bluuebunny/crossref_metadata_2025_split huggingface dataset:
Treatment of Produced Water Using Chelating Resins: Laboratory Case Study
Authors: Patil Anil , Nanda Jajati , Waikar Jyoti 
Published: April 2015

Abstract
The impetus for waste minimization and water recycling within the oil and gas industry comes from increasingly stringent environmental regulations and deteriorating water supplies. The most challenging part in terms of the design of a water recycling system is minimizing the capital and operating costs while meeting water quality requirements. A recent development in selective functionalization of ion exchange resins enhances the chances of developing an economically feasible process for the selective treatment of produced water.
A case study is presented wherein produced water containing high concentrations of calcium, magnesium (hardness), barium, strontium, iron (scale) and boron (crosslinking agent) was treated with three different chelating resins. Dynamic column studies were conducted on all three chelating resins and breakthrough curves were determined for different cations. It was observed that iminodiacetic acid based resin selectively decreases the hardness of water; sulphonic acid based resin decreases the concentration of iron, barium, and strontium; while N-methylglucamine based resin selectively adsorbed the boron.
Analysis of water was conducted using Inductively Coupled Plasma Spectroscopy (ICP) and Ion Chromatography (IC) instruments. The calcium and magnesium ions adsorbed on the column were eluted by allowing 1mol/L hydrochloric acid to pass through the column. Recycling of adsorption and elution was found to be satisfactory. Dynamic adsorption operations showed that adsorption had significant effect on selectivity of cations, and low flow rate enhanced said adsorption.
This case study could be helpful for designing selective adsorbents for removal of scale forming cations, hardness favoring cations, and boron from produced/waste water in an economically feasible process. This work will provide a basis for further evaluations of field applications of resin filters for oilfield produced waters.
How Extremely High-TDS Produced Water Compositions Affect Selection of Fracturing Fluid Additives
Authors: Li Leiming , Qu Qi , Sun Hong , Zhou Jia , Legemah Magnus 
Published: April 2015

Abstract
Oilfield produced water can often contain high levels of total dissolved solids (TDS) in addition to hydrocarbons, precipitates, and suspended particles. The dissolved solids mainly consist of sodium, calcium, and magnesium salts. The combination of the high salinity and hardness in produced water can be very detrimental to many types of fracturing fluids that are commonly formulated for fresh water. Therefore, the industry has sought fluid systems that can be formulated directly with high-TDS produced water and perform well at high temperature. Such fluid systems can also reduce produced water disposal cost and fresh water consumption. A group of fracturing fluids was successfully identified recently that performed very well at high temperatures when formulated with untreated, high-TDS produced water. The produced water tested had TDS up to about 330,000 mg/L and hardness (calcium carbonate equivalent) up to about 90,000 mg/L. The fracturing fluids comprised organometallic-crosslinked derivatized polysaccharides. In a typical test, the viscosity stayed above 100 cP (at 100/s shear rate) for over 80 minutes at 275 °F, recorded for a fracturing fluid prepared with untreated produced water with extremely high TDS and hardness. The magnitude and lifetime of the fluid viscosity were dependent on a number of factors such as the produced water composition, temperature, polymer loading, fluid pH, etc.
The success of the fracturing fluids formulated with untreated high-TDS produced water depended on the matching choice of additives to water compositions. In addition to the polymer (the derivatized polysaccharide polymer) and the organometallic crosslinker, a number of other fluid additives were used that worked synergistically in the untreated produced water. For example, one such additive (additive-A) was a derivatized alcohol. Adding the appropriate concentrations of the alcohol in the fluid formulas significantly mitigated the damage caused by the high hardness level in the produced water. Without this alcohol, the fluid viscosity could drop by well more than 50% under the same conditions. Another additive (additive-B) was a water-soluble salt. At right dosage, the salt could enhance the high-temperature stability of the fluids. In the meantime, the salt was also able to control crosslinking of the fracturing fluids, making it possible to greatly facilitate fluid placement.
The underlying working mechanisms of the high-temperature fracturing fluid additives selected for untreated extremely high-TDS and hard produced water will be discussed, and the field-related laboratory test results will be presented.
Selection of Calcium Carbonate Scale Critical Values for Deepwater Production
Authors: Zhang Ping , Allan Keith , Hugh Bourne 
Published: April 2015

