured on plug samples to the entire cored section and the computation of a horizontal stress and brittleness profiles derived from unbiased geomechanical properties.
From this case study follows a general discussion on the relevance of wireline sonic logs relative to centimetric resolution data (scratch profiles or plug measurement) acquired on dry cores for the geomechanical characterization of reservoirs. We conclude that measurements on dry cores enable the more robust calibration of mechanical earth model and in turn better description of the reservoir mechanical response. The upscaled profiles of horizontal stress and brittleness index derived from dry core measurements would ultimately lead to an alternative strategy for the design and placement of hydraulic fractures along producing wells.
Polymer-Based Scale Inhibitors for Seawater Injection Operations in High-Salinity Formation Water Reservoirs
Authors: Obied Marwa A. , Alkhaldi Mohammed H. , Mubarak Tariq A. , Yami Ibrahim S. , Sahman Faisal M. 
Published: November 2015

Abstract
Water flooding using seawater is a major oil filed operation implemented in different carbonate and sandstone reservoirs to maintain reservoir pressure and enhance oil recovery. However, due to the high sulfate content in the injected seawater, significant calcium, barium and strontium sulfate scale deposition can occur and cause severe formation damage. Typically, scale inhibitors are applied in the field to prevent the formation of calcium sulfate scale where they act either as chelating agents to form a soluble complex, as threshold inhibitors, which block the development of the supercritical nuclei or as retarders of the growth of the calcium sulfate crystals. The objective of this study is to evaluate the effectiveness of different types of scale inhibitors to prevent the formation of calcium sulfate scale during the injection of seawater into high-salinity bearing carbonate reservoirs.
Jar testing and SoftPitzerTM software were used to investigate the calcium sulfate precipitation due to the mixing of high calcium-content (37,000 mg/L) formation water and high sulfate-content (4,000 mg/L) seawater. This investigation was conducted on different mixtures of formation water and seawater at reservoir temperature of 155°F. Different types of scale inhibitors were tested to prevent the scaling of calcium sulfate in mixtures of seawater and formation water. The compatibility of these scale inhibitors with calcium ions present in formation water and also their effectiveness in preventing CaSO4 scaling were investigated using bottle testing. In addition, coreflood experiments were conducted to determine the adsorption behavior of these inhibitors in carbonate rocks.
Results showed that the application of two scale inhibitors (Acrylic homopolymer-based) can successfully mitigate calcium sulfate scale formation in seawater/formation water mixtures up to 155°F. Each one of these two scale inhibitors has its own effective minimum inhibition concentration (MIC). In addition to these results, the paper provides insights into the adsorption behavior of these inhibitors in carbonate rocks and how this affects their performance.
SCAL with Full Hysteresis Significantly Impact Giant Carbonate Reservoir Performance and Improve The History Match Quality Case Study
Authors: Ismail Ahmed M. , Jasser Majdolin Hanna , Hafez Hafez H. , Zubair Kalam Mohamed 
Published: November 2015

Abstract
Numerical reservoir simulation model of a giant carbonate reservoir with thick transition zone has been built and the saturation functions have been generated and tested with different Hysteresis options during full field history match process. In this super giant carbonate reservoir with multi-million active cells and twelve reservoir rock-types, running the full hysteresis option proved prohibitive due to excessive run times, and in many cases the run fails. Therefore scanning curves have been generated using algorithms to mimic the hysteresis option. This paper aims at presenting the impact of using water-oil capillary pressure and relative permeability full Hysteresis for mixed wet super-giant carbonate reservoir on the full field history match results of water flood and development plan for EOR as well as optimizing the 3D simulation run time. Different models were tested including Corey model, modified Corey, and Killough Hysteresis model to develop appropriate bounding and scanning curves. Sector model was built to ensure reliable scanning curves from each model, and the resulting scanning curves from this sector model compared with the mathematical approach used to generate scanning curves over a wide range of water saturation.
Several sensitivities on SCAL Hysteresis option have been made to improve the match quality of the water saturation changes, breakthrough time and production & pressure performance on field and individual wells level (i.e. No Hysteresis, both Kro & Krw Hysteresis, only Kro Hysteresis, full Hysteresis Kr & Pc…. etc.).
Using full Hysteresis saturation function curves show significant impact in the history match quality especially in transition zone where it was difficult to match the flood front with the normal saturation function. It worth mentioning that using scanning curves (121 curves was the optimum number of scanning curves) showed reduction in the simulation run times compared with the full hysteresis option.
Improved Hydrocarbon Recovery of a Lean Retrograde Gas Reservoir Under Propane Injection
Authors: Md Yusof Muhammad Aslam , Fuad Iqmal Irsyad , Matali Awangku Alizul 
Published: November 2015

