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Collaborating Authors
Production Chemistry, Metallurgy and Biology
Development of a Novel Biofilm Testing Method.
Keller-Schultz, Carrie (Nalco - Champion, An Ecolab company) | Barron-Aldana, Jesus (Nalco - Champion, An Ecolab company) | Peter, Cruz St. (Nalco - Champion, An Ecolab company) | De Paula, Renato M. (Nalco - Champion, An Ecolab company) | Keasler, Victor V. (Nalco - Champion, An Ecolab company) | Grieme, Linda (Ecolab USA Inc.) | Nguyen, Duc (PepsiCo)
Abstract Several issues associated with microorganisms found throughout the petroleum industry include microbial influenced corrosion (MIC), biotic souring, and biofouling. Traditional methods for evaluating biocide efficacy within the petroleum industry have been focused specifically toward the planktonic, or free-floating, microorganisms. The sessile population, or the community of microorganisms contained within the biofilms that adhere to each other on a surface are not adequately assessed. Since microorganisms contained within biofilms can contribute to all three major microbial issues in the oilfield and the complexity of the microbial community effects the chemical treatment strategy, there is an increased importance associated with the ability to develop a representative, mature biofilm in a lab setting in order to evaluate the efficacy of the chemical treatments prior to implementation in the field. Currently, there are a variety of laboratory methods designed to grow biofilms. However, these methods suffer from many drawbacks. This includes large quantity of fluid required to achieve a once-through system, the number of samples available to test, and the reproducibility of the biofilm growth itself. The purpose of this paper will be to introduce a novel method that will allow for an increased scalability, reproducibility, and utility in laboratory biofilm studies. This knowledge will help in a better understanding of biofilms and facilitate the development of treatment strategies targeting biofilms.
Abstract Production from deepwater environment often encounter ultra high temperature, pressure (ultra HTHP) and with more exotic fluid compositions. Most scale prediction programs were developed by semiempirically modeling the thermodynamic parameters using experimentally measured mineral solubilities and other chemical properties. However, the experimental data were limited at temperature, pressure, and ionic strength that were clearly below that typically encountered in deepwater production. Therefore, extending the existing thermodynamic models to HTHP applications is of questionable accuracy. Furthermore, the partitioning of H2O, CO2, and H2S in and out of the gas/oil phases during production can have a significant impact on scaling tendency. The authors have published papers on experimental solubility measurements and thermodynamic modeling to extend the solubility data to HTHP condition. The new thermodynamic parameters and a flash calculator that integrate the latest development of Equation of State (EOS) to model the partition of H2O, CO2, and H2S in hydrocarbon/aqueous phases at temperature and pressure have been incorporated into a scale prediction software that is specifically tailored for oil and gas production application. The objective of this paper is to validate the software's application range with a set of critically evaluated peer-reviewed mineral solubility data for general oilfield produced water and deepwater HTHP application. A total of 73 selected papers and more than 2,500 individual experimental data points were included in this evaluation. Our model has been shown to be applicable to greater than 95% of produced water compositions with SI prediction of better than ±0.03 for halite, ±0.05 for gypsum, ±0.1 for calcite and anhydrite, and ±0.2 for barite at temperature between 32 - 500 °F, and and pressure between 14.7 to 22,000 psia. The newly incorporated flash calculator is capable of predicting how CO2, H2S, and H2O partition in and out of the gas phase during production. The partitioning of CO2, H2S, and H2O between the hydrocarbon and aqueous phases has significantly changed the ion composition and pH and therefore, impacted the scaling tendency of the fluids at the production temperature and pressure. This is a particularly important issue for newer wells with high volumes of gas and low water cuts and for CO2 flooding.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.69)
Abstract 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.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology (1.00)
The Effect of Pressure and TDS on Barite Scaling Kinetics
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)
Abstract 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 Ba and SO4- 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.