Abstract
Calcium carbonate scale threats for deepwater developments have been predicted by calculating the saturation ratio (SR) and mass of calcium carbonate.
Assessing the threat scale may pose to an operation allows the design and implementation of robust barriers to reduce the risk. Scale threat assessment is particularly important in the early phase of a project when options for controlling the threat are being evaluated. It is important to correctly interpretate scale prediction result and its operational significance in terms of the threat likelihood and severity. Widely adopted guidelines, based on industry experience built up over many years from operations in US land and in the North Sea, have been used to aid interpretation. However, the relevance of these guidelines for deepwater projects has long been challenged.
The relationship between predicted SR and mass of calcium carbonate in deepwater is explored. Through case studies, it is apparent the current guidance is not stringent enough for deepwater. Additional guidance for deepwater operations is proposed.
This paper describes the deepwater operational experience that was used to justify a change in the critical SR and mass values in the scale threat assessment guidelines now adopted to assess the likelihood of scaling in deepwater fields.
Minimizing Surfactant Adsorption Using Polyelectrolyte Based Sacrificial Agent: a Way to Optimize Surfactant Performance in Unconventional Formations
Authors: He Kai , Yue Zhiwei , Fan Chunfang , Xu Liang 
Published: April 2015

Abstract
Surfactant is a critical component in fracturing fluid to help achieve higher productivity from unconventional oil and gas formations. However, adsorption of surfactant onto reservoir rocks and proppant could lead to inefficient use. The large surface area of shale formations (up to 700 m2/g) could yield a significant loss of surfactant attributed to adsorption onto reservoir rock. Field production data from the Barnett shale indicates that most surfactant could be tied up within the reservoir. For example, 3 gpt (3 gal/1,000 gal ~3000 ppm) of surfactant was injected into the reservoir, and only 0.5 gpt (or 500 ppm) was recovered when production began; surfactant concentration further decreased to 50 ppm in one month. Strong adsorption could potentially limit the contact of surfactant with reservoirs, as most surfactants could be adsorbed near-wellbore (NWB) before reaching the interior of the reservoir. Therefore, a need exists to reduce surfactant's adsorption to further optimize its performance during hydraulic fracturing.
This paper discusses static and dynamic adsorption tests performed to evaluate the use of polyelectrolytes (PETs) to reduce surfactant adsorption onto the Rainbow shales in Canada. Dynamic surface tension measurements and UV-vis data indicated surfactant adsorption could be significantly reduced using PETs based on the competing mechanisms. Additionally, oil recovery laboratory results reveal that surfactants extract more oil in the presence of PETs. On the other hand, scale inhibition performance testing suggests that these PETs can also serve as scale inhibitors. In this study, the inhibition efficiency of the PETs is compared to commonly used phosphonate and polymeric scale inhibitors. Static bottle testing results indicate the PETs can effectively control calcium carbonate scale formation. The synergistic effect between surfactants and PETs suggests a new route for formulating multifunctional surfactant blends that can be tailored to specific formation rocks.
A New Environmentally Friendly Acidizing Fluid for HP/HT Matrix Acidizing Treatments with Enhanced Product Solubility
Authors: Rabie Ahmed I. , Saber Mohamed R. , Nasr El-Din Hisham A. 
Published: April 2015

