bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integrated Approach to Address Reservoir Uncertainties in One of the Largest Recent Gas Discoveries Onshore Egypt
Authors: Abdelkhalek Mostafa , Elhares Layla , Van Heeswijk Victor , Amin Sameh , Gill Nick 
Published: November 2017

Abstract
The BTE field is one of the largest recent gas discoveries in the Egyptian Western Desert. The main subsurface uncertainties impacting the Initial Gas in Place (GIIP) are Gas Water Contact (GWC), structure, fault positions and sand development. Given the large subsurface uncertainties, it is planned to further appraise the field with one or two appraisal wells and reshooting seismic.
Other key uncertainties are sand quality, intra-field faults and aquifer strength. These uncertainties will impact the wells deliverability, Estimated Ultimate Recovery per well (EUR/well) and the Ultimate Recovery Factor (URF). The EUR/well and the URF are a function of the number of wells drilled.
An integrated probabilistic modelling (experimental design model) approach was developed to consider all main reservoir uncertainties together and determine the true P90, P50 and P10 EUR subsurface realizations. Three different software packages were used and linked together; Material Balance Equation1-3 (MBE) software, statistical4 package software, and Spreadsheet software. The three packages are talking to each other through Visual Basic for Application5 (VBA) programming language.
This probabilistic model enables the user to run sensitivity studies by changing one parameter at a time and check its effect of EUR. The model also lends itself for uncertainty studies (experimental design) by examining all the possible combinations scenarios between the different uncertain parameters; such as GIIP, tanks transmissibility, wells flow coefficient6 (C), wells flow exponent (n), relative permeability parameters, aquifer properties7, etc.
Optimization of LPG Recovery from Refinery Delayed Coking Gas Recovery Unit
Authors: El Khashab A. A. , El Maghraby A. M. , Refaat M. A. , El Meligy H. A. 
Published: November 2017

Abstract
Refinery Delayed Coking units produce light components from the top of the fractionation section as one of the products. The extent of recovering LPG from this stream via the Gas Recovery Unit mainly depends on the costs involved in recovery.
Gas Recovery Units usually comprise of feed compression to a higher pressure followed by absorption with a solvent (i.e. naphtha) and a stripper column where the light components absorbed in the process stream are stripped. The rich solvent from the stripper bottom is then routed to a debutanizer column where LPG is separated. The recovered LPG and Fuel Gas undergo further amine treatment to meet H2S specifications.
The objective of this paper is to present the methodology applied to evaluate/optimize the different process schemes and main operating parameters of a Refinery Delayed Coking Gas Recovery Unit for optimum energy/cost effective LPG recovery.
The Delayed Coking Gas Recovery Unit has been simulated utilizing HYSYS® steady state simulation software linked to Aspen Process Economic Analyzer to evaluate the effect of different combinations of process schemes and operating parameters on the products recovery as well as equipment sizing and thus the capital cost, while estimating the required utilities and thus the operating cost.
Two main different process operating parameters have been studied: Absorber operating pressureNaphtha (Solvent) recycle ratio
Four different process schemes have been studied: Including both Recontactor and PresaturatorIncluding Recontactor onlyIncluding Presaturator onlyWithout both Recontactor and Presaturator
The Absorber operating pressure and the naphtha recycle ratio have major effect on the LPG recovery. Increasing either of the above parameters enhances the absorption and thus increases the LPG recovery on the other hand increases the utility consumption and thus the operating costs as well as increasing the equipment sizing and thus the capital cost.
The optimum operating parameters resulting in the higher net present value (NPV) and internal rate of return (i.e. higher economics parameters) was found to be an Absorber pressure of 22 bar (i.e. the pressure that can be achieved by 2 compression stages) and Naphtha recycle ratio of 0.42.
The optimum scheme was found to be that including both the Recontactor and Presaturator, although this scheme has extra equipment, however the addition of these equipment result in higher product recovery at lower Naphtha recycle ratio and thus result in savings in equipment sizing and thus capital cost as well as savings in the utility requirements (i.e. power and steam) and thus the operating costs.
Coker Gas Recovery Units are common in most refineries, although the design of this unit is conventional; however, this paper introduces new level of absorber operating pressure which has been proven to be economically attractive in recovering more LPG with reduced operating costs.
A Different Approach to Evaluate Wettability in Shales
Authors: Araujo de Itriago Yani C. , Albrecht Jochen , Möeller Andre , Dallmann Gerald 
Published: November 2017

