Brazilian Pre-salts fields lie in approximately 2200 m w.d. in a challenging environment and are often characterized by highly corrosive produced fluids that pushed to the extreme the application of the most advanced material technology and engineering. Nevertheless, Lula, Sapinhoá, Mero and Búzios are definitively world-class prospects with production rates that may exceed 30.000 barrels per day per well. The development scheme of the Pre-salt fields followed the experience and the track record of the large number of deepwater fields that were previously developed in Brazil, in the post-salt regions, and is based on satellite wells tied to the floating production platform by means of dedicated production and service risers (i.e. each well has dedicated production and service lines). This satellite configuration offers the advantage to be simple, straightforward and resilient to field layout changes even during the project execution phase. However, the continuous pressure to which the Oil & Gas industry is exposed in order to increase profitability, reduce cost and, more recently, green house gas emission is encouraging Operators to evaluate different field architectures that are more traditionally implemented in other deepwater provinces outside Brazil and that the recent technology and construction asset developments made suitable also for a potential application in the Pre-salt fields. Moreover, those field architectures that are normally based on commingling of wells production are also prone to provide a faster production ramp-up and a reduced time to break even. This paper presents a description of possible Daisy Chain and Manifold-Based subsea architectures that are suitable to be applied to Brazilian pre-salt fields. The pros and cons of these alternative subsea layouts are explored. Additionally, cost and schedule analyses are presented to show the benefits of such architecture regarding CAPEX and ramp-up compared to satellite architecture, considering the "Brazilian pre-salt" scenario. Finally, a generic proposal for subsea architecture is presented for pre-salt developments jointly with practical solutions for typical operation demands related to flow assurance issues like, for instance, wax and hydrate management.

Numerous solids including gas hydrates, waxes, and asphaltenes have the potential to form in the production lines of gas and oil fields. This creates a highly non-ideal scenario as the accumulation of said species leads to flow assurance issues, especially with long-term processes like deposition. Since an ever-increasing amount of material is deposited in place at the pipe surface, production stoppage or active mitigation efforts become inevitable. The latter production issues result in increased safety risks and operational expenditures. Therefore, a cost-effective, passive deposition mitigation technology, such as a pipeline coating or surface treatment is especially appealing. The ability to address multiple pipeline flow assurance issues simultaneously without actively disrupting production would represent a dramatic step forward in this area. This study is part of a long-term ongoing effort that evaluates the performance and application of an omniphobic surface treatment for solids deposition prevention in industrially relevant systems. In particular, this specific work concentrates on the efficacy and robustness of the treatment under fully flowing conditions. The apparatuses utilized for this include two flowloops: a lab-scale, high-pressure flowloop for gas hydrate and surface treatment durability studies, and a bench-scale, atmospheric pressure loop for crude oil and asphaltene experiments. Film growth in high-pressure flowloop tests corroborated previous reports of delayed gas hydrate nucleation observed in rocking cells. Without the aid of the memory effect, treated oil-dominated experiments never experienced hydrate formation, spending upwards of a week in the hydrate stability zone (at the subcooled/fluid test conditions). Subsequent tests which utilized the memory effect then revealed that the hydrate formation rate reduced in the presence of the surface treatment compared to a bare stainless-steel surface. This testing was part of a larger set of trials conducted in the flowloop, which lasted about one year. The surface treatment durability under flowing conditions was evaluated during this time. Even after experiencing ∼4000 operating hours and 2 full pressure cycles, no evidence of delamination or damage was detected. Finally, as part of an extension to previous work, corroded surface asphaltene deposition experiments were performed in a bench-top flowloop. Treated experiments displayed an order of magnitude reduction in both total oil (all fractions of crude oil) and asphaltene fraction deposited.