Abstract
The success of matrix acidizing treatments, whether in carbonate or sandstone formations, depends significantly on the selected acid or acid mixtures. Limitations are applied on all existing acidizing fluids including hydrochloric acid and organic acids. These limitations include: low dissolving power, product solubility, stability, biodegradability, and the inevitable cost of additives necessary to mitigate corrosion problems. This work proposes a new mixture of lactic and gluconic acids which offers favorable technical characteristics and excellent health and environmental profile. After formulated, the acid was tested and optimized for the maximum calcium product solubility. The new acid is noncorrosive, nonvolatile, nontoxic, and can be used at a higher pH with significant sequestering power, and it is readily biodegradable (98 % at 48 h). The solubility of calcium salt of this acid is approximately 400g/l (compared with 300 g/l for calcium acetate, 166 g/l for calcium formate, and 79 g/l for calcium lactate). Interestingly, sodium salt of the acid mixture was reported as a corrosion inhibitor for steel alloys.
The objectives of the work are to: (1) examine the dissolving capacity and reactivity of the proposed acid through solubility and reaction rate studies over a temperature range of 80-300°F using the rotating disk reactor, (2) investigate the effectiveness of the new acid to create dominant wormholes and determine the optimum injection conditions in calcite cores.
Acid capacity reactions with Pink Desert limestone powder showed that 1:1 of 1 M lactic:gluconic acid mixtures was the optimum molar ratio that resulted in dissolving the maximum calcium amount for the reaction at 25°C and 500 rpm, while the reaction of lactic acid alone at the same acid concentration showed a white precipitation of calcium lactate in the collected samples. Reaction rate experiments on the rotating disk reactor showed that the rate of reaction of the proposed acid at 1:1 molar ratio is confined by the reaction rate of the two individual acids (lactic and gluconic acids). However, the reaction of lactic acids resulted in white precipitates on the surface of the rock disks used in the experiments. Coreflood study showed the ability of the new acid mixture to stimulate Indiana limestone cores at various injection rates, acid concentrations, and over temperature range between 150 and 300°F. The results also confirmed that 1:1 molar ratio of the two acids is the optimum for the minimum acid pore volume required to breakthrough. 20 wt% of the proposed acid was the optimum acid concentration associated with the minimum acid pore volume. Above this concentration, little impact was noted and the reduction in the pore volume leveled off.
Diblock Copolymers: A New Class of Fluid Loss Control Additive for Oilfield Cementing
Authors: Cadix A. , Wilson J. , Barthet C. , Phan C. , Poix C. , Dupuis P. , Harrisson S. 
Published: April 2015

Abstract
Oil well cementing uses a variety of organic additives such as dispersing agents, retarders or fluid loss control additives. The later, which prevent interstitial water from filtering into the formation during cement placement, are generally polymer based. A widely used class of fluid loss control additive are the high molecular weight Sulfonated copolymers, generally comprising AMPS (2-Acrylamido-2-methylpropane sulfonic acid) copolymerized with Acrylamide (Am) or N, N′ Dimethylacrylamide (DMA). The mechanism of action of these polymers has been studied recently and it was demonstrated that adsorption onto the cement surface is crucial to achieve the required product performance. It was also shown that other solutes and admixtures present in the cement interstitial solution can hinder adsorption resulting in performance losses. Thus it has been recommended to incorporate an additional monomer containing strongly adsorbing units in the copolymer to enhance the interaction with the cement surfaces hence limiting competitive adsorption issues.
In this study we investigated the use of diblock copolymers comprising a short but strongly adsorbing block and a long second block of DMA-AMPS as a potential new class of filtration control agent. We showed that diblock copolymers with much lower molecular weights than statistical polymers can provide satisfactory fluid loss control performance. Furthermore, it was demonstrated that these structured polymers show good formulation flexibility and deliver more robust performance in the presence of a wide range of admixtures and solutes.
Finally we focused on the analysis of the adsorption on cement of various formulation admixtures and how it affected the adsorption of our diblock copolymers. With the aid of an analytical method utilising size exclusion chromatography of collected filtrate from HPHT filtration cells, it was possible to have a direct access to a fluid loss polymer concentration in the filtrate even in the case of complex formulations.
Based on these studies, the mechanism of action of the diblock copolymers as fluid loss control agents is discussed with reference to that evoked for statistical polymers.
Scale Modeling in Reservoirs: a New Simulation Capability and its Validation with Field Data
Authors: Chen Huey J. , Shi Wei 
Published: April 2015

