bluuebunny/crossref_metadata_2025_split huggingface dataset:
Iron Sulfide Scale Dissolver for Downhole Application: Where Are We Now?
Authors: Wang Qiwei , Chen Tao , Chang Frank F. , Nasser Waleed Al , Shen Shouwen , Al-Badairy Hameed , Zaidi Syed , Liang Feng , Leal Jairo , Syafii Irfan , Al-Mukhles Amro 
Published: March 2017

Abstract
Downhole scale deposition in the Khuff sour gas wells in Saudi Arabia has been a persistent problem, which negatively affects operation and production. Scale deposits are composed of predominantly iron sulfides with other types of minerals also present. Mechanical descaling treatment, although expensive and time-consuming, is often required. Effective scale dissolver is highly desirable to enhance descaling efficiency and to reduce treatment cost. An ideal dissolver is required to have high scale dissolving power, no damage to downhole completion and well productivity, and minimal H2S liberation.
This paper presents the laboratory studies on the new scale dissolvers developed by service companies. These products have pH values ranging from strong acidic (pH &lt; 2) to high alkaline (pH &gt; 12). Dissolvers were evaluated for thermal stability, corrosivity to mild steel, and compatibility with formation water at downhole temperatures. The potentials of iron sulfide re-precipitation in spent solutions and free H2S generation were also examined. The qualified chemicals were then evaluated for their dissolving capacity using authigenic pyrrhotite and field scales at elevated temperatures.
The obtained results show that most effective acidic dissolvers evaluated in this study were very aggressive to low alloy carbon steel at downhole temperatures. For these with acceptable corrosivity, formation of iron sulfide reprecipitation in spent dissolvers and the generation of a large quantity of free H2S gas also prevented them from field application. Some dissolver products were disqualified due to incompatibility with formation water. Dissolvers with near neutral and alkaline pH values, in general, were inefficient to dissolve the heterogeneous iron sulfide scales. The performance of tested dissolvers varied with scales from different wells, attributed by differences in composition, microstructure, and the presence of hydrocarbon. Results also suggested that pyrite and marcasite were possibly formed during the dissolution process.
This paper presents an objective assessment on the currently available iron sulfide scale dissolvers, highlights the challenges on downhole scale dissolution in high temperature sour wells, and provides new insights on the scale dissolution process. The results suggest that further R&D efforts are required to develop more effective chemical solutions to mitigate the iron sulfide scale problem.
An Advanced, Balanced, and High-Performance Displacement Spacer System for Deepwater Formations
Authors: Gunawan Stanley , Fowler Drew A. , Mack Arthur 
Published: March 2017

Abstract
A successful wellbore displacement and clean-up is a critical step during well completion operations. A poor cleaning performance can lead to increased cost of completion operations, potential formation damage, and thus reduced oil and gas productions. Failure to achieve a balanced displacement system can lead to negative pressures on cement jobs and tie-backs, wellbore control issues, and wellbore instability.
Deepwater wells require a crucial and complete evaluation of a displacement system which will provide a balanced, effective, and efficient cleaning spacer system. Traditional displacement spacer systems typically consist of a solvent spacer and a surfactant spacer. A solvent spacer consisting of d-limonene is effective for removing oil-based drilling fluids from the wellbore; however, this is incompatible in water-based spacer systems and results in an underbalanced displacement system. On the other hand, a surfactant spacer is ineffective in displacing ester/isomerized olefin (IO) based drilling fluids. As the chemistry of drilling fluid additives become more diversified to accommodate various base oils, such as the blend of ester/IO used here, so too must the chemistry of cleaner/displacement additives to ensure appropriate compatibility.
On many occasions, barite residue from the weighted spacer was found to adhere strongly to pipe surfaces and be nearly impossible to remove chemically upon contact with the surfactant spacer. This issue can cause incomplete zonal isolation. A new, balanced, and high-performance displacement system (ADS-RD) was developed and optimized for its ability to effectively remove oil-based drilling fluids, barite residue, and water wet pipe surfaces. Lab test results showed that ADS-RD was fully compatible, consistently achieved an average of 98% cleaning efficiency, and yielded water wet pipe surfaces against the ester/IO based invert emulsion drilling fluids. ADS-RD also proved to be an effective and efficient solution to other oil-based invert emulsion drilling fluids.
This paper presents the testing program and lab test results for ADS-RD against a traditional displacement system with various oil-based invert emulsion drilling fluid systems with densities up to 14.8 lb/gal. This paper will also include cost savings and recommendations for field applications.
Scaling Risk and Inhibition Prediction of Carbonate Scale at High Temperature
Authors: Zhang Fangfu , Dai Zhaoyi , Zhang Zhang , Al-Saiari Hamad , Yan Fei , Bhandari Narayan , Ruan Gedeng , Liu Ya , Lu Yi-Tsung , Deng Guannan , Kan Amy T. , Tomson Mason B. 
Published: March 2017

