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.
The “Pre-salt application” offers some unique and challenging difficulties for producers and the service companies who support their operations. The carbonate reservoirs which occur in Brazilian deepwater fields provide unique challenges that relate to high temperatures, the high H2S content, as well as severe saline and scaling conditions. It is quite common to find oil and gas fields with estimated H2S level in the produced gas between 100 and 200 ppmv and salinity approximately 230,000 mg/L. Hydrogen sulfide is a poisonous gas, very harmful to life, and removal is essential to comply with sulfur emissions, as well as to ensure system and pipeline integrity.
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.
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.
The interaction of oil and gas biocides with critical environmental factors directly affects their performance in applications where successful water management practices are essential. These include hydraulic fracturing, water flooding, and water storage and disposal. Effective control of microbial contamination in these applications is required for the sustained quality of the production fluids and structural assets. The microbial groups of concern are sulfate reducing bacteria (SRB), acid-producing bacteria (APB), and facultative anaerobes.
In this study, representative oxidizers and non-oxidizers were tested under environmental parameters of importance including elevated temperature, biological organic matter, and individual process additives (xanthan, guar, polyacrylamide). These parameters represent common conditions which may be present and should be considered when selecting a biocide treatment. Results showed that all biocides have inherent antimicrobial activity versus SRB and APB. The stability and compatibility of these biocides varied widely. Oxidizing biocides, in general, showed good efficacy at low concentrations at room temperature. However, the oxidizers showed poor stability and a loss of activity at elevated temperatures (>40° C). By contrast, several non-oxidizing biocides showed very good stability and efficacy at significantly higher temperatures (60-80° C) providing microbial control for weeks to months. The addition of organic matter and process additives had little effect on the non-oxidizing biocides; however, certain oxidizers were rapidly inactivated and showed varying interaction with the additives. Understanding the compatibility and stability of biocides is critical to their performance and essential to define microbial treatment strategies to provide both rapid topside kill with extended downhole control under typical reservoir conditions.
The performance of surfactant-enhanced oil recovery (EOR) in fractured carbonates relies on spontaneous imbibition or low IFT-aided gravity drainage. This work investigated the synergism between wettability effects and IFT reduction mediated by a variety of surfactants through experiments and numerical simulation studies. Experiments have shown that oil can be recovered from oil-wet Silurian dolomite fracture blocks either by capillarity driven imbibition, gravity-driven imbibition or low tension-aided gravity drainage. The mixture of wettability alteration (WA) surfacant with IFT reduction surfactant exhibits the synergistic effect on the imbibition oil recovery from oil-wet carbonate rocks. It was found that divalent ion scavengers help the wettability altertion capability of some sulfonate surfactants in hard brine, which leads to the high oil recovery up to 70% OOIP (IFT+WA), compared with oil recovery of 30-50% OOIP by sulfonate surfactant only (only IFT reduction). We proposed a mechanism that the presence of a sufficient amount of divalent ion scavengers in the anionic surfactant formulation reduces the free divalent cations in hard brine, which then promotes the release of surfactant monomers from the micelles and enhances wettability alteration by surfactant adsorption. The UTCHEM simulation results confirmed the existence of synergism between IFT reduction and WA in spontaneous imbibition processes. According to the capillary desaturation curve (CDC), that residual oil saturation after gravity drainage is approximately 10% to 20% higher than gravity-driven spontaneous imbibition when two processes have the similar trapping numbers, confirming that the wettability alteration contributes to the ultimate oil recovery.
Tavassoli, Shayan (The University of Texas at Austin) | Korrani, Aboulghasem Kazemi Nia (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin) | Sepehrnoori, Kamy (The University of Texas at Austin)
We have applied UTCHEM-IPhreeqc to investigate low salinity waterflooding and low salinity surfactant flooding. Numerical simulation results have been compared with laboratory experiments reported by
Viscoelastic surfactant (VES) fracture fluids were developed as a nondamaging alternative to conventional polymer-based fluids. However, the viscosity performance of typical VES fluids is dramatically reduced at high temperature. Therefore, these fluids are typically limited to treat relatively low-temperature formations unless foamed with nitrogen or carbon dioxide. Recent laboratory work has shown that viscosity alone may not accurately assess proppant transport. Thus, combination of rotational and oscillatory measurements to determine the fluid viscous and elastic properties can better predict whether the fluid can be applied successfully in the field.
The present study was conducted to introduce a new Gemini VES system that can gel and maintain useful viscosity up to 275°F, which can provide additional downhole benefits. Dynamic and static proppant settling tests were conducted using a high-pressure/high-temperature visualization cell to confirm the effect of elastic properties of this fluid on proppant settling. Finally, proppant settling tests were conducted with three proppant types of the same size, but different density and shape at a range of concentrations.
Experimental results show that the surfactant gel behaved as an elastic material (elastic regime), where the elastic modulus (G') was dominant over the viscous modulus (G”) during the tested range of frequency. This behavior gives perfect proppant transport properties. At temperature less than 225°F, Values of G' were independent of the frequency and/or shear rate values, while G” increased with increasing frequency and/or shear rate. At higher temperature, both G' and G” increased with increasing frequency and/or shear rate. This gives a good proppant-carrying capacity during dynamic conditions (mixing and injection) with a small pressure drop. The addition of an internal liquid breaker increases the viscous regime with time and temperature. When elastic regime dominates, 100% proppant suspension was confirmed for at least two hours at static and dynamic conditions and temperatures in the range of 75 to 250°F.
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.
Bhandari, Narayan (Rice University) | Kan, Amy T. (Rice University) | Zhang, Fangfu (Rice University) | Dai, Zhaoyi (Rice University) | Yan, Fei (Rice University) | Liu, Ya (Rice University) | Zhang, Zhang (Rice University) | Bolanos, Valerie (Rice University) | Wang, Lu (Rice University) | Tomson, Mason B. (Rice University)
Despite the significant progress made for the expansion of oil and gas productions from conventional to unconventional sources in the last several years, the steady growth of the hydrocarbon demand is driving the oil and gas industries to explore new or under-explored areas that are often challenging. Because of technological difficulties associated with extremely high temperature (>150°C), pressure (>10,000 psia), and TDS (>300,000 mg/L) at deep water production environments, prediction and control of mineral scaling pose significant challenges. Appropriate experimental data is needed for better understanding of scaling risk in those harsh environments, but current literature lacks the experimental findings that correlate the importance of pressure and temperature on the mineral scaling kinetics. This study attempts to bridge this knowledge gap by formulating the pressure dependence of barite formation kinetics at various temperatures (T) and saturation indices (SI).
In order to study the effect of the pressure on the mineral scale formation kinetics, a high temperature high pressure (HTHP) flow loop apparatus was developed and experiments were carried out at various temperatures (70-175°C) and at a range of pressures (15-15,000 psia). Barite scale formation (precipitation) kinetics as a function of the pressure was investigated while maintaining constant pH, T, ionic strength, and SI. To determine the onset of scale formation (i.e. induction time), time dependent composition of reaction mixture containing Ba2+ and SO42- species was analyzed using ICP-OES. In a separate but independent study, barite induction time at various ionic strengths at constant T, P, and SI was determined by laser light scattering method. This work will show that barite precipitation kinetic is a strong function of applied pressure at constant T, SI and TDS. Based on experimental results, the relationship between induction time for barite formation as a function of T, P and SI was established.