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Collaborating Authors
wax inhibition
Abstract A study entitled "Long Subsea Tie-back Solutions for Pre-salt fields" was launched to compare different architectures concerning the hydrate and wax risks. In general, it aims the development of technical solutions and technologies applied to long subsea tie-back on pre-salt fields as a technically feasible and profitable solution. A fictive pre-salt field of two production wells located at 2,500m water depth tied back to a FPSO with a production flowline of around 30 km is considered. This study started with a screening study to assess the technical feasibility of different "single line" concepts. A cost estimate study has been done in parallel to support the most cost-effective solution. Five architectures have been investigated: Two architectures without subsea processing: 1 trunkline; 2 single lines. Two architectures with Subsea Separation Unit (SSU): SSU close to wells. SSU at riser base. One architecture with Multi Phase Pump (MPP) MPP close to wells. At the end of this phase, only three architectures Trunkline, Riser Base SSU and MPP architectures have been retained as the most attractive ones in terms of operability and costs (as indicated in the Fig 1). The concept Subsea Separation Unit (SSU) located close to wells even if inducing low costs was not kept as difficult to operate within the production field life. The two single lines concept was not competitive compared to the trunkline one. Moreover, in terms of costs, a strong incentive has been demonstrated for "lighter" architecture concepts (i.e. a flowline thermal insulation of a wet insulated flowline compared to a Pipe in Pipe (PIP) flowline and without flowline heating system such as electrical trace heating with pipe in pipe insulation (ETH-PIP) technology).
- North America > United States > Louisiana (0.66)
- South America > Brazil (0.47)
- Europe > France (0.29)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Piping design and simulation (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (0.99)
Dynamic Wettability Alteration at Pore-Scale Using Viscoelastic Surfactant/Chelating Agents Systems
Ahmed, M. Elmuzafar (Petroleum Engineering Department, College of Petroleum Engineering & Geosciences, King Fahd University of Petroleum & Minerals, Dhahran, Saudi Arabia) | Sultan, Abdullah S. (Petroleum Engineering Department, College of Petroleum Engineering & Geosciences, King Fahd University of Petroleum & Minerals, Dhahran, Saudi Arabia)
Abstract The role of wettability is crucial in the extraction of hydrocarbons as it determines how well the oil adheres to the rock surface, directly impacting the efficiency of the extraction process. Numerous studies have been conducted to modify the wettability of rocks to a favorable state. In this study, we delve into the microscopic level to observe the actual process of altering the contact angle during flooding using microfluidic technology within a glass micromodel. Initially, the micromodel is saturated with formation water and subsequently displaced by oil to establish the initial oil saturation. The microfluidic setup consists of a precise pump for flood control and a high-speed microscope to capture images for later analysis using image processing software to obtain the actual contact angle. The contact angle is measured at five arbitrary locations, and the average is calculated at specific time intervals based on image analysis. Three different fluid systems were utilized: pure Viscoelastic Surfactant (VES), VES with DTPA, and VES with GLDA. The concentration of these systems was selected based on optimal rheology and interfacial tension performance. The contact angle was measured at various injection stages to observe its dynamic change from the initial state to the final state and assess the resulting recovery from each fluid system. The pure VES system modified the wettability from slightly oil-wet to slightly water-wet and achieved a 48% recovery of the original oil in place (OOIP). On the other hand, the addition of DTPA altered the wettability from slightly oil-wet to extremely water-wet; however, this did not lead to higher recovery, and water breakthrough occurred, reducing the sweep efficiency with a 45% recovery. The GLDA VES system altered the wettability to moderately water-wet, which proved to be the most favorable wettability condition, resulting in a 56% ultimate recovery. This investigation successfully demonstrated the effectiveness of using VES-assisted chelating agents in altering rock wettability and increasing oil recovery at the pore scale.
