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Collaborating Authors
Results
Dissolver Treatments to Re-Instate Functionality of Subsurface Safety Valves in Water Injection Wells
Hatscher, S. T. (Wintershall Dea Norge AS) | Havrevoll, N. (Wintershall Dea Norge AS) | Herrmann, T. (Wintershall Dea Norge AS) | Gjersdal, S. (Wintershall Dea Norge AS) | Dzhuraev, D. (Wintershall Dea Norge AS) | Torsvik, M. (Wintershall Dea Norge AS)
Abstract The Downhole Safety Valve (DHSV) integrity tests of two water injection wells on the Nova subsea oil field on the Norwegian Continental Shelf failed after one month in operation. One of the two wells, W-1, also showed issues with the Injection Master Valve (IMV). The objective was to re-instate the functionality of all compromised valves as soon as possible. First, the root cause for the malfunction was to be identified. Several hypotheses were developed and assessed, including mechanical and chemical issues. Both injectors (W-1 and W-4) are completed in the oil leg of the reservoir and have been cleaned up to rig before an injection test was conducted. The wells were then suspended for several months prior to initial start-up and commencement of water injection. Although wax inhibition was used during the clean-up, wax deposition at DHSV depth could not be fully discarded. Monoethylene glycol (MEG) has been deployed for hydrate mitigation after the injection tests and during initial well start-up. Pressure data indicated that at least partially, a column inversion within the tubing, from water to hydrocarbons, occurred during the suspension period. This observation gave support to that wax or hydrate deposition might restrict the DHSVs' flappers' movement. Based on this hypothesis, an operation with an Inspection Maintenance and Repair (IMR) vessel was planned, organized and conducted within five weeks after the failed tests. The treatment concept included not only a wax dissolver, but also MEG and heated fluids to combine the benefits of temperature as well as chemical dissolution towards either potential type of deposit. Both wells were treated from the vessel as per plan. The operation successfully re-instated the functionality of all three compromised valves, allowing to safely commence water injection into the reservoir.
- North America > United States (0.47)
- Europe > Norway > North Sea (0.29)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.67)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 418 > Block 35/9 > Nova Field > Viking Formation > Heather Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 418 > Block 35/9 > Nova Field > Rannoch Formation > Heather Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 418 > Block 35/8 > Nova Field > Viking Formation > Heather Formation (0.99)
- (4 more...)
- Well Completion > Completion Selection and Design > Completion equipment (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (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 > Hydrates (0.86)
Detection of Iron Disulfide Materials in Geological Porous Media Using Spectral Induced Polarization Method
Badhafere, D. (Department of Petroleum Engineering, College of Petroleum Engineering & Geosciences, King Fahd University of Petroleum & Minerals) | Kirmizakis, P. (Department of Geosciences, College of Petroleum Engineering & Geosciences, King Fahd University of Petroleum & Minerals (Corresponding author)) | Oshaish, A. (Department of Petroleum Engineering, College of Petroleum Engineering & Geosciences, King Fahd University of Petroleum & Minerals) | El-Husseiny, A. (Department of Geosciences, College of Petroleum Engineering & Geosciences, King Fahd University of Petroleum & Minerals) | Mahmoud, M. (Department of Petroleum Engineering, College of Petroleum Engineering & Geosciences, King Fahd University of Petroleum & Minerals) | Ntarlagiannis, D. (Department of Earth and Environmental Sciences, Rutgers University) | Soupios, P. (Department of Geosciences, College of Petroleum Engineering & Geosciences, King Fahd University of Petroleum & Minerals)
Summary Iron sulfide (FeS) scale is a known problem that can significantly impact oil and gas (O&G) production. However, current monitoring methods cannot detect the problem at early stages, not until it is too late for any meaningful remedial action. Spectral induced polarization (SIP) is an established geophysical method increasingly used in near-surface environmental applications. The unique characteristics of the SIP method, mainly the sensitivity to both bulk and interfacial properties of the medium, allow for the potential use as a characterization and monitoring tool. SIP is particularly sensitive to metallic targets, such as FeS, with direct implications for the detection, characterization, and quantification of FeS scale. In a column setup, various concentrations of pyrite (FeS2), a common form of FeS scale, within calcite were tested to examine the SIP sensitivity and establish qualitative and quantitative relationships between SIP signals and FeS2 properties. The concentration of FeS2 in the samples directly impacts the SIP signals; the higher the concentration, the higher the magnitude of SIP parameters. Specifically, the SIP method detected the FeS2 presence as low as 0.25% in the bulk volume of the tested sample. This study supports the potential use of SIP as a detection method of FeS2 presence. Furthermore, it paves the way for upcoming studies utilizing SIP as a reliable and robust FeS scale characterization and monitoring method.
