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Collaborating Authors
Rice University
A Fast and Accurate Method for Scale Inhibitor Effective Concentration Measurement with Low Detection Limit
Wang, Xin (Rice University) | Dai, Zhaoyi Joey (China University of Geosciences) | Ko, Saebom (Rice University) | Leschied, Cianna (Rice University) | Dai, Chong (Rice University) | Li, Wei (Rice University) | Paudyal, Samridhdi (Rice University) | Yao, Xuanzhu (Rice University) | Shen, Yu-Yi Roy (Rice University) | Pimentel, Daniel (Rice University) | Kan, Amy (Rice University) | Tomson, Mason (Rice University)
Abstract Scale inhibitors have been widely used for scale control in oil and gas production. The accurate measurement of residual scale inhibitor concentration in the produced brine is essential for scale prevention. However, these scale inhibitors are effective at sub-stoichiometric concentration in most production conditions (e.g., 1 mg/L active concentration, or even lower). It is rather difficult to measure such low inhibitor concentration with traditional ICP-OES/MS or IC method, especially for non- or low- phosphorous polymeric scale inhibitors. Furthermore, the combo of scale inhibitors and corrosion inhibitors are used in the most application, which requires the measurement of effective scale inhibitor concentration. Therefore, there is a high demand of a fast, sensitive, universal and cheap method to determine the effective scale inhibitor concentration in complicated field brines. In this study, a new assay method is developed to determine the effective scale inhibitor concentration. This assay method is based upon the linear relationship between the effective inhibitor concentration and the critical time of barite scale formation, which is determined by turbidity measurement using a CSTR apparatus in Brine Chemistry Inhibitor (BCIn) method. This linear relationship has been validated by experimental observation. The recommended procedures for the sample preparations from the real oilfield brine were also developed to help in the quick setup of the measurement. Various types of inhibitors (i.e., SPCA, PPCA, PVS) have been tested with different sample types (i.e., in the synthetic brines, laboratory samples and real oilfield produced brine). The new assay method is quick, robust and accurate with the relative error less than 10% even at 1 mg/L of inhibitor, which indicating a limit of detection (LODs) around 0.1 mg/L for most cases.
- Europe > United Kingdom (0.46)
- North America > United States > Texas (0.46)
- Water & Waste Management > Water Management > Water & Sanitation Products (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (24 more...)
Sulfide Scale Controls and Predictions Using Water-Soluble Polymer
Ko, Saebom (Rice University) | Wang, Xin (Rice University) | Li, Wei (Rice University) | Dai, Zhaoy (Rice University) | Paudyal, Samridhdi (Rice University) | Yao, Xuanzhu (Rice University) | Leschied, Cianna (Rice University) | Shen, Yu-Yi (Rice University) | Pimentel, Daniel (Rice University) | Kan, Amy T. (Rice University) | Tomson, Mason B. (Rice University)
Abstract Recently, sulfide scale related issues have been significantly increased, probably due to implementation of more aggressive technologies and exploration of unconventional fields, such as high temperature, high pressure, and high salinity. Firstly, sulfide scales (i.e., FeS, PbS, and ZnS) are one of the most or significantly unsolved deposition problem in oil and gas production. Secondly, sulfide scales have oleophilic nature so that they can be difficult to separate sulfide scales from oil phase during production processes. Polymeric dispersants have exhibited their feasibility to prevent the deposition of sulfide scales, but dispersants have not been widely validated to control sulfide scale problems and limited numbers of trials and reports have been available. The objectives of this study are: (1) to evaluate dispersion efficiency of sulfide scale dispersants in a wide range of conditions of brine ionic strength, calcium concentrations, solution pH, and temperature; (2) to examine the effect of dispersants on sulfide scale wettability; (3) to understand the mechanism of a dispersion process; and (4) to apply the newly developed