Despite pre-salt fields in Brazil usually having high production per well, one of the areas presents a reservoir with low permoporosity, which results in small flowrates with fluid temperatures during production below the one that is critical for wax deposition. The operations commonly used to remove the wax deposits are diesel soaking and pigging, which brings production losses and OPEX increase. Thus, the economic analysis should consider these events reducing the operational efficiency of production. To evaluate the production drop due to wax deposition, it was necessary to perform a loop test to determine the wax growth throughout time. With a multiphase simulator, it is possible to choose the deposition model and the diffusion coefficient that best fits the analyzed fluid. However, one of the limitations of this first analysis is the lack of data to determine the effect of the shear stripping, as the test is performed under a laminar flow. As this term plays an important role in wax growth, it was necessary to add to the simulation model the shear coefficient fitted from another pre-salt field. With this information, it will be possible to make a more reliable evaluation of the impact of wax deposition, increasing the confidence in the production curve, OPEX and NPV of the full field project. This paper shows the methodology that has been applied to evaluate the impact of wax deposition in pre-salt fields. It presents the deposition model, and its coefficients used to fit the multiphase transient models to a pre-salt field.

Gas hydrate formation in natural gas systems and subsea infrastructure can block pipelines and instruments, restrict flow, and lead to safety and environmental hazards in production and/or transportation systems. These problems can lead to substantial economic and HSE risks. Therefore, understanding how, when and where hydrate formation occurs are important factors in developing the hydrate management strategies. This paper addresses the hydrate management strategy in one of the subsea developments in the Gulf of Mexico (GOM). The effects of salinity, water cut, and amount of methanol on hydrate formation and plugging risk were studied in this paper. The experimental results and modeling in advanced thermodynamics software showed that an increase in the concentration of methanol and salts in the autoclave cell leads to a shift of the equilibrium curves, reducing subcooling and hydrate volume fraction while increasing induction time. The results also show that for some under-inhibited systems, the volume fraction of the hydrate slurry is low enough to allow for safe transportation of fluids during various operational conditions.

Gas hydrates constitute a serious flow assurance problem. Over the last decades, industry has faced this problem by using avoidance methods (e.g. injection of thermodynamic hydrate inhibitors) and management strategies (e.g. addition of hydrate anti-agglomerants). In the former, hydrates are completely avoided by shifting the hydrate boundary towards higher pressure and lower temperatures; in the latter, hydrates are allowed to form but their tendency to agglomerate is reduced. It should be noted that some crude oils are naturally able to avoid hydrate agglomeration, this non-plugging tendency may originate from the surfactant-like behavior of fractions like asphaltenes and acids. Recent works have shown that the natural non-plugging potential of certain oils can be affected by the addition of polar molecules like alcohols. There is another strategy for managing hydrate that consist of the addition of THIs at a concentration lower that the one required to full hydrate inhibition. In this case, hydrates are under-inhibited. Studies carried out on hydrate agglomerating systems have shown that under-inhibition might prevent hydrate agglomeration only in a specific range of THI concentrations and sub-cooling; however, work on non-plugging oils is scarce. In this paper, the hydrate agglomeration of two crude oils under-inhibited with methanol and MEG was evaluated through a visual rocking cell apparatus and a high-pressure rheometer. Results showed that THIs and the crude oil's natural surfactants were capable of acting synergistically in reducing hydrate agglomeration and improving the system flowability.

Wax deposition is one of the known challenges of flow assurance management in upstream oil production and operations demanding continuous improvements and the search for more effective prevention and remediation methods. At the same time, there are no universally agreed upon test methods to evaluate the efficiency and mechanisms related to the chemical treatments. The objective of this paper is to present and debate different methods to evaluate the effectiveness of batch treatments for remediation of wax deposits and compare commonly applied solvents with fluids containing biosurfactants. One of the presented methods is a new test methodology that simulates dynamic and quasi-static flow regimes in production tubing and pipelines, as benchmarked methods, showed that the chemical treatments with biosurfactants, besides being a greener, sustainable option, were more efficient at dispersing wax deposits than the traditional solvent treatments.