- Europe (0.68)
- North America > United States (0.46)
- Asia > Middle East > Saudi Arabia (0.28)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
Abstract There has been a global surge in scale challenges across the oilfield industry, surpassing other flow assurance challenges. In principle, scale refers to the deposition of mineral solids (primarily inorganic), such as calcium carbonate, calcium sulfate, or barium sulfate, that can accumulate and obstruct flow pathways in various industries, including oil and gas production, water treatment, and other industrial processes. Scale formation can lead to reduced production rates, increased energy consumption, equipment damage, and operational disturbances. Hence, the mitigation and prevention of scale deposition have become pivotal for maintaining high-performing production processes. In this regard, among the known scales, the calcium sulfate scale, in the form of gypsum (CaSO2.2H2O), is deemed challenging for many applications. This type of scale is usually caused by mixing incompatible waters. CaSO2.2H2O is an acid-insoluble scale; thus, it requires an effective scale dissolving recipe. Herein, we demonstrate the use of lactic acid (C3H6O3) as an emerging green chemical to remove gypsum deposits in the presence of different bases, including potassium and sodium carbonates and hydroxides. Different scale removal recipes were developed comprising mixtures of lactic acid with individual bases or a mixture of two bases. We show that, generally, hydroxide bases have exhibited lower performance, particularly potassium hydroxide, compared to their carbonate counterparts. Nonetheless, potassium carbonate, in particular, has offered a better performance compared to sodium carbonate. Incorporating lactic acid with the experimented bases has further improved the performance of the developed recipes, thanks to the induced synergistic effect, specifically with potassium carbonate. The latter has also demonstrated the ability to polymerize lactic acid when coupled with another base, such as sodium hydroxide or potassium hydroxide. Noteworthy, using sodium carbonate has resulted in much lower performances when coupled with the other hydroxide bases. Therefore, mixing two bases when dissolving calcium sulfate is not always the optimum choice as it brings other negative consequences.
- North America > United States (0.46)
- Asia > Middle East > Saudi Arabia (0.46)
- Europe > United Kingdom (0.29)
- Europe > Netherlands (0.28)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Health, Safety, Environment & Sustainability > Environment (1.00)
Binary Mixture Thermo-Chemical (BiMTheCh) Technology for Development of Low-Permeable Formations of Oil Fields in Caspian Sea
Koochi, M. Rezaei (Petroleum engineering department, Kazan Federal University, Russia) | Rojas, A. (Petroleum engineering department, Kazan Federal University, Russia) | Varfolomeev, M. A. (Petroleum engineering department, Kazan Federal University, Russia) | Khormali, A. (Chemistry department, Gonbad Kavoos University, Iran) | Lishcuk, A. N. (HMS Group Company, Moscow, Russia)
Abstract Binary mixture thermo-chemical (BiMTheCh) technology refers to energy-releasing chemicals which can be injected into the reservoir with in-situ generation of heat, nitrogen and carbon dioxide. As laboratory investigations show, BiMTheCh or thermochemical fluid has proved to be a highly effective technology for stimulation of oil wells with heavy oil and low permeability. In this work, the feasibility of this technology for stimulation of brown fields from laboratory to field scale is investigated. First, on the laboratory scale, thermobaric parameters of the reaction were studied to optimize the composition of injecting chemicals. And finally, the optimized composition is applied to enhance oil recovery from low permeable reservoirs in Russia. Laboratory results show that BiMTheCh can be used for removing asphaltene and resin from near borehole zone by melting them. Generated gases after the reaction create a network of fractures in the vicinity of the reaction zone and simultaneously, by inducing a thermobaric shock, cracks oil molecules and upgrades oil directly into the reservoir. Oil field data in 5 wells shows that oil production increased 2-3 folds with a duration of 12 months or more. BiMTheCh can be used for stimulation of green and brown fields with a high efficiency in a safe rig-less mode.