Abstract
Calcium carbonate is the most common scales in oilfield and thus has been heavily studied. However, calcium carbonate scale problems continue to occur in oilfield causing significant economic loss. To better control carbonate scale, reliable models on carbonate scaling risk and inhibition predictions are clearly necessary, which motivates this study.
To develop such a model, it is necessary to gain a better understanding on mineral nucleation and inhibition kinetics based on experimental studies, which can correctly interpret field data and observations on carbonate scale occurrence. While heavily studied, what has been commonly ignored or failed to obtain in previous studies is a strict control of pH and CO2 pressure as well as a precise calculation of carbonate supersaturation in brine. Unlike BaSO4 or CaSO4, pH and CO2 pressure can strongly affect the supersaturation of carbonate in brine. Therefore, without careful control of pH and CO2 pressure and precise calculation of carbonate supersaturation, the reliability of data on carbonate scaling and inhibition kinetics can be questionable. Also, the difficulty in obtaining such a reliable control and calculation has limited studies on carbonate nucleation and inhibition kinetics to low temperature from 77-200 °F.
In this study, we have developed robust procedures in controlling experimental pH and CO2 pressure and calculating carbonate supersaturation from 39-350 °F. With newly developed apparatus and protocol, we studied the precipitation and inhibition kinetics of calcium carbonate in the time range of seconds to more than 24 hours. The inhibition efficiency of 9 commonly used inhibitors including both phosphonates and polymers were characterized at different temperature and supersaturation levels. Experimental results were consistent and reproducible. Furthermore, a novel inhibition model has been developed based on data from this study. Finally, field observations on carbonate scaling kinetics of a number of wells are used to validate our new model and minimum inhibitor concentrations observed in the field are consistent with model predictions. In conclusion, this study provides reliable methods in studying carbonate scales and the newly developed models can provide accurate predictions of scaling risk and inhibition, which can help optimize the scale treatment plan.
The Effect of Turbulence on Mineral Scale Control in Oilfield
Authors: Yan Fei , Zhang Fangfu , Bhandari Narayan , Ruan Gedeng , Alsaiari Hamad , Dai Zhaoyi , Liu Ya , Zhang Zhang , Lu Yi-Tsung , Deng Guannan , Kan Amy , Tomson Mason 
Published: March 2017

Abstract
Turbulent flow in oilfield pipes is very common, especially around chokes, tubing joints, and safety values. However, the effect of turbulence on mineral scale precipitation has not been well understood. The objective of this study was to investigate mineral scale formation and inhibition under turbulent conditions.
A novel tubing testing method has been developed to enable the study of turbulence in a tubing apparatus. In the tubing apparatus that consists of a long tubing (200 to 500 ft) and a high flow pump, high-velocity turbulent flow was generated. In another tubing experiment, a valve was installed in the tubing to examine the impact of valves on mineral scale precipitation. Barite scale formation and inhibition by inhibitors were investigated in turbulent flows by these novel approaches.
In the experiment, barium concentrations in the effluent of the tubing were measured to determine whether barite precipitation occurred in the tubing. Critical saturation index (SI) was determined by a series of experiments for both laminar and turbulent flow. Experimental results show the effect of turbulence depends on several factors such as reactant ratio and scale inhibitor. Under our test conditions, when the molar ratio of sulfate to barium is around one, we observe no difference in barite precipitation kinetics between laminar and turbulent flow without scale inhibitor; however, in the presence of scale inhibitor, barite precipitation kinetics is slightly faster in turbulent flow, or critical SI is higher in laminar flow than that in turbulent flow. When the molar ratio of sulfate to barium is high, critical SI of laminar flow is always slightly higher than turbulent flow with and without inhibitor. Two different tubing materials, i.e. polyethylene and stainless tubing, were both investigated in this study and experimental results shows the effect of turbulence on barite precipitation kinetics is the same for both materials. In the tubing with valve experiment, the valve in the tubing did not show an influence on barite precipitation kinetics.
This paper presents a novel tubing apparatus to investigate the effect of turbulence on scale control in oilfield. The findings in this paper will advance our understanding in scale control especially under turbulent conditions, and aid in developing optimal doses of scale inhibitors with regard to flow regimes.
Identification of New Chemical Formulation for Control of Metal Sulfides FeS, ZnS and PbS Scale Deposition
Authors: Bhandari N. , Ruan G. , Liu Y. , Zhang F. , Yan F. , Saiari H. A , Zhang Z. , Dai Z. , Lu Y. , Deng G. , Kan A. T. , Tomson M. B. 
Published: March 2017

