bluuebunny/crossref_metadata_2025_split huggingface dataset:
Scale Inhibitor Consumption in Long-Term Static Barium Sulphate Inhibition Efficiency Tests
Authors: Shaw S. S. , Sorbie K. S. 
Published: June 2014

Abstract
In typical bulk barite inhibition efficiency (IE) experiments testing scale inhibitors (SI), the IE is determined by comparing the concentrations of the barium ion in the mix to that in an uninhibited "blank" solution. That is, [Ba2+] vs. time is monitored for both a blank and an inhibited solution. The fate of the scale inhibitor itself over this test time period is rarely monitored although this can give some important insights into the inhibition mechanism. This paper presents a series of long-term (up to 96 hour) barium sulphate static inhibition efficiency (IE) experiments in which both the supernatant scale inhibitor concentration, [SI], and [Ba2+] are assayed at multiple sampling times after initial mixing of sea water (SW) and formation water (FW) brines. In standard IE tests to determine SI minimum inhibitor concentration (MIC), sampling is normally carried out at 2 hours and 22 hours only. The long-term IE experiments described in this paper involve up to eleven sampling times, typically at t = 0.5, 1, 2, 3, 4, 5, 6, 22, 48, 72 and 96 hours after mixing.
The aim of this type of experiment is to determine the fate of the SI over time, and secondly, to determine whether the IE and %SI in solution versus time profiles correlate with each other. Clearly, SI removed from solution is consumed into the forming barium sulphate lattice in the barite precipitate. IE and solution SI often continue to decline beyond 22 hours, up to 96 hours after the mixing stage. In these experiments, the SI concentration is set at a pre-2 hour MIC threshold concentration, such that the IE and %SI consumption profiles will both decline sufficiently over time, possibly even as early as 0.5 hour after mixing. The SI consumption profiles obtained testing an extensive range of phosphonate and polymeric SIs are compared and discussed. Normally a phosphorus-containing SI is selected for evaluation, to facilitate assay of SI by means of inductively coupled plasma (ICP) spectroscopy. However, intriguing results are also presented where selected polymeric SIs were assayed by non-ICP analytical techniques. We interpret this extensive series of SI lattice consumption experiments in terms of the mechanisms of barite inhibition and Type 1 / Type 2 SI classifications presented in previous papers (Shaw et al., 2012a, 2012b).
Inorganic Scaling and Chemical Inhibition Challenges Associated with Production of Reservoir Equilibrated Spent Acid Stimulation Fluids
Authors: Morrow Timothy , Farooqui Mohammad , Morshidi Leozarin , VanNuis Russell , Graham Gordon , Kidd Sam , Dyer Sarah , Simpson Caroline 
Published: June 2014

Abstract
Hydrochloric acid (HCl) is commonly used to remove wellbore damage and to enhance near-wellbore formation permeability in carbonate formations. Although in most cases the spent acid is recovered rapidly during well flow back after the treatment, in heterogeneous reservoirs some of the spent acid can remain trapped for long periods becoming fully saturated with CaCO3 under downhole conditions. These reservoir-saturated spent acids then lead to scaling when eventually unloaded into the production system.
This paper describes a modelling and laboratory study to replicate the system, to allow selection of inhibitors which are effective against carbonate scales in spent acid solutions containing extremely high levels of Ca2+/Mg2+, and also remain stable at elevated temperatures in the spent acids. The work also examined chemical retention and release via coreflood testing followed by field application modelling to select effective scale inhibitors (SI) which possess poor retention properties on the carbonate substrate thereby remaining present in the "spent acid".
One significant challenge associated with this study was the ability to reproduce the mildly oversaturated field scaling environment in the laboratory. When using these fully saturated (with respect to CaCO3) partially acidic brines, very small changes in the brine chemistry or preparation procedures had a significant impact on scaling. A detailed evaluation of brine preparation, stabilisation and buffering was therefore required prior to evaluating generic scale inhibitors for performance under these extreme conditions leading to selection of appropriate species. The second stage of the work then involved core test procedures to determine those chemicals that offered minimal retention properties on the reservoir along with performance.
This paper will present the field scaling challenges observed due to unloading of trapped spent acids; describe challenges faced within the laboratory in reproducing these conditions and present results from generic chemical types which are effective at preventing scale under these extreme conditions. From the shortlisted products further results are presented demonstrating those which offer poor retention, which is generally the opposite of what is required for conventional scale inhibitor squeeze treatments, allowing selection for upcoming field trials in the selected field system.
The Impact of Dissolved Organic-Carbon Type on the Extent of Reservoir Souring
Authors: Burger E. D. , Jenneman G. E. , Gao X. 
Published: June 2014