- North America > United States > Texas (1.00)
- Europe (1.00)
- Asia (1.00)
Scrutinization and Evaluation of Heavy Sludge Formation and In-Situ Tar Mat Problems Based on Robust Integrated PVT and Open-Hole Logging Approach- A Case Study of an Oil Field in Pakistan
Siyal, Amaar (Mari Petroleum Company Limited, Islamabad, Pakistan) | Solangi, Aftab Ahmed (Mari Petroleum Company Limited, Islamabad, Pakistan) | Virk, Muneeb Ali (Mari Petroleum Company Limited, Islamabad, Pakistan) | Hameed, Ali (Mari Petroleum Company Limited, Islamabad, Pakistan) | Abid, Hassan (Mari Petroleum Company Limited, Islamabad, Pakistan) | Hassan, Syed Saadat (Mari Petroleum Company Limited, Islamabad, Pakistan) | Ameen, Nadir (Mari Petroleum Company Limited, Islamabad, Pakistan)
Abstract Heavy oil is commonly produced in the form of water-in-oil emulsions. It has long been debated whether the emulsions are formed in the reservoir or inside the wellbore, and if so, what effect do they have on the recovery process. Meanwhile, sludge formation can significantly impair a well's productivity if deposited in the wellbore or at surface flow lines. In a field where sludge formation was not expected, the oil producing well showed a sudden deterioration in well productivity. Extensive lab analysis indicated that sludge deposition was promoted by the presence of asphaltenes, resins, high amounts of calcium and sodium contents, and low PH brine. The scope of this work was to investigate the root cause of strong oil-water emulsion and sludge issues of AB oil field in Pakistan based on a robust integrated approach. Secondly, to investigate whether the sludge formation is occurring within the reservoir or not. For this purpose, an integrated robust workflow that was followed for the investigation of sludge/tar mat deposits in the wellbore and reservoir started with an investigation of PVT data of the oil field. PVT tests were conducted such as Saturates, Aromatics, Resins, and Asphaltenes (SARA) on samples acquired during the DST and after the sludge problem occurred. This was done to determine the content of asphaltenes and resins and their indirect affect on heavy sludge formation. This was done to identify the effect of asphaltenes and resins on the heavy sludge emulsion formation. In addition, the De-Boer approach was also used for the potential asphaltenes precipitation in the reservoir. Moreover, the Total Acid Number (TAN) and Water Analysis were also conducted for the possible identification of the effects of Naphthenates deposit and salts on sludge. Furthermore, the effects of different reservoir parameters i.e., Reservoir temperature, pressure, bubble point pressure, Gas-Oil Ratio (GOR), sulfur and wax content, oil API, and naphthenates-deposits were also highlighted. Finally, an open-hole logging interpretation along with PVT and wellbore modelling was done to highlight the possible compositional gradient, wax appearance temperature, and asphaltenes appearances within the reservoir. The results showed that no compositional gradient or tar mat exist within the reservoir based on the micro-resistivity and mud-logging data as the separation between the deep later log and shallow resistivity was not broader. Meanwhile, no NMR log was available to confirm the presence of tar mat deposit within the formation and we can not rely solely on resistivity log. In addition, no thermal degradation and biodegradation of oil occurred in the reservoir as the temperature of the formation was below the threshold of 338 °F and higher than 122 °F, respectively. The sulfur and wax content along with depth were also far lesser from the threshold range of biodegradation which was confirmed through gas chromatography results. Moreover, the SARA analysis indicates a higher amount of resin content in comparison to asphaltenes which makes the oil more unstable and more prone to form stronger emulsion. Furthermore, the De-Boer method and PVT model indicate the reservoir pressure is above the asphaltenes precipitation window. While, the water and TAN analysis indicates that the ions concentration especially calcium and sodium were relatively higher while the TAN value was lower