Abstract
In most cases, retrograde gas reservoir in N Field which is located at the north of Malay Basin achieved 40-70% of recovery factor (RF) compared to dry gas reservoir, 80-90% of RF. Reservoir K, a lean retrograde gas reservoir of the N Field drained by Well 5 experience reduction in recovery (about 15% of RF) that is caused by a significant productivity loss, because of condensate banking. Condensate banking phenomenon (observed as skin) around the perforation zone restricted the flow of gas after the flowing bottom hole pressure falls below the dew point pressure. Therefore, the reduction in gas Inflow Performance Relationship (IPR) limits the Estimated Ultimate Recovery (EUR) of Reservoir K. It is the focus in this project to analyse the effect of miscible propane stimulated injection on the IPR, well deliverability and hence reservoir recovery. The retrograde gas reservoir model is integrated between E300, IPM PROSPER (well model) and IPM MBAL (reservoir model) software in reservoir performance prediction and forecasting study. Results show that there is 4% increment in gas recovery and 6% increment in condensate recovery after injection of propane to Reservoir K. There are about 4.2 million USD increment in revenue upon propane injection development. As conclusion, it is found that propane injection could minimize the condensate saturation that improves reservoir IPR and hydrocarbon recovery for both gas and condensate.
Knowledge Management in Multigenerational UAE Workplaces: Learning-Training Preferences and Knowledge Transfer Barriers
Authors: Lim Hwee Ling 
Published: November 2015

Abstract
Companies in the United Arab Emirates (UAE) need to understand generational differences in teaching-learning preferences so that vital job skills held by older employees are transferred successfully to younger workers. Hence, this study compared the preferred teaching-learning methods for technical skills between generations and identified the main barriers to knowledge transfer experienced in the UAE work context. Interviews were conducted with 85 supervisors and 91 supervisees from three generations (Boomers, Generations X and Y), comprising Emiratis and UAE expatriates. It found that on the job training and one-on-one coaching with a mentor were younger supervisees' most preferred methods for learning technical work skills that corresponded to teaching methods used most often by older supervisors. However, assessment/testing and feedback was a less preferred learning method yet experienced more at work by supervisees. While individual and organizational structure barriers were experienced in knowledge transfer processes, the former was predominant. Older supervisors attributed difficulties in transferring knowledge to supervisees' lack of motivation to learn and poor communication skills while main barriers experienced by younger supervisees were supervisors' sense of job insecurity and poor communication skills. The results highlighted difficulties in cross-generational knowledge transfer processes that stem from preferences in teaching-learning methods and individual factors. These findings could guide organizations in designing knowledge transfer mechanisms that ensure both employees and knowledge are used to their fullest potential.
ADGAS LNG Train-3 APC Implementation
Authors: Raghuraman S. N. , Dabak Abhay 
Published: November 2015

Abstract
ADGAS implemented Advanced Process Control Solution (APC) for LNG Plant with intent to Increase throughput while respecting all the constraints required for ensuring integrity and reliability of its assets. It is also helping us to improve efficiency, reduce emissions and also to reduce operator stress by substantially reducing operator interventions required.
Model based predictive control is used in implementation of APC. Overall structure of controller includes 5 controllers which are optimized by overall controller using QP technique.
This types of implementation is not so uncommon in industry today, however, at ADGAS we had some peculiar challenges which were eventually overcome using innovative solutions
MR Composition Control MR Optimization Need for Robust Inferential structure Tackle impact of gas drier change over on upstream and downstream plant
First Application of Thermal Activated Resin as Unconventional LCM in the Middle East
Authors: Knudsen K. , Leon G. A. , Sanabria A. E. , Ansari A. , Pino R. M. 
Published: November 2015

