Peng, Yang (Multi-Chem—A Halliburton Service) | Yue, Zhiwei (Multi-Chem—A Halliburton Service) | Ozuruigbo, Chioma (Multi-Chem—A Halliburton Service) | Fan, Chunfang (Multi-Chem—A Halliburton Service)
The Bakken formation has emerged as one of the major oil and gas sources in the United States primarily because of technological advancements in hydraulic fracturing and horizontal drilling. Because of the high level of dissolved iron and calcium, water in the Bakken formation can be challenging in terms of scale control compared to other types of formation water with low levels of dissolved iron and calcium. Generally, for controlling carbonate scale, the high level of dissolved iron present in water significantly reduces the performance of commonly used scale inhibitors, such as polycarboxylic acids and amino tri(methylene phosphonic) acids etc. Most studies attribute such adverse impacts to the additional consumption of scale inhibitors by iron carbonate. However, evidence has shown the mechanism can be more complicated because of potential crystal distortion and scale seed effects during the coexistence of the two scale forms (
This paper presents a series of field and laboratory studies conducted to better understand and address such problems. A discussion of acquired results and their implications is presented. Using Bakken formation water with more than 200 mg/L offerrous ions and 18,000 mg/L calcium ions, the inhibition performance of some conventional scale inhibitors and a few innovative solutions under anaerobic static and dynamic test conditions are evaluated and compared. Modeling analyses of Bakken water helped identify calcium carbonates and iron carbonates as primary potential scales. The compatibility of scale inhibitors in Bakken water with and without crosslinked gel fracturing fluid was also investigated. The results revealed two new chemicals are compatible with the fracturing fluid, both exhibiting high iron and calcium tolerance. These new solutions enabled effective control of calcium carbonate and iron carbonate scales in Bakken formation water.
Prigiobbe, Valentina (Stevens Institute of Technology) | Ko, Saebom (The University of Texas at Austin) | Wang, Qing (The University of Texas at Austin) | Huh, Chun (The University of Texas at Austin) | Bryant, Steven L. (University of Calgary) | Bennetzen, Martin V. (Maersk Oil Research and Technology Centre, Qatar)
Magnetic Nanoparticles for Efficient Removal of Oilfield "Contaminants": Modeling of Magnetic Separation and Validation
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.
In many areas water used for steam flood injection has varied concentrations of dissolved silicon (Si), which can form silica scale, reducing thermal efficiency, and lowering steam quality. Scale inhibitors are typically used today, but removal of Si may be a more cost-efficient process to reuse the water, especially in areas with limited fresh water availability. Removing Si in the water treatment plant before steam generation can lead to higher quality steam at lower costs and result in better production.
Typical chemical precipitation methods have been reported for Si removal by adding different coagulant compounds that contain elements such as aluminum (Al), iron (Fe) or molybdenum (Mo). In general, the chemical precipitation method needs high volumes of coagulants and generates considerable amounts of sludge, and may also input extra compounds or ions into the treated water. Electrocoagulation (EC) has been claimed for Si removal, but low conductivity water (or low concentration of total dissolved salt (TDS)), as seen in steam injection systems, is not well-matched to traditional EC systems.
In this paper, a uniquely designed electrocoagulation (EC) system with non-sacrificial electrodes and sacrificial material was tested for Si removal from steam injection water. This EC system has been shown to be highly flexible and efficient for treating waters with TDS levels from 3,000 to over 300,000 mg/L, especially for Si, Fe, and suspended solid removal. The water in this case was hot (180°F), low TDS (<6,000mg/L), and had 60 to 80 mg/L of Si. Both laboratory scale testing and pilot field trial showed efficient Si removal from the water to less than 2 mg/L at varied temperatures. Significant hardness removal was also achieved during the same process. Compared with chemical precipitation methods, this unique EC system used fewer chemicals, generated less sludge, and provided a higher quality of effluent water.