dispersion model for a prediction of a minimum dispersant concentration (MDC). Among tested natural and synthetic water-soluble polymers, carboxymethyl cellulose (CMC) showed the best dispersion efficiency for sulfide scales with an individual particle size of around 4 nm. The second-best dispersants identified in our study were polyvinyl pyrrolidone (PVP) and polyacrylamide (PAM). Despite some degrees of aggregation of dispersed sulfide particles, their size was still in the nanometer ranges of 100 to 500 nm. Dispersed sulfide particles remained in the water phase, while settled ones were transferred to the oil phase. Transmission electron microscope (TEM) and Fourier-transform infrared (FT-IR) results showed that CMC was adsorbed on the surface of FeS particles through H-bond and complexation between Fe(II) and carboxylate groups, controlling particles growth and preventing them from settling. CMC was effective to disperse sulfide scales in conditions of brine ionic strength (58.5 – 234 g/L NaCl), Ca concentrations (1,000 – 8,000 mg/L), pH (4.3 – 6.7), and temperature (70 – 120 °C). In these reaction conditions, MDC of CMC ranged from 5 to 200 mg/L. The combination of CMC and diethylenetriamine penta(methylene phosphonic) acid (DTPMP) enhanced CMC dispersion efficiency in some conditions. MDC of CMC for PbS and ZnS scales were 2 and 5 mg/L, respectively. MDC prediction model predicted MDC quite reasonably in wide range of NaCl concentrations (58.5 – 234 g/L) and SI of FeSm (0.13 – 2.03).
- North America > United States > Texas (0.29)
- Europe > United Kingdom > Scotland (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
Application of ScaleSoftPitzer in Big Data Era: Evaluations of Water Source, Scale, and Corrosion Risk – A Permian Basin study
Wang, Xin (Rice University) | Dai, Zhaoyi Joey (China University of Geosciences) | Li, Wei (Rice University) | Ko, Saebom (Rice University) | Paudyal, Samridhdi (Rice University) | Yao, Xuanzhu (Rice University) | Leschied, Cianna (Rice University) | Shen, Yu-Yi Roy (Rice University) | Pimentel, Daniel (Rice University) | Kan, Amy (Rice University) | Tomson, Mason (Rice University)
Abstract Oil and gas industry would generate a large volume of produced water during the exploration and production. The geochemistry of the produced water can provide valuable information for the analysis of formation water source evolution and the scale and corrosion risk of the production. In past decades, the water sample and the correlated condition have been collected during the production, which accumulate extensive amount of data. The successful analysis of such database would be very helpful for the scale and corrosion management. In this study, the ScaleSoftPitzer (SSP) software is used to proceed the analysis of produced water evolution and scale and corrosion risk. A Permian Basin example is selected based on USGS produced water database V2.3. The formation information from the database was critically reviewed, cleaned and standardized into 13 major formation groups related to the oil and gas production area. The missing depth, temperature and pressure were calculated, and the CO2% and downhole pH were calculated by assuming the downhole brine was in equilibrium with calcite. The saturation indices of various scale are calculated and statistically analyzed. According to our analyzing result, it is found that usually the saturation index of gypsum and barite are close to zero, which suggest that the produced water is in equilibrium with barite and gypsum mineral in the formation. The calculated calcite scale SI are generally larger than 1.0, suggested potential calcite scale risk. 1 mg/L of NTMP is recommended for all Permian Basin well for preventive scale control. The CO2 corrosion risk was also calculated using the corrosion model in SSP, a preventive action is suggested for Permian Basin. Furthermore, a good agreement between the calculated corrosion rate and the measured Mn concentration is observed. This study provided a template to use the produced water database to improve the scale and corrosion management at the field level in this big-data era.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (26 more...)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- (2 more...)
