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Abstract The need for more efficient, cost effective, relatively high flashpoint, and environmental friendly organic solvent is crucial. Due to safety and environmental effects of the conventional aromatic solvents, efforts are being focused to search for more natural based products. A total of 14 terpene-based and conventional solvents have been examined to identify their dissolving power of asphaltene/organic sludge. The organic solvents vary in their compositions from xylene or conventional based solvents to the more environmental friendly compounds of terpene (green solvents). They also vary in their flash points from as low as 75°F tod as high as 200°F. The organic scale/sludge samples have been studied by thermogravimetric analysis (TGA), FT-IR, ESI-MS and asphaltene analyses. The analysis showed the contents of asphaltene, functional groups, saturation level and weigh loss of both deposits. Dissolution tests were conducted on both organic deposits using 11 terpene-based solvents and 3 conventional solvents. Dissolution tests were conducted at room temperature and 50°C with soaking times of 3 and 24 hours. The solubility of deposit A at most of the solvents was found to be lower than the solubility of deposit B due to variation in both deposits’ compositions. Even though the increase of the soaking time was found to be of positive impact, most of the dissolving occurred in the first few hours. This study results also revealed that the efficiency of the terpene-based organic solvents is a function of terpene concentration; however, increasing the terpene concentration would decrease the flash point, which is of a safety concern in warm climate countries, especially during high temperature seasons. The environmentally friendly terpene-based solvents displayed promising results and can be an alternative to conventional solvents.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- 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)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Abstract The formation of calcite scale is induced generally through a change in pressure and temperature, which affects the saturation level of calcium and bicarbonate as the CO2 gas is released. Prevention of calcite precipitation through scale inhibitor squeezing job treatment is a well-known method for minimizing potential scaling. The selection of suitable scale inhibitor is important as its performance can be affected by the lithology and reservoir conditions. In this study, a scheme of screening new scale inhibitors was evaluated. The proposed scheme included the study of the adsorption/desorption characteristics of the scale inhibitor and its efficiency at higher temperature. The proposed scale inhibitor treatment design included pre-flush/post-flush fluid and the SI main fluid in addition to the synthetic formation water (SFW). Lithium chloride was introduced to the main SI fluid as a tracer. To study the SI fluid-rock interaction, core flood testing was conducted on the Outcrop Torrey Buff sandstone core plug. The results of the core flood was used to determine the change in permeability during the SI soaking and assess the formation damage. Ca, Mg and total iron in the effluents samples were used to study the dissolution of the plug. P and Li analysis were used to study the absorption/desorption behavior of the scale inhibitor during the 5 days of flooding and compared to the minimum inhibition concentration (MIC). Core flood data showed the differential pressures versus the cumulative pore volume of the injected fluids revealed that around 20% of formation damage was encountered during the SI flooding, which is anticipated in sandstone rock due to high adsorption of the scale inhibitor on the rock. The desorption profile of the scale inhibitor showed that the proposed treatment scale inhibitor could keep its concentration above the MIC at ultra-high temperature. The study revealed that the proposed phosphonate-based inhibitor showed effective performance at higher temperature. The desorption rate is adequate to keep the scale inhibitor concentration above the MIC. The scheme of study can be used to screen different scale inhibitors at higher temperature and to assess their adsorption/desorption characteristic.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.59)
- Geology > Mineral > Silicate (0.47)
- Geology > Mineral > Carbonate Mineral > Calcite (0.45)
- Water & Waste Management > Water Management > Water & Sanitation Products (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Review of Iron Sulfide Scale: The Facts & Developments and Relation to Oil and Gas Production
Okocha, Cyril (Clariant Oil Services) | Kaiser, Anton (Clariant Oil Services) | Wylde, Jonathan (Clariant Oil Services) | Petrozziello, Lena (Clariant GTI) | Haeussler, Matthias (Clariant GTI) | Kayser, Christoph (Clariant GTI) | Chen, Tao (Saudi Aramco) | Qiwei, Wang (Saudi Aramco) | Chang, Frank (Saudi Aramco) | Klapper, Markus (Max Planck Institute for Polymer Research)
Abstract Oilfield iron sulfide (FeS) control and prevention have been mostly proprietary with several disparate solutions. Frequently FeS control involves milling, jetting, acid soaking, pulling and replacing tubing and manually cleaning tanks, vessels, separators and pumps. These methods are costly, wasteful and strenuous. This paper reviews the latest developments in oilfield FeS researches with an attempt to integrate viable solutions and expose unworkable practices. In this work, we review and evaluate the most common FeS prevention and control solutions in an attempt to summarize the state-of-art FeS mitigation technologies. We have a closer look on FeS formation and control as well as potential integrated solutions. The paper reviews and differentiates treatment solutions between corrosion byproduct and FeS scale deposition from formation. Most FeS scales have generally been treated as the same, using various treatment methods. Complex FeS polymorphs have resulted in different outcomes. This work focuses on different treatment options that assert to work for all FeS scale not differentiating between corrosion-byproduct and reservoir formed scale. Successful case histories and suspected FeS polymorph are presented in this paper next to discussion of the model used to predict severity of the deposition and analyze the treatment design. FeS formation and deposition is evaluated, especially crystallography and fundamental studies into mechanistic aspects of FeS precipitation and how it relates to oilfield FeS precipitation. In this paper state-of-art FeS scale research is summarized and differences to normal scale types are presented. Mineral scale in the true sense of going through the stages of nucleation, pre-crystallization, crystal growth, agglomeration and deposition. This is an important step change in consolidating all the disparate areas of FeS studies into an advanced solution focused approach. If FeS scale is considered a mineral scale then solutions such as scale inhibitor applications (continuous injection and squeeze) that work for common mineral scales should work for FeS deposition as well. Thereby moving FeS research from a relatively empirical level with vastly different approaches that are mostly unrealistic into solutions that will be viable in the oilfield.
