The sophisticated molecular imaging methods, atomic force microscopy (AFM) and scanning tunneling microscopy (STM), have been utilized to image individual asphaltene molecules, both their atoms and bonds, and their electronic structure. The stunning images have confirmed previous results and have all but resolved the long-standing uncertainties regarding asphaltene molecular architecture. Asphaltenes are also known to have a strong propensity to aggregate. The dominante asphaltene molecular structure and hierarchical nanocolloidal structures have been resolved and codified in the Yen-Mullins model. Use of this model in a simple polymer solution theory has given the first equation of state (EoS) for asphaltene gradients in oilfield reservoirs, the Flory-Huggins-Zuo EoS. With this EoS it is now possible to address reservoir connectivity in new ways; equilibrated asphaltenes imply reservoir connectivity. For reservoirs with disequilibrium of contained fluids, there is often a fluid process occurring in geologic time that precludes equilibrium. The collection of processes leading to equilibrium and those that preclude equilibrium constitute a new technical discipline, reservoir fluid geodynamics (RFG). Several reservoirs are reviewed employing RFG evaluation of connectivity via asphaltene thermodynamics. RFG processes in reservoris often include diffusion, RFG models incorporating simple solution to the diffusion equation coupled with quasi-equilibrium with the FHZ EoS are shown to apply for timelines up to 50 million years, the age of charge in a reservoir. When gas (or condensates) diffuse into oil, the asphaltenes are destabilized and can convect to the base of the reservoir. Increasing asphaltene onset pressure as well as viscous oil and tar mats can be consequences. Depending on specifics of the process, either gooey tar or coal-like asphaltene deposits can form. In addition, the asphaltene structures illuminated by AFM are now being used to account for interfacial properties using simple thermodynamics. At long last, asphaltenes are no longer the enigmatic component of crude oil, instead the resolution of asphaltene structures and dynamics has led to new thermodynamic applications in reservoirs, the new discipline RFG, and a new understanding of tar mats.

Paraffin represents one of the main case of failures and production losses which facing the entire oil industry. Prevention of paraffin deposition on the subsurface/surface equipment can be achieved by keeping the paraffin dissolved in crude oil or minimizing the adhesion or aggregation process of wax crystals. The paraffin problems which occur, conduct to gradual reduction of the tubular and pipelines internal diameter, restriction or valves blockages, and reduce the equipment capacity until the production is stop. Problems due to paraffin deposition varies and is different according with each commercial field, sometime the difference is from a well to well which producing from the same reservoir with different consistency. How we shall proceed? Before or after paraffin is field on the equipment? How could be avoid the future paraffin deposition? How long the selected method is proper for well ? The decision represents a combination based on oil's chemical & physical characteristics, well's behavior, method selected for prevention or elimination and combined with economic analysis and field experience. The paraffin inhibition applying is a common practice in OMV Petrom, which cover majority of the production wells. For the special wells, which the paraffin inhibition didn't provided satisfying results (multiple intervention due to paraffin deposition) was selected the Down Hole Heating technology (DHH) which was successfully tested in our company since 2014 thanks according with the yearly New Technology Program. The operating principle consists in heating the fluid volume from tubing using the heating cable which can be installed inside tubing, for NF and ESP wells or outside tubing for SRP or PCP wells. The cable is designed and located at the interval of wax crystallization appearance and heats the fluid to the temperature higher than the wax crystallization point (WAT). Since then, the DHH technology had an upward course, proven by high run life (highest value 2500 days / average 813 days) of the technology at the total 47 wells equipped, until this moment. Based on the successful results, recorded of 64% of old production wells equipped, it was decided to apply the technology at first completion of the new wells (36%), thus ensuring the protection of the new equipment. The paper offers an overview of DHH technology implementation, achievements, benefits and online monitoring of technology implementation starting with 2014 until today. The total impact shown a decreasing of no.of failures with 73,8%, the cost of intervention with 76,5%. The production losses decreased only with 5%, which certifies the fact that the technology helping production maintaining during the exploitation in comparison with production losses due paraffin issues recorded at wells without equipped with DHH technology. During 6 years of down hole heating technology application were developed candidate selection decision tree, monitoring the electrical efficiency, using the adaptability capacity of the technology from one well to another and integrate the temperature parameters in online monitoring system as part of digitalization concept of OMV Petrom, aspects which will be present in this article.

