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.

Non-chemical scale prevention strategies are an important driver to reduce costs and minimize environmental impact on oilfield operations. Application interests includes both downhole and surface critical scenarios. Downhole use applies where chemical injection devices show low reliability or in the implementation of intelligent completion configurations which do not support chemical injection in the lower zones. This article summarizes both positive and non-conclusive experiences with different methods in onshore environment as a pilot for the implementation of massive offshore applications. The team tested electromagnetic and permanent magnet devices in different onshore and offshore applications, including downhole magnetic subs installed at a tubing string, surface electromagnetic/magnetic devices at production separation facilities and water and an ultrasonic assisted chemical remediation of an offshore hydrocyclonic separator. This article also discusses additional ongoing offshore tests. The use of several technology solutions employed so far showed promising results in order to enable subsea well construction employing completion designs with no downhole chemical injection.

Asphaltenes and waxes can precipitate and deposit in reservoirs, wells and equipment increasing production and operation costs. Previous studies showed the co-precipitation of these heavy organic compounds under field conditions and that the chemical treatment for one fraction can affect the deposition mechanism of the other fraction. These facts led to a key question: Can solvents that are normally used for asphaltenes remediations affect wax deposition? In this paper, we dealt with the impacts of aromatic solvents addition to a waxy crude and studied characteristics of wax deposits obtained from Cold Finger testing at different ratios of solvent/oil. The results showed that depending on solvent concentration the Wax Appearance Temperature (WAT), composition of paraffins and deposition rate have significantly changed. It was also shown that a biodegradable and low toxicity biosurfactant demonstrated a remarkable efficiency as wax dispersant to control and reduce organics deposition.

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.

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.

The Zohr subsea production system, around 180 km off the coast of Egypt in 1,500-m water depth, was configured with a novel metering system providing the necessary functionalities for optimized hydrate inhibition. Different subsea measurements from startup and normal production phases were obtained and combined to extract valuable information regarding water production and to monitor hydrate inhibitor dosage in real time. Conventional hydrate inhibition system overdesign and overdosage would have had a significant impact on the technical and financial viability of the Zohr development, considering that no monoethylene glycol (MEG) regeneration capability was available at startup due to the fast-track nature of the project. Therefore, it was critical to limit the use of MEG, selected as hydrate inhibitor, in order to manage the available storage capacity. A data interpretation model was developed for the subsea water analysis sensor based on flow loop testing and analytical methods, allowing for real-time measurement of the MEG dosage for each well. Flow assurance modeling was performed to validate subsea measurements, and to explore model limitations and enhancements. Field data comparisons provided unprecedented insight into unexpected reservoir behavior several weeks faster than measuring fluids arriving onshore, considering the 220-km tieback distance. Indeed, the produced fluids at startup contained water at an order of magnitude more than initially expected, which would normally have resulted in underinhibition and a possible hydrate blockage risk. The subsea measurement system allows for MEG dosage to be monitored and injection flow rates to be adjusted in real time, from the first day of production, to respond to the fluids produced subsea. With only two wells initially producing in a 26-in, 220-km-long flowline, up to 5 weeks were required until produced water was received onshore for sampling. Data analytics were applied to validate the measurements obtained, identify trends, and anticipate onshore fluid arrival conditions weeks in advance. The field data also allowed to identify areas requiring improvement and to specify additional functionality development needs. The use of innovative subsea metering and measurement systems has enabled a safe startup of the field while meeting the first-gas target date. This is the first time in the industry that a direct hydrate inhibitor concentration monitoring and control, aimed at real-time hydrate management, has been achieved subsea for gas fields. The success of this innovative application of a subsea water analysis sensor was made possible through an unusual level of collaboration and openness between the field operators and subsea hardware providers. The cooperation that occurred on the Zohr Field development, from early engineering activities to operational support, has allowed for the combined team to advance the data interpretation models, improve the concept and obtain great value from the subsea measurements. This pioneering application of subsea technology is a game changer that will enable unlocking additional long-distance deepwater gas reserves.