Paraffins are linear and branched aliphatic molecules (>C18) present within crude oil. As crude oil cools upon exiting a well, the paraffins can gel or precipitate and ultimately cause pipelines to plug. The result is costly downtime in production as the pipelines are cleaned or repaired. One solution to address this challenge is chemical prevention, namely the use of wax inhibitors and pour point depressants.
Traditionally wax inhibitors and pour point depressants are organic solvent-based materials that contain a low concentration of active inhibitor (approximately 5% active in a solvent such as toluene). In this work, newly developed high concentration (>30% active) aqueous-based wax inhibitors and pour point depressants will be discussed.
These formulations are stable dispersions of active copolymers in water and can be freeze-protected to -40°C, enabling their use in arctic environments. There is also an advantage of reduced logistics costs, decreased storage space and the absence of flammable solvents. Additionally, the replacement of organic solvent with water makes these materials more environmentally friendly and less expensive to dilute during application. The physical properties and stability of these materials throughout a broad temperature range from -40°C to 125°C will be discussed. The performance of these innovative materials on various crude oils will also be presented. Up to a 30°C reduction in the pour point temperature was observed. This unique combination of properties and significant reduction in pour point temperatures is a novel advancement in flow assurance technology.
In view of the great impact of asphaltene deposition in the petroleum industry, it is of paramount importance to estimate the tendency of crude oils and petroleum products towards precipitation as well as the potential amount of material that can precipitate. These are important parameters to consider in designing and monitoring of different processes in the petroleum value chain. It is common knowledge that asphaltene precipitation is strongly related to the colloidal nature of petroleum materials. Rather recently, a new method to evaluate the colloidal stability of crude oils was developed based on the determination of the solubility distribution of asphaltenes. It was found that samples from different origins give different solubility distribution patterns and that those patterns can be correlated to precipitation tendencies of crude oils.
In this work, asphaltene distributions in solid deposits are analyzed and compared to the original asphaltene distributions in the corresponding original oils. Additional chemical and physical properties were also examined and compared. This study aims to link specific asphaltene solubility distribution patterns to the formation of deposits and to find out how asphaltenes found in deposits are compared with the asphaltenes in the materials that originated them. This information is relevant for thermodynamic as well as kinetic modeling of the asphaltene deposition phenomena.
The results indicated significant differences between asphaltenes from the original crude oils and their corresponding deposits. Quantification of these differences in terms of solubility was carried out and showed that asphaltenes from deposits are in average composed of less soluble asphaltenes than those present in the original crude oils. In practical terms, this means that asphaltenes separated using heptane or pentane might not be representative of the asphaltenes found in deposits. The compositional variation of solid deposits seems to point out towards a complex mechanism of formation that is usually not considered in the tools used to model this phenomenon.
Corrosion inhibitors can behave as cathodic inhibitors when they mainly suppress the cathodic reaction. Conversely, they can also be anodic inhibitors when they mainly suppress the anodic reaction. When corrosion inhibitors interact with both cathodic and anodic reactions, they may behave as mixed inhibitors. This paper documents the electrochemical characterization of a phosphate ester based inhibitor which created protection from oxygen corrosion. Potentiodynamic polarization was used to determine the inhibitor behavior during the anodic and cathodic processes of corrosion. A system comprising a carbon steel electrode in 3.5% NaCl and a gas phase composed of 3% O2 in 97% CO2 with and without an inhibitor has been defined and tested. The oxygen corrosion mechanism on carbon steel was established through the comparison of the cathodic and anodic currents in the presence of 3% O2 in 97% CO2 and 100% CO2. The probable mechanism of inhibition by imidazoline and phosphate esters as well as the role of a sulfiding agent was explored. In the presence of oxygen, the anodic more than the cathodic inhibition performance was more related to the overall corrosion inhibition. As expected, phosphate ester based inhibitors demonstrated to be superior to imidazoline base inhibitors to abate oxygen corrosion. These results were confirmed with open-circuit (autoclave) corrosion experiments.