than 0.25 which was below the range of acidic crude which possibly indicates the formation of calcium Naphthenates that have caused the formation of strong sludge. Finally, PVT modelling and wellbore hydraulics indicated no compositional gradient existence within reservoir along with high salt drop out issue. No asphaltenes dropout was observed at the wellbore level. The outcome of this research study will provide a way forward to identify and mitigate the strong emulsion root cause problem, which had caused significant decreases in the deliverability of the oil well. In addition, it also aims for providing a method for the screening of chemical de-emulsifiers, which will result in restoring and maintaining the well potential.
- Asia > Pakistan (0.71)
- Europe > Norway > Norwegian Sea (0.24)
- Geology > Geological Subdiscipline (0.49)
- Geology > Mineral (0.46)
- Asia > Middle East > Iraq > Basra Governorate > Arabian Basin > Widyan Basin > Mesopotamian Basin > Rumaila Field > Zubair Formation (0.99)
- Asia > Middle East > Iraq > Basra Governorate > Arabian Basin > Widyan Basin > Mesopotamian Basin > Rumaila Field > Shuaiba Formation (0.99)
- Asia > Middle East > Iraq > Basra Governorate > Arabian Basin > Widyan Basin > Mesopotamian Basin > Rumaila Field > Nahr Umr Formation (0.99)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (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)
Evaluating the Potential of Biodegradable Carbohydrates and the Aqueous Extract of Potato Pulp to Inhibit Calcium Carbonate Scale in Petroleum Production
Ortiz, Ronald W. P. (NQTR, Instituto de Química, Universidade Federal do Rio de Janeiro (UFRJ)) | Oliveira, Jessica (NQTR, Instituto de Química, Universidade Federal do Rio de Janeiro (UFRJ)) | Vaz, Guilherme V. (NQTR, Instituto de Química, Universidade Federal do Rio de Janeiro (UFRJ)) | Passos, Nayanna Souza (NQTR, Instituto de Química, Universidade Federal do Rio de Janeiro (UFRJ)) | Bispo, Felipe J. S. (NQTR, Instituto de Química, Universidade Federal do Rio de Janeiro (UFRJ)) | Gonçalves, Vinicius Ottonio O. (NQTR, Instituto de Química, Universidade Federal do Rio de Janeiro (UFRJ)) | Cajaiba, Joao (NQTR, Instituto de Química, Universidade Federal do Rio de Janeiro (UFRJ)) | Ortiz-Bravo, Carlos A. (Departamento de Físico-química, Instituto de Química, Universidade Federal Fluminense (UFF)) | Kartnaller, Vinicius (NQTR, Instituto de Química, Universidade Federal do Rio de Janeiro (UFRJ) (Corresponding author))
Summary Scale is a significant operational concern in petroleum production that is commonly addressed by using chemical inhibitors. However, commercial inhibitors can potentially be pollutants depending on their composition and method of disposal. Consequently, evaluating the potential of biodegradable molecules to inhibit scale has gained attention. This study evaluates the effect of a series of carbohydrates (i.e., glucose, fructose, sucrose, maltose, maltodextrin, and soluble starch) and the aqueous extract of potato pulp on calcium carbonate precipitation and scale formation. Precipitation tests were conducted by combining aqueous solutions of sodium bicarbonate (3000 mg L) and calcium chloride (4000 mg L) in the presence of each carbohydrate, the aqueous extract of potato pulp, or a commercial inhibitor (1000 mg L). The precipitation was monitored through RGB (red, green, and blue) image analysis and pH measurements. The induction time in the presence of glucose, fructose, maltose, and sucrose is two to three times longer than in the blank test (in the absence of an inhibitor). This effect is slightly more pronounced in the presence of maltodextrin and soluble starch (approximately four times longer). However, the drop in pH and the mass of solids recovered is similar for all the carbohydrates tested (~0.5 mg and 120 mg, respectively), suggesting that carbohydrates slightly influence the precipitation kinetics but do not affect the precipitation equilibrium. Scanning electron microscopy (SEM) and X-ray powder diffraction (XRD) analysis reveals that calcium carbonate precipitates as calcite and vaterite in the blank test. In the presence of glucose, fructose, maltose, and