- Africa (0.68)
- South America > Brazil (0.46)
- Asia > Middle East (0.28)
Possible Increase of Production Through Magnetic Field and Inhibitor Association - Evaluation of Reduction Minimal Inhibitory Concentration - MIC in a Brazilian Pre-Salt Well
Aldeia, W. (Chemical Process and Particule Technology Laboratory, Instituto de Pesquisas Tecnológicas do Estado de São Paulo S/A – IPT, São Paulo, SP - Brazil) | Del Bigio, J. C. (Chemical Process and Particule Technology Laboratory, Instituto de Pesquisas Tecnológicas do Estado de São Paulo S/A – IPT, São Paulo, SP - Brazil) | Lourenço, V. S. (Chemical Process and Particule Technology Laboratory, Instituto de Pesquisas Tecnológicas do Estado de São Paulo S/A – IPT, São Paulo, SP - Brazil) | Martins, A. L. (Petróleo Brasileiro S/A – PETROBRAS, Rio de Janeiro, RJ, Brazil) | Castro, B. B. (Petróleo Brasileiro S/A – PETROBRAS, Rio de Janeiro, RJ, Brazil) | Schluter, H. E. (Petróleo Brasileiro S/A – PETROBRAS, Rio de Janeiro, RJ, Brazil)
Abstract This article presents the results obtained in the evaluation of the joint action of the chemical inhibition (inhibitor) and the magnetic field, aiming to evaluate the possibility of reducing the minimal inhibitory concentration (MIC), seeking an increase in production in oil extraction wells, increasing the reliability of the guarantee of flow in deep water wells. The magnetic field has the potential to retard the scaling of inorganic salts in oil production/water treatment systems. An evaluation of the combination of magnetic field and inhibitor to retard carbonate scaling was carried out, based on the tube blocking test method (TBT). The evaluation was carried out in two brine solutions, with reduced concentrations from a brine solution representative of the Brazilian pre-salt. A reactor with an internal diameter of 0.045 cm and a total flow rate of 20 cm/min was used. (Re ≈ 900), reactor inlet pressure of 10 kgf/cm and outlet pressure of 1 kgf/cm. The temperature was 60 °C and the inhibitor used was hydroxymethyl amino-di(methylene phosphonic acid) type in different concentrations. The magnetic field used was 1.0 Tesla. The results indicate that the association of inhibitor and magnetic field under certain conditions can lead to significant delays in calcium carbonate fouling, proving to be an interesting strategy for mitigating calcium carbonate fouling.
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.54)
Development and Evaluation of Asphaltene Inhibitors for Offshore Brazilian Crudes
Ewbank, Conrado Gerard (Indorama Ventures) | Clements, John (Indorama Ventures) | Deluge, Max (Indorama Ventures) | Rabelo, Rodrigo Balloni (Indorama Ventures) | Dezotti, Rafael Sobral (Indorama Ventures) | Dallaqua, Roger Pezzuol (Indorama Ventures)
Abstract Asphaltene deposition has been an extremely critical flow assurance challenge in the Oilfield industry and the chemical treatment with continuous asphaltene inhibitors injection has been one of the best solutions for operators to face this challenge preventively, especially in the offshore market where it has the presence of extreme application conditions. This study focuses on optimizing the selection of the best chemicals and dosages of asphaltene inhibitors in Brazilian offshore crudes quickly and effectively. Combinations of different techniques and surfactants (non-ionic and polymeric surfactants) were evaluated in this study. To determine the best solution to be used for these systems, studies were carried out through the colloidal characterization both of asphaltenes in petroleum and of the effect of additives on the asphaltene deposition mechanism using LUMiSizer (Dispersion Analyzer), an equipment that enables extremely effective techniques, with high sensitivity and fast response time, applied for different Brazillian Offshore crude oils To determine the kinetics of destabilization and a tendency of asphaltene aggregate formation, data were acquired from LUMISizer, confirming the minimization of aggregate growth in more stable systems. Results also indicate the existence of a minimum effective concentration, suggesting a minimum dosage that promotes coating in the flakes formed, so that the steric barrier is effective in the curvature of the growth and deposition of asphaltenes. The LUMiSizer was used to rank the efficiency of different inhibitors and dispersants for a specific oil. Such results are even more informative than just saying whether an inhibitor is suitable or not.