Pigging of Once Through Steam Generators (OTSGs) indicated various types of scales, the most predominant of these being silicates of hardness causing ions. It was noted that scaling propensity can potentially go up with higher Steam Quality (SQ) as the reject stream gets concentrated with ions. However, models suggested that there are benefits of higher SQ in enhancing fuel savings (8%) and electricity savings (2%) when SQ was increased by 20%. The challenges of higher SQ were noted in terms of increased scaling tendency and therefore the need for improved softening. In Field D, the service cycle, the backwash cycle, and the brining cycle were optimized leading to a gain in throughput and reduction in salt consumption. Service cycle improvement gained 30 % to 130 % in throughput between two regenerations, backwash cycle improvement by fluidizing the bed to nearly 35% helped gain 10% in throughput, and reduction of brining cycle from 75 minutes to 48 minutes helped reduce salt consumption by 56% without impacting the throughput. In Field B, a six month pilot revealed that shallow shell resins where ion-exchange is more efficient due to inert core (better intra particle diffusion control) can enhance the throughput by 30% - 80% and simultaneously reduce the number of regenerations by 15 – 30%. Resin fouling is still a major challenge to contend with as oil can foul the resin and throughput can decline by 0.5 – 3 folds. In a plant operation, where there are multiple softener and brine vessels, there is a need to optimize them as a system. Reliability, Availability, and Maintainability (RAM) Models are used in Field C to a) Address equipment configuration optimization with impact on capital capacity expansion project scope b) Understand how net softwater delivery capacity was affected by increases in inlet hardness and c) Assess through a comparison scenario, if the large cost of addressing the valve issue in an upstream nutshell filter was worth the lost production opportunity related to unplanned downtime.

The harsh conditions presented in Brazilian presalt, summed up with the complexity of its reservoir, generate a series of challenges to improve reservoir recovery. Routinely, we have used intelligent completion systems to address the major part of the challenges; however, with the new production rates new problems have arrived and the usual ones have turned more aggressive, generating risks even to the intelligent completion systems. Inorganic scale is a critical challenge in presalt reservoirs production. Future plans for presalt production include more robust flow conditions and the use of an all-electrical completion system. Higher flow rates are likely to increase the risk of scale deposition and an optimum design is required. To address the new challenges arising from the new perspective of exploration in the presalt fields, we developed the presented workflow to mitigate the scale deposition on completion valves. The method enables the optimization of choke geometry to reduce scale deposition on inflow control valves. The proposed workflow generates a criticalness parameter for geometry classification according to a scenario of mechanical failure (due to sleeve incapacity to move) or deviation of production design point. A computational fluid dynamics (CFD) simulation was developed and benchmarked by experimental data, thus CFD results for different scenarios and various choke geometries were used to build a risk analysis matrix, which allows the definition of the optimal choke design to mitigate scale on ICVs. The extracted criticalness parameter may be used as an evaluator to estimate the time to valve stuck due to scale deposition in a commercial 1D transient flow simulator, optimizing then valve cycling time.

An improved flow assurance solution based on a new additive with robust performance, low treat rate and versatile handling properties was developed successfully. It was applied in a waxy crude oil from West Africa with high pour point and a wax content of about 24%. Crucial for the project success was a close collaboration among all involved stakeholders from operator, service company and chemical supplier. In the initial lab screening by the chemical supplier, tests focused on pour point, viscosity and yield stress. This approach allowed to identify the most efficient type of additive chemistry for the specific crude oil and to meet target performance requirements. Crude oil viscosity and yield stress under pipeline operation conditions could be reduced by more than 95% while reducing the required amount of additive by more than 75% compared to the incumbent solution. This resulted in significant cost savings for the operator and in a reduction of the Health, Safety and Environmental (HSE) exposure.

This work presents a numerical assessment of chemical inhibitor injection to mitigate wax deposition in unconventional wells. The goal of this study is to simulate the deposition of wax under several operational conditions and later optimize the chemical inhibitor injection position, using two different types of numerical simulations. A transient one-dimensional multiphase flow simulator - ALFAsim, with a dedicated wax model, was used to predict flow conditions such pressure, temperature, holdup and flow pattern profiles, as well the position and rates that wax accumulates. The results from the 1D simulation were then used as boundary conditions in a 3D CFD simulator, which aimed to assess how long it would take to a satisfactory homogenization of the inhibitor with the flow and what would be the minimum depth for the injector should be installed. In this work, a 1D multiphase flow simulator with wax deposition model was used to identify on which operational conditions (flow rates and environmental temperatures) an unconventional well would start to present wax deposition on its tubing walls. After defining the susceptible region where the paraffin could deposit, it was important to verify if the inhibitor would be well homogenized with the stream when reaching this region. For that, a 3D CFD simulation was performed, using information obtained directly from the 1D simulator as boundary conditions. The CFD model was capable to show the mixing evolution of the inhibitor with the stream and it was possible to determine the minimum distance where the injector should be placed to guarantee such homogeneity. A real well was selected to provide comparisons between field observations and simulated data, in order to validate the model assumptions and accuracy.

