bluuebunny/crossref_metadata_2025_split huggingface dataset:
Nanopore Compositional Modeling in Unconventional Shale Reservoirs
Authors: Alharthy Najeeb S. , Teklu Tadesse W. , Nguyen Thanh N. , Kazemi Hossein , Graves Ramona M. 
Published: May 2016

Summary
Understanding the mechanism of multicomponent mass transport in the nanopores of unconventional reservoirs, such as Eagle Ford, Niobrara, Woodford, and Bakken, is of great interest because it influences long-term economic development of such reservoirs. Thus, we began to examine the phase behavior and flow characteristics of multicomponent flow in primary production in nanoporous reservoirs. Besides primary recovery, our long-term objectives included enhanced oil production from such reservoirs. The first step was to evaluate the phase behavior in nanopores on the basis of pore-size distribution. This was motivated because the physical properties of hydrocarbon components are affected by wall proximity in nanopores as a result of van der Waals molecular interactions with the pore walls. For instance, critical pressure and temperature of hydrocarbon components shift to lower values as the nanopore walls become closer. In our research, we applied this kind of critical property shift to the hydrocarbon components of two Eagle Ford fluid samples. Then, we used the shifted phase characteristics in dual-porosity compositional modeling to determine the pore-to-pore flow characteristics, and, eventually, the flow behavior of hydrocarbons to the wells. In the simulation, we assigned three levels of phase behavior in the matrix and fracture pore spaces. In addition, the flow hierarchy included flow from matrix (nano-, meso-, and macropores) to macrofractures, from macrofractures to a hydraulic fracture (HF), and through the HF to the production well.
From the simulation study, we determined why hydrocarbon fluids flow so effectively in ultralow-permeability shale reservoirs. The simulation also gave credence to the intuitive notion that favorable phase behavior (phase split) in the nanopores is one of the major reasons for production of commercial quantities of light oil and gas from shale reservoirs. It was determined that the implementation of confined-pore and midconfined-pore phase behavior lowers the bubblepoint pressure, and this, in turn, leads to a slightly higher oil recovery and lesser gas recovery. Also it was determined that the implementation of midconfined-pore and confined-pore phase-behavior shift reduces the retrograde liquid-condensation region, which in turn, leads to lower liquid yield while maintaining the same gas-production quantity. Finally, the important reason that we are able to produce shale reservoirs economically is “rubblizing” the reservoir matrix near HFs, which creates favorable permeability pathways to improve reservoir drainage. This is why multistage hydraulic fracturing is so critical for successful development of shale reservoirs.
Molecular Recognition of Wax Inhibitor Through Pour Point Depressant Type Inhibitor
Authors: Ridzuan Norida , Adam Fatmawati , Yaacob Zulkefli 
Published: May 2016

Abstract
The deposition or crystallization of wax paraffin from crude oils is one of the crucial issues faced in the petroleum industry particularly when the temperature of the crude oil is below the wax appearance temperature (WAT). Pour Point Depressants (PPDs) chemical is proven to be an efficient way to solve this problem. This study investigated poly(ethylene-co-vinyl acetate(EVA)) and Poly(maleic anhydride-alt-1-octadecene)(MA) polymer inhibitors on the van der Waals intermolecular interaction between the major wax component molecule n-octacosane C28H58, via molecular dynamics simulation (MD) technique on Material Studio 5.5 software Package. COMPASS force field was applied to analyse the desired structural property, Radial Distribution Function (RDF). The results showed that the radial distribution function and g (r) value is able to give the insight on which particular type of fuctional atoms were benefit to inhibit the self-agglomerate of the wax crystal formation. The presence of carbonyl oxygen in EVA plays a significant role to inhibit the wax formation through the van der Waals interaction between active hydrogen atoms in n-octacosane molecule. Therefore the chances of wax inhibition in octacosane is higher by introduced EVA as inhibitor compared to MA.