Paraffin buildup is a fact of life in many oil and gas production fields. When downhole reservoirs lose pressure or temperature, paraffin precipitates and builds up on everything from pipe to valves to instrumentation to the walls in vessels. This buildup slows the process, constricts lines, and clogs instruments. Chemical treatments to keep paraffin from precipitating out of the fluid are widely known, but expensive. In addition to treating the liquid, producers should also consider treating the devices in the flow line to resist buildup. This paper will show how using nano-material to treat surfaces of components in the flow line—such as sensitive instruments, vessels, meters, valves—can slow or stop the buildup of these contaminants. By changing the bonding energy of the surface metal, these nano surface treatments hinder the ability of contaminants to adhere to a surface. These treatments do not affect mechanical, optical, or electrical properties of the treated devices. The discussion will include technical differences between a "coating" and "surface treatment" and the impact of these differences on a flow process. The paper will highlight environments that are best suited for these nano surface treatments and the different application methods available for treating devices. Data will showcase the performance of nano surface treatments in common applications, such as Coriolis meters, turbine meters, valves, flow and level devices. Producers have seen significant extension in the functional life of these devices and achieved significant operational savings. The paper will discuss how this data applies to other applications such as vessels, chemical reactors, filters, and more. In conclusion, nano-materials offer new and novel ways to maintain flow through valves, sensitive instruments, and other critical components in a flow line. Surface treatments, using nano-materials are easily applied, have a permanent effect on the surface energy of the metal, and do not hinder the optical, mechanical, or electrical properties of treated devices. Benefits of these treatments include reduced maintenance downtime and cost, improved performance of critical instrumentation and increased reliability of flow meters and valves.

Gas hydrate formation in natural gas systems and subsea infrastructure can block pipelines and instruments, restrict flow, and lead to safety and environmental hazards in production and/or transportation systems. These problems can lead to substantial economic and HSE risks. Therefore, understanding how, when and where hydrate formation occurs are important factors in developing the hydrate management strategies. This paper addresses the hydrate management strategy in one of the subsea developments in the Gulf of Mexico (GOM). The effects of salinity, water cut, and amount of methanol on hydrate formation and plugging risk were studied in this paper. The experimental results and modeling in advanced thermodynamics software showed that an increase in the concentration of methanol and salts in the autoclave cell leads to a shift of the equilibrium curves, reducing subcooling and hydrate volume fraction while increasing induction time. The results also show that for some under-inhibited systems, the volume fraction of the hydrate slurry is low enough to allow for safe transportation of fluids during various operational conditions.

Despite pre-salt fields in Brazil usually having high production per well, one of the areas presents a reservoir with low permoporosity, which results in small flowrates with fluid temperatures during production below the one that is critical for wax deposition. The operations commonly used to remove the wax deposits are diesel soaking and pigging, which brings production losses and OPEX increase. Thus, the economic analysis should consider these events reducing the operational efficiency of production. To evaluate the production drop due to wax deposition, it was necessary to perform a loop test to determine the wax growth throughout time. With a multiphase simulator, it is possible to choose the deposition model and the diffusion coefficient that best fits the analyzed fluid. However, one of the limitations of this first analysis is the lack of data to determine the effect of the shear stripping, as the test is performed under a laminar flow. As this term plays an important role in wax growth, it was necessary to add to the simulation model the shear coefficient fitted from another pre-salt field. With this information, it will be possible to make a more reliable evaluation of the impact of wax deposition, increasing the confidence in the production curve, OPEX and NPV of the full field project. This paper shows the methodology that has been applied to evaluate the impact of wax deposition in pre-salt fields. It presents the deposition model, and its coefficients used to fit the multiphase transient models to a pre-salt field.