- North America > United States > Texas (0.70)
- Asia > Middle East > Saudi Arabia > Eastern Province (0.28)
- Europe > United Kingdom > Scotland > City of Aberdeen > Aberdeen (0.15)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract Tetrakis(hydroxymethyl)phosphonium Sulfate (THPS), an environmental friendly biocide, is gaining more interest as a dissolver to control iron sulfide (FeS) precipitation in oilfield production systems. In previous works, combinations of THPS and different additives, such as ammonium chloride, chelating agents or organic phosphonates, were examined for the synergistic effects of FeS scale dissolution under room and high temperatures. It was found that THPS and ammonium ion can create a purple-colored complex which can significantly improve the FeS dissolution. Studies also indicated that the synergistic effect of ammonium chloride was largely attributed to pH decrease. As a result, the corrosivity of THPS solution to metallurgy was increased. In this work, new formulations based on THPS is introduced. Chloride ions were substituted with different organic compounds. The dissolution rate of analytical grade FeS solid and carbon steel corrosion were investigated at different temperatures. The chemical composition of the undissolved FeS solid and the THPS-Amine-Iron complex structure were analyzed for the most effective dissolver formulations. The efficiency of new formulations was further evaluated using field scale samples collected from water injection pipeline and a sour gas well, and the structures of the FeS scale before and after dissolver treatment were studied to reveal the mechanism of dissolution.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.94)
Abstract One of the major challenges of corrosion and scaling management in sour gas wells is to effectively monitor corrosion and scaling under real-flow regime conditions. It is very difficult to simulate the actual environment and flow conditions in laboratory experiments to study downhole corrosion and scale formation. Understanding the corrosion and scaling mechanism under downhole conditions is very important in order to develop effective prevention and mitigation strategies in a timely manner. An advanced downhole corrosion and scale monitoring (DCSM) tool has been designed and developed to monitor corrosion and scale formation in sour gas wells. This monitoring system represents significant improvements over the current industrial technology by directly measuring corrosion and scale deposition in real downhole conditions using exchangeable coupons with identical metallurgy as the downhole completion tubing. A slick line with a retrievable high-expansion gauge hanger was used to deploy and anchor the DCSM downhole at the desired depth. The tool was retrieved after 3 months exposure to the reservoir conditions for post-laboratory analysis. Advanced analytical techniques were carried out to understand the corrosion and scaling mechanism, including SEM, EDS, XRD, and surface profile measurement besides quantifying the weight changes. The results showed that a thin layer (~3-4 μm in thickness) of iron sulfide scale was deposited on the surface of coupon. It served as a protective layer to prevent and reduce further corrosion and scale buildup. To understand the mechanisms of scaling, the surface scale deposit was removed by corrosion inhibited acidic solution. The surface profile measurement showed localized pitting corrosion which appeared on the surface of coupon, which indicates that corrosion happened first followed by scale layer deposition on metal coupon surface. The newly developed DCSM tool has an advanced design which allows direct corrosion and scaling monitoring under downhole conditions. Post-laboratory analysis on retrieved coupons can provide corrosion and scaling mechanism for specific metallurgy under real downhole conditions. Proper corrosion and scale management programs could be designed to minimize the effects of corrosive gases. The developed tool can be used to monitor the effectiveness of the corrosion treatment and can be deployed in sweet gas wells, oil wells and water supplier wells.