Abstract
Metal sulfides such as iron sulfide (FeS), zinc sulfide (ZnS) and lead sulfide (PbS) scaling have been a persistent flow assurance problem in oil and gas production. FeS is ubiquitous in nature; however, ZnS and PbS are exotic scales but still pose significant scaling issues especially at HT wells. Efficient chemical treatment of those sulfides scales has not been found yet. Therefore, this study seeks to identify new chemical compound(s) to inhibit metal sulfide scale formation. A strictly anoxic static bottle test setup was designed and various chemical formulations were screened toward FeS, ZnS and PbS scale nucleation and growth inhibition. Thermal stability of the chemicals (150 °C for 18 hours) and phase transformation behavior of FeS scale with and without chemical treatment (75 °C for up to 10 days) were also conducted in glass container under anoxic environment. Aqueous phases as well as metal sulfide solid products were characterized using ICP-OES, X-ray diffraction, SEM, ATR-FTIR and other analytical techniques.
Our laboratory studies indicate that a polymeric compound containing amide or its derivative functionalities showed a promising effect by preventing metal sulfide scale deposition at threshold quantities. Specifically, the polymer did not inhibit the formation of the FeS, ZnS and PbS particles; however, it significantly influenced the growth and deposition behaviors by dispersing nano-particulates for an extended period of time. The thermal stability test results indicated that performance is not likely to be influenced at 150 °C even after 18 hours of ageing. Polymer treated and untreated FeS particulates were tested for heat induced phase transformation to pyrite and result indicated that polymer is highly efficient for inhibition of FeS phase transformation as well. Similarly, interference of performances towards metal sulfide dispersion due to the presence of other scaling materials (such as barite, iron oxides) and deposition tendency of dispersed metal sulfide particles onto flowlines were also tested and preliminary results look encouraging. Mechanistic aspect of polymer-particles interaction that prevents particle growth and deposition of FeS, ZnS and PbS scales are discussed. Despite its huge industrial and economic importance, an efficient solution of metal sulfide scale control is still an elusive goal. Based on our current laboratory results, it is believed that these polymers will provide a novel chemical treatment option for simultaneous control of these three sulfides (FeS, ZnS and PbS) scaling issues.
Preparation and Evaluation of Thermo- and Salinity-Responsive Hydrogel as Intelligent Plugging Agent
Authors: Xue Yan , Wang Xinyong , Zhang Bo , Wei Bing , Ye Zhongbin 
Published: March 2017

Abstract
The swellable hydrogel particles have been developed as effective plugging agents. However, the harsh conditions would significantly detract the performance of conventional plugging agents. To address the problem, an amphoteric hydrogel (IHPA) modified by zwitterionic groups was successfully developed, which presented distinctive thermo- and salt-responsiveness. Environment Scanning Electron Microscopy (ESEM) images of swollen IHPA showed its multiporous structure contributing to its water absorptivity. The water absorption and swelling capacity of IHPA were systematically studied at various temperatures using water and different salines. The sudden increase of the swelling capacity of the hydrogels upon temperature and/or salinity, caused by the alteration of zwitterionic self-association, promised them as intelligent plugging agents. The plugging simulating tests indicated that IHPA possessed excellent plugging performance at 80°C with a plugging efficiency of 93.8% compared with the efficiency of only 33.3% at 20°C
Effectiveness of Polycarboxylate Dispersants in Enhancing the Fluid Loss Performance of Cellulose Ethers
Authors: Moumin Mouala , Plank Johann 
Published: March 2017