Introduction
Wax deposition from crude oil from the subsea can occur along the pipeline transpotation which is connected from offshore well to the onshore [1]–[4]. The deposition or crystallization phenomenon occurs when the operating temperature of the pipeline is below the Wax Appearance Temperature (WAT) where the long linear n-paraffin chains of waxy crude come into contact with the circumference of the pipeline. The chains crystalize and adhere to each other inside the pipeline [5]. The deposition of wax can reduce the oil production operation through the blockage due to pipeline restrictions, failure of equipment, additional horsepower requirement [1].
Removal of Divalent Cations from Brine Using Selective Adsorption onto Magnetic Nanoparticles
Authors: Wang Qing , Prigiobbe Valentina , Huh Chun , Bryant Steven Lawrence , Mogensen Kristian , Bennetzen Martin Vad 
Published: May 2016

Abstract
Divalent cations, especially calcium (Ca2+), are known to significantly affect the performance of anionic surfactants and polymers used in enhanced oil recovery (EOR) processes. An efficient technique to remove Ca2+ from brine is reported, which is based on selective adsorption of Ca2+ onto functionalized iron oxide magnetic nanoparticles (IOMNPs). Upon adsorption, the IOMNPs can be separated by applying a magnetic field, leaving behind softened water.
IOMNP was synthesized by coprecipitation, and the amine-functionalization of its surface was obtained according to an aqueous APTES coating process. Chelating agent, polyacrylic acid (PAA), was successfully coated on amine-functionalized IOMNPs via amidation of carboxylic acid using 1-ethyl-3-(3-dimethylaminopropyl) carbodiimide (EDC). PAA modification significantly enhanced the adsorption capacity of IOMNPs due to their great ability to chelate Ca2+. The effect of pH on adsorption capacity was also investigated. The adsorption capacity of Ca2+ onto PAA-IOMNPs was found to be as high as 57.2 mg/g at pH 7 from the 400 mg/L Ca2+ solution. However, in American Petroleum Institute (API) standard brine (8×104 mg/L NaCl and 2×104 mg/L CaCl2), the adsorption capacity of IOMNPs decreased to 9.8 mg/g since the high salinity screens the charges on the surface of PAA-IOMNPs and results in the formation of nanoparticle aggregates. PAA-IOMNPs can be reused after treated by acetic acid solution.
A geochemical model was developed to describe the competitive adsorption of Ca2+ and H+ onto amine-functionalized IOMNPs as a function of solution pH and Ca2+ concentration. Comparison between the model and the experiments shows that the adsorption isotherms predict the behavior of the system very well. Below pH 4, adsorption of Ca2+ is negligible and becomes important above pH 7. This opens the possibility of recovering the nanoparticles after the divalent cation removal, and reusing them for the repeated water softening.
Successful Application of Through Casing Saturation Technology to Increase Oil Production in an Offshore Mature Well
Authors: Hughes Mark Anthony , Kramer Hermann , Ramli Mohamad Najib , Abdul Razak Rafidah , Valouiski Konstantin 
Published: May 2016

Abstract
An oil well incremental production increase of 1534 bopd and water cut decrease from 40% to 26% was the result of collaboration between a new through casing petrophysical technology provider and the reservoir management team. Post-production saturation logging was conducted through casing over an upper unperforated section of sand in a mature Peninsular Malaysia offshore deviated oil producer (Well-X).Well-X initially discovered16m of gas and38m of oil in a channel sand reservoir. To avoid early gas coning, Well-X was completed as an oil producer in the lower sand below a shale barrier. Simulation studies indicated that oil had been pushed up with water injection from a down dip water injector and that the upper sand should now be oil saturated. The 72 degree wellbore coupled with tubing and casing across the zone of interest added a challenge to cost-effectively confirm the simulation results.
To meet the challenge, the upper sand was logged in real time mode using tractor delivery method with a new through casing petrophysical tool capable of measuring saturation through multiple strings of pipe among other important parameters. Comparing the saturation log with the pre-production saturation log indicated an increase in oil saturation as predicted. Subsequent perforation and flow-back of the upper zone confirmed the simulation studies increased oil saturation. Post perforation test rates indicated an increased oil rate from 2400 bopd to3934bopd, and decreased water cut from 40% to26%, and with no indication of any free gas production.