maltodextrin, calcium carbonate exclusively precipitates as calcite. However, in the presence of sucrose and soluble starch, calcium carbonate precipitates as both calcite and vaterite. Interestingly, a more prominent amount of vaterite was observed in the presence of soluble starch. All carbohydrates decrease the crystallite size of calcite, while sucrose and soluble starch increase the crystallite size of vaterite. The crystalline phases were also identified by Raman spectroscopy, ruling out the presence of any amorphous calcium carbonate phase. The inhibitory effect of soluble starch and the aqueous extract of potato pulp on calcium carbonate scale formation was evaluated in a dynamic scale loop (DSL) system. Soluble starch slightly delays scale formation even at high concentrations (1000 mg L). Conversely, the aqueous extract of potato pulp demonstrates enhanced performance by delaying scale formation by approximately 20 minutes for a 1-psi increase in the pressure of the tube and by more than 40 minutes for a 4-psi increase. As a result, it exhibited an impact on the kinetics of solid deposition. This agrees with the precipitation test in the presence of the potato extract (PE), which increases the induction time (from 2 minutes to 32 minutes), decreases the mass of solids (from 116 mg to 35 mg), and forms more distorted and smaller particles of calcite. These findings suggest a promising approach for the development of green scale inhibitors utilizing aqueous extracts of starchy foods or even starchy foods waste water.
- North America > United States (0.93)
- Europe (0.93)
- South America > Brazil (0.69)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.50)
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 211187, “Tackling Mixed-Scales Issue in an Oil Field Using a Novel Robust Scale Dissolver,” by Nora Aida Ramly, Luky Hendraningrat, SPE, and Latief Riyanto, SPE, Petronas, et al. The paper has not been peer reviewed. _ The evaluation of a recently developed robust solid dissolver (RSD), from the laboratory phase through pilot deployment, is presented in the complete paper. Based on laboratory tests, the RSD can dissolve mixed scales completely in 24 hours at well temperatures while experiencing no incompatibility issues with production chemicals and all pumping and wireline components. The RSD was developed based on the total organic system that can prevent corrosion and is compatible with hydrocarbon. The RSD was piloted at oil Well 1 in Field PN and successfully removed mixed scales, allowing the well’s revival. Introduction Solid scale deposition is one of the most frequent flow-assurance issues both in subsurface and at the surface. The scale can be classified as organic (wax or asphaltenes), inorganic (calcites, sulphates, sulfides, halites, carbonates, and oxides), soap-related (naphthenates and carboxylates), gas-related (hydrates), or mixed scales. Scale occurrence, quantity, and severity mainly are determined by mineralogy, water chemistry, reservoir pressure and temperature, and the flow characteristics of the producing fluid in the well. Furthermore, scale formation is exacerbated by higher pH conditions and a higher water-cut environment, as would be expected in oil fields where water is to be injected for pressure maintenance. The most common type of scales found in Malaysian oil fields are organic and inorganic scales. The operator’s previously deployed scale-dissolving chemical in its fields only could cater to a single type of scale treatment at a time, which was ineffective for dissolving mixed scales simultaneously. Another method is the use of a mechanical solution using a coiled tubing unit (CTU). Removal mechanically by CTU in tubulars is a successful method in removing hard barite scales, but the cost is high and the method requires several days of production deferment. An improved and cheaper mixed-scale removal approach was needed to clean out mixed-scale issues in more-challenging brownfields. The RSD technology was developed for wellbore cleanout caused by mixed scale based on a stable microemulsion solution consisting of acid and solvent components. The solution was proposed to dissolve both organic and inorganic scales simultaneously in the near-wellbore area and tubing string of an oil well. The very small droplet size formed by the surfactant system and solvent is a significant advantage of using microemulsion and can allow penetration even in tight formations with small pore throats and promotes more-uniform surface coverage because of the increased interfacial area of the droplets. Previous studies have reported that the microemulsion can be pumped without causing a significant increase in pumping pressure.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.55)
