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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 Exploitation of the Vaca Muerta formation in Argentina poses several challenges. During the production stage of the wells, paraffin precipitation in the tubing and flow assurance in the wells is vital. Initially, when natural flow begins, production temperatures are above the temperature corresponding to that of wax appearance; therefore, there is no formation of crystals inside the production tubing. As time goes by, wax precipitation begins to be noticed.The present work attempts to summarize the experiences acquired from production engineering concerning wax in wells that flow naturally, as well as in a more mature stage, of wells with Gas Lift assistance. Methods/Procedures/Process: In 2021, severe cases of deposition were observed within the gas-assisted well installation. This involved cleanup actions that took several days to complete and affected a variety of resources. As the cases began to multiply, it was decided to implement a comprehensive prevention/mitigation plan through the study of each of the components of the paraffin control triangle. This plan was framed within a project that covers chemical selection, well maintenance with wireline equipment, use of hot water, optimization of wireline equipment operation, and resource scheduling. Results/Observations/Conclusions: The generation of a statistical base from field data allowed us to detect the critical flow rate where, if this is not followed by the start of inhibitor injection or with a change in the dosage, it can obstruct the flow passage in the downhole installation. Additionally, with the information collected, it has been possible to determine the expected depths of deposition, as well as the detection of possible follow-up variables.
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Field > Vaca Muerta Shale Formation (0.99)
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)
Scaling Issue in the Platform Area of Tengiz Field and Preventing Solutions
Myrzabayeva, A. (TengizChevroil, Atyrau, Atyrau region, Kazakhstan) | Kydyrgazy, A. (TengizChevroil, Atyrau, Atyrau region, Kazakhstan) | Sadyrbakiyev, R. (TengizChevroil, Atyrau, Atyrau region, Kazakhstan) | Kalzhekov, N. (TengizChevroil, Atyrau, Atyrau region, Kazakhstan) | Gaziz, D. (TengizChevroil, Atyrau, Atyrau region, Kazakhstan) | Orazov, B. (TengizChevroil, Atyrau, Atyrau region, Kazakhstan) | Williams, D. (TengizChevroil, Atyrau, Atyrau region, Kazakhstan) | Lu, H. (TengizChevroil, Atyrau, Atyrau region, Kazakhstan) | Yan, C. (Chevron, Houston, Texas, USA)
Abstract Even though most wells in the Tengiz Field produce virtually water free oil (less than 1% water cut), inorganic scales have been observed in many wells. Acid stimulation treatment programs for existing wells with deteriorated productivity include implementation of scale inhibitors, however this reactive approach might not always be the best way to proceed. The scope of the paper is to identify the main parameters which increase the probability of scale formation before a well is put on production and proactively treat such wells with scale inhibitors. Previously Tengizchevroil (TCO) has conducted an extensive research project to reduce the need for frequent acid treatments while maintaining well deliverability at sustained rates. Compatibility and core flood tests have been performed to choose the best scale inhibitor, and an extensive surveillance program has been developed to track residual inhibitor concentration to timely plan subsequent stimulation treatments. This paper covers the next step of the study and includes analysis of the recent cases of scale formation including identification of similar properties between the cases to enable forecasting of the tendency of all new wells to encounter scale formation. The study consists of three main steps – analysis of formation water and solid samples, analysis of open hole log data and analysis of production history for Tengiz and Korolev wells. The formation of precipitates is dependent on ion concentration in the water. Analysis of the water composition for each region and formation has been performed to identify which set of parameters increases the tendency to form scale. Solubility of inorganic salts is highly dependent on pressure and temperature changes taking place in the wellbore; therefore, the scale prediction study also includes these factors with the correlation to well region and reservoir properties each well penetrates. Weighted ranks for every parameter have been developed to rank a well after the drilling stage and make a proactive decision on whether scale inhibitor injection should be included in the primary acid stimulation treatment program, or if it should be considered only for reactive acid treatments in case of loss in well productivity. This paper aims to share the best practices in scale inhibitor design, analysis of well parameters at the well completion stage and calculation of well tendency to scale formation. The decision tree for identification of well candidates for proactive scale treatments applicable for the Tengiz field presented in the paper can potentially be used in other carbonate fields.
