bluuebunny/crossref_metadata_2025_split huggingface dataset:
Aluminum and Iron Precipitation During Sandstone Acidizing Using Organic-HF Acids
Authors: Al-Harbi B. G. , Al-Dahlan M. N. , Al-Khaldi M. H. 
Published: June 2014

Abstract
Different organic-HF acid mixtures have been used to stimulate sandstone formations. Typically, they are used as alternative to regular mud acid in order to overcome its potential limitations such as rapid spending, high corrosion rate and incompatibility with sensitive clays. However, organic-HF systems are more susceptible to fluoride-based precipitations because they contain high amount of free fluoride ions. This paper focuses on identifying the type of precipitations that occur during reactions of organic-HF acids, and on determining the factors that affect these precipitations.
Solutions of different organic-HF acids namely formic, acetic and citric acid, containing HF concentrations of 0.5, 1 and 1.5 wt%, were examined in this study. Aluminum chloride or iron chloride were added separately to each organic-HF acid solution to contain 1,000; 5,000 or 10,000 mg/L of aluminum or iron (III) ions, respectively. The acid mixtures were neutralized by adding sodium hydroxide. Filtered solutions were analyzed using inductively coupled plasma (ICP) to assess the ability of used acids to hold Al and Fe (III) dissolved ions, while formed solid precipitates were analyzed by X-ray diffraction (XRD).
The type and amount of precipitates were found to be mainly dependent on solution pH, organic-HF type, and initial free fluoride concentration. All live organic-HF acids containing dissolved iron (III) showed no precipitation even after iron (III) level reached 10,000 mg/L. However, when solution pH value was raised, none of tested organic-HF acids were able to prevent iron fluoride precipitation. On the other hand, the main factor that controlled the aluminum-fluoride precipitation was found to be F/Al ratio. It was found that there is a critical F/Al ratio, above which the aluminum fluoride precipitation occurred.
The Impact of Complex Nanofluid Composition on Enhancing Regained Permeability and Fluid Flowback from Tight Gas Formations and Propped Fractures
Authors: Champagne Lakia M. , Zhou Hui , Zelenev Andrei S. , Lett Nathan 
Published: June 2014

Abstract
A continuing challenge in hydraulic fracturing of tight gas formations is associated with remediation of formation damage caused by fluid invasion into the porous media. Numerous studies documenting the use of complex nanofluids and surfactants to remediate formation damage have been reported. Recent publications have demonstrated that complex nanofluid additives resulted in lower pressures to displace injected frac fluids over conventional surfactants, and led to greater enhancement of gas and water production. These findings were also confirmed by several recent statistical analyses that took into consideration differences in the properties of treated wells. Many field case studies and supplementary laboratory data have illustrated benefits of complex nanofluid treatment over conventional surfactants. While these publications describe the successes of complex nanofluid treatment, the influence that the formulation composition has on its performance has not been fully investigated. In the present study, we prepared complex nanofluids with different chemical compositions and examined their performance in fluid recovery tests using columns packed with sand, ceramic proppant, and shale, as well as their ability to enhance permeability of sandstone cores to gas. We have established that performance of complex nanofluids in these applications was dependent on the amount of microemulsifed solvent in the original formulations and that optimal performance across all applications was achieved with a complex nanofluid formulation with a near-balanced composition.
"Squimulation": Simultaneous Well Stimulation and Scale Squeeze Treatments in Deep Water, West Africa
Authors: Patterson D. , Kendrick M. , Williams W. , Jordan M. 
Published: June 2014

Abstract
In a deepwater West African field the relatively small number of high-cost, highly productive wells, coupled with a high barium sulfate scaling tendency (upon waterflood breakthrough of injected seawater) requires effective scale management along with removal of near-wellbore damage in order to achieve high hydrocarbon recovery.
The nature of the well completion strategy in the field (frac packs for sand control) had resulted in some wells with higher than expected skin values due to drilling fluid losses, residual frac gel, fluid loss agents, and fines mobilization within the frac packs.
The paper will present how the challenges of managing impaired completions and inorganic scale forced innovation in terms of when to apply both stimulation and scale inhibitor packages to deep water wells. This paper will outline a novel process for non-conventional batch chemical applications where bullhead stimulation treatments have been displaced deep into the formation (&gt;20ft) using a scale inhibitor overflush. Not only does this benefit the stimulation by displacing the spent acid and reagents away from the immediate wellbore area, but the combined treatment provides a cost savings with a single mobilization for the combined treatment. The paper will describe the laboratory testing that was performed to qualify the treatments. The four field treatments that were performed demonstrate how these coupled applications have proven very effective at both well stimulation/skin reduction and scale inhibitor placement prior to and after seawater breakthrough. The term "squimulation" is used by the local operations team to describe this simultaneous squeeze and stimulation process.
Many similar fields are currently being developed in the Campos basin, Gulf of Mexico, and West Africa, and this paper is a good example of best-practice sharing from another oil basin.
Coiled Tubing Operational Guidelines in Conjunction with Multistage Fracturing Completions in the Tight Gas Fields of Saudi Arabia
Authors: Al-Gazal Mohammed , Abel Justin Tate , Wilson Stuart , Wortmann Henry , Johnston Bryan 
Published: June 2014

