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Collaborating Authors
Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene
A Successful Acid Fracturing Treatment in Asphaltene Problematic Reservoir, Burgan Oilfield Kuwait
Al-Shammari, A. (Kuwait Oil Company, Kuwait) | Sinha, S. (Kuwait Oil Company, Kuwait) | Sheikh, B. (NAPESCO, Kuwait) | Youssef, A. (NAPESCO, Kuwait) | Jimenez, C. (Kuwait Oil Company, Kuwait) | Al-Mahmeed, F. (Kuwait Oil Company, Kuwait) | Al-Shamali, A. (Kuwait Oil Company, Kuwait)
Abstract The Burgan Marrat Reservoir is a challenging high-pressure, high-temperature carbonate oil reservoir dating back to the Jurassic age. This specific reservoir within the Burgan Field yields light oil, but it has a significant issue with Asphaltene deposition in the wellbore. Additionally, its well productivity is hampered by low matrix permeability. Addressing these challenges is crucial, and a successful acid fracturing process can not only enhance well productivity but also address Asphaltene-related problems. This study delves into a comprehensive methodology that was employed. The focus of well selection was on ensuring good well integrity and maintaining a considerable distance from the oil-water contact (OWC). The approach involved conducting a Multi-Rate test followed by pressure build-up to establish a baseline for understanding the reservoir's behavior, including darcy and non-darcy skin. The treatment design aimed at better fluid loss control and initiating highly conductive fractures in the reservoir. Specific measures, such as using suitable diverters and acid, were employed to maximize the length of the fractures. To validate the approach, a nodal analysis model was fine-tuned to predict how the well would perform under these conditions. The results post-stimulation were impressive. There was a substantial improvement in well production and flowing bottom hole pressure. In fact, the productivity index of the well increased significantly, representing a substantial enhancement in output. The pressure build-up test after the fracture demonstrated a linear flow within the fracture, indicating a successful treatment with a fracture half-length of approximately 110 feet and a negative skin, which signifies an improvement in flow efficiency. Furthermore, the treatment effectively mitigated the risk associated with Asphaltene deposition, a significant accomplishment given the historical challenges faced in this reservoir. This success can be attributed to an innovative workflow that incorporated a meticulous surveillance plan, a well-thought-out fracturing treatment design, and the application of advanced nodal analysis. Together, these components not only optimized the well's performance but also paved the way for the development of similar high-pressure, tight carbonate reservoirs. This approach not only enhances productivity but also ensures successful mitigation of Asphaltene-related issues, marking a significant advancement in reservoir engineering techniques.
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Wara Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Ratawi Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Mauddud Formation (0.99)
- (15 more...)
Riserless Intervention on Deepwater Gulf of Mexico Well increases contributing interval length by 10-fold
Hosein, W. (BP America, Houston, Texas, United States) | Vick, M. (BP America, Houston, Texas, United States) | Quy, T. (BP America, Houston, Texas, United States) | Dada, M. (BP America, Houston, Texas, United States) | Sierra, J. (BP America, Houston, Texas, United States) | Cubides, J. (BP America, Houston, Texas, United States)
Abstract Well X is an oil producer in the Mississippi Canyon of the Gulf of Mexico. The well was originally designed as a smart downhole flow control (DHFC) completion that allowed split flow between two cased-hole frac-pack (CHFP) sand control completions. Unfortunately, the DHFC system failed, and the well must be produced with commingled flow from both zones. Over time the well's skin (frictional pressure loss across the completion screens) has increased to a point where the well's production rate needed to be reduced to limit erosion and maintain integrity of the completion. Well X receives pressure support from a downdip injector which has led to seawater production and introduced the risk of barium-sulfate scale. The well's previous scale prevention treatment expired at the end of 2022. The scope of the Riserless Light Well Intervention (RLWI) was to remediate skin and refresh the scale prevention treatment in both zones. The intervention required right scoping the well control and ancillary equipment to enable successful pumping and wireline operations on a sub-ambient well under elevated subsea and surface metocean conditions. Additionally, surveillance was necessary to assess damage and allocate contributions from each zone. Individual isolation of both zones was required for acid stimulation and scale treatment. Achieving this involved either setting plugs or installing isolation sleeves across the failed flow control device. Based on production logs, it was observed that the contributing interval of the lower zone had been reduced to about 10 ft despite having 110 ft of perforations. To address this, an acid stimulation with use of diverter pills was carried out on the lower zone which resulted in an increase in the contributing height to the full 110 ft, marking a greater than 10-fold increase. Furthermore, successful scale prevention treatments were administered to both zones to prevent barium sulfate scale deposition. Throughout the intervention, all wireline operations were carried out effectively under sub-ambient conditions without any hydrate problems, loss of well control, or seawater ingress. Acid stimulation bullheaded from surface aided in successfully treating non-contributing intervals with the use of diverter pills. The use of the collapse rated hoses along with other well control package modifications have enabled access to other sub-ambient wellwork in this field.