The deposition and growth of scale on the internal surface of oil & gas pipelines is a major challenge in the operation and maintenance of these lines. Pigging and chemical treatment are currently available solutions, but these are expensive, and a permanent passive alternative would be preferable. Diamond Like Coatings (DLC) have shown considerable promise, but the industry remains skeptical in the absence of conclusive evidence. This work addresses the question for a novel super hydrophobic DLC with a parametric evaluation of factors affecting adhesion and growth of common scale groups (such as Calcites and Barites) including surface finish of the substrate, metal composition, and thickness (or presence) of the coating, as well as the differing mechanisms of scale growth where applicable. The approach involves controlled deposition of inorganic scales onto rotational cylindrical electrodes (RCE) under varying conditions of temperature, solution chemistry, flow rates, followed by submerged jet impingement to quantify the corresponding deposit bond strengths and failure modes (cohesion vs. adhesion). Design of Experiments (DOE) methods are used to set and analyze the contribution of deposition and matrix factors simultaneously.

One of the most serious flow assurance challenges encountered during oil and gas production is the deposition of paraffins on formation surfaces, flowlines, as well as on other processing equipment. Paraffin deposition can cause problems in the production system that includes blocked pipelines, lower production rates, solids-accumulation, and increased remediation time and costs. Several thermal, mechanical, and chemical methods are used to mitigate these challenges, and, of the chemical techniques available, paraffin inhibitors are deployed to mitigate the deposition problem. Several classes of polymers have been developed into paraffin inhibitors to delay the onset of paraffin precipitation and alter the crystal morphology of the precipitated paraffin particles – these combined phenomena reduce the extent of deposition. While these polymers control wax deposition, several challenges remain for their use in both cold and deep-water environments. Many of these polymers exhibit reduced solubility in common solvents used to formulate treatment products, and, as a consequence can only be blended at low concentrations for use in harsh environments. A real demand exists for new paraffin inhibitors that have enhanced formulation-stability at much higher concentrations suitable for use under low-temperature and high pressure environmental conditions. This paper describes the developmental work and performance evaluation of a novel series of polymers specifically developed for use in low-temperature environments.

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.

The objective of this paper is to provide the results of key offshore oil and gas developments across the globe for common strategies and significant exceptions to those strategies. Most oil and gas companies have development processes consisting of the resource and terms attractive enough for development, what is the optimal path for development; detailed engineering and design; build and commission; operate and look back. Within this study, the projects examined reflect different producing basins, fluid type, and water and reservoir depths. Flow Assurance can be expressed as the coupling of multiphase flow and fluid phase behavior. There are only three questions to be answered for a pantheon of problems that can impede flow over the life of the development. The three questions are 1) will there be a flow assurance risk?; 2) how often will the issue require treatment?; and 3) can the risk be effectively managed by thermal, mechanical, and chemical means? The limitations of the strategies are becoming increasingly apparent as the requirements for system performance continue to become more demanding with changing and challenging offshore environment in the current dynamic market. Subsea technologies continue to be asked to facilitate recovering oil and gas while lowering cost while improving safety and operating efficiency to meet current industry challenges. Hence, there is a greater need to understand the flow assurance strategies to reduce overall field development costs and risk, and improve operability and reliability. Key flow assurance strategies adopted in various deepwater projects were considered for this study with an aim to summarize common strategies that arise and exceptions that could provide new strategies going forward.

One of the most promising Enhanced Oil Recovery (EOR) methods is CO 2 injection. However, if the oil contains asphaltenes, CO 2 injection may cause asphaltene precipitation and introduce production related challenges. Conventional three-phase (gas/oil/water) compositional simulators are unable to predict precipitation of asphaltenes and multiphase compositional simulators are required. The use of detailed multiphase equilibrium calculations is very CPU intensive and commercial simulation packages often employ a hybrid model that may not capture the true physics at play. Conflicting findings have been reported from experimental and theoretical studies: Some studies show that Asphaltene deposition, due to CO 2 injection, takes place near the injection well, while others have reported that asphaltene deposition occurs near the production well. True multiphase equilibrium calculations can be used to demonstrate that both findings are possible and that many factors will affect the deposition behavior. Accordingly, a general statement such as CO 2 injection causes more asphaltene precipitation relative to hydrocarbon (HC) gas injection is not always true. This added complexity indicates the need for multiphase compositional simulation to delineate asphaltene deposition behavior and quantity. In this work, we propose a four-phase compositional simulator (gas/oil/asphaltene/water) to predict the asphaltene precipitation during CO 2 and HC gas injection processes. A new hybrid formulation, based on a simple table look-up approach, is introduced to replace detailed multiphase calculations (gas/oil/asphaltene) at a CPU requirement that is comparable to two-phase (gas/oil) equilibrium calculations. A range of simulation models/scenarios are presented to test and validate the new formulation against detailed multiphase compositional simulation, and we demonstrate an excellent agreement between the hybrid model and the full multiphase calculations. The proposed approach is easy to implement in commercial tools and provides a path to allow for more detailed studies of asphaltene precipitation and related production challenges.