Abstract
This paper investigates the performance of different kinds of polycarboxylate (PCE) dispersants in combination with cellulose ethers as fluid loss additives and presents their influence on the fluid loss. The objective was to find out whether PCEs can better enhance the fluid loss performance of HECs than the currently applied acetone-based dispersant (AFS). Two different polycarboxylates were synthesized via free radical copolymerization using either methacrylate ester or isoprenyl ether as macromonomers and tested. The AFS polycondensate and the hydroxyethyl cellulose (HEC) were commercial samples. The impact of the PCE and AFS dispersants on the fluid loss of cement slurries achieved from hydroxyethyl cellulose was investigated via static fluid loss and rheology measurements. All PCE polymers improved the fluid loss performance of HEC significantly more than AFS; i.e. they required considerably lower dosages than AFS to achieve the same volume of fluid loss. For example, at 27 °C the addition of 0.1 % bwoc PCE to 0.4 % HEC improved the fluid loss from 250 mL/30 min to 50 mL/30 min. For the same effect, 0.4 % of AFS were needed. Most important, such low fluid loss values were achieved at very thin filter cakes, indicating that although the PCEs reduced slurry rheology considerably, no sedimentation had occurred which can also lead to low fluid loss, but is highly undesirable. Furthermore, a linear correlation between cement slurry rheology and fluid loss was observed: The stronger the dispersing effect of the PCE, the better is the fluid loss control. Among the PCEs tested, the isoprenol ether-based copolymer stood out as performing best. Dynamic light-scattering measurements revealed that the presence of PCEs strongly enhances the association of the HEC molecules, thus improving their ability to plug cement filter cake pores.
Using Properties in Nature to Modify Proppant Surfaces and Increase Flow
Authors: Bestaoui-Spurr Naima , Sun Steve , Williams Vanessa , Volk Alyssa , Nguyen Susan 
Published: March 2017

Abstract
In oil and gas wells that are hydraulically fractured, wetting properties of surfaces (formation and proppant) significantly affect hydrocarbon and liquid displacement. During the life of a well, the water saturation of surfaces changes, leading to reduction of relative permeability to oil or gas and consequently affecting production. In order to reverse the formation to a reduced water wet state and improve the movement of hydrocarbons, strong water-wet surfactant is pumped. The surfactant is then adsorbed onto the surfaces reducing the capillary pressure and water saturation within the porous systems. This is, however, not a permanent solution, as the surfactant is washed out over time. A more permanent and robust solution is needed.
Nature encompasses many examples of biological systems and surfaces that are permanent and have special wettability and interfacial interaction with fluids. Research and development within the last decade in bio-mimicking nature has been fruitful and led to the development of many new surfaces such as superhydrophobic, ice phobic and low-drag surfaces.
In this work we apply some of the knowledge and principles found in nature to modify proppant surfaces (silica sand and ceramic proppant) in order to study how wettability will affect the fluids recovery and their interaction with the solid surfaces. Nanotechnology was used to deposit hydrophobic/oleophobic moieties onto the proppant surfaces, and several surface modifiers were tested. These molecules were covalently bonded to the surfaces. The new surfaces were characterized for wettability and flow to water and oil. A new proppant that show promises for improved stimulation fluids recovery and flow was identified and further developed.
Nanomaterials-Enhanced High-Temperature Viscoelastic Surfactant VES Well Treatment Fluids
Authors: Ozden Sehmus , Li Leiming , Al-Muntasheri Ghaithan A. , Liang Feng 
Published: March 2017