Managing asphaltene accumulation in offshore Gulf-of-Mexico wells is a significant challenge. Until recently there was no real-time chemical monitoring that could advise on whether chemical inhibition was making a particular well more, or less, stable. This changed with the development of real-time hardware that directly measures the ratio of asphaltene flowing in the oil. A new generation of that hardware has now been launched which meets all of the Qualification and HSE requirements for deployment on offshore platforms. A microwave resonator was designed to receive fluid at wellhead conditions, i.e., without a reduction in pressure or temperature, and the parameters of that resonator were optimized to maximize microwave intensity for typical oilfield fluids. The microwave circuitry is incorporated in an explosion-proof container with Class 1 Div 2 rated electrical and fluid connections. By combining that resonator with a solenoid that can generate a large magnetic field around a flowline, the resulting device resonates electrons within asphaltene molecules to create a unique signature that is proportional to the total asphaltene count. Estimates of oil-water cut and gas-oil ratio are also obtained as part of the processing and this combination gives the percentage of asphaltene within the oil. The use of this hardware with controlling software and cloud processing creates a unique Internet-of-Things device which can be used to optimize asphaltene-related flow assurance challenges offshore. Pressure testing up to 5ksi and 120C gives the device a working envelope well exceeding typical offshore production hardware requirements. For a fixed fluid, the computation of asphaltene ratio was shown to be independent of applied pressure. Conversely, it was found that in a live well chemical properties of fluids can change over the course of a few hours even when the surface pressure and flow-rates stay the same. In one well, the surface asphaltene percentage within an oil was seen to vary from 0.3% to 3% because of alternating deposition and erosion of an asphaltene layer that had been forming along the ID of production tubing. Over the course of a series of tests in the Middle East, it was observed that those wells with uniform asphaltene percentage were seen as less troublesome to manage compared to wells with a higher deviation. In two Permian fields subject to CO2 flooding, a geographic variation in asphaltene percentage which correlated to the long-term exposure to injected gas was observed. It has long been standard for chemical properties of fluids to be obtained by sending samples to a lab. This paper demonstrates additional value that can be obtained from getting that data in real-time, especially when viewed in the context of an overall chemical management program.

The aim of this paper is to present the results obtained by the use of fresh water in order to remove inorganic scale deposited inside production tubing from carbonate reservoir deepwater production wells with high salinity and low BS&W. The paper covers the entire process from the identification of production loss, the investigation of its main causes, treatment propositions and discussion of obtained results. One of the hypotheses regarding the scale deposition mechanism in the studied wells is that the precipitation of salts is due to the evaporation of produced water. This phenomenon occurs through the contact of water with dry gas applied in the artificial elevation method (gas lift). The proposed and tested scale removal procedure consists of a soaking of the production tubing with fresh water in order to dissolve the deposition or at least part of it that is soluble in water. Preventive care actions in relation to flow assurance were taken, since the suggested method uses a high volume of fresh water, increasing the hydrate risks. Scaling in wells with those characteristics was systematically removed through remote acidification (with specialized vessel assistance). That approach has shown to be always effective. On the other hand, remote acidification was always costly and dependent on the availability of critical resources. The technique depicted in this paper requires neither a vessel nor acid and, therefore, incurs significantly lower costs. The results obtained in the first tests were substantially positive since the wells’ productivity was fully restored. In this sense, the hypothesis of water solubility of the scale deposition was confirmed, and the method validated. Since its validation, the method has been applied a number of times, confirming its repeatability, and extending its use to other wells with similar scaling occurrences, reducing costs and restoring the production in a short time. Nevertheless, new challenges arise in relation to the full comprehension of the deposited material and the prevention of its deposition.

A cold flow plant consists of a Water Management System (WMS) for separation and treatment of produced water, and a Wax Control System (WCS) for making solid wax particles that can travel through the long tieback line without further deposition on the pipe wall. Pre-conditioning to a level of 1-2% remaining water implies that avoidance of hydrate formation can be handled by reasonable volumes and traditional chemical methods. The Wax Control System enable a temperature independent transport of oil dominated flows by continuous removal of deposited wax from the pipe wall, allowing the solid wax particles to travel with the flow in the export line without any risk of further deposition of wax along the export pipeline. The technical qualification work included design and operation of a Pigging Loop that allowed continuously removal / handling of wax within a bundled pipeline.

