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Organic deposition formed at high temperatures in oil and gas production systems is commonly linked to instability of asphaltenes. Recent studies revealed that deposits collected in offshore production wells produced in Gulf of Mexico exhibited compositional variation pointing to a more complex fouling process than solely related to the asphaltene fractions. To better understand the mechanism of deposition and external factors that could contribute to this precipitation, crude oils and their respective deposits collected from the field were characterized for comparison in terms of properties and composition. Moreover, crude oils were treated with Asphaltene Inhibitors (AI) and Paraffin Inhibitor (PI) and tested applying three techniques: Asphaltene Dynamic Deposition Loop (ADDL), cold finger and rheology. The deposits collected from the ADDL and from cold finger were analyzed and compared to the field deposits. A lab-to-field correlation was observed when analyzing the deposits collected from the ADDL and cold finger tests. In both deposits, asphaltenes and wax fractions were observed to co-precipitate and form "Waxphaltenes". The efficiency of the AI on dispersing the asphaltenes was observed to have a major impact on the precipitation as possibly increasing the deposition of microcrystalline waxes. The influence of the AI at certain dosage rate in the precipitation of waxes is highlighted. In this research, the mechanism of asphaltene dispersion and instability of waxes in the presence of AI at low concentrations is proposed.
Asphaltene precipitation and deposition is a major flow assurance issue faced by the oil and gas industry. The complex nature and non-uniform molecular structure of asphaltenes complicates efforts to accurately assess their stability. Moreover, developing test methodologies with strong laboratory-to-field correlation presents additional challenges. The focus of this study is to discuss the successful validation and application of a novel test method for determination and monitoring of asphaltene stability in a Gulf of Mexico deepwater field.
Remediation and stimulation procedures were performed on a deep-water field in the Gulf of Mexico experiencing severe asphaltene deposition problems in the wellbore and near-wellbore region. This study evaluates the correlation between the thermo-electric properties as determined by Asphaltene Differential Aggregation Probe Testing (ADAPT) and dispersion tendencies of asphaltenes in treated and untreated crude oil samples at both laboratory and field environments. The remediation job was conducted through a multi-step process involving a coiled tubing clean out, solvent-soak, and continuous AI injection through downhole chemical injection tubing following the stimulation. Samples were collected prior to the start of treatment, during the initial flow-back of stimulation fluids, and over the course of one year following the stimulation. Field ADAPT measurements were performed to monitor the effect of continuous Asphaltene Inhibitor (AI) injection over time and validate the direct laboratory-to-field relationship.
Higher ADAPT readings are indicative of a better dispersion state of the polar asphaltene fraction within the test sample. Hence, the pre-treatment samples were observed to have lower ADAPT values as compared to the flow-back samples collected after the solvent-soak stage. Stabilized higher readings were recorded for the samples analyzed in the next three months and a step-down trend was observed with reduction in AI dosage. Additionally, the amount of asphaltenes that precipitated from the field samples were also measured and followed an inverse relationship with the ADAPT values, corroborating the expected asphaltene stability behavior. Furthermore, differential pressure across the flowline was also monitored for this well to confirm the absence of asphaltene deposition throughout the assessment period. A strong correlation between the laboratory and field results obtained from this thermo-electric technique and its validation with other industry standard methods highlight the reliability and high degree of accuracy of the novel ADAPT method.
With this study, an innovative method of assessing and monitoring the stability of asphaltenes and efficiency of an AI within the native crude oil medium is presented. The effectiveness of the technique to decipher and record variations during different stages of an asphaltene remediation job demonstrates its robustness and applicability as an efficient monitoring tool with great laboratory-to-field correlation.
Recent studies revealed that field deposits collected from production tubing of offshore wells often exhibit compositional varieties pointing to a more complex fouling process under field operations than original predictions purely based on asphaltene instability. Asphaltenes are estimated to constitute only 50 - 60% of total field deposit. The objective of this work was to understand the strong affinity between paraffin wax and asphaltenes resulting in co-precipitation of "waxphaltenes" and their impact on overall Asphaltene Inhibitor (AI) performance efficiency. This approach allows more objective and reliable product development and recommendation strategy to be adopted for offshore production with flow assurance management challenges caused by waxphaltenes deposition.