Polymer retention caused by increase of hydrodynamic force acting upon polymer molecules was evaluated in this study. The results indicate this hydrodynamic retention is strongly flow rate dependent. In the low-flow region, the retention increases abruptly with increased flow rate. In contrast, in the high-flow region, the increase becomes much more gradual. Our results also demonstrate that this flow-induced retention is totally reversible (no incremental irreversible retention occurs), which is also confirmed by the constant residual resistance factors determined after 100 PV of brine postflush. Consistent with previous literature, distinct flow behaviors of partially hydrolyzed polyacrylamide (HPAM) and xanthan polymers in porous media were observed. For HPAM, in the low-flow regime, Newtonian behavior (i.e., resistance factor is independent of flow rate) was exhibited. In the moderate-to-high-flow regime, HPAM showed shear-thickening behavior (resistance factor increase with flow rate). In contrast, only shear thinning (resistance factor decreases with flow rate) was detected for xanthan polymer. By analyzing the retention and rheology of both HPAM and xanthan polymers, we show that hydrodynamic retention has little effect on polymer rheology in porous media.
Successful liner cementing in unconventional shale wells is strongly dependent on slurry stability. A delayed-release, high-temperature suspending agent was developed that provides viscosification and stabilization of the slurry without causing excessive viscosification and mixing problems at the wellsite. The suspending aid was prepared from water-soluble, thermally stable monomers copolymerized with degradable crosslinking monomers. The crosslinks degrade as the temperature of the slurry increases, ultimately resulting in dissolution of the polymer and concomitant slurry viscosification. The performance of the suspending aid was demonstrated by means of laboratory testing under typical Eagle Ford shale conditions. Improvements were observed in terms of fluid-loss control (54 cc/30 min [control] to 28 cc/30 min), free fluid (5% [control] to 0%), sedimentation (?? 5.2 lbm/gal [control] to ?? 0.2 lbm/gal), and consistometer off/on tests. Three field examples from the Eagle Ford are presented where the suspending aid was used to establish the desired mud-spacer-cement rheological hierarchy at bottomhole circulating temperature (BHCT); provide sufficient slurry stability to set the liner top plug, circulate out excess cement, and produce a competent cement sheath; and improve the mixability and stability of a barite-weighted spacer.
Zhang, Zhang (Rice Univerity) | Zhang, Fangfu (Rice Univerity) | Wang, Qiliang ‘Luke’ (GE Global Research Oil and Gas Technology Center) | Bhandari, Narayan (Rice University) | Yan, Fei (Rice University) | Liu, Ya (Rice University) | Dai, Zhaoyi (Rice University) | Wang, Lu (Royal Dutch Shell Technology Center) | Bolanos, Valerie (Rice University) | Kan, Amy T. (Rice University) | Tomson, Mason B. (Rice University)
Ferrous iron (Fe2+) is one of the most common cations existing in oil and gas production water. Most Fe2+ ions come from dissolution of siderite in reservoir and corrosion of steel pipes. Compared to Ca2+ and Mg2+, Fe2+ has a higher complex stability constant with some common inhibitor function groups like phosphonate and carboxyl due to its transition metal structure. Therefore, understanding the influence of Fe2+ on inhibitors is important to enhance inhibition performance. Work still remain to be done to understand the effect of Fe2+ on scale inhibition, including a systematic study of the Fe2+ influence on phosphonate and polymeric scale inhibitors at different pH, values and molar ratios. Little research has been done at temperatures above room temperature, probably due to the difficulty of developing strictly anoxic test apparatus. In this study, a new anoxic laser apparatus is designed to test inhibitor performance. This newly designed apparatus features constant Argon gas headspace purging during an experiment to guarantee a strict maintenance of anoxic condition. This anoxic apparatus is based on laser detection method of nucleation induction time. It is easy to operate and enables experiments to be conducted at temperatures up to 200°F.