Asphaltene deposition is a notorious flow assurance problem faced by oil companies that causes production loss and large expenses for operators. The complex nature of asphaltenes and limited data available makes it challenging to develop a full field implementation strategy that is economically viable as well. Conducting asphaltene clean-up operations whenever wells get plugged up are the reactive approach to deal with asphaltene issues. However these approaches often result in prolonged well downtime, production losses and high well intervention costs. As part of proactive measures, chemical inhibitors were screened for formation squeeze and field trials conducted to assess their performance. Results from these trials helped to frame the full-field implementation strategy that is promising from a technical-economic standpoint. This paper describes the asphaltene mitigation journey of a major Abu Dhabi oil operator that resulted in multi-million dollar savings.

Gas hydrate inhibition through the use of chemicals has been ongoing over the years and these chemicals are toxic, synthetic and expensive, adding to the cost of doing oil and gas business, and also leads to environmental degradation. The call for greener environment has necessitated the search for more eco-friendly gas hydrate inhibitors. This paper takes a look at the use of a bio-extract in its unmodified state to inhibit gas hydrate using a locally made mini flow loop for gas hydrate studies. The bio extract was compared to a conventional gas hydrate inhibitor 2-Di(methylaminoethyl)methacrylate (2-DMAEM). For all the weight percentages considered (0.01-0.05wt%), the bio-extract had better pressure profiles. At the end of the experiment which lasted for 120 minutes, this is attributed to the fact that the pressures in the system were more regulated which prevented rapid gas dissolution in water. The Bio-extract is plant based, locally available in the commercial quantity and is eco-friendly so it should be harnessed as gas hydrate inhibitors in lieu of the expensive and imported conventional hydrate inhibitor 2-DMAEM which non-eco-friendly.

In offshore production, the type of field development scheme is crucial aspect due to its associated flow assurance risks, which affect project economic, safety, and sustainability. The objective of this study is to simulate and evaluate two offshore field development schemes, namely subsea and platform in offshore Kuwait. Further objective is to carry out detailed transient simulation study on the subsea scheme to investigate flow assurance risks related to terrain slugging, and hydrates formation during shut-in and re-start transient events. The evaluation of the two schemes is based on the associated flow assurance risks, and project economics. Steady state simulations are used to identify the feasible production scheme, which is further simulated under transient shut-in/restart events to investigate flow assurance risks related to terrain slugging and hydrates formation. The steady state simulation results of this study showed that flow assurance risks such as hydrates and pipeline corrosion are significant in both production schemes. To mitigate these risks, sixteen different field development designs of both production schemes were simulated and economically evaluated. Results revealed that the subsea multiphase development scheme with 10-in. ID carbon steel multiphase flowline and 0.3-in. thick polypropylene thermal insulation is the optimum design. Consequently, the optimum design is further analyzed under transient conditions, resulting in appreciable risk of terrain slugging due to hilly-terrain pipeline configuration, especially for the low production rate cases. The transient shut-in/restart simulation results revealed a risk of hydrates formation due to cooling effect during shut-in, which is mitigated by MEG injection. In conclusion, the subsea multiphase flow scheme is selected over platform scheme due to manageable flow assurance risks, low capital investment cost, and minimum environmental impact. This study would enable Kuwait Oil Company to evaluate different offshore development schemes to ensure sustainable production with safe operation and protected environment.