Some crude oils contain naturally occurring surfactants that avoid hydrate agglomeration. Natural hydrate anti-agglomeration has been linked to different crude oil fractions, including asphaltenes and petroleum acids. Asphaltenes are known to promote the formation of stable water-in-oil emulsions due to their high interfacial activity. The surfactant-like behavior of asphaltenes is directly related to their aggregation state. Asphaltenes are strong interfacial agents when in a colloidal aggregation state, but weak interfacial agents when either precipitated or well dispersed in the bulk oil phase. The asphaltene aggregation state may be artificially modified (changing the interfacial activity) by mixing crude oil with heptane-toluene mixtures (heptol). This work investigated the influence of the asphaltene aggregation state on gas hydrate agglomeration. Results show that the hydrate dispersing capability of crude oils is highly dependent on the asphaltene aggregation state. For instance, if asphaltenes were induced to be solubilized into the bulk oil phase (i.e. toluene rich heptol), the hydrate dispersing behavior was diminished. However, when asphaltene precipitation was induced (i.e. heptane rich heptol), gas hydrates were efficiently dispersed. These new findings could have important implications for the ultimate implementation of novel hydrate management strategies that can eliminate/reduce the need for external interventions and hence minimize capital and operational expenditures.

This paper presents the drivers used to determine the preferred method for pre-commissioning the flexible flowlines for a shallow water gas development project in Trinidad by BP. Upon mechanical completion, the flexible flowlines are required to be hydrotested to ensure the system is leak-free. After the hydrostatic pressure test, the industry norm is to dewater and dry the flowlines. However, the system architecture (one flexible flowline per well) requires subsea maneuvers around the subsea trees, which brings about significant risk of damaging the trees. Several alternatives (shown below) were proposed: Base Case – The original plan was to remove the tree choke insert, then insert the newly developed temporary subsea pig receiver into the choke body. Nitrogen (N2) and gel pigs are used to push water from the topsides to the subsea tree. The specification is to reduce the flowline water content to 5% or less. Alternative 1 – Involved not using the gel pigs and only using N2 gas to push the water out from the topside to the subsea tree. This alternative would not require a temporary pig receiver, which reduces the chance of damaging the choke insert profile. Alternative 2 – Involves dewatering the flowline using the umbilical tubes (methanol lines). This has an advantage in that there is no need to pull the subsea tree choke insert, which reduces the risk of damaging the trees. Alternative 3 – Do nothing and leave the seawater in the flowlines. The production stream would be used to push the water into the production system during first gas production (well offloading). The study concluded that all three alternatives were technically feasible. For Alternative 3, an additional assessment was conducted to determine the impact of seawater on the flexible pipe when exposed for an extended time. Ultimately, the decision was made to not dewater the flowlines. The corresponding well offloading (flow back) procedure and a contingency plan were then developed. The Juniper development had first gas in September 2017. The first well offloading with integrated de-watering went as planned. The decision of not-dewatering the flowlines was proven to be a good decision by reducing risks, costs and simplifying the schedule during the commissioning period.

In an effort to maximize the value of the Enhanced Oil Recovery(EOR) process, a condition monitoring software program aims to optimize Seawater Treatment system performance and maintenance efforts. By collecting digital inputs from sensors, instruments and controllers on the platform or vessel, you can monitor system behavior and use application expertise and data science to characterize the operational conditions which enable operators to reduce their operating costs and maximize production. Combining unparalleled process expertise with data science and software development team, a system-wide view of the Seawater Treatment (SWT) process is produced. Using current and historical data from SWT operations, ingesting into an IOT platform and, utilizing custom software program, provide full visualization of the system performance and condition monitoring of critical components within the system. One example is monitoring the sulphate removal unit (SRU) and predicting fouling types of the membranes. With this enhanced view of performance and predictive analysis, you can reduce the need for offshore supervision and troubleshooting efforts and can prevent repeat failures and unplanned downtime. Using the SRU as an example, the Seawater Treatment software program enables early stage detection of membrane fouling which allows the operator to proactively implement a fouling mitigation program. By detecting the fouling early, the operator can optimize the cleaning in place (CIP) sequences, perform timely CIP and chemical dosing to extend the life of the membranes and prevent unnecessary downtime and prevent permanent membrane damage. It has been observed through historical data that operators can save a significant amount of money per year on membrane life, downtime reduction and production penalty prevention. There are additional potential savings by using an optimized chemical injection program to manage and prevent biogrowth/scale formation in the system. To address the operator's need of optimizing Seawater Treatment and other topside process equipment, a suite of process specific software applications can be fully integrated into a digital platform, providing a framework that easily can be tailored to customer's needs to include additional features if required. Combining a comprehensive selection of wellstream processing technologies with deep understanding of fluids behavior and proven track record of digitalization, operational issues can now be uncovered and solved. This is different from typical remote monitoring initiatives in that it applies proven machine learning and predictive analytics frameworks to detect patterns and traces from the captured data to provide the earliest possible detection of future issues and provide proactive recommendations to prevent disruption to operations.