- North America > United States (1.00)
- Asia > Middle East > Saudi Arabia > Eastern Province (0.28)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
Investigation of Heavy Oil Recovery Using Sequential Viscoelastic Surfactant and Chelating Agent Solutions as EOR Fluid for HTHS Conditions Carbonate Reservoirs
Janjua, Aneeq Nasir (King Fahd University of Petroleum & Minerals) | Sultan, Abdullah S. (King Fahd University of Petroleum & Minerals) | Kamal, Muhammad Shahzad (King Fahd University of Petroleum & Minerals)
Abstract Viscoelastic surfactants are known to be the best for chemical EOR (cEOR) applications as compared to polymers and surfactants because of its dual capability of reducing the oil/water interfacial tension (IFT) and improving the sweep efficiency. Carbonate reservoirs become most challenging cEOR targets when they are characterized as high temperature and high salinity (HTHS). In this work, a systematic study is carried out to design a formulation using a sequential viscoelastic surfactant (VES) and chelating agent (CA) solutions for recovering heavy oil from carbonate reservoirs. The objective of this work is to investigate the chemical formulations of viscoelastic surfactant and chelating agent with heavy reservoir oil of 17°API and 234,189 ppm salinity formation brine. Thermogravimetric analysis (TGA), nuclear magnetic resonance (NMR) and fourier transform infrared (FTIR) are used to evaluate the thermal stability of VES. Encouraging results with TGA demonstrate that VES is thermally stable and show high resistance to temperatures up to 250°C. NMR and FTIR results also show good long-term thermal stability when aged for 30 days. Ultra-low oil/water interfacial tension measurements are recorded using spinning drop tensiometer and lie in the range of 10 to 10 m-Nm. Effects of concentration, time and temperature on IFT are evaluated. It is also noted that ultralow IFT is obtained at 50°C and 80°C. Static adsorption has been evaluated by shaking the powdered core samples with VES at two different temperatures for 24 hours. Concentration measurements are performed using total organic carbon (TOC) analysis. Static adsorption results give less adsorption when we have higher temperatures compared to lower temperatures. Coreflooding experiments are designed with VES and VES-CA at 90°C using carbonate core samples to determine the additional oil recovery. Overall oil recovery factor with VES and VES-CA of 47% is calculated when plotted against injected pore volumes. Pressure drop profile, oil rate and water rate are also determined, and their graphs are presented with injected pore volumes. This study provides an integrated approach of evaluation and application of viscoelastic surfactant and chelating agent solutions for chemical EOR in heavy oil reservoirs. Thermal stability, ultralow IFT's, adsorption and additional oil recovery obtained with viscoelastic surfactant and chelating agent show that they are excellent additives that can be used in cEOR for high salinity and high temperature conditions. They are also very useful when we have heavy crude oil and where IFT reduction is required to mobilize the oil and improve the sweep efficiency of the reservoir.
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
Abstract Asphaltene aggregation is one of the biggest problems in the oil and gas industry for both upstream and downstream processes. It called the cholesterol of crude oil since it can deposit on the reservoirs pores and block it. It can also plug the production tubes and pipelines which could cost millions of dollars. One of the solutions is adding different chemicals such as asphaltene dispersants (ADs) or asphaltene inhibitors (AIs). ADs reduce asphaltene particle size which will keep them in the crude while AIs prevent the asphaltene aggregation by shifting the onset pressure of asphaltene. In this paper, three different asphaltene inhibitors were tested and investigated thoroughly with different concentrations for heavy Arabian crude oil. Several tests were performed: asphaltene inhibitors efficiency was tested using laser scanner analysis and asphaltene stability was investigated by using spot test method and asphaltene solubility class index. The results showed that the Arabian crude oil has a high asphaltene content and it reasonably stable. Two of the inhibitors (SF-1742 and AI-410) have showed better efficiency than the third inhibitor (AI- 108) in the inhibitors efficiency test with low optimum concentration.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.72)
Abstract The formation of gas hydrates in pipelines continues to be a major challenge in gas production. Conventionally, thermodynamic hydrate inhibitors (THIs) are used to inhibit hydrate formation. Mono- ethylene glycol (MEG) is commonly utilized as a hydrate inhibitor due to its recoverability. However, during the recovery process, MEG may undergo multiple phases of thermal exposure which may lead to the degradation of MEG. In this study, MEG solution with realistic brine composition was tested for its gas hydrate inhibition performance. The typical lean-MEG solution was prepared by combining pure MEG in a brine solution based on common formation water salt composition. The degraded samples were extracted from a MEG recovery pilot plant that had undergone a complete recovery operation (~13 h). Samples were then taken for gas hydrate testing using a high-pressure PVT cell. The isobaric hydrate testing method was employed for accurate hydrate equilibria results. The new hydrate equilibria data revealed a hydrate promotion effect amongst the degraded MEG samples as opposed to pure non-degraded MEG. Although salt in the MEG solution improved hydrate inhibition, the results show that the inhibition effect was decreased as the extent of MEG degradation increased. Furthermore, MEG degradation products were identified to be acetic, formic, and glycolic acid. Observations reveal a color change from colorless to slightly yellow depending on the extent of thermal degradation of the MEG samples.