During the production of offshore oil and gas, the cooling of hydrocarbons toward seafloor temperatures enables the formation of gas hydrates, which may restrict fluid flow and ultimately block the flowline. During the formation of a hydrate blockage, a hydrate film may grow between individual particles or between hydrate particles and the pipeline wall, respectively resulting in a higher slurry viscosity or a reduced hydraulic diameter. This hydrate film growth rate has been previously studied as a function of pressure, temperature, and hydrate guest species, but limited data are available to guide whether naturally-occurring surface active components in the oil may affect the hydrate film growth rate. In this study, we have used a micromechanical force (MMF) apparatus to quantify the film growth rate of cyclopentane hydrate at moderate subcooling. Naturally-occurring surface active species were obtained from an Australian crude oil by solvent extraction to separate out asphaltenes, binding resins, and free resins. Each crude oil fraction was then added to a chemically inert hydrocarbon phase, and the impact of the hydrate film growth rate was measured. The results illustrate that, at mass fractions below 300 ppm, the hydrate film growth rate was reduced by at least one order of magnitude with asphaltenes and free resins being the most and least effective fractions, respectively, at suppressing hydrate film growth rate. The presence of each fraction also caused an increase in the wetting angle of the water droplet on the hydrate particle surface, which suggested that these naturally-occurring components may adsorb to the hydrate particle surface. Measurements with the MMF revealed that each of the three fractions was able to reduce the hydrate particle cohesive force by two orders of magnitude.

Asphaltenes are the heaviest and most polar class of compounds in crude oil, which may precipitate out of solution due to changes in the pressure, composition, or temperature. During production, aggregation between asphaltene solids may lead to viscosification of the oil phase and/or deposition of the solids on the flowline wall. This study presents the first measurement of asphaltene interparticle cohesive forces using a micromechanical force (MMF) apparatus, which is similar to that used previously to investigate gas hydrate interparticle cohesion. Asphaltene solids were precipitated from two crude oils, and cohesive force measurements were performed for particle pairs with diameters ranging from 100 to 200 μm. In air, the measured cohesive forces between the asphaltene particles were approximately one-half of those measured between hydrate particles in cyclopentane-saturated nitrogen vapor. Asphaltene cohesive force was measured in liquid cyclopentane, to provide a comparison against cyclopentane hydrate; in the liquid phase, the asphaltene cohesive forces were 1 order of magnitude smaller than the cohesive forces between cyclopentane hydrates. In addition, the hydrate–asphaltene adhesive force in liquid cyclopentane was measured to be of the same order of magnitude as that of hydrate particle cohesion; this result suggests the potential for asphaltene-hydrate solid aggregation as a potential flow assurance risk in oil and gas production flowlines.

During the production of offshore oil and gas, production fluids will cool toward seafloor temperatures which will place the flowline into the natural gas hydrate stability region. Small particles of hydrate can form, which can aggregate and result in blockage of the flowline. The most common hydrate management strategy involves using large volumes of thermodynamic inhibitor (THI) to operate outside the hydrate stability region. The THI hydrate management strategy represents a significant CAPEX and OPEX investment, rendering some deepwater fields economically unviable to develop. Low dosage hydrate inhibitors (LDHIs), in the form of kinetic hydrate inhibitors (KHIs) and anti-agglomerants (AAs), present an alternative to THIs. AAs allow hydrates to form, but limit hydrate agglomeration and enable the transport of a stable hydrate-in-oil slurry. AAs have traditionally been qualified for field deployment on black oils using high-pressure rocking cells and autoclaves. These tools provide qualitative assessments of AA performance, but are unable to resolve structure-function relationships at the interfacial length scale. In this study, a quantitative micromechanical force (MMF) has been deployed to study the performance of seven industry AAs. Four of these AAs are current generation AAs being deployed today and the remainder represent successive generations of AA products. The results illustrate that an effective AA must be one that lowers the cohesive forces between hydrate particles. For the four generations of AA chemistry an improvement in the maximum hydrate cohesive force reduction for the current generation chemistry (80%> force reduction) relative to the previous ones (40-50% force reduction) we observed. All current generation AA chemistries lower hydrate cohesive force by more than >80% indicating a high likelihood of successfully dispersing hydrates. To assess this likelihood each chemistry was then validated in high pressure sapphire autoclave under high shear; in this technique, which is analogous to more traditional qualification methods, performance may be quantified in terms of the maximum relative torque, defined as the ratio of the maximum torque required to maintain a set shear rate in the presence of hydrates to the torque required before hydrate formation. Consistent with the observations in the MMF, all current generation AAs kept the relative torque < 2, while systems with no AA experienced a maximum relative torque of ~20. The MMF results are consistent with the more traditional autoclave qualification but provides a more quantitative insight into hydrate cohesion which is a key aspect of AA performance.