Abstract At present, approximately 37,000 out of 110,000 oil and gas wells in onshore California are classified as ‘idle’ - they have not been producing hydrocarbon or water, including EOR, for two consecutive years without abandonment. In this context, we examine whether operators retaining those current or potentially future idle wells could economically re-purpose their assets for a carbon storage operation. Such an approach would potentially defer the eventual decommissioning, abandonment, and remediation costs of these assets. This study models the economics of a fully integrated system from source CO2 capture through subsurface storage for a thermal steam operation. The model workflow developed in this paper is as follows: capture carbon dioxide from steam co-generation plants in heavy oil steam injection fields in the San Joaquin Valley, delivering it via pipeline to selected idle producing or injection wells, converting those wells into carbon dioxide injectors, and finally injecting and monitoring for sequestration. The well re-purposing process would isolate the formerly produced hydrocarbon interval and re-complete in the overlying saline aquifer interval to be used for CO2 sequestration. The fundamental difference of project economics between hydrocarbon production and carbon capture and sequestration is the regulatory and policy-defined financial incentives. In California, those consist of three major elements: Section 45Q tax credits by the federal government, low-carbon fuel standard (LCFS) credit by the State of California, and cap-and-trade emission allowances. The economic model shows that two factors, LCFS credit price and the cost of carbon capture systems, comprise the most significant proportion of impact on economic feasibility. To achieve the breakeven IRR of 10%, first, LCFS eligibility of the CCS project for a co-generation plant should be improved, and credit price needs to remain at least at the current level. On top of that, the expected increase in future LCFS credit prices and cap-and-trade allowance as potential revenue in an opportunity cost context would enhance economic performance. Secondly, the most plausible, the CAPEX of carbon capture systems at steam co-generation plants would need to be reduced to the lowest cost benchmarks currently seen in process plant implementations. This paper can be viewed as a starting point to stimulate examination of carbon capture and sequestration project options by both operators managing end-of-field life producing assets, as well as State of California regulatory agencies pursuing carbon reduction as part of the state's larger energy transition strategy.
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract Foam is a promising means to assist in the permanent, safe subsurface sequestration of CO2, whether in aquifers or as part of an enhanced-oil-recovery (EOR) process. Here we review the advantages demonstrated for foam that would assist CO2 sequestration, in particular sweep efficiency and residual trapping, and the challenges yet to be overcome. CO2 is trapped in porous geological layers by an impermeable overburden layer and residual trapping, dissolution into resident brine, and conversion to minerals in the pore space. Over-filling of geological traps and gravity segregation of injected CO2 can lead to excessive stress and cracking of the overburden. Maximizing storage while minimizing overburden stress in the near term depends on residual trapping in the swept zone. Therefore, we review the research and field-trial literature on CO2 foam sweep efficiency and capillary gas trapping in foam. We also review issues involved in surfactant selection for CO2 foam applications. Foam increases both sweep efficiency and residual gas saturation in the region swept. Both properties reduce gravity segregation of CO2. Among gases injected in EOR, CO2 has advantages of easier foam generation, better injectivity, and better prospects for long-distance foam propagation at low pressure gradient. In CO2 injection into aquifers, there is not the issue of destabilization of foam by contact with oil, as in EOR. In all reservoirs, surfactant-alternating-gas foam injection maximizes sweep efficiency while reducing injection pressure compared to direct foam injection. In heterogeneous formations, foam helps equalize injection over various layers. In addition, spontaneous foam generation at layer boundaries reduces gravity segregation of CO2. Challenges to foam-assisted CO2 sequestration include the following: 1) verifying the advantages indicated by laboratory research at the field scale 2) optimizing surfactant performance, while further reducing cost and adsorption if possible 3) long-term chemical stability of surfactant, and dilution of surfactant in the foam bank by flow of water. Residual gas must reside in place for decades, even if surfactant degrades or is diluted. 4) verifying whether foam can block upward flow of CO2 through overburden, either through pore pathways or microfractures. 5) optimizing injectivity and sweep efficiency in the field-design strategy. We review foam field trials for EOR and the state of the art from laboratory and modeling research on CO2 foam properties to present the prospects and challenges for foam-assisted CO2 sequestration.