- South America > Brazil (0.46)
- North America > United States (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.72)
Hyamine Method Applied to Brazilian Campos Basin
Rizzo, P. (SENAI Innovation Institute of Green Chemistry, Rio de Janeiro, Rio de Janeiro, Brazil) | Santos, I. (SENAI Innovation Institute of Green Chemistry, Rio de Janeiro, Rio de Janeiro, Brazil) | Brant, V. (SENAI Innovation Institute of Green Chemistry, Rio de Janeiro, Rio de Janeiro, Brazil) | de Barros, L. (SENAI Innovation Institute of Green Chemistry, Rio de Janeiro, Rio de Janeiro, Brazil) | Fidalgo Neto, A. (SENAI Innovation Institute of Green Chemistry, Rio de Janeiro, Rio de Janeiro, Brazil) | da Silva, M. (Petrobras, Rio de Janeiro, Rio de Janeiro, Brazil) | Fontes, R. (Petrobras, Rio de Janeiro, Rio de Janeiro, Brazil) | Sacorague, L. (Petrobras, Rio de Janeiro, Rio de Janeiro, Brazil) | Carvalho, R. (Petrobras, Rio de Janeiro, Rio de Janeiro, Brazil) | Freitas, T. C. (Petrobras, Rio de Janeiro, Rio de Janeiro, Brazil) | Silva, J. (Petrobras, Rio de Janeiro, Rio de Janeiro, Brazil) | Silva, G. M. (Petrobras, Rio de Janeiro, Rio de Janeiro, Brazil)
Abstract The residual level analysis related to scale inhibitors in produced water using offshore methodology is the key challenge in inorganic scale management, therefore proposal of simple and fast analytical techniques is mandatory. The objective of this work is to quantify residual polymeric scale inhibitors in produced water from a Brazilian post-salt well A using the solid-phase extraction (SPE) followed by reaction with a precipitating agent and subsequent turbidimetric evaluation. Major obstacle in this development topic regarding residual scale inhibitor detection methodologies relay on the matrix interference due to contaminants and the usual high salinity in samples. In fact, SPE allowed the removal of these interferents and, also, made feasible the analyte pre-concentration. The reagent Hyamine 1622 was employed due to its ability to effectively precipitate anionic surfactants, generating detectable turbidity. For this, the methodology was optimized considering sample percolation and desorption volumes, pH, time and temperature related to the complexation between the inhibitor and Hyamine 1622, being then successful in quantifying the polymeric scale inhibitor (usually employed in squeeze treatment) in residual levels with adequate linearity. In addition, it was found that the possible presence of iron (due to corrosive processes) does not compromise the analy sis, which is highly desirable. Further evaluation was also carried out with synthetic brine samples (representative of the field conditions), showing similar behavior that is found for produced water, indicating that the procedure is efficient in removing interferents. Each brazilian scenario offers physicochemical particularities due to the inherent well characteristics, which are based both on the matrix and the active polymeric compounds from the squeeze treatment. Therefore, each development and optimization method will depend on these variables, but the present initiative demonstrates not only the viability of the analytical and operational approach, but also the potential to standardize analyzes in an offshore environment.