This article's goal is to present some of the main flow assurance challenges faced by PETROBRAS in the Buzios oil field, from its early design stages to full operation, up to this day. These challenges include: hydrate formation in WAG (Water Alternating Gas) operations; reliability of the chemical injection system to prevent scale deposition; increasing GLR (Gas Liquid Ratio) management and operations with extremely high flowrates. Flow assurance experience amassed in Buzios and in other pre-salt oil fields, regarding all these presented issues, is particularly relevant for the development of future projects with similar characteristics, such as high liquid flow rate, high CO 2 content and high scaling potential.

Hydrate occurrence is synonymous in deep water wells, notably when the well experience significant reduction in fluid temperature during production. Hence, the operating philosophy must take into consideration the ability to maintain the well-fluid outside the hydrate or wax phase envelope and ensure the contingencies are in place to mitigate any plug, deposit or gel formation. This paper illustrates the characterization of hydrate and wax plug encountered and devise of innovative solution to remediate the blockage in two wells in Sabah waters which were plugged due to cooling of the wells during an unplanned shut down. The solution devised is to set precedence to manage temperature dependent blockages in similar Deepwater wells or facilities. Hydrate and wax models were created to predict blockage severity and its location. Nodal analysis was used to model thermodynamic equilibrium at target location of the plug where the temperature is below the melting point and ultimately to predict the required heat to dissolve the blockages. A Thermo-chemical system was identified, selected, and customized and then injected into well to ensure the temperature generated at the location of the plug was above the melting point of hydrate and wax. Thermo-chemical injection was identified as a viable method of In-situ Heat Generating Technique to generate heat at desired location. The chemical solution was injected via capillary tubing to transmit the heat via conduction and convection to melt the hydrate and paraffinic plug in these 2 wells. An arriving temperature of 40°C at the target zones was required to melt the plug. A positive pressure was maintained in the production tubing during chemical injection to avoid rapid pressure increase as the hydrate plugs dissolved. A temperature of 100 °C was recorded at the wellhead throughout the injection. The downhole gauge indicated positive response, suggesting the heat generated transmitted effectively. After a short duration of injection, communication was established. Hydrate inhibitor was injected to secure the well prior to unloading. The wells were successfully relieved and stabilized production of 1,200 bopd and 800 bopd respectively. The simulation was redesigned based on data collected from the operation to improve the model and to be used for future works. The ability to integrate laboratory analysis, computer aided simulation and operational data was integral to this paper demonstrating an effective way to characterize temperature dependent blockages in production system. Design of experiments provided better insight to address the problem. Innovative use of novel chemistry to produce heat, in-situ heat solved hydrate and wax related issues in a most cost-effective manner. The process of customizing a chemical system based on laboratory and simulation results was effective in ensuring delivery of the results. The bull-heading operation to inject the chemical system proved to be a cost-effective remedial method to unlock the barrels and can be considered preventive or as a contingency measure in dealing with temperature dependent blockages or plugs in future.

Petrobras acquired the right to produce 3.058 billion boe under the Transfer of Rights (ToR) in Buzios field, which still has a recoverable surplus, recently auctioned by the Brazilian Petroleum Regulatory Agency. Properly planning the production development of a supergiant field and under two tax regimes, requires a large multidisciplinary effort of data acquisition, characterization and modelling. Located in the Santos Basin Pre-Salt Pole, the Buzios field is a deep-water supergiant that has a large thickness of carbonate reservoirs, with significant areal and vertical variation. The presence of faults, fractures, karsts and other diagenetic processes adds complexity to the field, which motivated the development and implantation of industry innovations to enable its development. The presence of high levels of CO2 and H2S in the reservoir fluid, the risk of inorganic scaling and asphaltene deposition and risks of early fluid channeling and low sweep efficiency due to the aforementioned geological complexities are challenges that need to be addressed. One of these challenges is to ensure a better seismic data for the reservoir characterization. The 3D seismic data from a streamer acquisition did not have sufficient quality for this. The geological complexity of the field, the great reservoir depth and mainly the very irregular topography of the overlying evaporitic sequence indicated the need for rich azimuth seismic data. This led to the world's largest ultra-deep water seismic survey using Ocean Bottom Nodes (OBN) technology. This paper will address the static and dynamic data acquisition from the wells and the Early Productions Systems (EPS), as well as the challenges that arose and were faced by Petrobras through technology and innovation, and the complexity of the reservoir dynamic modelling. Furthermore, the OBN seismic acquisition in Buzios will be discussed in more detail, as well as the frontier that this acquisition opens to the development of the field.