Abstract
One of the major challenges when drilling gas wells in offshore fields is to drill under high pressure and in a loss circulation zone in intermediate hole sections. Heavy mud is used to control the pore pressure in a narrow operational window that creates losses and, as a consequence, well control issues. Several solutions/ideas have been implemented while drilling this intermediate section, including a thermal-activated resin, rigid rapid fluid treatment, used to regain full circulation and successfully increase the window gradient.
The solution to these challenges was developed by designing a fast setting, thermal-activated resin LCM liquid plug with a density equal to 152 pcf. This new treatment slurry was able to be bullheaded and displaced with a polymer mud 152 pcf. The slurry was easily pumped through drill pipe, measurement while drilling (MWD) and drill bits.
This paper presents case histories and field applications of this novel polymer-based lost circulation material, for successful treatment of heavy mud losses to formation in wells in offshore gas fields in the Middle East. The paper also includes a discussion of the methodology, material properties and applications.
Possibility of Nanofluid/Gas Alternating Injection as an EOR Method in an Oil Field
Authors: Al Matroushi M. , Pourafshary P. , Al Wahaibi Y. 
Published: November 2015

Abstract
Water flooding and gas injection are the most commonly used EOR methods. Due to the viscous fingering, reduction of sweep efficiency and early breakthrough of the injected fluid, the performance of these methods are not appropriate. Hence, water alternating gas approach (WAG) is applied to solve the unfavorable mobility ratio and enhance the fluid contact in the reservoir by segregating gas to the top and accumulating of water toward the bottom.
Through the past years, several experimental works have been done to prove the ability of nanoparticles to increase the oil recovery efficiently. Presence of nanoparticles in water alternating gas (NWAG) is a novel method of enhanced oil recovery in intermediate and oil-wet reservoirs. This novel method results in economic and efficient oil recovery by combining improved macroscopic and microscopic sweep efficiencies. Nanoparticles sit on the rock surface and alter the wettability of the rock. Also, nanoparticles locate in oil/water interface and reduce the interfacial tension. These mechanisms modify oil properties and mobilize trapped oil in the reservoirs.
This research project aims to study the effects of the nanoparticles on the wettability alteration, relative permeability curves, and IFT changes during Nanofluid alternating gas approach (NWAG) by modeling the fluid/rock interactions during coreflooding experiments. Moreover, the possibility of using this approach as an EOR method in the field scale was investigated. Our results showed a good history match for oil recovery obtained from coreflooding experiment for WAG and NWAG injections with less than 10% error between the model and the lab data. Our simulation showed that application of nanofluid instead of water during WAG process shifts the wettability of the system toward more water wet which affects the relative permeability curves and enhances the recovery. For example application of NWAG in 6 months’ time cycle with 5 months nanofluid and 1 month CO2 injection period in 2:1 NWAG ratio with Dual Five-spot well pattern improves the oil recovery for 13% compared to the conventional WAG method.
A Systematic Integrated Approach to Evaluate Artificial Lift Requirements While Dealing With High Uncertainty
Authors: Caicedo S. , Montoya C. , Abboud J. , Tiar S. 
Published: November 2015

Abstract
When evaluating artificial lift requirements, sometimes data present uncertainties at the initial planning stage, which could be related to reservoir complexity, poorly defined reservoir development plans etc. This is the case for a field that had ten wells drilled and only four of them producing after 6 years when operations were suspended. The high level plan was to exploit and abandon the reservoir as soon as possible taking into consideration the HSE regulations for this urban area.
In addition, there were major challenges associated with this development: adjusted timeline, high H2S and CO2 concentrations and fluid processing facilities located 45 km away that necessitates a high transfer line export pressure. The data and studies initially available required revision to understand the reservoir and the production history and to have a suitable and more reliable model to predict the well production profiles. Typically, an artificial lift evaluation stage comes after the reservoir has a good model and a defined exploitation scheme. In contrast, in this case, the selection of the artificial lift method dealt with high data uncertainty associated with: the reservoir pressure, GOR and water cut time profiles as a result of the reservoir's complexity and PVT properties.
To overcome this situation and advance quickly a novel matrix approach was adopted, which focused on the following: To understand and demonstrate how uncertainty affects artificial lift selection;To perform a preliminary Artificial Lift method screening covering the uncertainties in order to discard some methods and focus on possible solutions;To use the matrix to determine the envelopes when wells can flow naturally and when artificial lift is required;To determine the probability of the scenarios in relation to the results of an ongoing reservoir simulation that would be available at later stage.
The present paper shows how an integrative and structured methodology can deal with high uncertainty conditions in a real case.
The approach used suggests how to discard artificial lift options using constrains while focusing in the real options and evaluating the possible outputs and conditions for the worst case scenarios based on the expected wide ranges.
Production Optimization Strategy Using Hybrid Genetic Algorithm
Authors: Salam Damian Dion , Gunardi Irwan , Yasutra Amega 
Published: November 2015