- North America > United States > Texas (1.00)
- Europe (1.00)
- North America > United States > Oklahoma (0.68)
- Geology > Rock Type > Sedimentary Rock (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.66)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (43 more...)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Iron Sulfide Scale Control using a Dispersant of Carboxymethylcellulose (CMC) in Sour Environment
Ko, Saebom (Rice University) | Wang, Xin (Rice University) | Lee, Wei (Rice University) | Dai, Zhaoyi (Rice University) | Kan, Amy T. (Rice University) | Tomson, Mason B. (Rice University)
Abstract When hydrogen sulfide gas is evolved in the presence of iron from various corrosion processes in downhole, iron sulfide can quickly precipitate. In the recent year, sulfide scale issues have been drawing lots of attention. Firstly, iron sulfide is one of the most or significantly unsolved deposition problem in oil and gas production. Secondly, iron sulfide has oleophilic nature so that it can be difficult to separate iron sulfide from oil phase during production processes. Polymeric dispersants have exhibited their feasibility to prevent the deposition of iron sulfide scales, but dispersants have not been widely validated to control FeS scale problems and limited numbers of trials and reports have been available. The goals of this study were (1) to develop efficient and effective technology preventing iron sulfide particle deposition on the surface as well as maintaining iron sulfide in the water phase; and (2) to understand FeS scale controlling reaction mechanism. Our studies indicate that carboxymethycellulose (CMC) displays the excellent performance of iron sulfide dispersion in pH 4.3 – 6.7, temperature 70 – 90 °C, and FeS saturation index (SI) 0.13 – 1.27. At pH 5.2, the required minimum CMC concentration to disperse FeS particles (Ccrit) was 20 mg/L at 70 °C and SI(FeSm) = 0.54 and 40 mg/L at 90 °C and SI(FeSm) = 0.59. As pH increased to 6.7 at 70 °C, Ccrit was reduced to 5 mg/L at SI (FeSm) = 1.27. On the other hand, Ccrit significantly increased to 100 mg/L at SI (FeSm) = 0.13 and 400 mg/L at SI(FeSm) = 0.44 at pH 4.3 and 70 °C. Hydrodynamic particle sizes remained in nano-size in different CMC concentrations in ranges of 300 to 530 nm at pH 4.3 and 170 to 335 nm at pH 5.0. The combination of DTPMP and CMC displayed synergistic effect. The greater portion of FeS particles were dispersed and kept their size smaller in the combination of DTPMP and CMC than CMC by itself. But it became less effective at 90 °C to inhibit or disperse iron sulfide solid formation than at 70 °C. FeS particles remained in water phase in the presence of CMC, while they stayed in oil phase in the absence of CMC.
- North America > United States > Texas (0.29)
- Europe > United Kingdom > Scotland (0.28)
Iron Sulfide Solubility Measurement and Modeling Over Wide Ranges of Temperatures, Ionic Strength, and pH
Wang, Xin (Rice University) | Dai, Zhaoyi (Rice University (Corresponding author)) | Ko, Saebom (Rice University) | Deng, Guannan (Rice University) | Zhao, Yue (Rice University) | Dai, Chong (Rice University) | Li, Wei (Rice University) | Paudyal, Samridhdi (Rice University) | Yao, Xuanzhu (Rice University) | Kan, Amy T. (Rice University) | Tomson, Mason (Rice University)
Summary Iron sulfides constitute a diverse group of solid phases and aqueous complexes, many of which are critical in both natural and industrial processes, such as marine sedimentation, oil and gas productions, metallic equipment corrosion by hydrogen sulfide, and water treatment, to mention a few. As the fundamental basis of related research on iron sulfides, an accurate thermodynamic model for iron sulfide solubility prediction under wide ranges of conditions (e.g., water compositions, temperature, pressure, and pH) is required. In this study, a plug flow reactor was built to measure iron sulfide solubility at various temperatures (25–90°C), pH (5.9–6.9), and ionic strength (0.150–4.27 mol/kg). Using the mackinawite solubility data measured in this study and in literature, a new Pitzer theory-based thermodynamic model with the explicit presence of ion complexes was developed. In this model, a neutral aqueous ion complex, FeSaq, was included explicitly. The mackinawite solubility product constant was fitted with a temperature-dependent equation from 23 to 125°C: , with TK as temperature in Kelvin. This model can accurately predict the mackinawite solubility with standard error of estimate (SEE) of the mean SI = ±0.015 SI units, under wide ranges of temperature (23–125°C), pH (3.16–9.66), ionic strength (0–5 mol/kg water), and Fe(II) to S(-II) molar ratio (from 1:1,000 to 10,000:1). The Gibbs free energy and enthalpy of formation for mackinawite were also derived. This new model could help improve FeS scaling and corrosion control in complicated industrial systems, as well as the sulfide-related heavy metal transport in natural aqueous systems.