Abstract
Conventional methods for wettability assessment are based on volumetric measurements such as displacement tests, and have to be modified for shales because of their low porosity, ultra low permeability with natural fractures, and reactive components. These methods are time consuming and the results are often questionable; these facts that have motivated the search for new approaches to estimate this property. A methodology for measuring shales wettability that uses X-Ray Photoelectron Spectroscopy (XPS) is presented in this paper. Results are compared with conventional imbibition tests. XPS is being used as a faster way to infer the wetting condition on sandstones rocks.
XPS allows knowing the chemical composition of the outer layers of a solid surface. Using XPS the organic carbon content at the surface is evaluated, and then it is correlated with the wetting condition from imbibition tests. Water wet and oil wet shales from different countries were investigated. Samples were prepared rigorously for mineralogical and XPS measurement.
The relationship between wettability and surface composition as determined from XPS is reported. Wettability index measured by imbibition tests is used in this study as an indicator of the wettability of shales. The XPS spectra of oil-wet surfaces of shales reveal the existence of organic carbon and also of an organic mineral species such as Si–CH. These species have a well-defined binding energy which differs from the inorganic species of mineral grains. In this study we present quantifiable evidence that chemisorbed organic material on the surfaces defines the oil-wetting character of oil shales. In the case of gas shales gas is adsorbed onto clay surfaces, as well in natural fractures and porous giving them oil wet condition. This view is supported by a strong correlation between the organic matter content on shale surfaces, the mineral composition and the wettability. In this paper we demonstrate a different approach for measuring shale wettability using XPS analysis. Instead of waiting for many days for the results from imbibition test, XPS takes less than one day. As a result, the time needed for the wettability measurement is reduced significantly.
Molecular Simulation of CO2 Sequestration and Enhanced Gas Recovery in Gas Rich Shale: An Insight Based on Realistic Kerogen Model
Authors: Huang Liang , Ning Zhengfu , Li He , Wang Qing , Ye Hongtao , Qin Huibo 
Published: November 2017

Abstract
Injection of CO2 into shale plays has been considered as one potential scenario for CO2 sequestration with enhanced CH4 recovery (CS-EGR). In this work, a realistic molecular model of bulk kerogen was constructed by molecular dynamics simulations (MD). Grand canonical Monte Carlo simulations (GCMC) were performed to investigate the replacement of CH4 by CO2 under different reservoir pressures, CO2 mole ratios and kerogen moisture contents. The radial distribution functions (RDF) were computed to discuss the affinity between CH4/CO2 and atoms in the kerogen. Also, the CO2/CH4 adsorption selectivity was computed to evaluate the preferential adsorption of CO2 and CH4. Results show that the CO2/CH4 selectivity increases at the beginning, and then decreases with further increasing pressure, which indicates that low reservoir pressure is beneficial to the efficiency improvement of CS-EGR. The amount of CO2 sequestration and CH4 desorption increases, while the CO2/CH4 selectivity decreases as the CO2 mole ratio increases, indicating the adsorption stability of sequestrated CO2 weakens with increasing CO2 mole ratio. The CO2/CH4 adsorption selectivity decreases initially, and then increases with the kerogen moisture content. Increasing the reservoir moisture content can improve the performance of CS-EGR. The preferential adsorption sites for CH4 are the sulfur-containing groups, while these for CO2 are the nitrogen- and oxygen-containing groups. One adsorption layer is observed for CH4, while two adsorption layers are identified for CO2. This study gains enhanced insights on the replacement exploitation of shale gas by CO2 at molecular scale, and it can provide applicable guidelines for the optimization of CS-EGR in shale gas reservoir.
A Geochemical Model for Investigation of Wettability Alteration during Brine-Dependent Flooding in Carbonate Reservoirs
Authors: Awolayo Adedapo , Sarma Hemanta , Nghiem Long , Emre Gorucu 
Published: November 2017