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)
Summary The stability of asphaltenes in crude oil is influenced by various factors, including interactions with reservoir components such as brine and rock formations. While previous research has focused on pressure and temperature effects, a comprehensive understanding of the combined impact of brine and reservoir rock on asphaltene stability is lacking. This study investigates the individual and combined influences of brine and rock formations on asphaltene stability. First, 11 crude oil samples from diverse locations were characterized using API gravity, viscosity, and saturates, aromatics, resins, and asphaltenes (SARA) fraction analysis. The elemental composition of the crude oils, including carbon, hydrogen, nitrogen, and various metals, was determined. The surface properties of asphaltenes were analyzed using scanning electron microscopy coupled with energy-dispersive X-ray spectroscopy (SEM-EDS). The interaction between asphaltenes and deionized water was examined through zeta potential, particle size, conductivity, and pH measurements. The behavior of asphaltenes in an 8,000 ppm NaCl solution was also investigated. The SEM analysis revealed the presence of inorganic content on the surfaces of asphaltenes, indicating interactions between asphaltenes and reservoir rock. A strong correlation between the zeta potential and sulfur content of asphaltenes was observed, highlighting the influence of sulfur compounds on surface charge and stability in heavy crudes. Additionally, the correlation between total dissolved solids (TDS) content and alkaline Earth metals and alkali metals in asphaltenes confirmed interactions between asphaltenes and reservoir brine. This interaction is likely influenced by the composition and properties of both the brine and reservoir rock. The presence of electrical charges on the asphaltene surfaces, as determined by zeta potential measurements, further supports the role of electrostatic interactions in asphaltene stability. The low precipitation tendency observed for most asphaltene samples, coupled with the abundance of negatively charged particles, underscores the importance of electrical charges in controlling stability. This study provides novel insights into asphaltene stability, highlighting the significance of surface charge and elemental composition. The results demonstrate the substantial impact of both reservoir brine and rock formations on asphaltene stability in crude oil. Further research is needed to unravel the complex mechanisms underlying these interactions and their implications in diverse reservoir environments.
- South America (0.67)
- North America > United States > Texas (0.28)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.70)
- Geology > Mineral (0.95)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.47)
- Geology > Rock Type > Sedimentary Rock (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.48)
- South America > Venezuela (0.89)
- South America > Colombia (0.89)
- North America > United States (0.89)
- (2 more...)
The Effect of Temperature on the Size and the Deposition of Asphaltene Particles
Mohammadi, Mohammad (Department of Gas Engineering, Ahvaz Faculty of Petroleum, Petroleum University of Technology) | Bahrami, Masoud (Department of Gas Engineering, Ahvaz Faculty of Petroleum, Petroleum University of Technology (Corresponding author)) | Torkaman, Mohammad (Department of Chemical Engineering, Faculty of Engineering, Shahid Chamran University of Ahvaz)
Summary The deposition of asphaltene as a main component of crude oil is considerably affected by temperature. Despite the studies on influencing factors on deposition and size of asphaltene particles, no experimental research was previously conducted on the simultaneous impact of temperature on asphaltene particle size and deposition. In this study, the asphaltene deposit mass was measured within a Couette device at various temperatures ranging between 20 and 65°C under a constant angular velocity. Furthermore, the asphaltene particle size was simultaneously measured to investigate the relationship between deposition mass and asphaltene particle size and also to validate the concept of critical particle size. A digital microscope was used to measure the size of unstable asphaltene particles in oil. Asphaltene solubility and oil viscosity were measured to understand the deposition mechanisms. The analysis of microscopic images indicated that larger asphaltene particles are produced at higher temperatures. Although the total mass of the deposit was decreased with temperature, the deposition fraction, defined as mass fraction of total unstable asphaltene particles that deposit, was increased. Higher fraction of deposition was found for larger particles that is in contradiction to the previously introduced critical particle size concept. Additionally, the effect of solubility was found to be dominant in comparison with viscosity from the point of view of the total mass of the deposit. For the oil sample investigated in this study, a 45°C increase in temperature reduced the total mass of the deposit by 46.84%.
- North America > United States (0.93)
- Asia (0.68)
- 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)
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)
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)
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)