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > Mississippi > Collins Field (0.93)
Abstract The oil and gas industry has adopted several methods to obtain insight as to how a fluid may affect reservoir material. The Capillary Suction Time (CST) test has become a de facto standard test method, largely due to its simplicity and speed. The most obvious shortcoming of the CST test is that it introduces a medium (paper) that is far different from anything found in an actual reservoir; in fact, one may argue that the CST test is essentially a measure of the interaction of the test fluid with the paper. The lack of theoretical foundation of the CST test precludes reproduceable results or proper estimation of errors in measurement. We present a new test method that observes only intrinsic properties of the formation in contact with a test fluid, bolstered by a strong theoretical basis, in stark contrast to the CST test. Our method preserves the desirable attributes of the CST test, but replaces imbibition into paper with imbibition into reservoir material. The method uses a comminuted sample, and the results from the imbibition step are used to determine formation wettability in the form of the advancing contact angle. The results from a subsequent drainage test are used to determine the receding contact angle, and the capillary pressure versus saturation curve. Prior to performing the drainage test, test fluid is placed on top of the saturated pack and the permeability of the pack to the test fluid is determined. The permeability of the pack to liquid is then compared to the pretest permeability of the pack determined using nitrogen. Use of this pack as a testing environment allows the technique to be applied to formation samples of virtually any permeability and porosity. We have found that there is no correlation between CST test data and the permeability data obtained using the new method presented here. We present several cases in which a positive result from a CST test is inconsistent with the results obtained from the new test method. We maintain that the discrepancies cast serious doubts on the general applicability of the CST test as a tool for studying rock/fluid interactions. In summary, there is a great need to standardize testing that investigates rock/fluid interactions. The widely used CST method introduces a foreign material and it does not offer sufficient resolution, reproducibility, or estimation of error. Even if the CST method were adequate, the lack of standardization in testing and analysis methodologies makes comparisons of published results difficult. Our method provides superior results. The strong theoretical foundation of the new method allows rigorous analysis making comparisons between treating fluid options far more trustworthy.
- North America > United States > West Virginia (0.28)
- North America > United States > Texas (0.28)
- North America > United States > Ohio (0.28)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.94)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.94)
- (37 more...)
Abstract Production of sour crude oil releases hydrogen sulfide (H2S) into production tubing and surface equipment, causing corrosion, flow assurance issues, safety, and environmental concerns for the producer. As a result, increased costs related to metallurgical upgrades, gas sweetening equipment, increased manpower costs for monitoring, and liability from the potential release of H2S can become significant parts of the total operation cost. These issues can be alleviated if the H2S is reliably removed downhole and prevented from reaching the surface. Conventional hydrogen H2S scavengers such as triazines or glyoxal are commonly applied by direct injection topside to mitigate H2S in oil and gas production facilities. However, when applied in direct-injection applications, these scavengers exhibit slow kinetics that reduce their effectiveness in short residence-time systems, resulting in a much greater amount required than theoretical efficiency would predict. Neither triazines nor glyoxal are suitable for downhole application because of their low thermal stability and, in the case of triazine, its high scaling tendency. To achieve reliable and cost-effective removal of H2S topside or downhole, the development of a new scavenger and a new delivery system for downhole application was required. As a result, a new non-triazine, organic acid metal complex-based H2S scavenger (OAC) with high-temperature stability, fast kinetics and quantitative H2S removal was developed. The new delivery equipment comprises an injection skid, H2S monitoring equipment, and an automated chemical dosing system to ensure delivery of the precise dosage required to remove H2S downhole. Field test results for the new OAC scavenger and delivery system will be presented for mixed production applications, demonstrating the ability of this approach to reliably remove H2S both topside and downhole.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.95)
- North America > United States > Wyoming > Uinta Basin (0.99)
- North America > United States > Utah > Uinta Basin (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (3 more...)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
Abstract Scale control in ultra-deepwater under high temperature, high pressure and high total dissolved solids (TDS) is critical for efficient and safe oil and gas production. With the continued development of offshore production in ultra-deepwater, more and more wells are exposed to extremely high temperature (>150 °C) and pressure (>15,000 psig) under anoxic condition. However scale testing, prediction and control under these extreme conditions is often challenging due to the limitation of testing equipment to accurately simulate these environments. The dynamic tube blocking test is a widely applied test approach for evaluating scale risk and scale inhibition efficiency in the laboratory. However, little information has been reported for studying control and inhibition of siderite (FeCO3), a major product from corrosion. Furthermore, very few studies assess the scaling risk of iron oxides under extremely high temperatures. In this research, the kinetics of siderite nucleation and precipitation has been studied in the absence and presence of scale inhibitors including sulphonated polycarboxylic acid (SPCA), polyvinyl sulphonate (PVS), carboxymethyl inulin (CMI) and sodium citrate. Scale inhibitors have been evaluated at high temperature (up to 250 °C) to determine if they are applicable for siderite (or iron oxide) inhibition. Inhibition of iron oxide precipitation under 250 °C and 600 psig was observed. All solutions used in this research are strictly anoxic with ≪ 1 parts per billion (ppb) of dissolved oxygen and in the absence of added reducing reagents, that might alter the reaction. This strictly anoxic condition is critical for evaluating inhibition efficiency and degradation of scale inhibitors due to the interferences and reactions between dissolved oxygen and scale inhibitors.