Abstract
The impact of brine salinity and compositions on improving brine-dependent recovery processes has been an active research area over the past two decades. Various studies have demonstrated an improvement in oil recovery, attributed predominantly to the ability of the brine to alter rock’s wettability towards water-wetness. The proposed hypothesis is that the wettability of carbonate rocks is altered due to desorption of oil carboxylic groups from rock surfaces by the adsorbed sulfate, while the divalent cations are co-adsorbed.
We developed a reactive transport model to test this hypothesis and considered wettability alteration through geochemical interactions among brine, oil and rock surface. In this model, we used various reaction pathways to account for the competition between oil acid-groups and active ionson the rock surface. The equations developed from various reactions are coupled with multiphase flow equations to control flow functions that ultimately determine the oil recovery. The model we developed was used to investigate the effects of ionic variations during carbonate coreflooding experiments. Thereafter, we extended DLVO (Derjaguin, Landau, Verwey and Overbeek) theory of surface forces to explain the molecular interactions between rock−brine−oil system by generating interfacial disjoining pressure and interaction energy.
The model was tested by matching and predicting results from recently published flooding experimental studies related to ionically-modified brines conducted under single-phase and two-phase flow conditions. In these experiments, sulfate concentration in seawater was halved and quadrupled, and compared to injections of formation water and seawater. We found remarkable agreement with the produced ion histories reported from the single-phase tests, although there were delays in the produced sulfate concentration because of retention within the core. For two-phase experiments, the model yielded excellent replication of the produced ion histories and oil recoveries obtained during injection of various brines. Results show that increasing sulfate while maintaining the concentration level of other ions improved oil recovery up to 10% OOIP. However, when sulfate was reduced, neither additional oil was recovered nor sulfate ion production was delayed. Application of DVLO theory shows that disjoining pressure, which dictates the water film thickness, is extremely sensitive to sulfate content of the brine. Brines with more sulfate content exhibit higher disjoining pressure and energy barrier compared to brines with fewer sulfates. This suggests that increasing sulfate in the injected brine is essential to alter rock wettability.
Drivers and Constraints of International Projects Development in the Arctic
Authors: Akimova Irina 
Published: November 2017

Abstract
Nowadays more than ever there can be no doubt that world economy and especially global energy markets are driven by technology innovations. As Arctic currently serves as a potential game changer for energy markets, emerged technologies it will bring to the market and its infrastructure development can totally reshape the global landscape of the international energy market.
This paper highlights benefits that development of international projects in the Arctic can bring to the market by making it more innovative and competitive along with potential usage of some of its technologies in other offshore and marine projects.
Evaluation of Eco Friendly Bio-Oil Dispersants on the Inhibition of Asphaltene Precipitation in a Kuwaiti Crude Oil
Authors: Alrashidi Hessah , Nasr-El-Din Hisham A. 
Published: November 2017

Abstract
Asphaltene precipitation, flocculation and deposition are vital problems that may cause serious damage to reservoirs, wells, and production facilities. Asphaltene precipitation may occur during primary depletion or acidizing jobs as well as after the injection of rich gas or carbon dioxide. The Organic deposition removal is considered a costly workover job with the current oil prices. The solvents that are usually used are toluene and xylene, which are considered carcinogenic and toxic chemicals. The use of dispersion to inhibit the organic deposition is essential and can be expensive, as it is required for the life of the well.
The objective of this paper is to compare the effectiveness of two chemical dispersants and deasphalted oil against vegetable oils (coconut oil and andiroba oil) on the inhibition of asphaltene precipitation.
A Kuwaiti crude oil sample was used in this study with an API of approximately 38° and asphaltene content of 2 wt%. The crude oil was characterized by a variety of analytical techniques including: Total acid number (TAN), Total base number (TBN), water content, Saturates, Aromatic, Resins, and Asphaltene analysis (SARA), density, viscosity and elemental analysis. Dispersants and vegetable oils were analyzed by Fourier Transform Infrared spectroscopy (FTIR) to determine the functional groups. An Asphaltene dispersants test was carried out at different concentrations of 150, 300 and 500 ppm and temperatures of 25 and 70°C to evaluate the dispersant efficiency and limitations.
The results of this study showed that the dispersant should be designed based on understanding the asphaltene structure and interaction mechanism. Temperature greatly affects the blended dispersant performance due to the relation of asphaltene solubility and temperature; therefore designing optimum concentration must be taking into account. Employing the deasphalted oil as solvent to mitigate asphaltene precipitation can be desirable from economical perspective.
Coconut oil performs very well as an asphaltene dispersant when paired with DAO at a concentration of 500 ppm or solely at 25°C. The results can be employed in designing and optimizing dispersants that are environmental friendly and cost effective.
Running Feed Gas Compressor without Atmospheric Gas
Authors: Al Braiki Wael Khaled 
Published: November 2017