- Europe (0.93)
- Asia > Middle East (0.93)
- North America > United States > Texas (0.28)
- North America > United States > New York (0.17)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.34)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
New Kinetic Turbidity Test Method and Prediction Model for Calcite Inhibition
Dai, Chong (Rice University) | Dai, Zhaoyi (Rice University) | Paudyal, Samiridhdi (Rice University) | Ko, Saebom (Rice University) | Zhao, Yue (Rice University) | Wang, Xin (Rice University) | Yao, Xuanzhu (Rice University) | Kan, Amy (Rice University) | Tomson, Mason (Rice University)
Abstract Calcite, as one of the most common scales in oilfield can be inhibited by common scale inhibitors. The measurement of calcite nucleation and inhibition is a challenge, because of the difficulty to control pH as a result of CO2 partitioning in and out of the aqueous phase. A new kinetic turbidity test method was developed so that the partial pressure of CO2, pH, and SI can be precisely controlled. Calcite nucleation and inhibition batch tests were conducted under various conditions (SI = 0.24-2.41, T = 4-175 °C, and pH = 5.5-7.5) in the presence of common phosphonate and polymeric inhibitors. Based on experimental results, calcite nucleation and inhibition semi-empirical models are proposed, and the logarithm of the predicted induction time is in good agreement with the measured induction time. The models are also validated with laboratory and field observations. Furthermore, a new BCC CSTR Inhibition (BCIn) test method that applied the Continuous Stirred Tank Reactor (CSTR) theory has been developed, for the first time. This BCIn method was used for calcite inhibitor screening tests and minimum inhibitor concentration (MIC) estimation. By only running one experiment (< 1 hour) for each inhibitor, BCIn method selected the effective inhibitors among 18 common inhibitors under the conditions of SI = 1.23 at 90 °C and pH = 6. It was also found that the critical concentration (Ccrit) from BCIn method has a correlation with the MIC from batch tests. This study provided a simple and reliable solution for conducting calcite scale inhibition tests in an efficient and low-cost way. Furthermore, the newly developed prediction models can be used as guidance for laboratory tests and field applications, potentially saving enormous amounts of time and money.