Routine screenings and initial chemical treatments were found unsuccessful and not reliable for samples received from offshore deep-water fields. In this study, the oil sample was fully characterized though Fourier Transform InfraRed (FTIR) spectroscopy and High Temperature Gas Chromatography (HTGC). A series of dispersion and deposition tests were then conducted in order to identify potential chemistries for treatment. Dispersion testing was mainly carried out using Asphaltene Differential Aggregation Probe Test (ADAPT) technique, whereas deposition tests were conducted on a customized Asphaltene Dynamic Deposition Loop (ADDL) test. Crude oil characterization indicated presence of unstable asphaltene fraction within the analyzed crude oil sample. Dispersion efficiency with different asphaltene inhibitors revealed possible co-precipitation issue of other crude oil solubility fractions. Futher characterization analyses highlighted heavier paraffinic components to have very high affinity towards the asphaltene clusters and creating waxphaltene precipitation issue. Efficiency of traditional asphaltene inhibitor chemistries were observed to not perform well for waxphaltene deposition. Imporvement in the chemical treatment program and product development based on the knowledge obtained through this work resulted in better inhibitor formulation. The deposition test results using the improved inhibitor chemistry was tested on ADDL and showed better performance than the traditional asphaltene inhibitor.
The new approach presents a unique opportunity to revisit the way product development is performed allowing chemical treatment strategy to be adopted and aligned based on actual deposit characteristics. Findings from this work shed light for more innovation in methods and products to tackle unforeseen waxphaltene deposition in offshore production systems.
Asphaltenes represent the most polar solubility fraction of crude oil. The polar-polar interactions between asphaltene-water, asphaltene-clay, or asphaltene-asphaltene molecules can cause severe flow assurance issues in the oilfield such as formation of highly stable emulsion, pore-throat blockages within the reservoir, and plugging of production and transportation flowlines. A novel approach of understanding these polar interactions through thermo-electric measurements is presented in this study, which can evaluate overall asphaltene stability in native crude oil.
Most of the techniques currently being used to assess asphaltene stability and efficiency of different asphaltene inhibitors on preventing asphaltene deposition are based on light scattering and transmittance phenomenon. Since crude oils are intrinsically dark colored, these techniques require dilution of the oil sample with solvents like toluene and xylene or precipitants like pentane and heptane. Addition of these chemicals alters the nature and thermodynamic equilibrium of crude oil solubility fractions. Thus, a novel approach of measuring the thermo-electric properties of crude oil and crude oil-asphaltene inhibitor mixtures was developed and tested using a custom-built capacitor setup.
The thermo-electric measurements were conducted on 10 different crude oil samples. These samples were altogether tested with 10 asphaltene inhibitors (AI). Measured data was used to indirectly estimate the polarity of the test sample, which is related to the dispersion efficiency of the asphaltene inhibitor. A standard light scattering technique was also used to analyze the oil and oil-inhibitor samples and the results were compared to the thermo-electric method outcomes. It should be noted that some of the oil samples tested in this study were obtained from production systems having asphaltene deposition issues and undergoing effective prevention and remediation treatment. Therefore, it is important for the success of the new technique to not only correlate with the standard light scattering test results but also be able to precisely the efficacy of asphaltene inhibitors for each of the test oil samples. From the results obtained, it was observed that using the thermo-electric method, the asphaltene inhibitors can be accurately screened for all the oil samples and the inhibitor efficiency analyzed in terms of its dosage curve, also agrees well with the conditions observed in the field.
A strong correlation between the results obtained from the thermo-electric technique and the light scattering method indicates the validity and higher-level accuracy of the innovative technique. Moreover, direct application of this method on the production platform at the well-head using the native crude oil sample highlights the versitality of this novel method. In addition to testing overall asphaltene stability and inhibitor efficiency, the method can also be used to monitor and optimize the field scale production scenario.
Da Silva de Aguiar, Janaina Izabel (Clariant) | Pimentel Porto Mazzeo, Cláudia (Clariant) | Garan, Ron (Clariant) | Punase, Abhishek (Clariant) | Razavi, Syed (Clariant) | Mahmoudkhani, Amir (Clariant)
Recent studies revealed that solids from lab-generated deposits often exhibit compositional differences from those of field deposits, pointing to a more complex fouling process in field operations. The objective of this work was to understand and apply knowledge from field deposit characteristics in order to design and conduct laboratory experiments which yield solid deposits with comparable compositional fingerprints. This approach allows a more objective and reliable product development and recommendation strategy to be adopted for increased success in the field applications. First, oil and deposit samples from an offshore field was characterized. Second, samples of the asphaltenes extracted from oil (AEO) and from the deposit (AED) were characterized based on solubility using an Accelerated Solubility Test (AST). A customized Asphaltene Dynamic Deposition Loop (ADDL) was used in this study to simulate the precipitation and deposition of asphaltenes from the crude oil. Crude oil used in the tests was from the same well where the deposits were collected. ADDL tests were conducted at high temperature and pressure and the composition of the collected deposit from this test was compared with the deposits from the field. At last, Light Scattering Technique (LST) was applied to screen asphaltene inhibitors (AI). Four candidate chemistries were tested on LST. To confirm the efficiency, the high performer was tested on ADDL under dynamic conditions. Deposits collected from the ADDL were characterized and results showed a high degree of similarity to the field deposit. AI1 was evaluated by ADDL and it decreased the deposition in the filters by 60% and 84% at 1000 ppm. This product was selected to be tested in the field and a plant trial is ongoing.