This paper presents the lessons learnt during an intervention to remove a gas hydrate blockage and reinstate oil production from an oil well in Field D. It also uses economics to justify facilities projects for hydrate prevention and flow assurance. Field D is a deep water oil field with 10 subsea production and water injection wells tied back to a floating, production, storage, and offloading (FPSO) vessel. Field D was shut down for turnaround maintenance work during the summer of 2016. After the field was brought back online, one of the production wells (D2) failed to flow. An evaluation of the pressure and temperature data suggested that the well had a tubing restriction. This was attributed to hydrate formation and blockage caused by limited methanol injection capacity. A number of attempts were made to induce the well with no success. A subsea intervention vessel was then hired to execute a clean out intervention operation, and this restored oil production from the D2 well. To minimise hydrate blockage and oil production losses, the asset team completed a feasibility study to evaluate the viability of installing a second methanol umbilical and a test separator. The hydrate clean-out intervention reinstated oil production from the D2 well, and the feasibility study suggested that installing a second methanol umbilical and a test separator are economically attractive as standalone or joint projects. It is recommended that flow assurance strategies are regularly updated as production fluids change over the lives of petroleum fields, from dry oil production to high water cut production. This paper presents hydrate remediation steps in a producing oil field, and outlines practical methods to justify methanol umbilical capacity enhancement projects.

Asphaltenes are a major problem for oil industry. Their variability in size, structure and polarity presents a challenge to develop formulations that are effective against precipitation and deposition for all types of asphaltenes. Also, changes in production systems, such as the rate of water break through, can also impact the efficiency of dispersants. In this paper sophorolipids, a class of microbial surfactants, that are renewable and biodegradable with low aquatic toxicity, are tested as asphaltene dispersants. In order to achieve the objectives of this study, asphaltenes were extracted from a heavy oil and their solubility and stability were evaluated at different concentrations of n-heptane and water. The behavior under n-heptane concentration sweep was found to be in line with previous experimental works and water did not change that behavior. The sophorolipids were able to inhibit ~100 % of the polar asphaltenes precipitation at low concentrations. Under similar conditions dodecylobenzesulfonic acid, which was used as a benchmark for comparison, did not perform at concentrations up to 1000 ppm either with or without water. The high performance of biosurfactants is attributed to their enhanced dispersing properties for organics such as wax and asphaltenes.

As deep-water activities and development into deeper operations (depth of 6,000ft or more) increases, temperatures and pressures become favorable for hydrate nucleation and growth. This results in additional risk and challenges as to how to prevent formation of gas hydrates. This paper takes a look at the performance of a local surfactant derived from plant material in a laboratory mini flow loop made of a 0.5-inch internal diameter 316 stainless steel pipe enclosed in a 4-inch PVC pipe mounted on an external metal frame work. The performance of the local surfactant (Surf. X) was compared with that of the conventional hydrate inhibitor N-Vinyl Caprolactam (N-VCap). Varying weights of Surf. X were evaluated in the laboratory mini flow loop. Pressure versus Temperature, change in Pressure versus Time plots showed that Surf. X performed better than the conventional N-VCap in almost all the concentrations considered (except at 0.04wt %). The optimum concentration for inhibition was 0.02wt% with inhibition efficiency of 81.58% while that of N-VCap was 77.19%. The inhibition efficiency of Surf. X for 0.01, 0.03 and 0.04wt % were 72.81% and 75.44% respectively. Surf. X is locally sourced, readily available in commercial quantity and also eco-friendly because it is plant based unlike the N-VCap which is toxic and expensive. It is advised that the local surfactant X be developed as an alternative to the conventional inhibitor for gas hydrate inhibition.