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract The interventions on wells such as cleaning and reperforations improve production but not for a long period of time. CaCO3 scale could be the reason for the decline of production; it is therefore crucial to understand the production issues with the objective to design better future wells. The aims of this study are the evaluation of the scaling risk and determination of any link between decline of production, before well intervention, with the scale deposit. A multidisciplinary approach where analyses from several disciplines such as reservoir engineering, petrophysics and well performance are used for a better scaling risk management in the wells. This study concerns an Ultra HPHT deep gas condensate Southeast Asian field. No formation water is available; therefore, an analog water has been used for the evaluation of the scaling risk; this water is characterized by a low level of barium; therefore, barium sulphate scaling risk is not expected. The scaling risk has been modelled for the bottomhole and wellhead for individual wells. The results have been analyzed together with the evolution of the production data associated with well interventions. The scaling risk assessment has shown a moderate to a high risk of CaCO3 at bottomhole. The decline of production could be explained by the deposition of CaCO3 at bottomhole, blocking the perforations, this is due to a high drawdown. To reduce the CaCO3 scaling risk at bottomhole, it is recommended to reduce the current drawdown and maintain the bottomhole flowing pressure above the recommended value, depending to individual wells. Some evaporation of the formation water is also possible due to the very high temperature of this Ultra HPHT reservoir. In addition to the reduction of the current drawdown, it is recommended to perform a curative treatment with a help of bull-heading acid wash treatment as soon as a reduction of production is observed. This treatment will help to dissolve the CaCO3 scale at bottomhole, at the perforations and tubing. The scaling risk evaluation shows that as soon as water is produced there is a risk of formation of CaCO3 scale. This risk occurs even with very low production water flowrate. A complementary study including the analysis of the mineralogy and petrophysics of the reservoir, production data, water composition and prediction of the scaling risk has helped to identify the causes of the production decline and propose an adapted scaling risk mitigation for individual wells.
- South America > Brazil (0.47)
- Europe > United Kingdom (0.29)
Systematic Modelling and Laboratory Testing to Allow the Potential for Economic Inorganic Scale Control in the Brazilian Pre-Salt Fields
Littlehales, Ian (Scaled Solutions USA) | Simões Neto, Saul (Petrobras) | Dias Neto, Jose Mateus (Petrobras) | Lee, Ji-young (Shell International Exploration and Production Inc.) | Ko, Saebom (Brown & Root Industrial Services) | Mendes, Marcello (Shell Brasil Petroleo Ltda.) | Graham, Gordon (Scaled Solutions Ltd) | Dyer, Sarah (Scaled Solutions Ltd) | Peat, Stephnie (Scaled Solutions USA)
Abstract Pre-salt oil fields such as those produced in the Offshore market in Brazil, offer a unique set of challenges related to the control of inorganic scale deposits. Scale deposition has the potential to negatively impact production rates and profitability of the operations. Often laboratory testing studies examine the performance of scale inhibitors using so called industry standard techniques like the Dynamic Scale Loop (DSL) but can sometimes be conducted under unrealistic scaling conditions considered by the operators or laboratory scientist to be "worst case". This however can severely limit the number of products that can be successfully qualified for application in the field and lead to recommendations of very high dose rates, which may not be achievable as water cuts increase. To successfully test chemicals in the laboratory prior to field application, the conditions of the tests must closely represent the field. This includes the brine chemistry of the well, the CO2 concentration and pH of the fluids. This paper will detail the results of a new modelling and laboratory study which shows an extremely severe scaling regime that could be expected under the pre-assigned worst case field conditions leading to the failure of chemicals to economically prevent scale. However, when all parameters are considered, laboratory conditions were optimized to represent field conditions more closely, resulting in a more representative (milder) in-situ scaling regime such that chemical performance was significantly improved. Ultimately when the laboratory conditions were tuned to the newly modelled in-situ field conditions, there was a significant reduction in the minimum effective dose (MED) determined in the lab for all conditions, offering the potential for effective treatments to be achieved even at increased water cuts. This work shows that only focusing on one system parameter like maximum field pH results in an overly severe testing regime, limiting the number of products available to the Operating Company. The "worst case" approach also results in the dose rates of those chemicals which are selected being unrealistically high for field application at high water cuts. When more representative in-situ conditions are modelled and then utilised in the laboratory, a wide range of scale inhibitor chemistries would potentially be available for field applications allowing the operator to realize significant OPEX savings. The paper also highlights how careful modelling and optimisation of test conditions is a critical aspect associated with scale inhibitor qualification and highlights the best practice approach to selecting and optimising test conditions in the laboratory to ensure they remain representative of the field conditions.