Abstract
ADGAS LNG Plant 26 contains two identical multi-wheel single stage Centrifugal Compressors. Their function is to compress atmospheric gas from ADMA to 2.0 barg pressure. The compressor is designed for running parallel both, in load sharing mode by master pressure control to be able to maintain Atmospheric gas pressure at about 29"of H2O. The suction of both Booster compressors draw from common suction drum (26-C-0101) which has two separate demister pads and suctions.
The inlet pressure of south and north dropped to min of 15 & 9"WG respectively Due to the difference in the suction flow, the LNG Operations started facing the difficulties to maintain south (26K101) and north booster compressor (26K2O1) in AUTO load sharing mode.
Due to sticky oily viscous sludge type material coming along with the incoming Atmospheric feed gas stream, demister pads were fouled and the high DP made it difficult to pull, all the available atmospheric gases from ADMA & resulted in flaring of about 9mmscfd. To open the suction drum & clean/replace the demister pads it required 9 days outage of both the booster compressors.
Both LNG trains’ Feed gas compressors had to be run without atmospheric gases, which was never attempted earlier It was required to capture all Atmospheric gases in OAG. The challenge was running both LNG FGC-1/2 without any ATM gases & OAG with Minimum required 35 Psig Gas.
LNG boosters were unloaded and FGC’s were loaded with more 35# gas. OAG booster compressors were fully loaded with all the available atmospheric gases (100mmscfd).
LNG Booster compressor demister pad replacement require 10 days shutdown, Traditionally FGC also stopped and LNG trains run with HP Gas only
By Implementing the innovation of Feed Gas compressor is running without Atmospheric gas, there were no impact on ADMA oil production, LPG loss reduced by 2581 tonnes per day and LP Gas Flaring of 2 MMSCFD saved. Demister pads were replaced and High DP problem resolved
Performance Enhancement of Drilling and Completions Operations in Giant Offshore Field Abu Dhabi by Tracking and Monitoring Invisible Lost Time and Defined KPIs
Authors: Raza Syed Ali , Al-Braik Haythem , Attalah Mohamed , Corona Mauricio , Kojadinovic Nenad 
Published: November 2017

Abstract
Drilling and Completions operations optimization requires as starting point the building of an alive database that sustains the benchmark for a list of defined KPIs. The KPIs will represent main well construction activities conducted in different well types in a specific field. Once the data is captured and processed, the operations efficiency is obtained with the computation of the Invisible Lost Time (ILT). Computations are defined in different ways by different operators with different margins. The purpose of this paper is to probe that operational efficiency that can be tracked better when the percentiles lead the targets and not the Composite Best as a target.
The continuous monitoring of the performance and the daily distribution of KPI's tracking dashboard has changed the mindset of the entire team, engaging the rig personnel in the identification of specific limiters that affect the performance and defining specific actions to take to revert the trend. The year to year comparisons showed a significant performance improvement in all the rigs but not at the same rate. The expected learning curve has deferred from one rig to another.
A forecast tool has been created to generate an automatic AFE that delivers automatically TvD curves for the different percentiles and it is aligned to the latest rig's performance and the well architecture. This tool will help the drilling engineers to estimate, quick and more accurate, the well duration time, especially when the rig allocation is crucial for the yearly objectives of the project.
pH-Responsive Supramolecular Gelling Agents Used in EOR and Their Potential as Fracking Fluids
Authors: Yegin Cengiz , Temizel Cenk , Yegin Yagmur , Sari Mufrettin Murat , Jia Bao , Alklih Mohamad Yousef 
Published: November 2017

Abstract
Hydraulic fracturing is an important method to recover shale oil and gas that has drastically increased U.S. energy production in recent decades. Shales are low permeability formations where natural resources are trapped, and require a well-planned hydraulic fracturing process and a highly developed fracturing (fracking) fluid for efficient oil/gas recovery. In this study, a pH-responsive solution synthesized by supramolecular assembly of maleic acid and an amino-amide in an aqueous media is described as a potential fracking fluid owing to its mobility control, proppant carrying and settling capacities. Previous investigations on this solution system had shown its large potential to replace displacement fluids in EOR due to pH-tunable and reversible viscosity behavior.
The main working mechanism is that; the initial viscosity of injected solution is kept at moderate/high values to easily transport proppants and easily inject the fluid; and then decreased when the solution reaches a position near fissures for settling of proppants. It has been reported by rheology tests of the developed fracking fluid, which consists of the supramolecular solution and proppants (silica sand), viscosity can be changed about 1600 times from pH 3.8 to pH 8.3 in a reversible fashion at only 2 wt.% concentration. On the other hand, sedimentation studies indicated that the sedimentation speed of the silica proppants decreased around five orders of magnitude from pH 4 to pH 8, again in a reversible way. Furthermore, experimental studies revealed that the developed supramolecular solutions have both reversible pH-responsive properties, and tolerance against high salinities and elevated temperatures. Another outstanding property of these supramolecular solutions is their self-healing feature which enables them to disassemble and reassemble upon exposure to extreme shear stresses, while polymer viscosifying agents the fracking fluids degrade and break up under similar conditions.
The supramolecular assembly system discussed in this study has a promising potential to become next-generation fracking fluids with its outstanding properties including but not limited to pH-sensitivity, reversible viscosity, high proppant transfer capacity, tolerance to high temperatures and salinity, self-healing behavior, environmental friendliness and sustainability.