Abstract
Open hole multistage fracturing (MSF) completions are becoming standard practice in the south gas fields development in Saudi Arabia with more than 25 wells completed to date using open hole packers and selective port technology.
Overall, the production results from the use of MSF completions have been very positive and the forecast is that MSF technology usage will grow considerably over the next several years. In general, MSF completions provide an excellent advantage in that they are intervention-less in their standard mode of operation. An aspect that is evolving is the secondary use of coiled tubing (CT) to handle the planned and unplanned (contingency) operations occasionally required to reach well production objectives. Without optimum operational planning and the selection of correct CT downhole tools, completion problems can be encountered and this ultimately can result in the job objective not being reached at all or only at increased costs. In addition, the use of CT to function ball-activated ports to shut off zones or to re-stimulate is starting to be appreciated.
This paper presents MSF case studies where CT has been deployed and investigates the operational impact and productivity enhancement. Correlations taken from the key hardware variables, such as fracturing port size and type, motor type, mill bit type, and CT size, are also considered and analyzed.
Following the lessons learned and best practices from these experiences, with correct implementation, the findings from this paper should increase the potential for successful multistage completion operations and ultimate improvements in productivity. These guidelines can thus be transferable to other operators using similar MSF completion technologies.
Test of SAGD Flow-Distribution-Control Liner System in the Surmont Field, Alberta, Canada
Authors: Stalder John 
Published: June 2014

Summary
The Surmont Well Pair 102-06 started steam-assisted-gravity drainage (SAGD) operation in April 2009 with flow-distribution control (FDC) built into the horizontal liners for both the injection and the production wells. After preheat steam circulation, this liner system has allowed operation without a toe tubing string in either completion and has delivered superior steam-chamber development and overall performance. The design also allowed reducing the liner and casing size for the injection well. Future SAGD-well design may benefit by further reduction in liner and casing sizes for both the injector and producer, which could allow longer completions by reducing liner drag and increasing directional-drilling flexibility. Ultimately, these SAGD-well design changes could increase the amount of reservoir developed per well and per well pad, using longer wells and more wells per pad while achieving superior SAGD performance.
Pore-Scale Modeling of Waterflooding in Mixed-Wet-Rock Images: Effects of Initial Saturation and Wettability
Authors: Zhou Y.. , Helland J.O.. O. , Hatzignatiou D.G.. G. 
Published: June 2014

Summary
We simulate transient behavior of viscous- and capillary-dominated water invasion at mixed-wet conditions directly in scanning-electron-microscope (SEM) images of Bentheim sandstone by treating the pore spaces as cross sections of straight tubes. Initial conditions are established by drainage and wettability alteration. Constant rate or differential pressure is imposed along the tube bundle. The phase pressures vary with positions along the tube length but remain unique in each cross section, consistent with 1D core-scale models. This leads to a nonlinear system of equations that are solved for the interface positions as a function of time. The cross-sectional fluid configurations are computed accurately at any capillary pressure and wetting condition by a semianalytical model that is based on free-energy minimization. The fluid conductances are estimated by newly derived explicit expressions that are shown to be in agreement with numerical computations performed directly on the cross-sectional fluid configurations.
An SEM image of Bentheim sandstone is taken as input to the developed model for simulating the evolution of saturation profiles during waterfloods for different flow rates and several mixed-wet conditions, which are established with various initial water saturations and contact angles. It is demonstrated that the simulated saturation profiles depend strongly on initial water saturation at mixed-wet conditions. The saturation profiles exhibit increasingly gradual behavior in time as the contact angle, defined on the oil-wet solid surfaces, increases or the initial water saturation decreases. Front menisci associated with positive capillary pressures promote oil displacement by water, whereas for large and negative capillary pressures at small flow rates, oil displaces water because the associated front menisci retract. This results in the development of pronounced gradual saturation fronts at mixed-wet conditions. The waterfloods simulated at conditions established with a large initial water saturation and small contact angle on the oil-wet solid surfaces exhibit sharp Buckley-Leverett saturation profiles for high flow rates because the capillary pressure is small and less important. The shape of the saturation profiles is interpreted on the basis of the simulated capillary pressure curves and the corresponding fluid configurations occurring in the rock image.
Double-Layer Expansion: Is It a Primary Mechanism of Improved Oil Recovery by Low-Salinity Waterflooding?
Authors: Nasralla Ramez A. , Nasr-El-Din Hisham A. 
Published: June 2014