This work aims to develop a fracturing nanofluid with a dual purpose: i) to increase heavy crude oil mobility and ii) to reduce formation damage caused by the remaining fluid. Three commercial nanoparticles were evaluated: two fumed silica of different sizes and one type of alumina. They were acidified and basified, obtaining nine nanoparticles (NPs) by the surface modification, characterized by TEM, DLS, Z Potential and Total Acidity. The effect of adding nanoparticles at different concentrations onto the linear gel and heavy crude oil was determined by their rheological behavior. Also, there was assessed the alteration of the rock wettability by contact angle for all NPs and concentrations. Based on these results, the nanoparticle with better performance was the neutral fumed silica of 7 nm at 1000 mg/L. These were used to make a fracturing nanofluid from a commercial fracturing fluid (FF). Both of them were evaluated through their rheological behavior overtime at high pressure following the API RP39 test and quantitative measurements of the rock sample wettability changes. Displacement tests also were performed on proppant and rock samples at reservoir conditions: pressure and temperature. Finally, there was evaluated the rheological behavior of the crude oil recovered in the displacement test. It was possible to conclude that the inclusion of nanoparticles allowed obtaining a reduction of 10 and 20% in the two breakers used in the commercial fracture fluid formulation. An alteration of the rock wettability was achieved, where the rock sample became up to 50% more wettable to water. Moreover, there was a diminution of 53% in the damage caused by the remaining fracturing fluid to the oil effective permeability in the proppant medium. In the rock sample, a decrease of 31% of this kind of damage was observed. Increases of 28 and 18 % in the crude oil recovery were noticed in the proppant and the rock sample, respectively. Finally, there was a reduction of 40% in the crude oil viscosity, showing the effectiveness of adding nanoparticles to fracturing fluids for increasing oil mobility and reducing the formation damage.

Acid jobs with conventional acid systems like hydrochloric acid in high temperature conditions is challenging on various fronts. Enhanced reactivity of strong acids results in poor penetration and severe face dissolution. Also, it aggravates the issue of corrosion of downhole equipment and may also result in sludge formation/asphaltene deposition. Worldwide, chelating agents has emerged as a standalone stimulation fluid for high temperature acidizing. Their unique attributes and properties have been proved very useful for acid jobs at elevated temperatures. However, the chelating agents-based formulations need to be carefully evaluated on various acidization parameters for a fruitful stimulation. Mumbai Offshore field has been encountering the above-mentioned problems in acidizing of its high temperature (>275°F) limestone reservoirs. The paper presents innovative solutions devised for high temperature matrix acidizing. Two chelating agents viz., EDTA (Ethylenediaminetetraceticacid) and GLDA (L-Glutamic Acid N, N-diacetic acid) were explored and evaluated with meticulous laboratory studies. The performance of the chelating agent-based stimulation fluid was compared with acetic acid. Slurry tests were performed to quantify the dissolving power of each acid. Consequently, core flooding tests were carried out to to find the optimum pH of the chelating agents from stimulation point of view. Core flooding studies were performed at anticipated injection rates on representative core samples from a payzone A, with BHT 275-290° F, from Mumbai Offshore. pH optimized formulations were tested against N-80 metallurgy coupons at reservoir temperature for corrosion potential estimation. Also, sludge, asphaltene and emulsion formation tendencies were analyzed with representative oil samples. The results convey that both EDTA and GLDA were able to mitigate the challenges encountered at elevated temperatures. EDTA and GLDA were found to stimulate the cores with wormholes formed at wide pH range with no face dissolution observed. Chelating agents enjoyed good dissolving power with negligible corrosion rates, absence of sludge and asphaltene deposition, compatibility with formation fluid and excellent iron control properties.

The success of stimulation fluid placement in openhole extended reach wells (ERWs) through coiled tubing (CT) is highly dependent on the depth achieved. Friction forces and helical buckling typically cause early CT lockup, which limits the reach. Organic deposits in the wellbore increases frictional forces causing premature lockup or in some cases even complete blockage. Efficient removal of organic deposits enables CT to reach maximum depth to perform the matrix stimulation. Analysis of these organic deposits was conducted and following a thorough comparative test, a new solvent-external phase emulsion inhibitor was selected to treat the wellbore prior to matrix stimulation. Optimum cleanout methodology was identified for the CT run with a high-pressure jetting nozzle (HPJN) combined with a chemical dissolution effect of the chosen solvent. Focused, high-energy fluid streams loosen any compacted deposits, while the high rate of fluid passing through the tool allows for an efficient cleanout. A matrix stimulation treatment with CT was then executed in the openhole section of the ERW with a TD of 18,773-ft (9800-ft horizontal lateral section) with HCl and emulsified acid systems. By using a solvent-external phase emulsion, only the external phase of the emulsion containing the dissolver is in contact with organic deposits; the remaining internal phase fluid is not. This therefore allows a reduction in total solvent volume. The proposed wellbore cleanout treatment with HPJN reduced the friction coefficient between CT and the completion by 10%. In turn, it was verified that during the operation, an additional 3,320 ft of reach was achieved in the openhole section. Combined with other extended-reach techniques (i.e., mechanical agitator tools, friction reducers), it allowed the 2.0-in CT pipe to reach the TD of the well (18,773 ft). These efforts together maximized the reservoir contact during the matrix stimulation in the openhole section with HCl and emulsified acid systems. Distributed temperature sensing (DTS) methodology was used with the aid of fiber optic installed CT, and the intake profile of the openhole section was mapped. Analysis of the data was applied to optimize the pumping schedule to obtain uniform production contribution across the openhole section. The systematic engineering workflow presented includes the organic deposit diagnostic procedure, laboratory testing, chemical selection, and treatment application. This yields a wellbore treatment that minimizes friction for the remainder of the operation and enables maximum CT reach. This provides more insights of integrated matrix stimulation treatment with CT to overcome the serious challenges present in extended reach openhole wells.