Abstract
The development of oil and gas reservoirs in the deep water environment is playing an increasingly significant role in supporting the global energy demand. Oil field scale is an important aspect of flow assurance that determines continuous production from reservoirs, because improper scale management could result in astronomical losses. Currently most commercial software packages for scale prediction and risk assessment use stand-alone thermodynamic models that rely on water composition data as input parameters. As seawater injection has become an integral part of deepwater development, the coupling of scale modeling with reservoir simulation becomes necessary to not only track scale reactions and precipitation in the reservoir, but also to assess scaling risks in production wells and surface facilities as a result of the these reactions. Appropriate treatment strategies can thus be recommended based upon simulation results. The scale reaction for barium sulfate (BaSO4) has currently been implemented as a coupled option in our in-house reservoir simulator, CHEARS. Besides conventional reservoir simulation results, the model also outputs scale related information, such as barium and sulfate scaling ion concentrations, the amount of barium sulfate precipitation, scaling tendency of barium sulfate, as well as the time and extent of injection water breakthrough over years.
The scale model in reservoir simulation has been validated using both literature data (Delshad and Pope, 2003) and field data from one of Chevron's assets. The recommendations for scale control based upon the simulation results are in good agreement with field operation. Scale modeling in reservoir is expected to provide a more precise evaluation of scaling risks under challenging production conditions, and a more realistic recommendation for scale squeeze treatment. With the continuous advancement in deepwater development, scale modeling in reservoirs should be an integral part of reservoir management. Reservoir management strategies will be implemented in the field development with the collaboration among experts from different disciplines such as reservoir, scale, flow assurance, production, and process engineers.
Zeta Potential Measurements: Impact of Salinity on Sandstone Minerals
Authors: Shehata Ahmed M. , Nasr-El-Din Hisham A. 
Published: April 2015

Abstract
Waterflooding has been used for decades as a secondary oil recovery mode to support oil reservoir pressure and drive oil into producing wells. Recently, extensive experimental work has indicated that optimizing the salinity of the injected water is an enhanced oil recovery technique that improves oil recovery in sandstone and carbonate reservoirs. Ion interactions between formation water, crude oil, injection water, and rock surface are quite complex. The question is how the surface charge of the minerals of sandstone formation affects the waterflooding performance. In this study the zeta potential measurements are conducted for rock/brine interfaces using the Phase Analysis Light Scattering (PALS) technique.
This work demonstrates the results of zeta potential experiments to evaluate the effect of electrical surface charge and double layer expansion for common sandstone minerals. Four sandstone rock types (Buff Berea, Grey Berea, Parker, and Bandera) with different clay contents are studied. In addition, several minerals such as quartz, carbonate (calcite and dolomite), clays (kaolinite, chlorite, and montmorillonite), micas (muscovite, biotite, and illite), feldspars (microcline and anorthoclase), and ilmenite are selected to perform this work. Various brines are tested including seawater, 20% diluted-seawater, 0.5 wt% NaCl, 0.5 wt% MgCl2, and 0.5 wt% CaCl2.
Based on the results of 100 experiments we found that the monovalent cations are more efficient in increasing the absolute values of the zeta potential than the divalent cations at 25°C. Zeta potential becomes more negative while the salinity of the brine decreased. Changing the pH of the solution causes a significant alteration in charge of Buff Berea and Bandera sandstone particles and subsequently, the zeta potential values. The zeta potential of Bandera is more negative than that of Buff Berea at any condition of pH in the range of 5 and 10. It is observed from the results that most of the minerals tends to be more stable for 0.5 wt% NaCl solutions compared to 0.5 wt% CaCl2 and 0.5 wt% MgCl2 solutions. Feldspars surfaces charge are significantly influenced using 0.5 wt% NaCl, followed by micas and clays. The resulting zeta potentials for the dolomite and calcite minerals showed different trend from the other sandstone minerals for low-salinity brine. For dolomite, all the samples show positive zeta potentials at original pH. At low pH, dolomite shows small negative zeta potentials in 0.5 wt% NaCl.
Mechanisms of Environmentally Acceptable Inhibitors for Zinc Sulphide Inhibition
Authors: Williams H , Tortolano C , Champion Nalco , Adenuga T 
Published: April 2015