Summary
Literature review shows that improved oil recovery (IOR) by low-salinity waterflooding could be attributed to several mechanisms, such as sweep-efficiency improvement, interfacial-tension (IFT) reduction, multicomponent ionic exchange, and electrical-double-layer (EDL) expansion. Although these mechanisms might contribute to IOR by low-salinity water, they may not be the primary mechanism. Therefore, the main objective of this study is to investigate if the mechanism of EDL expansion could be the principal reason for IOR during low-salinity waterflooding.
Low-salinity water results in a thicker EDL when compared to high-salinity water, so we tried to eliminate the effect of low-salinity brines on double-layer expansion to show to what extent IOR is related to EDL expansion caused by low-salinity water. The double-layer expansion is dependent on the electric surface charge, which is a function of the pH of brine; therefore, the pH levels of low-salinity brines were decreased in this study to provide low-salinity brines that can produce a thinner EDL, similar to high-salinity brines. ζ-potential measurements were performed on both rock/brine and oil/brine interfaces to demonstrate the effect of brine pH and salinity on EDL. Contact angle and coreflood experiments were conducted to test different brine salinities at different pH values, which could assess the effect of water salinity and pH on rock wettability and oil recovery, and hence involvement of EDL expansion in the IOR process.
ζ-potential results in this study showed that decreasing the pH of low-salinity brines makes the electrical charges at both oil/brine and brine/rock interfaces slightly negative, which reduces the double-layer expansion caused by low-salinity brine. As a result, the rock becomes more oil-wet, which was confirmed by contact-angle measurements. Moreover, coreflood experiments indicated that injecting low-salinity brine at lower pH values recovered smaller amounts of oil when compared to the original pH because of the elimination of the low-salinity-water effect on the thickness of the double layer. In conclusion, this study demonstrates that expansion of the double layer is a dominant mechanism of oil-recovery improvement by low-salinity waterflooding.
Refined Adaptive Gaussian Mixture Filter - Application on a Real Field Case
Authors: Valestrand Randi , Nævdal Geir , Shafieirad Ali , Stordal Andreas S. , Dovera Laura 
Published: June 2014

Abstract
Over the last decade the ensemble Kalman filter (EnKF) has attracted attention as a promising method for solving the reservoir history matching problem: Updating model parameters so that the model output matches the measured production data. The method possesses unique qualities such as; it provides real time update and uncertainty quantification of the estimate, it can estimate any physical property at hand, and it is easy to implement. The method does, however, have its limitations; in particular it is derived based on an assumption of a Gaussian distribution of variables and measurement errors.
A recent method proposed to improve upon the original EnKF method is the Adaptive Gaussian mixture filter (AGM). The AGM loosens up the requirements of a linear and Gaussian model by making a smaller linear update than the EnKF and by including importance weights associated with each ensemble member at computational costs as low as EnKF. In this paper we present a refined AGM algorithm where the importance weights are included in the calculation of the apriori and the aposteriori covariance matrices. Moreover, in this paper the AGM algorithm is for the first time applied to a real field study.
To validate the performance of AGM the results are compared with the EnKF, with and without distance based localization. Several statistical measures are used to validate the performance of the filters, and we are able to distinguish the performance of the different filters. In particular all the methods provide good history match, but we see that the AGM stands out by better honoring the original geostatistics and by providing consistent predictions when rerun is performed.
Estimation of Relative Permeability by Assisted History Matching Using the Ensemble Kalman Filter Method
Authors: Li Heng , Chen Shengnan Nancy , Yang Daoyong (Tony) , Tontiwachwuthikul Paitoon 
Published: June 2014

Summary
An ensemble-based history technique has been applied to implicitly estimate three-phase relative permeability curves from production data. A power law representative of relative permeability curves is used. Both endpoints and shape factors of relative permeability curves are included in state vectors that are updated sequentially by assimilating observation data. This method has been validated by accurately evaluating relative permeability in a synthetic reservoir with 2D, three-phase flow. It is shown from the synthetic case that good estimation of relative permeability curves can be obtained by assimilating the observed oil rates, gas/oil ratios, and bottomhole pressures of production wells. Both shape factors and endpoints of relative permeability curves are accurately evaluated; however, a larger ensemble size is needed to avoid filter divergence. Compared with the existing implicit methods, the ensemble-based history matching technique does not require the gradient of the objective function, which makes the technique easy to implement.
Some Results of Fracturing with the Single-Point Entry Technique
Authors: Swift V.N. , Jennings J.W. , Bauman W.E. , Huitt J.L. 
Published: June 2014

Abstract
Fracturing with the single-point entry technique is discussed for the Big Piney and Patrick Draw fields, Wyo., and the Bijou field, Colo. In the single-point entry technique, the wellbore is notched at a selected point. The well is fractured and then is produced by way of the single fracture. The results indicate that fracturing treatments can be performed more easily through the single entry than through perforations, and the production histories available thus far indicate that wells fractured with the single-point entry technique have higher productivities than those fractured by conventional wellbore preparation.