Objectives/Scope Many midstream operators are developing plans to introduce Hydrogen (H2) into natural gas networks in concentrations of 0 to 20%. It is important to keep the concentration in all locations in the network within these limits, to reduce H2 induced cracking of pipelines and because most burners in the US are not designed for the different heating values (Wobbe Index) associated with the H2 mixtures, and flame speed present with H2 flames. This paper presents a model which dynamically tracks H2 concentrations, and associated Wobbe Index, in a complex delivery network and discusses the operational challenges associated with the introduction of H2 in these systems. Methods, Procedures, Process The model is based on proven technology which has been used on gases of variable quality for 30 years. The key item currently however is the new addition of H2 to the composition mix. The model is dynamic and responds to changes in the H2 concentration and flowrate. It is envisioned that the H2 supply to these networks will be variable (for example solar generated H2). This paper will present several case studies showing how H2 affects an existing gas distribution network and the paper will also discuss how H2 impacts the thermodynamics used in the calculation engine. Results, Observations, Conclusions The case studies will show that for even simple events like a customer trip, high concentration H2 packets can travel into pipelines that normally do not receive H2. As H2 travels through the pipeline, parameters within the system start to change such as the pipeline pressure drop increases and the compressor duty and outlet temperature increase. Novel / Additive Information The model tracks gas packets dynamically in the network (packet size is based on dispersion length) and calculates the density and energy content based on the local concentration. It then has a built in EOS (equation of state) based on GERG 2008 to calculate the density. Even with this complexity the model can run at speeds 100 times real-timefor a network that has approximately over 1,000 km of pipe.

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Top of line corrosion (TOLC) is typically a concern in the first few kilometres of wet gas pipelines where water in the warm gas condenses on the cold pipe walls. With the introduction of a subsea tieback to existing infrastructure, the changing fluid composition and temperature profiles may increase condensation in sections not previously expected to have condensation. Accurate prediction of the water condensation rate (WCR) becomes essential to support reliable corrosion modelling. Transient flow simulation of pipeline operating conditions and detailed heat transfer modelling is required to calculate the WCR. This calculation is complicated because the mass of water condensation is very small compared to the fluid mass in the pipeline, and sensitive to glycol that is often present in the aqueous phase for hydrate management purposes. This paper introduces a method to calculate WCR by using detailed transient modelling of the pipeline operating conditions. The fluid thermal hydraulic behaviour and hydraulic pressure drop in the pipeline are considered in the model. The fluid composition in the pipeline and glycol component in the aqueous phase are calculated by using a PVT software package. A few sensitivity studies will also be presented. The implications of Equation of State (EoS) and transient flow module on WCR calculation will be quantified. The WCR sensitivity results will be analysed based on varying inlet temperatures, glycol concentrations, and pipeline heat transfer coefficients. A WCR calculation method will be recommended for TOLC modelling.

Hydrate management is a pervasive challenge for the offshore oil and gas industry. The consequences of a hydrate blockage in a flowline can be significant due to deferred production and additional expenditure to remediate a blockage. A common hydrate management strategy for gas-condensate systems is to avoid hydrate formation using a thermodynamic inhibition strategy. Towards end of field life, costs associated with inhibiting produced water can increase OPEX and CAPEX. The reduced production and increased costs associated with hydrate avoidance can create economic pressure to discontinue production. An alternative to this is to consider a commercial risk-based hydrate management strategy, which can result in considerable OPEX and CAPEX savings, making marginal developments economic. A case study on the adoption of a successful risk-based hydrate management strategy is presented. The goal was to maximise production from a declining asset to deliver incremental business value. Historically a hydrate avoidance strategy had been used; to continue with hydrate avoidance would have needed further capital outlay to manage the produced water from the declining reservoir. It was determined that during normal operation, hydrate risk could be managed without the need for continuous injection of a hydrate inhibitor. Further, in the event of an unplanned shutdown, where the hydrate risk is greater, it was also demonstrated that the production system could be restarted with minimal intervention.

The growth and aggregation potential of gas hydrates in subsea flowlines are critical risk parameters for oil and gas production flow assurance. Hydrate interfaces may be exposed to water and hydrocarbon phases where natural oil surfactants may have a tendency to adsorb. The cohesion and growth between cyclopentane hydrate (structure II hydrate) particles exposed to natural oil surfactants in modified hydrocarbon phases were studied using a micromechanical force (MMF) apparatus. An Australian crude oil (unmodified), isolated asphaltenes and resins obtained via SARA fractionation and, when added to the cyclopentane phase, reduced the hydrate cohesive force by up to 98% (<1 wt % of additive). During cases of flowline shutdown, hydrate particles may have the opportunity to sinter with each other, whereby the force required to separate particles may be representative of the shear requirement to fracture aggregates in a flowline restart. The force required to separate hydrate particles was measured as a function of interparticle contact time to quantify the activity of naturally present surface-active material at resisting sintering-type phenomena. The results indicate that naturally occurring species adsorb to hydrate interfaces and decrease the extent of sintering between particles across the range of contact times studied. In a modified experimental setup, cyclopentane hydrate film growth rate measurements illustrated a comparable suppression in hydrate film growth rate to previous work. These results indicate that naturally derived surfactants from some crude oils may stabilize both water-in-oil emulsions and hydrate-in-oil suspensions. The elimination of otherwise necessary chemical management may be suitable if natural oil surfactants can perform suitable flow assurance functions.