Background
The H sand oil reservoir is one of many stacked (&gt;250) gas and oil clastic reservoirs located in a Peninsular Malaysia offshore asset. The H sand oil reservoir was discovered by an appraisal / development well (Well X) drilled from one of the field's satellite platforms in 2009. (Figure 1)
Well X was drilled to appraise / develop a primary I sand oil target, with well trajectory optimized to penetrate a secondary H sand gas appraisal (Figure 2). The primary target I sand however turned out to be gas on water, whereas the well discovered a GOC in the H sand (Figure 3).
Well X was completed in the H oil zone below a shale barrier to avoid the gas (Figure 3), and put on an extended well test for 6 mths. Material balance / simulation history match indicated sufficient oil column for subsequent downdip water injection, which was drilled and completed in 2010 and saw the H sand OWC. From 2010 the H sand has been under production with downdip water injection support.
Well-X produced dry oil at about 3600 bopd until early 2013, when water breakthrough occurred (Figure 4). By 2013 Well X had recovered 5 mmstb of an estimated 17 MMstb in place. The observed water breakthrough was predicted by a history-matched Eclipse numerical simulation model of the H sand model.
High Resolution Anisotropic Earth Model Building on Conventional Seismic Data Using Full Waveform Inversion: A Case Study Offshore Australia
Authors: Lim Bee Jik , Vigh Denes , Alwon Stephen , Hydal Saeeda N. , Bayly Martin , Manuel Chris , Chagalov Dimitri , Hampson Gary , Bevc Dimitri 
Published: May 2016

Abstract
We present a case study from the North West Shelf of Australia where the complexity of the overburden consists of several thin multi-level channel systems filled with a combination of anomalously high or low velocity sediments. Not accounting for these strong velocity variations accurately, can lead to subtle image distortions affecting the underlying section down to and including the reservoir level. This can have significant impact on the volumetric estimates of reserves in place. To resolve these complexities in the overburden, full waveform inversion (FWI) was utilized to generate an updated earth model exploiting both early arrivals and reflection events. One caveat to using full waveform inversion is the need for low frequencies to be present in the seismic data, or, the initial starting velocity model must contain the correct low wavenumber components. However, conventional seismic data acquired at shallow tow depths are usually band limited particularly at the very low frequencies. Our case study will discuss these issues along with other limitations that this "conventional data" presented along with the workflows and quality control methods adapted to this data in order to converge to a plausible, high resolution earth model.

Introduction
An accurate earth model is fundamental to any depth imaging project. Full waveform inversion is an advanced model building technique incorporating the full two way wave equation. Full waveform inversion produces an accurate high resolution earth model by simultaneously using the information of travel time, amplitude and phase contained in the full recorded seismic wavefield. One pre-requisite to full waveform inversion is an initial starting model. In this case study, the initial starting model was derived from a smooth version of a reflection travel time tomography velocity field derived from a depth migration workflow. The full waveform inversion process utilizes this model and a two-way wave equation finite difference acoustic wavefield propagator to generate modelled seismic data. These modelled shots are then compared to the acquired (observed) recorded seismic shots. The residual differences are backward propagated from time to depth domain, into velocity gradients and velocity changes required to obtain an updated model (see Figure 1). As with solving any non-linear inversion problem, it is an iterative process and is repeated as required until the residuals between the modelled shots and the actual observed seismic data are minimized. Iterations start at low frequencies and progress to higher frequencies.
Paradigm Shift in the Development of the North Kuwait Fields
Authors: Al-Rasheedi Saleh , Yannimaras Demetrios V 
Published: May 2016

Abstract
This paper discusses the reasons and results of the paradigm shift in NK reservoir management that was necessary in order to increase oil production and safeguard reserves. The new best practices implemented included: field development via horizontal & slant wells, significantly increased water injection with peripheral horizontal wells, Produce High-Inject Low (PHIL) strategy to enable gravity-stable oil production, horizontal re-entries and sidetracks, and the wide adoption of the advanced completion technology of passive inflow control devices (ICDs). Implementation results are provided for those implementation steps where enough time has passed, sufficient to form meaningful conclusions.
In order to promote dependable production forecasting and accurate operations results reporting, the QRI-KOC AVAILS+Ô (from "available production") package was developed. It is a powerful tool for the management and developmental planning of NK's set of oilfield assets and its two aspects, production forecasting and operations monitoring, are described below.