Introduction
The single-point entry technique of fracturing for well stimulation per se was first used in the Big Piney field, Wyo., in June, 1959. This technique of fracturing, in which the wellbore is notched for the fracture placement and a single, high-flow-capacity fracture is used for the production stimulus, was originally considered to have its greatest potential in secondary recovery schemes and in the control of gas and/or water coning. However, during the development of the techniques for notching the wellbore and for selection and placement of the fracture propping agent, it became apparent that for a number of reservoirs conventional fracturing techniques did not provide the well stimulation that the single-point entry technique would provide. Thus, the mechanics of the technique was adapted for use as a production stimulus during primary recovery.
Since June, 1959, single-point entry fracturing has been used in several hundred cases for well stimulation. In a majority of the cases, a comparison of the results with those obtained by conventional fracturing in a perforated interval cannot be made because the available data are insufficient. However, sufficient data are available for three fields in the Rocky Mountain area to allow an evaluation of the usefulness of the single-point entry technique in performing fracturing operations. These fields are the Big Piney and Patrick Draw fields in Wyoming and the Bijou field in Colorado. Also, for the Patrick Draw field, productivity index data are available to enable a comparison of the results of fracturing to be made, and sufficient production history on the Big Piney field makes it possible to compare the performance of the wells fractured conventionally with those wells fractured by the single-point entry technique. In this paper, fracturing operations in the three fields listed are discussed as case histories.
Determining Areal Permeability Distribution by Calculations
Authors: Kruger W.D. 
Published: June 2014

Abstract
Methods for analyzing flooding or cycling projects by means of two-dimensional flow calculations are presented in the literature. The use of these methods allows the determination of optimum operating conditions for such projects and provides information on pattern efficiencies, relative flow rates, pressure distributions and floodout histories. The accuracy of such analyses depends on the basic reservoir data employed, especially the absolute permeability distribution in the reservoir; however, absolute permeability data normally are determined from well flow tests and/or core measurements and are so limited in quantity and quality that they do not adequately describe the reservoir flow properties.
A calculation procedure is presented for determining the areal permeability distribution in the reservoir. Use of the procedure allows verification of the basic reservoir data through the matching of past reservoir conditions, thereby providing proper data for reliable predictions of future operations. The calculation procedure is a numerical technique based on a mathematical model of the reservoir and is designed for solution by means of an electronic digital computer.
Results from field application of this procedure are presented. Permeability distributions from measured data are compared to those calculated to indicate the need for the analysis. Comparisons of field-measured and calculated pressure distributions are given to establish the validity of the calculation procedure.
The conclusions of this paper areuse of the calculation provides data that allow a match of past reservoir conditions and thus reliable prediction of future operations; andthe procedure should, where applicable, be used to provide adequate reservoir data for use in two-dimensional flow calculations and related reservoir analyses.

Introduction
One means of providing more precise engineering control over reservoir operations during all stages of depletion is to develop some type of model to simulate the reservoir, using information developed from the behavior of the prototype to predict the performance of the actual reservoir. The use of mathematical rather than physical models for this purpose has been gaining in importance recently because of the application and availability of electronic computers. Mathematical models avoid instrumentation difficulties and allow easier handling of large-scale problems. At present, analyses employing two-dimensional models are common, and thought is being given to the use of models in three dimensions. The use of multi-dimensional models is necessary to show not only what is occurring in the reservoir, but also where in the reservoir the phenomena of interest are taking place.
SPE Dives Into the Gender Diversity Pool
Authors: Capello Maria Angela 
Published: June 2014

Abstract
With the ever increasing global demand for energy, the oil and gas industry must improve and anticipate its talent management needs by considering the current workforce profile, in which female employees are the minority. Being a traditionally male-dominated industry, gender-diversity concepts only recently have found their way into corporate policies, executive managers' desks or into Board of Directors meetings. In many cases, the inclusion of women in leadership roles is far from being a reality for companies in the up-and down-stream sectors.
This article summarizes some of the results of the global scale efforts of the Society of Petroleum Engineering (SPE) towards the establishment of new paths to exchange lessons learned, and the creation of new networking opportunities for its female members. Up to now, the SPE is the only oil and gas professional society that consistently has promoted the empowerment and progress of its female members with dedicated activities since the late 80's, in a 30-year pioneering role.
More actions are certainly needed, but this SPE visionary effort must be shared and celebrated.