Asphaltene deposition in oil wells is a challenging flow-assurance phenomenon that affects the well production, project economics, and operational safety. While asphaltene precipitation is governed by the hydrocarbon mixture thermodynamics, Asphaltene deposition is governed by the complexity of flow hydrodynamic behavior and characteristics. This study aims to evaluate and compare the performance of the existing asphaltene deposition models and improve the current theoretical understanding of the deposition phenomenon by developing better predictive asphaltene deposition model. A large experimental database is collected, including aerosol and asphaltene particles deposition in air and crude oil systems, respectively, to carry on the evaluation. The results of this study revealed that Kor and Kharrat (2017) model of transport coefficient, which accounts for both diffusional and inertial deposition mechanisms outperformed other models in matching the transport coefficient from aerosol/air data. In addition, an improved sticking probability model is proposed in this study, and curve fitted using corrected deposition flux data to obtain the model constant. The improved model is not only physically sound, i.e. SP ≥1, but also it requires less input data than other models. A validation study of the improved model shows a slight over prediction of experimental data with an absolute average error of 6.8% and standard deviation of 11.4%. The significance of this work is to provide theoretical predictive tool for asphaltene deposition in pipes to enable prevention, mitigation, and management of oil field asphaltene deposition strategies.

Chelating agents are used to stimulate high-temperature carbonate reservoirs and remove mineral scales. For field applications, commercial chelates—EDTA, DTPA, GLDA, etc.—are commonly supplied as 3550 wt% (1.2-1.7 M) solutions and diluted two times in water. However, the dependence of the reaction rate on the concentration of chelate in solution has never been quantified. This paper focuses on determining the kinetics of calcite dissolution as a function of the dilution factor of commonly used chelates at acidic pH. Using a rotating disk apparatus, the kinetics of calcite marble dissolution in 0.10.25 M EDTA (pH=4.9-5.0), 0.1-0.25 M DTPA (pH=3.5-5.0), and 0.28-0.85 M GLDA (pH=3.7-5.0) solutions has been investigated. The dissolution of calcite in all chelates has a negative fractional-order that increases with temperature in the range -0.6 < n < -1.9. Thus, less concentrated chelate solutions react faster with calcite, and the effect of chelate dilution becomes less pronounced with a temperature increase. For example, three times dilution of pH=3.7 commercial GLDA solution—from commonly used 50 vol% (0.85 M) to 16.7 vol% (0.28 M)—increases calcite dissolution rate 8.4, 4.9, 2.7, and 2.0 times at 98.6, 116.6, 134.6, and 188.6°F, respectively. Dilution of pH=5.0 EDTA and pH=3.5 DTPA from 0.25 M to 0.1 M increases the dissolution rate of calcite 1.4-3.1 times at 98.6-188.6°F. Probable reasons for such an unusual reaction behavior are discussed in the paper. Presented results are integral for designing the stimulation operations in carbonate reservoir rocks and the removal of carbonate scales.