Abstract
A reservoir souring forecasting model was presented previously. This model utilized a generic algorithm to determine, via history match, the extent of H2S biogeneration by sulfate-reducing bacteria (SRB) within the waterflooded reservoir such that the production to the surface could be forecasted. The generic algorithm assumed a decline in SRB-usable organic nutrients as a function of water flow within the reservoir. However, nutrient utilization by non-SRB (e.g., nitrate-reducing bacteria) could not be differentiated from the SRB with this model. The current study has incorporated stoichiometry of microbial sulfate and nitrate reduction utilizing both volatile fatty acids (VFA) and BTEX components as dissolved organic carbon (DOC) substrates. This paper presents the updated algorithms and discusses partitioning of the DOC components between oil and water within the reservoir. VFAs such as acetate have historically been assumed to be the favored nutrient source by SRB, but recent field experience has suggested that other DOC sources are contributors. BTEX components, especially toluene, are shown with the model to potentially have a large impact on souring in spite of their limited solubility in the reservoir water. While nitrate usage to control reservoir souring is becoming a "standard" practice, H2S generation in reservoirs with conditions that support BTEX as an SRB nutrient might not be sufficiently inhibited with nitrate.
Calcium Naphthenate Mitigation at Sonangol's Gimboa Field
Authors: Junior Jorge , Borges Luis , Carmelino Carlos , Hango Pedro , Milliken John Duncan , Asomaning Sam 
Published: June 2014

Abstract
Sonangol's Gimboa production is located in deepwater block 4 offshore Angola. Early in the life of the field and with the advent of water cut, it experienced solids production that fouled processing equipment and that were later identified as calcium naphthenates. The paper describes in detail Gimboa's calcium naphthenate deposition including its history and progression. Detailed characteristics of the crude and produced water are provided. The mechanisms of solids formation are elucidated and the remedial measures adopted to solve the problem are examined in detail. The impact of water cut and the role of system parameters like temperature and pressure in the resolution of the naphthenate problem are outlined and the use of field filtration and bottle testing methods in designing the eventual solution are highlighted. As with most oilfield problems calcium naphthenate deposition at Gimboa was brought under control through the conscientious efforts of Sonangol, Nalco Energy Services and Saipem personnel working as a team.
Prevention of Acid Induced Asphaltene Precipitation: A Comparison of Anionic vs. Cationic Surfactants
Authors: O'Neil Bill , Maley Darren , Lalchan Chris 
Published: June 2014