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Application of a Novel Method for Real-Time Monitoring of Scale Control Products at the Site of Use
Johnstone, James (Kemira Chemicals Ltd. (UK)) | Peltokoski, Brita (Kemira Oy., Helsinki, Finland) | Toivonen, Susanna (Kemira Oy., Helsinki, Finland) | Griffin, Rick (Kemira Chemicals (US)) | Hurd, Michael (Kemira Chemicals (US)) | O'Brien, Ashleigh (Kemira Chemicals (US)) | Fournier, Frances (Kemira Chemicals (US)) | Siivonen, Joonas (AQSENS Oy., Turku/Espoo, Finland) | Väisänen, Pave (AQSENS Oy., Turku/Espoo, Finland) | Tittanen, Satu (AQSENS Oy., Turku/Espoo, Finland) | Lehmusto, Mirva (AQSENS Oy., Turku/Espoo, Finland) | Mäkinen, Piia (AQSENS Oy., Turku/Espoo, Finland) | Wahrman, Jonas (AQSENS Oy., Turku/Espoo, Finland) | Mundill, Paul (AQSENS Oy., Turku/Espoo, Finland)
Abstract Operators in the oil and gas industry make extensive use of scale inhibitors to provide the level of flow assurance required to maximise safe and economic hydrocarbon production. For continuous and scale squeeze treatments, field operators need to verify the residual inhibitor concentrations regularly to ensure that the implemented scale management program remains effective. Sulfonated polymers are effective and widely used sulphate (barium, strontium, calcium) scale inhibitors, however detection of residual (less than 15 ppm) amounts has been problematic, leading to the use of an overdose on continuous applications or resqueezing before reaching the minimum effective dosage (MED) level. The authors have developed a testing protocol that enables measurement of the residual concentration of polymeric scale inhibitors at the point of use and directly in produced water, providing a timely and accurate scale inhibitor concentration to the facility operator. Field operators with minimal training use sample preparation protocols that are minimized and standardized to determine polymer concentrations within 15 minutes down to 1 ppm active polymer. The testing protocol uses an aqueous liquid fingerprinting technology platform to detect a range of scale inhibitor products and provides direct field analysis for either continuous or scale squeeze application programs. Operators determine the residual scale inhibitor level at the point of use, eliminating the cost and time delay of shipping samples to a remote analytical laboratory. We previously presented laboratory results of this technology (Johnstone et al. 2014). In this paper, we present the results of the performance of this system in actual field operation which was completed late 2014 at oil and gas production locations and validated at an analytical laboratory. The results demonstrate the benefits of the protocol in field applications in monitoring residual levels to a level of accuracy for polymeric scale inhibitors previously only achievable in fully equipped analytical laboratories. This technology has been demonstrated to the oil and gas industry and has generated significant interest in a number of communities for which monitoring polymeric scale inhibitors at concentrations less than 5 ppm active is a business-critical activity. The validity of the protocol has been confirmed by ongoing work across a number of application areas, supporting the global industry challenge of scale control.