- Geology > Mineral > Sulfate (0.69)
- Geology > Geological Subdiscipline (0.68)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Oceania > Australia > Victoria > Bass Strait > Gippsland Basin (0.99)
- Asia > Kazakhstan > Mangystau Oblast > Precaspian Basin > Tengiz Field > Tengiz Formation (0.99)
- Asia > Kazakhstan > Mangystau Oblast > Precaspian Basin > Tengiz Field > Korolev Formation (0.99)
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (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 211943, “Prediction and Prevention of Wax Deposition in MERO-006T: A Thermodynamic Modeling Approach,” by Obiora Nwosu, Olugbenga Daodu, SPE, and Basil Ogbunude, SPE, Shell, et al. The paper has not been peer reviewed. _ Well MERO-006T is an oil development well that came into production in March 1988 and has been plagued with incessant wax buildup. Research indicates that a wax-inhibition tool can be deployed in the well. The complete paper highlights the thermodynamic modeling approach adopted to determine the wax appearance temperature (WAT) in Well MERO-006T, the well-modeling approach to estimate the depth at which wax formation would occur, and the optimal depth for the wax-inhibition tool based on life-cycle-production expectations from the well. Introduction Problems associated with wax deposition can occur anywhere in the production system, from the reservoir to the terminal. Wax deposits result from the cooling effect of oil flowing from high-pressure reservoirs through the wellbore to the surface. Depressurization of the oil as it is produced leads to its expansion and temperature drop, which induces crystallization of wax. Considering the effects of wax deposition on producing wells and facilities, prevention of the phenomenon is preferable to correction. Challenges Well MERO-006T was drilled and completed as a single-string single in November 1981 on the Q2100X sand. The crude oil in the reservoir is waxy and has resulted in several wax-cutting jobs across the production life of the well. By February 1989, the production rate had declined to 198 BOPD on /64-in. bean. A dewaxing job was completed, and production rose steadily, peaking at 1012 BOPD at 195-psig tubinghead pressure and 0% basic sediment and water in May 1991, after which the well quit production because of wax by November of that year. Several unsuccessful attempts were made to produce the well until March 1994, when stimulation, wax cutting, and nitrogen-lifting intervention was performed. In April 1994, the interval produced dry at an average rate of 160 BOPD on /64-in. bean until January 1995, when it quit again. Wax cutting was performed in June 1997; the interval produced dry at an average rate of 300 BOPD on /64-in. bean. The well produced at approximately 300 BOPD until March 2003, when production rate dropped to 170 BOPD. Solvent soak and dewaxing was performed in Q4 2004, and the well was opened to flow; production fluctuated between 500 and 100 BOPD. The well was closed in for low productivity as the result of wax formation in October 2005. However, in 2017, the well’s B annulus pressure was found to be higher than maximum allowable annulus surface pressure at the wellhead. Post-risk assessment, the well was classified as high-risk. In 2018, a remediation using conformance control was performed, but this was unsuccessful. It was decided to carry out a workover to restore well integrity. The cumulative production from this interval has been recorded as 1.485 million STB.
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)
Novel Structural Aspects of Heavy-Crude-Derived Asphaltene Molecules for Investigating the Crude Mix Processability in Refinery Operation
Das, Raj K. (Corporate R&D Centre, Bharat Petroleum Corporation Ltd.) | Voolapalli, Ravi K. (Corporate R&D Centre, Bharat Petroleum Corporation Ltd.) | Upadhyayula, Sreedevi (Department of Chemical Engineering, Indian Institute of Technology-Delhi (Corresponding author)) | Kumar, Rajeev (Corporate R&D Centre, Bharat Petroleum Corporation Ltd. (Corresponding author))
Summary In this paper, we investigate the role of asphaltenes derived from heavy crudes, which dictates the behavior of crude mix properties for hassle-free downstream refinery operation. Combined characterization techniques such as proton nuclear magnetic resonance (H-NMR), cross-polarization magic-angle-spinning carbon-13 (CP/MAS C)-NMR, heteronuclear single-quantum coherence (HSQC), Fourier transform infrared (FTIR), thermogravimetric analysis (TGA), and X-ray diffraction (XRD) are used for the detailted study of Ratwai and Ras Gharib (RG)-derived asphaltenes to validate their structural role in selecting the optimal crude mix. As per our investigation, when the polyaromatic core of asphaltene structures are less substituted, the availability of aromatic hydrogen is more; it exhibits a stable crude mix as compared to heavy crudes that have more aromatic core substitution, despite the crudes possessing similar asphaltene content and physicochemical properties. This finding is further extended to West Canadian (WC) and Belayim (BL) heavy crudes for operational suitability. In this study, the key feature is to develop a CP/MAS C-NMR-based robust and quick characterization technique that could potentially become a prescreening method to assess crude oil compatibility and its various blend processability in the refinery system. Other characterization techniques, such as H-NMR, HSQC, FTIR, TGA, and XRD, would corroborate and confirm the reliability of the data obtained by CP/MAS C-NMR.
- North America > United States (0.95)
- Africa > Middle East > Algeria (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.75)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- Africa > Middle East > Algeria > Ouargla Province > Hassi Messaoud > Oued Mya Basin > Hassi Messaoud Field (0.99)
- Africa > Middle East > Algeria > Ouargla Province > Hassi Messaoud > Berkine Basin (Trias/Ghadames Basin) > Hassi Messaoud Field (0.99)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (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)