- South America > Brazil (1.00)
- North America > United States > Louisiana (0.70)
- North America > United States > Texas (0.46)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Calcium Carbonate Formation within the Oil and Gas Workflow: A Combined Thermodynamic, Kinetic and CFD Modeling Approach
Poletto, V. G. (Research Center for Rheology and Non-Newtonian Fluids, CERNN, Federal University of Technology - Parana, UTFPR, Curitiba, Parana, Brazil) | Neubauer, T. M. (Research Center for Rheology and Non-Newtonian Fluids, CERNN, Federal University of Technology - Parana, UTFPR, Curitiba, Parana, Brazil) | Mazuroski, M. E. (Research Center for Rheology and Non-Newtonian Fluids, CERNN, Federal University of Technology - Parana, UTFPR, Curitiba, Parana, Brazil) | De Lai, F. C. (Research Center for Rheology and Non-Newtonian Fluids, CERNN, Federal University of Technology - Parana, UTFPR, Curitiba, Parana, Brazil) | Junqueira, S. L. M. (Research Center for Rheology and Non-Newtonian Fluids, CERNN, Federal University of Technology - Parana, UTFPR, Curitiba, Parana, Brazil) | Pinheiro, H. E. S. (Leopoldo Americo Miguez de Mello Research Center, CENPES, Petrobras, Rio de Janeiro, Rio de Janeiro, Brazil) | Castro, B. B. (Leopoldo Americo Miguez de Mello Research Center, CENPES, Petrobras, Rio de Janeiro, Rio de Janeiro, Brazil) | Martins, A. L. (Leopoldo Americo Miguez de Mello Research Center, CENPES, Petrobras, Rio de Janeiro, Rio de Janeiro, Brazil)
Abstract The formation and deposition of inorganic salts on industrial equipment surfaces pose significant financial and technological challenges for various industries, particularly the oil industry, due to the transportation of multiphase fluids such as water, oil, and gas under high temperature, pressure, and salinity. (Crabtree, M., Eslinger, D., Fletcher, P., Miller, M., Johnson, A., King, 1999; Kamal et al., 2018a). These conditions can bring significant challenges in scale control, especially for calcium carbonate scaling, which is a scale type that can be vulnerable to pressure and temperature variations (Blue et al., 2017; Cosmo, 2013a; Du & Amstad, 2019). To ensure optimal scale control and surveillance, smart completions have emerged as one of the most favorable approaches in the oil and gas industry. These completions offer real-time and selective zone control in oil and gas wells, minimizing unwanted water production and maximizing oil and gas production. They allow operators to isolate or produce specific zones, controlling or preventing mixing of incompatible water chemistries. Additionally, smart completions provide water shutoff capabilities, allowing operators to remotely control valves and downhole tools to shut off water-producing zones. This feature significantly reduces the undesirable production of water, commonly encountered during oil or gas production in mature reservoirs (Bouamra et al., 2020; H. F. L. L. Santos et al., 2017). However, the design, size, and geometry of the smart completion tool can impact the prevention of scaling deposition. As a result, there is a need to investigate operating conditions and equipment design that can promote the formation and deposition of precipitates within the oil production process (Kamal et al., 2018a; Sanni et al., 2022). To address this issue, a novel mathematical methodology has been developed to predict precipitation rates along the oil and gas workflow within these smart completions. A complete simulation of the particles, characterizing the kinetic, thermodynamic, and fluid-dynamic aspects of the CaCO3 produced within the fluids produced in the oil and gas industry, could be used as a virtual sensor for potential analysis, control and monitoring of incrustation problems, offering a more complete tool than the pure thermodynamic simulations that are usually used as prediction tools by the oil and gas industry (Bouamra et al., 2020; Lassin et al., 2018; T. Neubauer et al., 2022; Sanni et al., 2015). The proposed methodology involves the use of calcium carbonate thermodynamics, kinetics, and flow dynamics along the production flow to assess the risk of CaCO3 precipitation. The simulation workflow combines a polymorphic population model to define the CaCO3 particle kinetics, a multiphase thermodynamic model to simulate supersaturation conditions, and computational fluid dynamics to produce the pressure and fluid flow profiles along the equipment. The combined simulation of the three models produces kinetic and thermodynamic precipitation rates that are used to obtain a CaCO3 risk index. This work describes the model calculations to assess calcium carbonate formation in an open-hole completion assembled with a perforated liner composed of multiple tiny, drilled holes along the production tubing.