Introduction
The North Kuwait (NK) production area is made up primarily of the Raudhatain (RA), Sabriyah (SA), and Border fields.
The major productive horizons are the Mauddud (MA), Upper Burgan (UB), & Lower Burgan (LB) formations. Production for the last 4 years has ranged from 600–700 KBOPD.
The operator, KOC (Kuwait Oil Company), faced an overall production challenge, in that the options to sustain and increase production were limited by: (a) lack of new proven acreage, or behind-pipe resources, for development, (b) continuous drop in Pres, approaching Pb, for the reservoirs under depletion or under waterflooding (due to VRR&lt;&lt;1), and (c) gradually diminishing oil rate and rising watercut for the reservoirs with aquifer support, due to oil column invasion by water.

Discussion
In view of the serious challenges discussed in the Introduction, a paradigm shift, a fundamental change in approach or underlying assumptions, was necessary in order to increase production and reserves.

Drilling & Completions.
In the Drilling & Completions area, the need to quickly implement advanced well technology required the NK assets to implement best practices in all phases of their well planning and drilling operations. The organization quickly moved away from vertical wells and conventional completions to deviated wells (horizontal and slanted) with ICDs, in order to maximize reservoir contact and well productivity, while controlling water production. This paradigm shift impacted all partners and vendors, who had to shift their work emphasis to better support KOC in both the new horizontal drilling paradigm and the higher oil rate targets.
The Drilling & Completions improvements have been gratifying. Figure 1 shows the drilling improvements for the last three years. Figure 2 shows the resulting production improvement (20+ MMBO benefit) in one large reservoir, due to the adoption of horizontal wells and improved drilling and completion practices.
Challenges in Data Integration, Design and Modeling of the Coreflood for FWAG EOR
Authors: Jalan Shlok , Karkooti Hooman , Masoudi Rahim , Baruah Bikram Mojinder , Salmi Norbashinatun 
Published: May 2016

Abstract
Most of the Malaysian oil fields are mature and the need for IOR/EOR driven development planning is vital to maintain the national production. The most common EOR methods employed in Malaysia are immiscible WAG and CEOR. However, one of the main problems in WAG is how to control gas mobility to minimize the conformance issue and maximize the 3-phase region in the reservoir. Using Foam is a relatively cost effective way of controlling gas mobility by means of low concentration of surfactant. However, the practical implementation has been hindered due to the lack of general understanding of the complex process of foam phase behavior and flow dynamics in porous media, the absence of reliable predictive models of multi-phase foam flow, and also the challenges in upscaling the lab results to the field application.
The data integration, fundamental understanding, input evaluation and predictive modeling of WAG and Foam Assisted WAG (FAWAG) have been reviewed in this work using two extensive core flooding data of one of the Malaysian oil field in two different simulators. Review of the laboratory procedure showed the importance of taking proper pre-design measures to be able to achieve conclusive results. The modeling practice shows that output parameters from coreflood experiments might be affected by forced history matching and consequently unrealistic simulation input parameters as well as the shortcomings of the predictive capability of different simulators.
The study showed that in the core flood experiments and simulations, various aspects need to be carefully considered including:Reliable data integration and understanding of the physics/dynamics involved in the process are important for proper evaluation of the foam effect.Simulation studies to be used for the pre-design and optimization of the coreflood experiment and parameters (i.e., rate, cycles, pore volume, etc.).The measured rates and pressures must be of consistent resolution to be able to capture the exact phase breakthroughs and precise fractional flows of the experiment.The SCAL endpoints and WAG parameters must be measured and fixed prior to FAWAG experiment and simulation.Capillary end effect, formation water salinity effect on contact angle and capillary pressure impact on coreflood results needs to be carefully considered in both laboratory and modeling stages.Different commercial simulators may results in different prediction on foam output and the effect, hence proper evaluation, de-risking and sensitivity analysis should be performed to capture the foam EOR window of opportunity.
Experimental and CFD Erosion Modelling of Large Radius Pipe Elbows in Liquid
Authors: Johar Zurita , Bin Jadid Maharon , A. Shaffee Siti Nur , A. Zamberi M Shahrul , Wong Chong Y , Solnordal Christopher B. , Boulanger Joan 
Published: May 2016

