Several gas fields are being developed off the coast of Western Australia. The risk for hydrate blockages in these fields is high and presents several challenges for hydrate inhibition, including high subcoolings, low water salinities, and high system temperatures. The current strategy is to use mono-ethylene glycol (MEG) for hydrate inhibition, which includes MEG regeneration units (MRUs) in the design of the facilities. The installation and maintenance of MRUs capable of handling the large required volumes of MEG is costly and other issues such as scale, foaming, and accumulation are a concern when using an MRU. Therefore, the use of a low dosage hydrate inhibitor (LDHI) is being considered for some developments. Kinetic hydrate inhibitors (KHIs) are typically considered for gas fields, not anti-agglomerate low dosage hydrate inhibitors (AA-LDHIs). KHIs, however, are not effective at high subcoolings and can become unstable when subjected to the high temperatures of the MRUs. Instead, a new generation of AA-LDHI chemistry can be considered for Australian gas fields. Field data will be presented supporting the new AA-LDHI’s effectiveness in inhibiting hydrate blockages in a gas/condensate field, eliminating the need for MEG and the MRU. The new AA-LDHI chemistry is being evaluated for several Australia projects, and data supporting the chemistry’s stability at temperatures greater than 150°C and its effectiveness with low-water salinities will also be presented. The new AA-LDHI chemistry could eliminate the need for MEG or greatly reduce the volume of MEG required for inhibition, which would reduce CAPEX and OPEX.

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A number of gas fields have been developed in the Middle East, Offshore Western Australia and in the Asia-Pacific region for the last five years as the demand for Liquefied Natural Gas (LNG) has grown tremendously worldwide. Most of these gas field production systems consist of long subsea flowlines, which are flowing with three phase fluids gas, condensate and water. The cold temperatures of the subsea environment pose a flow assurance risk to production, especially for hydrate blockages.The only solution currently being considered to address the risk for hydrate blockages in gas fields is the usage of Kinetic Hydrate Inhibitors (KHIs), not Anti-Agglomerate Low Dose Hydrate Inhibitors (AAHIs). The most significant production concern for all producers associated with this production scenario is that the performance of the KHI is compromised in the presence of the Corrosion Inhibitor (CI). The reason for not considering the AAHIs for this application, whose performance is not compromised by the corrosion inhibitor, is the general belief that these chemistries are predominantly water soluble and therefore increase the toxicity of the produced water.The published literature to-date is focused on understanding the interactions between the KHI and the CI chemistries to solve the incompatibility issue. The lack of literature to-date showcasing the success of such an understanding warrants a solution with a different perspective. Data is available for new generation chemistries currently being used in the industry that show greater than 99% oil solubility and would hence overcome the toxicity concern that was valid for the first generation AAHI chemistry.This new generation chemistry was tested by Heriot-Watt University in the United Kingdom (UK) that shows the product effectiveness up to 90% water cut at a reasonable subcooling, applicable for these subsea flowlines in discussion. The performance at these high water cuts will make this new generation chemistry more applicable for these subsea flowlines without the risk of hydrate blockages.

The second generation new anti-agglomerate low dosage hydrate inhibitor (AA-LDHI) chemistry is greater than 99% oil soluble and has proven performance to prevent hydrate blockages in both wet-tree and dry-tree applications. This new chemistry has been successful in field applications of water cuts up to 80%. The first generation AA-LDHIs are known to perform at low water cuts, such as less than 40%, and cause poor produced oil/water quality.Hydrate crystals formed during a flowing condition and/or shut-in condition could form a hydrate blockage and result in a production shut-down. The remediation of such a hydrate plug involves lost revenue, risk for the safety of the personnel and a potential negative impact on the environment. The subcooling involved in deepwater applications is usually higher than 25°F, which would require the use of an AA type LDHI which can protect the production systems up to 50°F subcooling.Two case studies, one for a wet-tree well and one for a dry-tree well will be presented. The results show a significant decrease in the total oil and grease (TOG) levels in the produced water and percent BS&W in the produced oil. The data will include the performance results, TOG data for long periods of time, toxicity/environmental testing data and shut-in/restart history.A major benefit of this new chemistry is that the produced water quality is improved compared to the first generation chemistry in field applications. The oil-soluble nature of the new chemistry makes the produced water less toxic and can reduce the chemical costs involved in produced water polishing. The new chemistry can extend the production life of the wells by allowing it to produce at higher water cuts. Given the high crude oil sale price, the new chemistry could add significant value to the producers while not affecting the produced water quality.

This paper presents the successful implementation of a flow assurance strategy for a new deepwater production system offshore Africa derived from results of experimental assessments of associated paraffinic and hydrate formation. The rheological behaviour of production fluids under field conditions at various pressures and temperatures are compared with results from conventional PVT and flow modelling including latest models specifically designed to review pipeline clearance times and pressure wave propagation during restart. These assessments differentiated between the individual contributions of hydrate formation and paraffin gelling and included analysis of the interaction between hydrate crystals and the wax-gel network. Additionally, the performances of Low Dosage Hydrate Inhibitor (LDHI) and Pour Point Depressant (PPD) were assessed for various production conditions in the presence of other production chemicals in the temperatures range of 65°C to 4.5°C. The results showed excellent performance of both LDHI and PPD and additionally an incremental performance from the synergy between the two applied chemistries. The predicted flow behaviour of the multiphase system based on the modelling was aligned significantly with the findings of the experimental assessment creating confidence for planned optimisation of the shutdown/restart procedure. Simultaneous formation of gas hydrates and paraffinic gels during multiphase transportation poses significant potential risks for interruption of production in deepwater operations. An accurate assessment of these risks is critical in implementing a cost-effective flow assurance strategy which will minimises downtime during shutdown and restart procedures. This investigation realises the potential development of a best practise solution to gelling problems associated with complex micro-crystalline paraffin wax. Crude oils which contain large fractions of branched and cyclic alkanes typically show poor performance with conventional PPD chemistries, but may show improved effective treatments with new chemistries specifically designed to lower the yield stress. Extension of this new treatment technology on complex waxy crude oils can encourage development of new reserves in regions such as Southeast Asia, west coast Africa, and South America where traditional chemistries are ineffective.