Maintaining overall asphaltene stability is imperative for a successful flow assurance treatment program. However, complex interactions between the polar asphaltene fraction and other components in crude oil or reservoir minerals makes the stability assessment extremely challenging. These interactions can contribute towards the precipitation and subsequent deposition of unstable asphaltene clusters comprising of impurities such as paraffin, polar organics, and inorganic mineral composites. This study investigates the impact of inorganic salts and minerals on asphaltene stability and inhibitor performance efficiency.
Four problematic crude oil samples having asphaltene deposition issue along with its field deposits were analyzed. Primary characterization of oil samples was conducted by measuring physicochemical properties. Crude oil and deposit samples were further evaluated by performing multiple compositional analyses like Fourier Transform InfraRed (FTIR) Spectroscopy, Carbon Chain Distribution (CCD), and X-Ray Fluorescence (XRF). Furthermore, asphaltene inhibitor performance efficiency was measured by carrying out both dispersion test analyses.
Primary characterization of crude oil samples did not suggest any anomalous behavior indicative of unstable asphaltene fraction. However, the solid field deposition in the production and flow-lines were observed. Therefore, further analyses of the oil as well as the solid deposits was necessitated. The analyses revealed unusually high concentration of inorganic impurities co-precipitating out with the asphaltene fraction. In general, polar nature of asphaltene induces van der Waals force of attraction between permanent dipoles (Keesom), induced dipoles (London dispersion), and permanent with induced dipoles (Debye). Paraffin and polar organic fractions associate with asphaltene through van der Waals forces and reduces the active polar sites available for the inhibitor to interact with. Moreover, presence of ions within the salts and inorganic minerals introduce ion-ion or ion-dipole interactions, which are considerably stronger than the van der Waals forces. Thus, these interactions with ionic salts and minerals interfere with the inhibitor-asphaltene interactions to a greater extent and consequently reduces the inhibitor performance efficiency significantly within laboratory screening methods.
This study, for the first time, highlights detailed contribution of impurities, specifically of ionic salts and minerals originated from drilling and completion fluids or reservoir minerals, on the overall asphaltene stability and inhibitor performance efficiency. The molecular forces arising due to co-precipitation of organic and inorganic minerals were observed to impact the asphaltene inhibitor performance considerably. Therefore, it is important to comprehend the compositional and elemental content of both crude oil and field deposit samples and accordingly select asphaltene testing methodology and modify the asphaltene inhibitor chemistry.
The near wellbore damage due to asphaltenes deposition is one of the major flow assurance issues currently faced by the petroleum industry. This study examines the pore scale flocculation and deposition processes of asphaltenes onto rock matrices. The effect of sand-grain size, clay presence in the reservoir rock, crude oil type, and precipitated asphaltenes type on the depositional behavior of asphaltenes is investigated. The porous media is prepared using sands with two different grain sizes or using sand-clay mixtures. Reservoir rocks were fully saturated with two different oil samples. 8 samples was prepared and they were washed by using either n-pentane or n-heptane, which are known as asphaltene insoluble solvents. In total, 16 experimental samples washed with solvents were subjected to optical microscopy and Scanning Electron Microscopy (SEM) – Energy Dispersive Spectroscopy (EDS) analyses to assess the asphaltene depositional mechanism. For all cases, porosity variations were measured experimentally. Our results suggest that asphaltene-clay interaction can increase the near-wellbore damage due to the strong polar ends in asphaltenes which are attached to clay surfaces and/or asphaltenes that are stuck in clay layers. Porosity of the sand has been found to decrease after the injection of solvents, indicating pore blockage due to asphaltene deposition. While the n-pentane precipitated more asphaltenes than n-heptane, n-heptane asphaltenes occupied more volume and resulted in higher porosity reduction due to higher polarity of n-heptane asphaltenes than n-pentane asphaltenes. Furthermore, the presence of clays and non-uniformity of grain sizes are observed to aggravate formation damage by asphaltenes. The SEM images showed that the interaction of clays with asphaltenes mainly reduces the permeability rather than porosity. The EDS analyses indicate that the impurity content of asphaltenes affect mainly the interaction of asphaltenes and clays.