Abstract
With the recent proliferation of horizontal drilling specifically targeting oil bearing reservoirs, high strength acid fracturing treatments in the Beaverhill Lake formation in northern Alberta have dramatically increased in both product volume and number of treatments. The Beaverhill Lake formation is a limestone/calcareous shale that produces a desirable mid to high API sweet crude oil. Although the crude oil typically has a low concentration of asphaltenes, the oil is very sensitive to acid and/or iron induced asphaltene precipitation. As the acid strength increases and ferric iron is dissolved into solution, it becomes increasingly difficult to chemically prevent the asphaltenes from precipitating. Acid blends designed to prevent asphaltene precipitation also tend to be very emulsifying with the crude oil, therefore a careful balance between anti-sludge additives and non-emulsifiers must be found.
This paper will describe the chemistry of surfactants that can be used to prevent asphaltene precipitation as a result of acid/oil contact. Specifically, a comparison of anionic versus cationic surfactants will be given, describing both the benefits and detriments of using these in acid blends. A discussion of the change from vertical well completions in the Beaverhill Lake formation to horizontal multi-zone completions will be presented. As a result of this change in completions, the desired properties of the acid blends have changed noteably. The final results of a comprehensive laboratory study to optimize cost and performance of the acid blends will be presented. A review of field case studies comparing formation response to anionic and cationic acid blends will also be presented.
Simultaneous Well Stimulation and Scale Squeeze Treatments in Carbonate Reservoirs
Authors: Jordan M. M. 
Published: June 2014

Abstract
In many oilfields the relatively small number of high-cost, highly productive wells, coupled with a carbonate and or 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 new fields such as frac packs for sand control and acid stimulation for carbonate reservoirs has 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 where applied.
This paper presents 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 carbonate reservoirs. The combined treatment has the potential to provide cost savings with a single mobilization for the combined treatment. The paper will describe the laboratory testing that was performed to qualify the treatments for two carbonate reservoirs (black oil and HT gas/condensate). In the test program assessment was made of oil, brine and gas permeability prior to and following application of the stimulation packages. The chemical packages assessed included classic HCl formulation and chelant stimulation chemicals on their own and with inclusion of scale inhibitor chemicals to provide simultaneous stimulation/squeeze treatments. These formation damage results and chemical return profiles were then compared to coreflood test results with scale inhibitor applied as a typical squeeze treatment. Results for these studies show that under matrix flow conditions inclusion of even highly compatible scale inhibitor resulted in formation damage due to chemical/rock/brine incompatibility during the stimulation process. Details of the solution to this problem are outlined within this document.
A Coreflood Investigation of Nanofluid Enhanced Oil Recovery in Low-Medium Permeability Berea Sandstone
Authors: Hendraningrat Luky , Li Shidong , Torsæter Ole 
Published: June 2014

Abstract
Nanoparticles have become an attractive agent for improved and enhanced oil recovery (IOR & EOR) at laboratory scale recently. Most researchers have observed promising result and increased ultimate oil recovery by injecting nanofluids in laboratory experiments. In previous study, we observed that interfacial tensions (IFT) decreased when hydrophilic nanoparticles were introduced to brine. The IFT decreases as nanofluids concentration increase and this indicates a potential for EOR. We have also investigated nanofluid flow in glass micromodel and high permeability Berea sandstone (ss) cores, and we observed that the higher concentration of nanofluids; the more impairment of porosity and permeability. Since low permeability oil reservoirs have still huge volume of oil reserves, this study aims to reveal nanofluids possibility for EOR in low-medium permeability reservoir rocks and investigate its suitable concentration.
In this paper, laboratory coreflood experiments were performed in water-wet Berea ss core plugs with permeability in range 9- 35 mD using different concentrations of nanofluids. Three nanofluids concentrations were synthesized with synthetic brine; 0.01, 0.05 and 0.1 wt.%. To investigate disjoining pressure as displacement mechanism due to nanoparticles, contact angle between crude oil from a field in the North Sea and brine/nanofluids have been measured. Increasing hydrophilic nanoparticles will decrease contact angle of aqueous phase and increase water-wetness.
Despite increasing nanofluid concentration shows decreasing IFT and altering wettability, our results indicate that additional recovery is not guaranteed. The processes and results are outlined and also further detailed in the paper to reveal the possible application of nanofluid EOR in lower-medium permeability oil reservoir.
The Development and Field Application of New Surfactant Chemistries for Application to Heavy Oils
Authors: Temple-Heald Clare , Davies Craig , Wilson Natalie , Readman Nicola 
Published: June 2014