Abstract
Carbonate and sulphate scales are the most common types of mineral deposit associated with the recovery and processing of hydrocarbon and associated produced water. In high temperature fields (&gt;140°C) within the North Sea, more unusual scale types have been observed, namely zinc and lead sulphide. Limited studies have been focussed on zinc sulphide (ZnS), and mechanisms for scale inhibitors to control this scale are still relatively unknown.
In laboratory studies, the relatively small amount of ZnS deposited and ‘soft’ scale characteristics make it difficult to test ZnS using traditional test methods, especially at high temperature. A novel dynamic loop test combining the traditional test coil and novel test filter system has been developed to evaluate ZnS inhibitors and was published in SPE paper 169810.
The mechanisms of the inhibitor interactions with ZnS suggested from this previous study have been further evaluated and will be reported in this paper. The investigation of the inhibitor mechanisms have been addressed by scanning electron microscope evaluation of scale texture and size distribution of scales recovered from static bottle tests conducted at 70°C.
Several different generic types of ZnS scale inhibitor chemistries were selected based on the previously published study. Type 1 inhibitor is dispersion/nucleation inhibitor, Type 2 is nucleation/growth inhibitor, and Type 3 has no inhibition function on ZnS. The test results at 70°C agree well with the mechanism suggested in the previously published tube / filter blocking study, and the inhibition mechanisms are reinforced. The difference in particle size, particle quantity and crystal morphology shows how different generic types of inhibitors interact with the ZnS scale.
This paper is a comprehensive study of the mechanism of ZnS formation and inhibition via a range of experimental test methods to fully understand the impact that inhibitor functional groups have on crystal growth inhibition, nucleation inhibition and dispersion mechanism.
Stimulation of High Temperature SAGD Producer Wells Using a Novel Chelating Agent (GLDA) and Subsequent Geochemical Modeling Using PHREEQC
Authors: Ameur Z. Ouled , Kudrashou V.Y. , Nasr-El-Din H.A. , Forsyth J.P.J. , Mahoney J.J. , Daigle B.J. 
Published: April 2015

Abstract
Acidizing of sour, heavy oil, weakly consolidated sandstone formations under steam injection is a real challenge. Fines migration, sand production, inorganic scale, corrosion products, and damage due to asphaltene precipitation are some of the common concerns with these sandstone formations. They cause decline in the productivity of the wells, and there is always need to stimulate these wells to restore their productivity. Furthermore, the complexities of sandstone formations require a mixture of acids and several additives, especially at temperatures up to 360°F. Three treatments were tried in a horizontal well in this field: HCl acid, A (GLDA), and B chelating agents. In this paper, we evaluate the results of field applications using geochemical modelling, production data, and analysis of well flow back fluids after field treatments.
The field treatment included pumping a foaming agent to have proper rheological characteristics and a better controlled pumping process, followed by the main stage of the treatments. The treatment fluids were displaced into the formation by pumping produced water and were allowed to soak for 6 hours, then the well was put on production, and samples of flowback fluids were collected. The concentrations of key cations were determined using ICP, and the chelate concentration of the chelating agent A was measured utilizing a titration method using ferric chloride solution. Geochemical modelling was conducted using specialized software, and was used to predict the concentrations of key ions in the flow back samples.
The first two treatments including HCl acid and chelating agent B produced results below expectation. The third treatment using GLDA was successful and the well productivity increased significantly. The treatment was applied in the field without encountering any operational problems. A significant gain in oil production was achieved without adversely impacting the water cut, causing sand production, or fines migration. Analysis of flow back samples indicated that iron was the main cation, which shows that the chelate dissolved corrosion products. Geochemical modelling was able to predict the trend noted in the concentrations of key ions and chelant in the produced fluids.