Heavy oil (HO) production and transportation has been one of the major concerns for the oil and gas industry in recent years. In this sense, nanotechnology has raised as a promising solution for enhancing heavy oil mobility at surface and subsurface conditions. However, its implementation in real field applications at midstream conditions is still underexplored. Thus, the primary objective of this study is to expose the methodology applied for carrying out an upscaling from a technology readiness level (TRL) of 3 up to a TRL–8 for the nanotechnology implementation at a real field application, going through the experimental design and the initial field trial results. Thereby, nanoparticles of different chemical nature and textural properties such as surface area and diameter were evaluated in HO viscosity reduction. A nanofluid composed of the nanoparticles with the best performance and a carrier fluid was designed and the viscosity reduction was assessed again as well as the treatment perdurability. Finally, a field trial application in a Colombian field was carried out through a continuous capillary-injection of the nanofluid (with a concentration of 1000 mg/L of nanoparticles), reducing its dosage from 3200 to 2700 mg/L. The initial rheological measurements were performed with a fixed concentration of 1000 mg/L of the nanoparticles. The results showed a trend between the viscosity reduction and the nanoparticles adsorptive capacity as higher values (30% of reduction) were obtained with the material that leads to a higher amount adsorbed of asphaltenes. The nanofluid evaluation showed a treatment perdurability enhancement compared to the carrier fluid alone as it was observed a viscosity increase of 26 and 116% for the HO-nanofluid and the HO-carrier fluid mixtures, respectively after 10 days. From the field trial application, it was observed a viscosity reduction of at least 60% which was maintained through time due to the continuous nanofluid injection. Furthermore, well-testing exhibited an oil production rate increase of 10%. At last, a rigorous economic analysis was made, which indicated that the process profits would yield the 400,000 USD per year for a single well application, while several operational expenses would be reduced derived from naphtha consumption reduction in the upstream and midstream stages.

Shale producers in North America continue to face challenges with paraffin wax deposition in well bores, production tubing and flowlines as production declines and artificial lift methods such as gas lift are applied. Preventative measures are often based on traditional screening and assessment methods which rely on crude’s wax appearance temperature (WAT). Recent studies have shown that operators are increasingly turning to costly remediation program and stimulation jobs to maintain production rates as oil wells decline at faster rates than anticipated. It appears in many cases that these declines can be exacerbated by downhole organic fouling and wax deposition that surprisingly may have occurred above the original WAT. This paper aims to conduct a root cause analysis to identify the key internal and external factors impacting an oil’s WAT. Four crude oils and field wax deposits from Gulf of Mexico, South Texas and West Texas areas were used for this study. Due to the unique composition of the field deposits and depleted crude sample available for analysis, a novel strategy for lab screening was adopted. Crude oil samples were examined "as received" and after reconditioning via the addition of solvents and/or field deposits. Further measurements were performed to identify and quantify the effects of the addition of production chemicals particularly hydrate inhibitors. A series of dispersion and deposition tests were then conducted in order to demonstrate the potential impacts of incompatible chemistries. Fractionation based on solubility revealed a dynamic behavior for the WAT of crudes that corelated to their paraffin content and distribution. Samples containing C 45+ paraffin chains demonstrated significant WAT changes upon reconditioning. The addition of methanol and MEG typically used as hydrate inhibitors, impacted the WATs of the crudes as measured by DSC showing increases in the WATs compared to unconditioned samples. An additional suite of dispersion and deposition testing conducted on the same samples supported the findings of the DSC studies. A nonlinear correlation was found between increasing WAT and paraffin deposition rate. The approach outlined in this paper provides a more accurate field condition simulation leading to more effective inhibitor selection and ultimately improved flow assurance management in more complex production systems. The methodology of mimicking hydrocarbon fluid behavior was the key factor identified by the root cause analysis and correlated to the series of past failures attributed to organic fouling. WAT was found to be a parameter that can vary for a crude oil over the life of a production system. With the current evolution of shale oil production in North America and around the world, we expect these findings will also be relevant to unconventional production and will aid the oil industry to anticipate and manage previously unforeseen problematic paraffins in production systems.