Offshore reservoirs EOR present new challenges every day, during water flooding the primary injectant is sea water which is the mostly used fluid in Egyptian offshore wells in Mediterranean sea and Red sea which demonstrate undesirable problems to overall oil recovery process, main problem is scale deposits formation, specially of metal sulfate scale. Scale deposition was found in many offshore wells in injection tubes and production well and both surface and subsurface equipment causes production declines and costing millions of dollars every year In this study we developed unconventional techniques to remove and control scale formation during using sea water in injection, That techniques must be efficient and consider all reservoir and water compatibility aspects. When scales found in either in water flooding pipelines or oil production pipelines and surface equipment's, the conventional way to remove those scale and regain efficient flow is mechanical jet blasting using high-pressure water to crack the scale but it was a time consuming root and need special equipment and large man power although it wasn't that efficient in areas with heat exposure and it can't reach some areas. So we moved to next root for removing scales by chemical cleaning based on inorganic acid like hydrochloric acid, sulphuric acid, etc. although it can dissolve the scale in very limit efficiency we didn't accept this method because those chemicals was very corrosive to metal surface like cast iron and stainless steel grade 304/316 also using those chemical present hard handling problem for adding or dilution. Therefore, we had to take the challenge to develop our new chemical cleaning methodology that combines between efficiency and safety. In new methodology, we developed new chemical formula based on mild organic acid mixture combined with sequencing agent, anti-re-deposition agent, wetting agent and pickling agent to chemically dissolve the scale in efficient and safe way. The chemical cleaning technique was successful to dissolve the scale in very short time and in safe way to metal surface like cast iron and stainless steel. This invention is useful for the removal of sulphate scale like iron sulphate, calcium sulphate, barium sulphate and strontium sulphate from process equipment including pipes, pumps and storage tanks. It is also can be used to the removal of these scale deposits from other equipment such as boilers and heat exchangers.

The formation/precipitation and deposition of pipeline solids, such as gas hydrates, asphaltenes, and waxes have long plagued production fields. Given the vast differences in chemistries of these solids, any current prevention or mitigation strategy, particularly for cases where multiple issues are a concern, is likely to involve an extensive assortment of undefined chemical additives that are both costly and add complexity to the system. Surface treatments (coatings), on the other hand, present a relatively new viable option for management strategies. A chemically and physically robust surface treatment with the ability to address deposition issues for multiple pipeline solids could not only decrease the operating expenditures for a field through material cost savings and obviation of downstream separation, but could also simplify produced fluids by eliminating additional chemicals from the mixture. The purpose of this study is to explore the feasibility of a particular surface treatment as part of a solids management strategy. This work utilizes an omniphobic surface treatment to probe its effects on gas hydrate, asphaltene, and wax deposition. Specifically, high pressure rocking cells are employed to study gas hydrate nucleation and deposition. A bench-scale flowloop filled with crude oil and heptane is used to quantify the deposition of crude oil and asphaltenes after a set time period. Lastly, a mechanical shear device measures the adhesion force of wax deposits on untreated/treated surfaces. The gas hydrate rocking cell tests demonstrate an increase in induction time and occasional elimination of hydrate nucleation with the surface treatment. Moreover, the same apparatus indicates that the critical shear to avoid hydrate deposition may be lowered in the presence of the surface treatment compared to untreated pristine carbon steel coupons. A custom-built asphaltene flowloop then establishes that this surface treatment is effective in dramatically reducing the deposition of the aliphatic components of a crude oil, with a moderate reduction in the asphaltene fraction. Finally, mechanical adhesion force measurements for solidified paraffin wax display trends in agreement with the asphaltene results. The surface treatment on both pristine and corroded surfaces is able to reduce the adhesion of wax deposits to values below a pristine, untreated surface.