Debottlenecking of a Deepwater Production Network by Converting an Uninsulated Service Line Into a Production Line: Engineering Analyses and Successful Application
Montini, Marco (Eni SpA) | Brioschi, Samuele (Eni SpA) | Bianco, Amalia (Eni SpA) | Di Lullo, Alberto (Eni SpA) | Torri, Lucia (Eni SpA) | Piseri, Chiara (Eni SpA) | Magi, Stefano (Eni SpA) | Locci, Andrea (Eni SpA) | Lamberti, Andrea (Eni SpA) | Castelnuovo, Luca (Eni SpA)
Abstract This paper presents the repurposing of a non-insulated, carbon steel service line into a production line for a deep-water oil field, successfully carried out without any plant shutdowns and continued for several months and under several operating conditions. The main differences between the repurposed service line and the subsea production lines of the field were the lack of insulation, to prevent hydrates during shutdowns and wax deposition during production, and the lack of internal cladding, to protect the line from generalized CO2 corrosion. Therefore, the conversion required deep multidisciplinary analyses, including flow assurance, production chemistry and materials technology, along with the definition of a proper continuous monitoring workflow. The analyses started from a reservoir study to quantify the potential production increase and recovery factor due to the availability of the repurposed line, from some wells to the FPSO. After a positive outcome, a detailed flow assurance study was performed to select the wells to be routed to the service line and to define its operating conditions. The laboratory identification of the most effective wax inhibitor and hydrates anti-agglomerant was conducted, together with a corrosion study to estimate the life span of the carbon steel line to be repurposed. The lack of subsea chemical injection umbilical lines was addressed by identifying a combo product with both hydrate and corrosion inhibitor functionalities. All the above studies were associated to the definition of a strict monitoring workflow of the line corrosion and performance, in terms of potential restriction due to deposits. The overall techno-economic analysis demonstrated the feasibility and benefits of the production mode achievable with the repurposed line, even at higher operating costs. Consequently, the conversion was successfully carried out and is now effectively in place since more than one year. The whole study also strongly benefitted by the critical re-evaluation of all the engineering and operating margins made possible by the data acquired and recorded by Eni’s digital oilfield e-DOF system.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.46)
- 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)
- (5 more...)
Abstract Hydrates, solid crystals looking like compact snow (gas system) or slurry (oil system), are formed of water and gas at high pressure and low temperature (Figure 1) [1]. These conditions are usually encountered during shutdowns and restart operations in deepwater environment. Considering the associated production shortfalls and the cost of offshore remediation means, line blockage due to hydrates formation must be avoided [2]. And as a consequence, one of the main constraints in the design and operation of deepwater subsea developments has often been the management of hydrates in the production flowlines.
- South America > Brazil (0.46)
- Africa > Angola (0.29)
- North America > United States > Texas (0.28)
- Europe > France (0.28)
- 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 > Offshore Facilities and Subsea Systems (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Hydrates (1.00)