Abstract
A critical part of any Oilfield production processing is oil and water separation and although this area has had highly efficacious demulsifier products developed for a number of production scenarios the application to "heavy" oils remains problematic.
Over 70% of the future recoverable reserves have been designated as heavy oil and these developments will pose a number of unique oil and water separation challenges in production, transportation and refining compared to lighter crudes. Demulsification and desalting of these challenging crudes is needed in a wide variety of secondary and tertiary enhanced oil recovery applications and techniques, including waterflooding, steam assisted gravity drainage and cyclic steam stimulation.
This paper describes the laboratory development and subsequent field-testing of a specific range of chemistry for application to broad spectrum of heavy oil scenarios. It was found that specific properties related to interfacial tension were important, and this will be elaborated further. From the data, a model situation using specifically selected heavy oils has been developed for the evaluation of a number of surfactant chemistries, the criteria also includes a structure versus performance relationship to identify optimum surfactant properties.
This work has resulted in a tailored range of demulsifiers, which will add to the relatively small number of chemistries able to effectively be applied across the growing heavy oil development and production area. In addition to technical efficacy recognition of environmental impact and some specific chemistry relating to application in environmental regulated areas such as the North Sea will be discussed.
Recent Advances in Organically Crosslinked Conformance Polymer Systems
Authors: Reddy B. R. , Eoff Larry , Crespo Freddy , Lewis Chris 
Published: June 2014

Abstract
Organically crosslinked polymer systems have experienced considerable commercial success in shutting off undesirable water production. One of the systems most widely used to date employs acrylamide-containing polymers as base polymers and polyamines as crosslinkers. Its success can be attributed to 1) low viscosity in a noncrosslinked state, 2) versatility and stability over a wide temperature range, 3) rigid ("ringing") gel formation, and 4) deep matrix penetration.
The objective of the present study was to improve the current acrylamide- and amine-based polymer formulations by significantly reducing the polymer concentrations while retaining the gel performance. This was accomplished by the inclusion of organic activators that substantially increase the crosslinking reactivity of the polyamine, allowing reduction in the polymer loading necessary to achieve desired gel times at a specific temperature. The activator materials included alkanolamines and quaternary ammonium salts. An increase in base polymer molecular weight also allowed for significant reduction in base polymer concentrations (to ≤ 1%). While this results in a lower cost system, and is more environmentally acceptable, the change in the quality of the gel from a stiff to a highly deformable type can result in the decreased ability of the gel to resist pressure. Bimodal molecular weight distribution is presented as an alternative approach to decrease polymer loading. This technique consists of the addition of variable amounts of high-molecular-weight base polymer to a constant concentration of low-molecular-weight base polymer.
The newly developed formulations, in some cases, allowed for a reduction of up to 40% of base polymer concentration. Results from gel time measurements over a wide temperature range using different base polymers, crosslinker polymers, and potential activation mechanism(s) are discussed.
Mechanical and Thermal Stability of Polyacrylamide-based Microgel Products for EOR
Authors: Dupuis G. , Al-Maamari R. S. , Al-Hashmi A. R. , Al-Sharji H. H. , Zaitoun A. 
Published: June 2014