The goal of this study was to provide in-sight regarding use of laboratory asphaltene inhibitor testing to help guide expectations for inhibitor field performance. Specifically, this paper compares results from asphaltene inhibitor testing using two laboratory methods: (1) dead-oil analytical centrifuge stability analysis for asphaltenes method and (2) high-pressure live-fluid test that includes deposition evaluation. The analytical centrifuge method was developed as a simple laboratory test with test conditions pushed closer to field conditions than previous stability methods. As live-fluids are often not available, if data from the analytical centrifuge method can be used to help form better, more reliable field expectations, it would benefit operators in making field development plans and optimizing field operations. The high-pressure testing in this study was performed with a Solids Detection System (SDS) apparatus designed to measure asphaltene onset pressures (AOPs) of live-crude oils through monitoring near infrared laser transmittance but also run with an augmented procedure to quantify the amount of asphaltenes deposited during depressurization. Although not replicating the exact higher shear flow environment in many wells, the live-fluid SDS testing represented the closest test possible to field conditions available with our current laboratory capabilities. As such, in the absence of complete field data, it represented our next best alternative to mimic field data for use in comparison against the analytical centrifuge method. Included in this paper are results with four different asphaltene inhibitors. The high-pressure test results show the inhibitors shifting measured AOPs and reducing asphaltene deposit weights. The analytical centrifuge test results are shown over a range of crude oil to destabilizing solvent ratios at different temperatures. One example comparing analytical centrifuge testing to a field data set is also presented. Results from the study indicated that the dead-oil analytical centrifuge stability testing should be performed at equivalent temperatures and with relatively high crude oil to destabilizing solvent ratios (~30 % crude oil or greater) to achieve similar results to high-pressure live-fluid testing. When performing dead-oil testing at lower temperatures and lower crude oil to destabilizing solvent ratios, the ability of the inhibitors to increase asphaltene stability were generally significantly greater than that achieved for reducing asphaltene deposition within the SDS apparatus. Testing at lower temperatures and lower crude oil to destabilizing solvent ratios, however, did indicate trends for determining relative asphaltene inhibitor performance.

Prior to a planned transition in producing zones, an 18,000′ single well subsea tieback flowline to a deepwater Gulf of Mexico production facility experienced a restricted flowline ID and partial blockages due to paraffin deposition. Efforts were coordinated to provide support in the design, product selection, and determination of success for the flowline remediation. Transient multiphase flow simulations were created and tuned/validated with historical slugging data to estimate initial effective ID of the subsea flowline. The models were then applied to the planned clean-out procedure to develop performance indicators during and after flushing operations. A two-step remediation consisting of a 24 hour hydrocarbon solvent/dispersant mixture soak, followed by a 4,000 bbl seawater and waterbased paraffin dispersant flush at increasing rates utilizing solvency, dispersancy, and shear was used to remove deposition and increase cross-sectional flow area of the pipeline by 85% (initial effective ID ~2.5 in., final effective ID ~3.4 in.). The procedures were created to minimize risk of packing solids following initial disaggregation, while maximizing effectiveness of the flowline clean-out within the economic constraints of a depressed oil market.