Since 2015, scale problems have appeared when gas production decreased below 30 Mm3/day and wells could not evacuate liquid and solids to the surface due to liquid loading. Scale depositions were found in casing and tubing at different depths close to Quintuco Formation perforations. During 2019, more than 30 wells were mechanically cleaned using slick line to remove scale every 30 days approximately. This paper describes the study of the origin of scale in gas wells producing from multiple formations and the chemical technology applied to solve this problem in the mature urban field Centenario (Neuquén - Argentina). Core and water analysis were performed to study the scale phenomenon at the productive formations and to determine the compatibility between fracturing and formation waters. In addition, it established the scale origin and served to detect further wells susceptible to suffer scaling problems. Scale is produced in the casing, not in the formation, due to changes of pressure and temperature related to the expansion of gas and changes in water mix compatibility at Quintuco perforations depth. Due to the field location, subsurface safety valves were installed in the tubing to prevent possible blowouts. Thus, capillary string for product injection was discarded. A proven chemical technology for oil wells-encapsulated scale inhibitors-was adapted to treat gas wells aiming for a treatment duration of three months. The method consisted of a mechanical clean-up followed by a batch treatment of encapsulated product with water and, finally, a slick line run to ensure it reached the bottom-hole. The chemical treatment pilot was carried out in 6 wells. Candidates were selected based on abnormal production decline, scales showed after slickline intervention, favorable response after mechanical clean-up, and high intervention frequency. The pilot held in 2019 showed an increase in gas rate production of 12 Mm3/day on average representing 40% of well production, high stability in gas production and a reduction of slickline intervention frequency. The duration of the treatment was initially estimated according to the liquid rate of the well and the product concentration used. During 2020 the pilot will be expanded to 32 wells in the field. Solid scale inhibitor for gas wells is relatively new in the industry and there is not much bibliography about application and results in this type of wells. This paper describes the methods used for scale characterization, the prediction of its formation in gas wells, the selection method for scale inhibitors, the product application technique to the wells and the results obtained in the pilot, demonstrating its technical and economic feasibility for field use.

Removal of wellbore scale from downhole equipment continues to impact well economics due to productivity losses and asset maintenance. The use of first-of-its-class calcium sulfate (CaSO 4 ) scale dissolver in high producing offshore wells equipped with electric submersible pumps (ESP) is presented. The efficiency of the new fluid surpasses the performance of established dissolvers since it does not require long shut-in periods. Anhydrite (CaSO 4 ) scale dissolution and removal can be accomplished with a simple treatment fluid employing a formulation that has been field-proven to restore production and protect downhole equipment in a time-efficient manner. Mineral anhydrite and wellbore scale samples were tested with the dissolver formulation at 200°F (93.3°C), under static conditions for one hour. Dissolution efficiencies greater than 94% were a requirement. Fluid compatibility with metallic and non-metallic components in the wellbore were assessed at bottom hole static temperature (BHST) conditions for a period of 24 hours. The fluid was deployed from a stimulation vessel at a pumping rate from 1 to 5 bpm. A small volume pill of 5 m 3 on average was pumped in at least 20 wells, through the production tubing to the ESP and was allowed to soak for 1 hour. Wells were immediately opened to production after a 1-h soak period. Minimizing the non-productive time incurred when long soak periods are required has been attained with the use of the new dissolver fluid, leading to greater efficiencies associated with CaSO 4 -type scale removal. ESP temperature was monitored and reduced by 13°F (7.2°C) after treatment, similar to temperatures before scale build up. After the treatment, the results show a 1.125-fold increase in oil production. The fast-acting formulation exceeds 90% dissolution efficiency within one hour and improves operations by using a fluid that is non-corrosive to downhole materials in a one-stage removal package. The dissolver formulation provides dissolution of anhydrite at 200°F in ESPs. The fast acting dissolver is delivered as a single fluid package and eliminates the need for separate fluid stages as well as the use of incompatible fluids. Anhydrite scale dissolution and removal can be accomplished with a simple treatment fluid and extend the life of the ESP.

This study investigates the role of heavy oil polar fractions in surfactant-steam flooding performance. Performance analyses were done by examination of the dipole-dipole and ion-ion interactions between polar head group of surfactants and charged polar fraction of crude oil, asphaltenes. Surfactants are designed to reduce the interfacial tension between two immiscible fluids (such as oil and water) and effectively used for oil recovery. They reduce the interfacial tension by aligning themselves at the interface of these two immiscible fluids, this way, their polar head group can stay in water and non-polar tail can stay in oil phase. However, in heavy oil, the crude oil itself has high amount of polar components (mainly asphaltenes). Moreover, polar head group in surfactants is charged and the asphaltene fraction of crude oils carry reservoir rock components with charges. The impact of these intermolecular forces on surfactant-steam process performance was investigated with 10 coreflood experiments on an extra-heavy crude oil. 9 surfactants (3 anionic, 3 cationic and 3 nonionic surfactants) were tested. Results of each coreflood test were analyzed through cumulative oil recovery and residual oil content. The performance differences were evaluated by polarity determination through dielectric constant measurements and by ionic charges through zeta potential measurements on asphaltenes fraction of produced oil and residual oil samples. The differences in each group of surfactant tested in this study are the tail length. Results indicate that longer hydrocarbon tail yielded higher cumulative oil recovery. Based on the charge groups present in the polar head of surfactants anionic surfactants resulted in higher oil recovery. The further examinations on asphaltenes from produced and residual oils show that the dielectric constants of asphaltenes originated from the produced oil gives higher polarity for surfactant-steam experiments conducted with longer tail length, which provide information on polarity of asphaltenes. The ion-ion interaction between produced oil asphaltenes and surfactant head groups were determined through zeta potential measurements. For the most successful surfactant-steam processes, these results showed that the changes on asphaltenes surface charges getting lower with the increase in oil recovery, which indicates that once asphaltenes are interacting more with polar head of surfactants, then, the recovery rate increases. Our study shows that surfactant-steam flooding performance in heavy oil reservoirs controlled by the interaction between asphaltenes and polar head group of surfactants. Accordingly, main mechanism which controls the effectiveness of process is the ion-ion interaction between the charges in asphaltene surfaces and polar head group of crude oils. Since crude oils carry mostly negatively charged reservoir rock particles, our study suggests the use of anionic surfactants for the extraction of heavy oils.