Abstract
Numerical erosion modelling of elbows at various elbow curvatures (ratio of elbow radius to elbow inner diameter) in gas only flows has been well validated with extensive experimental data available in the literature. Surprisingly, this is not the case for liquid only flows.
Rather, the available literature data presents conflicting results of the erosion ratio trend for elbows of various curvature ratios in liquid only flows. The present work seeks to address and clarify these ambiguities through physical erosion experiments using a Coordinate Measurement Machine (CMM) to measure the net eroded surfaces of a standard elbow with a curvature ratio of 1.5 and an elbow with curvature ratio of 4.
Both elbows are tested in water-sand slurry at ambient conditions. Numerical modelling using Computational Fluid Dynamics (CFD) complements the physical understanding of the erosion results. The validated CFD model is then used to conduct parametric studies for the development of a revised correlation to predict erosion ratio, defined in this work as maximum erosion of elbows of given curvature with respect to erosion of a standard radius elbow (elbow curvature of 1.5) in liquid-solid flow.
CFD is able to predict qualitative erosion trends and erosion patterns, and provide quantitative match of relative erosion ratio of elbow with curvature ratio 4 to standard elbow in experimental specimen to within 10% accuracy.

Introduction
Management of erosion is one of the challenges in an oil and gas system with sand production. Severe erosion caused by impingement of sand particles on a metal wall may cause damage to facilities such as piping, pipe fittings, choke valves and crude oil transfer pumps as sand is being transported along the flow path. Erosion on pipe fittings such as standard and long radius elbows and plugged tees has been studied by various researchers over the years both through experiments and Computational Fluid Dynamics (CFD) modelling [1–8].
The Use of Fluorescent Tracers for Inhibitor Concentration Monitoring Useful for Scale Inhibitor Squeeze Evaluation
Authors: Brichart Thomas , Moussaron Albert , Marais Arthur , Martini Matteo , Tillement Olivier , Hurtevent Christian , Baraka-Lokmane Salima 
Published: May 2016

Abstract
A common problem, in oilfield reservoirs is mineral scale deposition. The build-up of scale inside well bores and the surrounding reservoir causes millions of dollar in damage every year. The most common remedy is to treat the formation of such minerals with scale inhibitor chemicals in a "squeeze" treatment; which is performed periodically. One of the big challenges remains the real-time and on-site control of inhibitor concentration during production. A simple and accurate method to determine the concentration of inhibitors has been developed; this method is based on the use of luminescent tracers. The multiple lifetimes as well as the differences shown in the emission and excitation spectra of the tracers appear to be suitable for the luminescence detection. The increased signal to noise ration due to the suppression of the background resulting from the organic oil residues is used to measure the concentration of residual inhibitors in production waters. Furthermore, the use of a technique as versatile and simple as luminescence spectroscopy allows the online and/or on-site monitoring with very limited drawbacks. This paper describes the use of novel real-time scale inhibitor monitoring; this new technique will help to optimize the treatment rates of the scale inhibitor squeeze treatment.

Introduction
Limescale (calcium carbonate) that deposits on the surface of well bore will, if untreated, reduce the efficiency of the exploitation, inducing corrosion of the production chain and ultimately leading to appliance failure. Indeed, pipework scale reduces the available cross-section area, and fluids are affected by increased pipe wall friction. A larger, more power-consuming pump will be required to maintain throughput volumes, but this can only be a temporary solution to the problem. A plant that needs to be shut down for cleaning costs millions of dollar in damage every year (Moghadasi, J. et al. 2004-A).
The formation of a thin uniform layer of scale or wax temporarily gathers the steel corrosivity, but at long-term the stagnant conditions of deposit and electrochemical reactions will corrode the steel surfaces. The fluid leaks as well as the equipment failure have been expected with potentially dangerous consequences.
Performed periodically, "squeeze" treatment is one of the most common remedies to treat the formation of such minerals. Treatment options include inhibitor chemicals, descalers, ion exchange, physical cleaning such as pipeline pigging (Collins, I.R. et al. 2001).