- Europe (0.97)
- North America > United States > Texas (0.69)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Moray Firth Basin > Witch Ground Graben > P.213 > Block 16/26a > Brae Field > Alba Field > Caran Sandstone Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Moray Firth Basin > Witch Ground Graben > P.213 > Block 16/26a > Brae Field > Alba Field > Alba Sandstone Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Fladen Ground Spur > Witch Ground Graben > P.213 > Block 16/26a > Brae Field > Alba Field > Caran Sandstone Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Fladen Ground Spur > Witch Ground Graben > P.213 > Block 16/26a > Brae Field > Alba Field > Alba Sandstone Formation (0.99)
A Highly Effective Corrosion Inhibitor Based on Gemini Imidazoline
Yang, Jiang (RIPED, PetroChina & Xi'an Petroleum University) | Liu, Xuan (Xi'an Petroleum University) | Jia, Shuai (Xi'an Petroleum University) | Qin, Wenlong (Xi'an Petroleum University) | Yin, Chengxian (Tubular Goods R&D Center, PetroChina) | Liu, Chen (Southwest Petroleum University)
Abstract Corrosion inhibitors are widely used to control corrosion under the sweet and sour environments in oil and gas industries. More effective and environment friendly corrosion inhibitors need to be developed. This paper studies a new gemini imidazoline corrosion inhibitor, which two hydrocarbon chains and two headgroups are linked by a rigid spacer. The gemini imidazoline was synthesized through the reaction of oleic acid with triethylene tetramine at 2:1 molar ratio. The product was characterized by infrared spectroscopy, chromatography and mass spectroscopy. The performance of the gemini imidazoline on inhibition of CO2 corrosion was evaluated by linear polarization resistance in sparged beaker testing. Rotating wheel testing was performed to evaluate the film persistency of the test inhibitors. The results showed that corrosion inhibition of the gemini imidazoline was more effective at lower concentration than that of conventional imidazoline. The gemini imidazoline mixed with fatty acid also showed better film persistency than that of conventional imidazoline. The emulsion tendency of the gemini imidazoline was less than that of conventional imidazoline. The mechanism of the highly effective gemini imidazoline was studied. It showed that gemini imidazoline has much higher surface activity than that of conventional imidazoline. The critical micelle concentration is several times lower than that of conventional imidazoline. Hence, the new gemini imidazoline (GIM) corrosion inhibitor and its mixture give more effective corrosion inhibition at low concentration, which also has less environmental impact.
- Water & Waste Management > Water Management > Water & Sanitation Products (1.00)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract Wax deposition is one of the major problems for onshore and offshore crude oil production. High molecular weight wax (HMWW) is commonly defined as a wax containing more than 40 carbons in its chemical structure. These types of wax are challenging to treat, as they form hard deposits that can be difficult to remove. Most paraffin inhibitors available in the market currently are not effective at inhibiting the formation and deposition of HMWW in oil production systems. This paper discusses extensive work on understanding HMWW characteristics and chemical methods to treat such deposits. A variety of wax characterization techniques, such as cold finger (CF), differential scanning calorimetry (DSC), cross polarized microscopy (CPM), and high-temperature gas chromatography (HTGC), were used to study the impact of inhibitor chemistry on wax characteristics. Oil from South Texas with high wax content (8%) was evaluated using five different types of inhibitor chemistry. DSC and CPM were used to obtain the wax appearance temperature (WAT), and CF was used to deposit the HMWW and evaluate inhibition efficiency. HTGC results were obtained from the wax collected from CF to determine carbon distribution of the deposit. DSC of the wax was also performed to obtain the crystallization of the wax and estimate the wax content in the deposit. Of the five chemistries evaluated, one showed good performance, with approximately 30% inhibition, while two polymers reduced the crystallization temperature and softened the wax deposit. The other two chemicals did not show any effects on the HMWW.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)