In this paper a new method of performing a wireline large scale formation test is introduced. To measure reservoir properties a significant distance from the wellbore, drill stem testing (DST) tests are often employed. In addition to measuring reservoir dynamic properties, a DST provides information regarding reservoir geometry including the extent of the reservoir, upper and or lower boundaries of the reservoir, barriers to flow within the reservoir. The DST is considered the gold standard for dynamic parameters such as reservoir pressure, formation mobility/permeability, well bore skin factor, flow anisotropy, and the best estimate of production potential for the measured interval. Conceptually, a typical DST is simply a controlled limited production of formation fluids over the reservoir interval of interest. However, a full DST has become an operationally intensive and costly endeavor often lasting many days to weeks. Planning and executing a DST is costly requiring highly specialized equipment that is customized for a unique set of reservoir and operating conditions. One of the primary considerations is to insure the environmental compliant disposal of a considerable quantity of produced fluid. Due to the high cost of traditional DSTs, alternate methods of testing have been employed. Wireline formation testers capabilities have increased their pumping capacities and are used to perform a small scale mini-DST that has increasingly been employed as a substitute for full DSTs at a much lower cost. A mini-DST can provide measurements of the reservoir dynamic properties, albeit over a smaller depth interval and smaller radius of investigation. The mini-DST radius of investigation generally extends up to 100feet from the wellbore and over a vertical height of a few feet as opposed to the full DST which can extend thousands of feet from the wellbore and be extended over tens of feet covering an entire vertical producing interval. While a DST can accurately characterize an entire formation production interval's potential, the mini-DST can delineate the formation flow interval and determine the most productive layers, flow barriers and thief zones which are critical to optimizing the completion design. This new method combines a conventional wireline mini-DST and sampling procedure with an extended injection test in order to recover the reservoir flow interval geometry information and improve flow interval delineation. The mini-DST measures the local mobility of the formation, cleans the wellbore of mud filter cake and near well bore mud filtrate contamination, thus enabling the acquisition of a clean formation sample. When acquiring a formation sample the formation fluid properties can be determined with downhole sensors and a subsequent mini-DST can provide the in situ dynamic properties. A selected injection fluid can be used to reverse the process by flowing into the interval. Because the injection fluid would have known properties that are measured in controlled laboratory testing, the dynamic data results will be more definitive. For example, the viscosity will be known enabling the rock permeability determination, where traditionally only the mobility can be determined. In many cases the reservoir oil type is known and the injection fluid can be closely matched to improve the in situ dynamic data results. Aided by favorable backing pressure from the surface, and not limited by the fluid bubble point, the injection fluid may be pumped into the formation at a higher rate than the formation fluid can be withdrawn from the formation. This allows a greater sand face to reservoir pressure differential, yielding an improved pressure signal for evaluation. Furthermore, because fluid is injected, no environmental sensitive disposal is required, and the procedure is inherently safer for maintaining well integrity than a formation fluid withdraw. However, interpretation of the pressure rebound after the injection stops may require a reservoir simulation if the injection fluid property is significantly different from the in situ reservoir mobile fluid. This paper evaluates the new method based on detailed reservoir simulations and using available field equipment capabilities. These simulations include considerations of invasion and cleanup in a multiphase environment. In addition, a sensitivity study summarizes the testing effectiveness by varying the primary parameters such as permeability, anisotropy, skin, and formation barrier distances. From this work, conclusions are drawn comparing the new reverse injection DST method to traditional DST and wireline technologies.