- Well Completion > Completion Installation and Operations (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
This year has seen a focus on gas development projects and the energy transition. Flow assurance plays an interesting role in this area. Even though the attention has been on the energy transition, where gas development is concerned, the production processes through which gas is produced cannot be ignored. Thus, flow-assurance issues remain prevalent today, and an analysis of existing solutions, key to the success of oil and gas producing facilities, needs to be addressed. Tackling mixed-scale issues in the oil field using a novel robust scale dissolver (RSD) was studied in paper SPE 211187. Scaling, an incompatible-fluids-related flow-assurance problem in oil and gas wells at various locations in the Malaysian basin, results in rapid oil production decline. RSD is said to be capable of dissolving up to 100% of mixed scales in 24 hours at well temperatures with no incompatibility with production chemicals, pumping, and wireline components. This was done under laboratory conditions. A field trial was completed, with outstanding results for the RSD as it proved capable of reviving the well by resolving mixed-scale issues. Paper SPE 211943 discusses a thermodynamic modeling approach for prediction and prevention of wax deposition. Wax deposition, an oilfield problem prevalent with aging wells, requires a degree of accuracy with prediction to have better control over prevention approaches. The paper discusses the thermodynamic modeling approach used to determine the wax appearance temperature in a well. This tool also confirmed the optimal depth at which to place a wax-inhibition tool based on the life-cycle expectations of the well. This improved well availability by 30%. Paper OTC 32170 addresses performance mapping of a multiphase-flow model. Exploration-data-analysis techniques were used that enabled a comprehensive analysis of several independent data sets from various origins. The analyses provided actionable and more-general insights that would have been otherwise obscured were individual data sets to be analyzed independently. These papers addressed prevailing issues critical for success and production optimization. Addressing the dissolution of mixed scale is a pressing need in modern operations without necessarily finding the scales in isolated conditions. Wax remediation relies highly on accurate temperature data for maximum efficiency and cost savings. I highly recommend reading the second highlighted paper to understand how the well availability of 30% was achieved. Data analytics in oil and gas enables actionable insights easily identified by the last reviewed paper. I trust, with these updates in flow assurance in recent times, we are well placed and assured of production-facility support for the coming years, contributing positively to the goals of the energy transition through fuels such as gas. Recommended additional reading at OnePetro: www.onepetro.org. SPE 213817 Multifunctional Flow Assurance Inhibitors: Three Birds With One Stone? by Malcolm A. Kelland, University of Stavanger, et al. SPE 215003 Significant Reduction of the Viscosity of Waxy Oils by Electrical Treatment by Hao Wang, The University of Texas at Austin, et al.
- North America > United States > Texas > Travis County > Austin (0.25)
- Europe > Norway > Rogaland > Stavanger (0.25)
- 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 (1.00)
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)
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)