The objective of this paper is to provide a review of the evolution of the flow assurance discipline over the years as it applies to the design of gathering and export pipeline systems. In the early days, pipeline design was essentially a job for one engineer when pipelines were on land or in shallow water, not in a new geological province, flowing temperatures / pressures were not abnormal, and had no multi-phase flow or contaminants. This paper will identify events or circumstances that affected how "~Pipeline Hydraulics" were designed. Flow Assurance Engineering has evolved from two fundamental pillars – thermo-hydraulic analysis of fluid flow in production systems, and production chemistry. Today, flow assurance engineers in a project not only provide predictions, but also prevention strategies, and remediation methods for: Fluid characteristics Flow hydraulics and thermal behaviors Performance of the production system Guidance of operation strategies Identification and management of solid deposition issues: hydrates paraffins (waxes) asphaltenes scales, etc. They interface with multiple disciplines involved with the project, including subsurface, pipeline and risers, subsea hardware, topsides process facilities, chemical vendors, the fluid laboratory, etc. Beginning in the late 1940s, pipelines began transporting hydrocarbons over long distances onshore (conversion of the Big Inch Crude and Little Inch product pipelines to natural gas service for example) when unforeseen flow problems began to occur. Exploration gradually moved to nearshore drilling, and finally, to shallow water. Additional flow problems increased in complexity and magnitude. To track how these increasingly complex flow problems affected pipeline design, this paper presents: The evolution of Flow Assurance from simple hydraulics calculations to a well-defined engineering discipline The critical responsibilities in current deepwater development - Greenfield and Brownfield projects The re-shaping of Flow Assurance Engineering by digital revolution and big data technologies The evolution of the discipline applying new technologies to unlock new reserves with longer, deeper tiebacks

Selection of effective paraffin inhibitors is critical for managing wax deposition risks in existing assets and for enabling potential CAPEX savings in new developments. Cold finger (CF) testing is a common method used for screening paraffin inhibitors (PI), but there are various kinds of in-house-developed and commercial CF equipment used throughout the industry. Additionally, there is no standard PI testing protocol. In some cases, there are inconsistent results between laboratories when evaluating PI performance. To better understand the root causes of PI testing discrepancies and investigate the impact of key parameters on test results, a benchmarking study using both in-house and commercial CF equipment was conducted. Additionally, Shell (the Company) and BHGE (the Vendor) conducted a detailed joint exercise to understand and benchmark the commercial CF equipment used in both of their laboratories. Finally, the laboratory results were compared against field performance through a case study for a Gulf of Mexico operating asset. PI performance was found to depend upon the particular oil as well as testing conditions, test procedures, and equipment. Good agreement in PI performance was observed between the two laboratories using the same testing conditions with the same CF equipment and equipment specifications, under similar procedures for a given crude oil. In this study, it was observed that shear and CF roughness can play a significant role on PI test results. Rougher CFs tend to make certain PIs less effective under low shear conditions. Hence, a PI chosen based on a specific set of conditions, equipment, and procedures might appreciably differ in its performance if any of the above parameters are changed. Therefore, selecting appropriate testing parameters is important to identify and qualify an effective PI suitable for a specific field application. This work makes it possible to improve standardization between laboratories and helps to better understand the limitations, uncertainties, and suitability of CF tests for predicting PI performance in the field. It also provides insights on how to design tests and equipment to better represent PI field performance.

The primary objectives of this paper are as follows: To share the lessons learnt from a recent blockage remediation experience offshore West Africa. To highlight the importance of sound engineering assessment in locating and identifying the nature of blockage and in the selection of appropriate blockage remediation technology. To present the methodology applied which minimized the need for costly rental equipment which in turn resulted in significant OPEX savings and minimal impact to production. The approach taken to remediate blockages is usually driven by the cost and time required, customer preference and remediation goals (i.e., establishing communication and flow Vs. full clean out), impact to production, operating conditions, production chemistry of the produced fluids and injected chemicals, geographical location of the field, field layout, available facilities, operating history and availability and access to specialized equipment and skilled personnel. If not properly assessed and planned, blockage remediation costs can easily go out of control with no guarantee for success and a long term solution. To minimize the required resources and maximize the chances for successful blockage remediation, a structured path needs to be developed. This paper presents and highlights the importance of accurate produced fluid sample data, information on injected chemicals and production history to determine efficiently the nature and location of the blockage. Review of the pressure and temperature sensors data at key locations along the flowpath and a good understanding of the early blockage remediation attempts and their outcomes help are key inputs to the engineering assessment of the blockage. This paper shows how the right interpretations of the sensor data prior to and during remediation of the blockage are essential part of a sound engineering assessment. The assessment followed by the selection of suitable remediation options led to the successful remediation of the blockage. The options selected were those that could be readily implemented requiring no specialized or additional equipment, avoiding alternatives that involved considerable cost and time for deployment.