Abstract
Nanomaterials are being implemented in more and more industries due to their unique properties and performances at the nanoscale. In the oilfield, nanomaterials can significantly improve the performances of well treatment fluids including hydraulic fracturing fluids. Fluids based on polymers such as polysaccharides are widely used in the oilfield as fracturing fluids, but these fluids can have some limitations. For example, high molecular weight and incomplete breaking of these polymers can cause serious formation damage.
An alternative material is viscoelastic surfactant (VES) which has been used for fracturing and acid jobs. VES-based fluids are low molecular weight in nature and show minimum formation and conductivity damage. Yet, there remain challenges associated with their use such as limited thermal stability and high leakoff rate. The use of nanomaterials such as MgO and ZnO was found to enhance their thermal stability and leakoff properties at temperatures up to 250°F. For wells with higher bottomhole temperatures, the nanomaterials that can significantly enhance the performances of the VES fluids at 350+°F will be much sought after.
In this paper, we report the use of a number of the selected nanomaterials to enhance the VES gels at temperatures up to 350°F or higher. In one example, the addition of about 0.1 wt% nanomaterial-I enhanced the viscosity of the VES fluid by about 24% averaged over the temperature range from 250 to 350°F. In another example, nanomaterial-II at a dose of about 0.04 wt% enhanced the viscosity of the VES fluid by about 23% averaged over the temperature range from 250 to 350°F. Additionally, measurements showed that the viscosity of the VES fluids remained above 110 cP (at 100 s-1 shear rate) for over two hours at 350°F with the addition of either nanomaterial-I or nanomaterial-II. The fluid stability at elevated temperatures could also be improved with the selection of other nanomaterials.
This paper will discuss the applications for these nanomaterials in hydraulic fracturing and other oilfield operations under high temperature conditions, based on the laboratory test results that will be shared in detail. This technology could open the door for more advancement in hydraulic fracturing with non-damaging VES systems at high temperatures.
Synthesis, Properties and HT Performance of a Novel Cement Fluid Loss Polymer Modified with Phosphate Groups
Authors: Hurnaus Thomas , Echt Timon , Plank Johann 
Published: March 2017

Abstract
Fluid loss additives (FLAs) based on 2-acrylamido-2-tert.-butyl sulfonic acid (ATBS) provide fluid loss control by reducing filtercake permeability through polymer adsorption. However, when highly anionic dispersants or retarders are present in the slurry, adsorption of the ATBS polymer is hindered resulting in high fluid loss. To overcome this problem, ATBS - N,N-dimethyl acrylamide (NNDMA) copolymers were modified with phosphate groups to enhance their affinity to the surface of cement and make them more robust in the presence of other anionic additives. Fluid loss tests revealed that modification of the ATBS-NNDMA copolymer with phosphate groups greatly improves its fluid loss performance in both fresh and sea water cement slurries. Additionally, it extends its temperature stability up to 150 °C (300 °F), as was observed in stirred fluid loss tests. Furthermore, the excellent fluid loss performance of the phosphate-modified FLA remained unaffected in the presence of AFS dispersant or ATBS-co-acrylic acid retarder, while the effectiveness of the conventional, non-phosphated FLA was severely impeded by these additives. Adsorption measurements illustrated that the superior fluid loss performance can be attributed to stronger adsorption of the phosphated FLA on cement. Adsorbed layer thickness measurements elucidated that the phosphated FLA adsorbs in a "train" like conformation on cement as compared to the conventional ATBS-NNDMA copolymer which attains a "loop"-type conformation.
New Polymeric High Temperature Cement Retarder with Synergistic Suspending Aid Property in Fluid Loss Control Polymers
Authors: Pernites Roderick , Clark Jordan , Santra Ashok 
Published: March 2017

Abstract
This paper presents a new high temperature retarder that can effectively delay the setting time of an oil and gas cement up to 450 °F via a single polymer only instead of the usual combination of synthetic copolymer of 2-acrylamido-2-methylpropane sulfonic acid and acrylic acid (AMPS®/AA)-based or natural lignosulfonate-based polymer retarder along with an intensifier small organic molecules like tartaric, citric, or gluconic acids that are relatively costly and sometimes degrade the performance of cement fluid loss control polymer. More interestingly, this new differentiated polymer cement retarder provides unique synergistic property in presence of an AMPS®-based cement fluid loss control polymer that is giving additional suspension capability useful for water-extended lightweight density cement slurry; thereby, eliminating the need for an extra viscosifying agent and/or high temperature suspending aid. With the use of this new polymer retarder, complicated cement design is actually simplified having less additive in the mixture, giving the advantage of better logistics, easier operations, and cheaper economics.