Asphaltenes and resins are the polar and saturates and aromatics are the nonpolar fractions of the crude oil. The mutual interaction within crude oil fractions results in different overall polarity. With the onset asphaltene precipitation, the overall polarity starts to change drastically and this change affects the asphaltene stability more. This study investigates the crude oil fractions polarity and their individual impact on asphaltene precipitation.
Two crude oil samples with different asphaltene content, API gravity, and viscosity were divided into their Saturates, Aromatics, Resins, and Asphaltenes (SARA) fractions. The crude oils and their SARA fractions were characterized by Fourier Transform InfraRed (FTIR) spectroscopy. The polarity of crude oils and their SARA fractions were determined through dielectric constant measurements by in-house-built capacitance.
The polarity of the individual fractions and bulk crude oil samples were analyzed together to understand how the mutual interaction of crude oil fractions affects the asphaltene stability. The overall polarity of the crude oil is the key to asphaltene stability. Resins and asphaltenes are the polar components of crude oil, thus, resins to asphaltenes ratio affects the overall stability of the asphaltenes. Asphaltenes are soluble in aromatic solvents and insoluble in normal alkanes, thus, while the increase in the saturates fraction in crude oil decreases the asphaltene stability, the increase in the aromatics fraction in crude oil reestablishes the stabilization. The solvent power of saturates and aromatics fractions are controlled by the impurities in saturates and aromatics fractions. Because while saturates and aromatics are known as nonpolar fractions of crude oils, the impurity content of those fractions results in polar sides in both saturates and aromatics fractions. The polar side of those fractions makes the interaction with asphaltenes more pronounced and affect the stability of asphaltenes considerably.
The holistic understanding of the asphaltene stability is achieved by analyzing the polarity of asphaltenes alone and within crude oil. These results are very useful in preventing the asphaltene precipitation and modelling its stability.
Prakoso, Andreas (Texas A&M University) | Punase, Abhishek (Texas A&M University) | Klock, Kristina (Texas A&M University) | Rogel, Estrella (Chevron Energy and Technology Center) | Ovalles, Cesar (Chevron Energy and Technology Center) | Hascakir, Berna (Texas A&M University)
Significant effort has been dedicated to understand the variables affecting asphaltene precipitation. Based on years of research, it is well known how variables such as temperature and pressure can affect the deposition of asphaltenes. However, much less is understood about the effect that asphaltene characteristics have on the tendency towards precipitation of different crude oils. We characterize extensively a series of n-pentane extracted asphaltenes and construct novel correlations with the stability of their corresponding crude oils.
11 different bitumen and crude oil samples are characterized first with API gravity and viscosity measurements, and thermogravimetric and differential scanning calorimetric analyses (TGA/DSC). The weight percentage of the asphaltenes in bulk samples are determined through n-pentane precipitation. The molecular structure of the asphaltenes is investigated with Fourier Transform InfraRed (FTIR) spectroscopy. Asphaltene stability is measured by ?PS and by determining the Asphaltene Solubility Profile. The impact of hydrogen deficiency, heteroatom content and solubility distributions on other properties such as viscosity and aggregation behavior is also explored.
It has been observed that there is weak relationship between the asphaltene content and API gravity or viscosity of the bulk samples. The weight percent of the light, intermediate, heavy, solid, and ash fractions of the asphaltenes, defined with TGA/DSC experiments, indicate that the carbon rich solid component of the bulk samples that can decompose over 550 °C, correlate with the weight percent of the asphaltenes in bulk oil. The ash content of the bulk oil, which is mainly composed of heavy metals like sulfur, nickel, and vanadium, is correlated to the amount of asphaltenes precipitated out of the oil. Moreover, FTIR and solubility profile analyses reveals that the polarity of the asphaltene molecules is affected not only by its molecular composition and structure but also by its interactions with other crude oil components.
This study discusses the impact of the physical and chemical properties of crude oils and their asphaltenes on asphaltene precipitation. Several asphaltene deposition mechanisms are developed and validated for 11 different crude oil and bitumen samples with different asphaltene contents, thereby providing important and fundamental insight into asphaltene related problems.