Abstract
In a previous work (Zaitoun, et al., 2012), a study of the shear stability of different EOR polymers was reported. Shear stability was found to directly correlate to chain flexibility. Thus, for a flexible coil such as polyacrylamide, the presence of large monomer groups (e.g. ATBS, NVP) leads to an increase of its rigidity, hence enhancing its shear stability. However, these polymers remain highly shear sensitive in comparison to the rodlike Xanthan gum.
In this paper shear and thermal stability studies of different microgels are reported. Microgels are micrometric hydrophilic gel particles composed of partially cross-linked polyacrylamide-based chains. These microgels are already used for water shut-off treatments and conformance control. Because of their stability, they could be used in the future as sweep improvers EOR chemicals.
Comparative tests were performed with microgels and three different polyacrylamide-based EOR polymers in terms of shear and thermal stability. The impact of the internal cross-linking density, the size and the conditioning on microgels mechanical stability was investigated. For each microgel, solutions were prepared at different salinities and aged in ovens at 80, 105 and 140°C over one month in oxygen-free conditions to check their thermal stability.
Results showed that microgels maintain their integrity over a wide range of shear rate (up to 1.2x106 s−1) behaving like the rodlike Xanthan gum, whereas classical polyacrylamide-based polymers loose more than 50% of their initial viscosity at shear rate as low as 104 to 105 s−1. No difference in behavior is observed for the product prepared in powder or in emulsion form. Finally, at the highest temperature investigated (i.e. 140°C), thermal degradation is minimal for the microgels with low cross-linking densities and no thermal degradation has been observed for the microgels with the highest cross-linking densities.
The exceptional mechanical and thermal stability of the polyacrylamide-based microgels and their easiness to be tailored for the required application make these chemicals excellent candidates as future sweep improvers under harsh reservoir conditions in which other conventional polymers might fail.
An Experimental Study on Chemical Flooding Using In-Situ Precipitation Inhibitor
Authors: Elraies Khaled A. , Alta’ee Ali F. , Ibrahim Ahmed A. , Saaid Ismail M. 
Published: June 2014

Abstract
This paper introduces a new in-situ precipitation inhibitor that improves the performance of the conventional ASP flooding. This inhibitor is generated to overcome the precipitation problems prevalent with ASP flooding using brines containing high total dissolved solids. The generated precipitation inhibitor (sodium acrylate) was tested in a chemical formulation containing Alpha Olefin Sulfonate as a surfactant and sodium carbonate as an alkaline. A fluid-fluid compatibility tests were conducted to examine the performance of the precipitation inhibitor using hard brine having large quantity of divalent metal cations. The effect of the precipitation inhibitor on interfacial tension and surfactant adsorption were investigated using various inhibitor concentrations. The in-situ precipitation inhibitor showed an excellent performance in preventing calcium and magnesium precipitations, and solutions remained clear for 45 days at 80 °C. The interfacial tension was reduced significantly when the inhibitor was present in the system. As the sodium acrylate concentration is increased to an optimal value, an ultralow interfacial tension of 0.04 mN/m could be achieved. The advantage of the in-situ inhibitor is the use of hard brines without the need for softening the injection water. This could reduce the cost of chemical EOR process and makes it more suitable for environmentally sensitive applications, particularly offshore application.
Development Field Having Dolerite is Extra Challenging
Authors: Widjiastono Agus , Belzuz Fernando Pérez , Vicente Mario Gustavo 
Published: June 2014

Abstract
The effectiveness and efficiency on developing the field are influenced by the development drilling cost and reservoir production rate performance. The cost of drilling is reliant to the reservoir objective depth and the obstacle anomaly features encountered prior to reach the reservoirs. The more and difficult obstacles faced will cost more on drilling operation.
Dolerite is a hard rock originated from volcanic rock deep beneath basement. When dolerite is present at shallower depths than the main reservoir, it will become one of the obstacles due to its hardness that can cause the slow drilling rate. The fact that the character of the distribution and thickness of dolerites is pattern less, make it more challenging on the drilling design and plan.
The geological condition of the Kahlouche field area has brought to the situation of the presence of dolerite in the shallower sedimentary layers of upper Devonian, Carboniferous and lower Cretaceous. Dolerite intruded vertically and laterally into the sedimentary layers in the form of dyke and sills in variety range of thickness and areas of distribution.
Better understanding of dolerite thickness and distributions are additional challenging work of development subsurface team, but it is necessary to provide proper input for development well prognosis, design and plan. These dykes and sills framework existing above the reservoir zones make the well development placing become challenging, mostly in the situation where a good location for reservoir target is often coincident with the complex dolerite configuration. This paper shares the issues caused by dolerites and the working plan and progress to better understand and well prepare for effective and efficient development phase activities.