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract As part of the continuous efforts to save freshwater resources in the Middle East, seawater-based fracturing fluid offers a high-potential solution to help save millions of gallons of fresh water while developing fracturing fluids for hydraulic fracturing applications. Scale deposition is one of the major technical challenges for fracture stimulations using seawater-based fluid. To understand the scale deposition and mitigation for fracturing using seawater-based fluid, a series of dynamic and static performance, compatibility, and thermal stability tests were conducted. Results showed that harsh scale forms with mixing raw seawater and high total dissolved solids (TDS) tested formation water at higher temperatures under dynamic and static conditions. Scale inhibitors cannot effectively inhibit scale deposition in such harsh scaling conditions because of the issues of compatibility and performance at static conditions. Nanofiltration of seawater is introduced to remove most of the sulfate ions in seawater and help significantly reduce the scaling tendency when mixing with high TDS formation water during fracturing treatments using seawater-based fluid. Combining the nanofiltration technique and scale inhibitor application, the scale issue during fracturing using seawater-based fluid can be effectively mitigated and was determined to be suitable for field application. The scale inhibitor showed good compatibility with nanofiltered seawater. The dynamic scaling tests were successful when the proper scale inhibitor and optimum concentration were used, while the static tests did not form any precipitation. Thermal aging resulted in a color change for all tests, as expected, and the performance of the thermal-aged scale inhibitor was evaluated. This paper provides insight into the scale deposition and inhibition for fracturing treatments using seawater-based fluid at high-temperatures up to 300°F and furthers the effective strategies to address the scale issue during fracturing using seawater-based fluid.
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Effect of Novel Chelating Agent Seawater Based System on the Integrity of Sandstone Rocks
Ahmed, Abdulazeem (King Fahd University of Petroleum and Minerals) | Mohamed, Mahmoud (King Fahd University of Petroleum and Minerals) | Elkatatny, Salaheldin (King Fahd University of Petroleum and Minerals) | Barri, Assad (King Fahd University of Petroleum and Minerals) | Muhammadain, Abdulrahim (King Fahd University of Petroleum and Minerals)
Abstract The objective of sandstone acidizing the objective is to reduce the skin around the wellbore. This process may affect the stability of the formation and may decrease the efficiency of the stimulation job. One of the main problems related to rock integrity is sand production. Sand causes erosion of surface and down hole equipment. The objective of this work is to introduce DTPA (diethylene tri-amine pentaacetic acid) to sandstone acidizing. Moreover, use mechanical properties estimated based on acoustic measurements to address the impact of the new formulation on the integrity of Bandera and Berea sandstone cores after stimulation. In this study, DTPA and EDTA (ethylene di-amine tetra-acetic acid) chelating agents at high pH diluted with seawater combined with potassium carbonate were used to acidize Bandera and Berea sandstone cores. Core flooding system was used to acidize the sandstone samples. Non-destructive tests were conducted to evaluate the effect of injected solution volume on the rock integrity. The samples were scanned using Computed Tomography (CT) to detect any precipitations after using the seawater based chelating agents. The results showed that DTPA and EDTA chelating agents at pH of 11 diluted using sea water injected at rate of 5 cm/min into 2-inch Bandera and Berea sandstone cores at temperature of 250°F enhanced the permeability ratio. Furthermore, increasing the fluid injected pore volumes raised the permeability improvement ratio of the sandstone cores. CT-number of the treated samples decreased which means no precipitations formed inside the cores. Elastic moduli of the cores after the acidizing showed that the integrity of the samples was not affected and no sand production is expected under the flooding conditions. The obtained results of this work will provide the engineers with sandstone acidizing seawater based fluids that will not affect the rock integrity after stimulation.
- North America > United States > West Virginia (0.66)
- North America > United States > Pennsylvania (0.66)
- North America > United States > Ohio (0.66)
- (2 more...)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.89)
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- (2 more...)