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.55)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Santos Basin > Merluza Field > Juréia Formation (0.99)
- North America > United States > California > San Joaquin Basin > South Belridge Field > Tulare Formation (0.99)
- North America > United States > California > San Joaquin Basin > South Belridge Field > Diatomite Formation (0.99)
A Semiempirical Model for Predicting Celestite Scale Formation and Inhibition in Oilfield Operating Conditions
Zhao, Yue (Rice University) | Dai, Zhaoyi Joey (Rice University) | Dai, Chong (Rice University) | Paudyal, Samridhdi (Rice University) | Wang, Xin (Rice University) | Ko, Saebom (Rice University) | Yao, Xuanzhu (Rice University) | Leschied, Cianna (Rice University) | Kan, Amy (Rice University) | Tomson, Mason (Rice University)
Abstract Mineral scale formation has always been a serious problem during production. Most scales can be treated by adding threshold scale inhibitors. Several crystallization and inhibition models have previously been reported to predict the minimum inhibitor concentration (MIC) needed to control the barite and calcite scale. Recently, more attentions have been paid to the formation of celestite scale in the oilfield. However, no related models have been developed to help determine the MIC needed for the celestite scale control. Therefore, in this study, the crystallization and inhibition kinetics data of celestite under a wide range of celestite saturation index (SI = 0.7 – 2.6), temperature (T = 25 – 90 °C), ionic strength (IS = 1.075 – 3.075 M) and pH (4 – 6.7) with one phosphonate inhibitor (diethylenetriamine penta(methylene phosphonic acid, DTPMP) and two polymeric inhibitors (phophinopolycarboxylate, PPCA and polyvinyl sulfonate, PVS) were measured by laser apparatus or collected from previous studies. Then, based on the results, the celestite crystallization and inhibition models were established accordingly. Good agreements between the experimental results and calculated results from the models can be found. By using these newly developed models, the MIC needed for three commonly seen inhibitors, DTPMP, PPCA and PVS on celestite scale control can be predicted under extensive production conditions. The developed models can fill in the blank in scaling management strategies for high Sr2+ and SO42- concentrations in the produced waters.
- Asia > Middle East (0.93)
- North America > United States (0.68)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.36)
Novel Mineral Scale Deposition Model Under Different Flow Conditions with or Without Scale Inhibitors
Dai, Zhaoyi Joey (Rice University) | Kan, Amy (Rice University) | Lu, Yi-Tsung Alex (Rice University) | Leschied, Cianna (Rice University) | Zhao, Yue (Rice University) | Dai, Chong (Rice University) | Wang, Xin (Rice University) | Paudyal, Samridhdi (Rice University) | Ko, Saebom (Rice University) | Tomson, Mason (Rice University)
Abstract Mineral scale formation causes billions of dollars’ loss every year due to production losses and facility damages in the oil and gas industry. Accurate predictions of when, where, how much, and how fast scale will deposit in the production system and how much scale inhibitor is needed are critical for scale management. Unfortunately, there is not a sophisticated scale deposition model available, potentially due to the challenges below. First, an accurate thermodynamic model is not widely available to predict scale potential at extensive ranges of temperature, pressure, and brine compositions occurring in the oilfield. Second, due to the complex oilfield operation conditions with large variations of water, oil and gas flow rates, tubing size, surface roughness, etc., wide ranges of flow patterns and regimes can occur in the field and need to be covered in the deposition model. Third, how scale inhibitors impact the mineral deposition process is not fully understood. The objective of this study is to overcome these challenges and develop a model to predict mineral deposition at different flow conditions with or without scale inhibitors. Specifically, after decades of efforts, our group has developed one of the most accurate and widely used thermodynamic model, which was adopted in this new deposition model to predict scale potential up to 250 °C, 1,500 bars, and 6 mol/kg H2O ionic strength. In addition, the mass transfer coefficients were simulated from laminar (Re < 2300) to turbulent (Re > 3,100) flow regimes, as well as the transitional flow regimes (2300 < Re < 3,100) which occur occasionally in the oilfield using sophisticated flow dynamics models. More importantly, the new deposition model also incorporates the impacts of scale inhibitors on scale deposition which was tested and quantified with Langmuir-type kink site adsorption isotherm. The minimum inhibitor dosage required can be predicted at required protection time or maximum deposition thickness rate. This model also includes the impacts of entry-region flow regime in laminar flow, surface roughness, and laminar sublayer stability under turbulent flow. The new mineral scale deposition model was validated by our laminar tubing flow deposition experiments for barite and calcite with or without scale inhibitors and laminar-to-turbulent flow experiments in literature. The good match between experimental result and model predictions show the validity of our new model. This new mineral scale deposition model is the first sophisticated model available in the oil and gas industry that can predict mineral scale deposition in the complex oilfield conditions with and without scale inhibitors. This new mineral scale deposition model will be a useful and practical tool for oilfield scale control.
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Energy > Oil & Gas > Upstream (1.00)