Abstract
Optimizing production is no longer an option, nowadays, it is a necessity. The wells have to produce longer and better than ever before in order to influence projects attractiveness. However, the process to define variables such as well placement, number and type of wells, well production and injection scheduling, and operational conditions is time-consuming and demands high computational effort. Therefore, the objective of this research is to provide an optimization algorithm resulting good solution efficiently.
The optimization algorithm used in this work is the hybrid genetic algorithm (HGA) which is the combination of GA with artificial neural networks (ANN) and evolution strategies (ES). This HGA attempts to simplify the complex and diverse parameters governing the production optimization problem. The HGA is coupled with commercial simulator and has been applied in real fields to quantify the benefits of this HGA over a base case with the conventional one. Additionally, it is proposed to minimize the number of combinations of possible solutions that makes the optimization algorithm becomes simply elegant by performing the process efficiently and effectively.
The HGA proposed in this study is used to optimize the production strategies in realistic reservoir models, defining the number, type, and position of production and injection wells, and also the production or injection flow rates. Therefore, the HGA is proved to be suitable for any kind of reservoir models. Moreover, the number of individuals in a population, the number of generations, and the genetic parameters are varied and adapted by applying ANN and ES to evaluate the efficiency of the algorithm. From this study, an optimization algorithm in production strategy is provided. Results showing the performance of several optimization processes are presented in this work. The analysis and comparison regarding the genetic parameters are presented. Moreover, the proposed HGA is proved to be time-saving and operation-efficient, plus it provides an optimized solution.
Based on the fact that every well is a new challenge that defines a single-solution approach which results the production optimization strategy becoming more and more complicated, the use of an optimization algorithm to achieve a good solution can be very valuable to the process, yet it can also lead to an exhaustive search, demanding a great number of simulations to test many possibilities. This novel HGA is presented to tackle and handle those issues.
IT and OT Convergence, or Collision? Managing the Merger for Greenfield LNG
Authors: Garvin Thomas 
Published: November 2015

Abstract
The worlds of information technology (IT) and operational technology (OT) in the Oil & Gas space are often considered worlds apart: different goals, different strategies, and different stakeholders. While there is much focus around the convergence of technologies across these domains in support of process optimization and data exchange, organizational aspects come into play which create a multi-dimensional challenge for major capital projects (MCPs) deploying a wide variety of information systems. This paper discusses the broader spectrum of convergence, and shares insights and lessons learned from delivering complex systems integration programs for world-class Liquefied Natural Gas (LNG) MCPs.
Important Considerations for Reserves Estimation in Unconventional Resource Plays
Authors: AbdelMawla Ahmed , Hegazy Mohamed 
Published: November 2015

Abstract
Unconventional resource plays have recently been traded favorably in Acquisitions and Divestitures "A&D" markets due to view of having lower risk and or better growth prospects compared to conventional resources "Devashish, 2014". For unconventional plays, the reservoir geological boundaries usually extend beyond the limits of the acreage holding. Some of the major uncertainties in the unconventional plays reserves and resources assessment tend to be: the basis of declaration of discovery, the definition of the project boundary (technically and commercially), the categorization of reserves/resources referenced to the degree of uncertainty, and the appropriate methods to estimate the production forecasts and ultimate recovery.
In this paper we present field example from unconventional resource play. The reasons for variations between different reserve estimations for the same asset (based on real case history) are explained, with recommendations for practical considerations. These include using diagnostic techniques of production data to establish production forecasts that satisfy the reasonable certainty criteria required for booking reserves. We will discuss examples for the implementation of the reserves categorization in unconventional resource plays according to the guidelines of SEC and SPE Petroleum Resources Management System "SPE-PRMS". Additionally, some practical rules for the assessment of contingent resources in unconventional plays will be discussed.
It should be noted that reserves categorization in unconventional resource plays is an area that is subject to different interpretations across the industry, resulting in variations in the results of reserves estimation between different estimators. The contribution of this work is a critical discussion on these differences, and how they relate to the uncertainty on production forecasts. It is our expectation that better understanding of the uncertainty leads toward best practices for reserves estimations throughout the industry.