This paper presents the various challenges faced by a 10-km waxy crude oil pipeline at Field 23, as the pipeline has not been able to be pigged for almost one year due to recurring pigging issues such as broken/damaged pigs, vibrations and high pressures that were close to trip settings. The implemented pigging frequency as per operating philosophy is every two weeks. However, the frequency has been extended based on field experience. Due to these issues, Operation team immediate action is to devise a pigging program that works and to avoid recurring issues. Flow Assurance (FA) engineers working together with Operation team devised a plan that incorporates lab analysis and conducted desktop studies which include field data analysis and application of various FA simulation tools. The main challenge is to develop a robust FA model that is reliable enough to use for detailed analysis, be able to reproduce field data and use it to develop the most suitable pigging program. Additionally, it is worth noting that the pipeline has gone through rigorous wax chemical optimization that potentially contribute towards wax incremental issues in the pipeline. It was also observed that the fluid has changed tremendously from initial design basis due to fluid blending from non-associated gas (NAG) and oil zone and production header temperature mixing effects. Therefore, the initial operating envelope was found to be no longer suitable for this pipeline. From extensive lab analysis, fluid modelling update, metocean data calibration and wax deposition tuning, the FA models were able to match the field conditions within < 10 % variance. A field tuned baseline model was developed. Several options have been proposed and analyzed such as varying pig types, pigging and chemical methods where extensive FA modeling were performed to evaluate the suitability of each method/application to develop a more suitable pigging program. A detailed workflow on the chosen program was then produced based on a progressive pigging method utilizing multiple pig types at a reduced flowrate with chemical application. Although wax dissolution effects from wax dissolver chemical was not modeled, this model-based approach was a success in that we were able to reduce pig stuck risk during actual field implementation. The success of the waxy crude oil pipeline pigging campaign has sparked an immediate interest among the Production/Operation engineers especially on the application of a robust FA models, in which when it is well calibrated, enable effective and immediate troubleshooting of issues at site. This work has set a benchmark for FA engineers to update/develop a well-calibrated FA model during operation phase to facilitate optimization and troubleshooting programs.

Aging facilities and increasing complexity in operations (e.g., increasing water cut, slugging, sand or wax production) continue to widen the gap between actual production and the full potential of the field. To enable production optimization scenarios within an integrated system comprises of reservoirs, wells and surface facilities, the application of an integrated network modelling has been applied. The highlight of this paper is the synergy of Integrated Production Network Modelling (IPNM) utilizing Steady State Simulator (PROSPER-GAP) and the Transient Simulator (OLGA) tools to identify potential quick gains through gaslift optimization as well as mid and long-term system optimization alternatives. The synergy enables significant reduction in transient simulation time and reduced challenges in OLGA well matching, especially in selecting accurate modelling parameters e.g., well inflow performance (validated well (string) production data, reservoir pressure, temperature and fluid properties and the Absolute Open Flow (AOF) of each well). The paper showcased the successful production gain achieved as well as the workflows and methodologies applied for both Steady State Integrated Production Modelling (IPM Steady State) and Integrated Transient Network Modelling (IPM Transient) as tools for production enhancement. Even though IPM Steady State shows promising results in term of field optimization potential, to increase accuracy and reduce uncertainties, IPM Transient is recommended to be performed to mimic the actual transient phenomena happening in the well to facilities

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Hydrates have been a constant threat to subsea deepwater operations. Partial or total hydrate blockages usually occur after shutdown of a host facility, which invariably affects the resumption of production. The complexities of subsea production systems and extensiveness of deepwater fields present challenges in implementing hydrate management strategies. In the past, erroneous and ad-hoc strategies were implemented due to a lack of flow assurance (FA) awareness and understanding, resulting in production deferment caused by frequent hydrate formation/ blockages. Hydrate inhibition based on Mono-Ethylene Glycol (MEG) and Methanol (MeOH), if not properly understood and managed may lead to significant increases in a field's annual operating expenditure (OPEX). PETRONAS has gained a fair amount of experience in dealing with hydrates. The approaches taken in mitigating hydrate related issues in subsea developments have been exemplary and it is beneficial to be shared across the fraternities. These approaches will be discussed in detail throughout the article based on case studies from two subsea field developments: Field D Deepwater Gas Development and BG Gas Flowline at Field C

The dissolution of quartz mineral in sandstone reservoir due to chemical enhanced oil recovery (cEOR) processes, such as alkaline surfactant polymer (ASP) flooding has resulted in the scaling of silica and silicates around the wellbore formation and in the production wells. These scales can block and hinder the flow of producing fluids if left untreated. This will lead to reduced production rates as well as equipment damages eventually. The adsorption and squeeze performance of developed scale inhibitors that made up of polyamidoamine (PAMAM) dendrimers and pteroyl–L–glutamic acid (PGLU) was assessed in this paper. The results were compared to diethylenetriamine penta(methylene phosphonic acid), a commercial phosphonate scale inhibitor known as DETPMP. The crushed Berea sandstone core was soaked in scale inhibitor solutions for static adsorption test. Core flooding was performed to investigate the adsorption and retention of scale inhibitors in sandstone formation. The prediction of scale inhibitor squeeze performance was simulated based on core flooding data obtained. Laboratory results reveal PAMAM–2–PGLU scale inhibitor that comprises second generation PAMAM dendrimer exhibits the highest adsorption and retention in sandstone core. On top of that, the permeability of sandstone core was also increased with the treatment of PAMAM–PGLU scale inhibitors. SQUEEZE IV software also predicted that PAMAM–PGLU scale inhibitors yielded longer squeeze lifetime than DETPMP scale inhibitor. Both experimental and modelling results showed a good fit in terms of adsorption and squeeze lifetime. In this paper, the tested PAMAM–PGLU scale inhibitors demonstrate better adsorption, retention, and squeeze lifetime in sandstone formation. Although commercial scale inhibitors are effective at a wide range of reservoir conditions, the disposal of phosphonate scale inhibitors has raised concern due to their toxicity and low biodegradability. Hence, these developed PAMAM–PGLU scale inhibitors could be offered as environment–friendly and effective alternatives.