An asphaltene threat has been identified in production wells located in a Gulf of Mexico (GOM) deepwater field. After production started from different reservoirs and the operating conditions for some of the wells reached the asphaltene precipitation onset, solid deposits were detected at different points in the production system, which caused production deferrals, disturbed the operating strategy of the field, and increased the operational expenditure. To remediate asphaltene deposition in deepwater subsea wells, a rig-less remediation costs up to $0.12 million (MM); a well intervention that requires a rig costs approximately $20 MM, and a vessel-based pumping remediation costs about $5 MM. These costs do not include the impact of production deferrals.A plan was developed to acquire and interpret the required information to properly understand and manage the asphaltene threat. The methodology includes:This paper presents an integrated approach to evaluate the key elements of asphaltene risk for deepwater projects, the strategy to manage the issues during production implementation, and lay out the aspects to be considered in the mitigation of the negative impact of asphaltene thread in the field development plan.
A critical technology for composite piping systems in offshore platforms is the joining technique. This paper discusses the development of a hybrid joining approach by using heat-activated prepreg welding and adhesive bonding. The joining procedure was demonstrated via specimens' fabrication. Four adhesives, with varying mechanical properties, were used to seal the gap between the two pipes. A glass fiber reinforced prepreg was used to wrap the pipes. A total of forty-five specimens were prepared and evaluated using standardized internal pressure tests. A finite element analysis was conducted to aid in the understanding of the mechanisms of the hybrid joining method. Recommendations for further studies were made based on the test and finite element analysis results.
Asphaltene is a naturally occurring constituent of crude oil consisting of high molecular weight components which in most cases are in equilibrium within the liquid phase at initial reservoir conditions. As crude oil is produced and the energy of the reservoir depletes, the equilibrium is distressed and asphaltene can precipitate out of the liquid phase. Precipitation of asphaltenes is a condition for asphaltenes deposition, but precipitation will not always result in deposition. Deposition of asphaltene has the potential to negatively impact productivity of oil wells up to the point of completely shutting in production if the problem is not identified on time and mitigated and/or treated properly. The objective of this work is to present a systematic process for data acquisition and data analysis to identify the region in the well production system where asphaltene deposition is occurring leading to a properly designed operating strategy for production and interventions.In order to identify and mitigate (or treat) the organic damage caused by asphaltene deposition near the wellbore, a methodical surveillance plan has been developed to acquire and interpret the required information at the right stage of the oil field development. The methodology consists of combining two different approaches: 1) Laboratory analysis of reservoir fluid samples using near infrared (NIR), high pressure microscope (HPM), and particle size analysis (PSA); and 2) Pressure transient analysis and multi-rate testing.This procedure has allowed us to determine when skin develops and where in the well production system between the perforations and the downhole gauge asphaltene deposition is occurring. Specifically, we have been able to integrate results of asphaltene onset pressure (AOP) with quantification of total damage and the evolution of Darcy versus non-Darcy skin to identify if damage is worsening in the formation rock or anywhere below the permanently installed downhole pressure gauge. This paper presents an innovative approach as the integration of reservoir fluid characterization; pressure transient analysis and multi-rate testing have been combined to fully assess the damage mechanism, location of the damage, and the evolution of damage as a function of cumulative production. As a result of this methodology we have been able to properly design and schedule treatments to enhance well productivity and extend the longevity of the wells without exorbitant operating expenses and unnecessary downtime. Individually, these interventions have generated economic value and greatly increased the worth of deepwater oil fields in the Gulf of Mexico through sustainable delivery.
Integration of well and reservoir surveillance techniques: production measurements, reservoir fluid characterization, pressure transient analysis, production logging, relative permeability, and fractional flow are critical in understanding well and reservoir performance for an adequate well and field management specially in a high cost interventions environment. Well productivity deterioration for a specific well was identified based on production testing and well performance nodal analysis (NA). The productivity deterioration was then confirmed by means of pressure transient analysis (PTA). Standard diagnostic derivative analyses suggested that permeability decrease was the main source of performance detriment due to an apparent transmissibility reduction of 60%. Since water breakthrough took place before productivity impairment was acknowledged, the immediate reaction was to establish the hypothesis that effective permeability reduction due to relative permeability effects was the main reason for the impairment. A multilayer (ML) PTA type curve model together with fractional flow analysis did not support the relative permeability premise as the primary cause, leaving the potential for severe plugging of the reservoir rock as the predominant hypothesis. A production logging tool (PLT) was run confirming that about 60% of the completed interval was not producing at the expected levels. It was possible to separate the relative permeability effects from the plugging effects using the integrated technique described above. Relative permeability effects contributed to production impairment with an equivalent effective thickness of 14% and plugging effects impacted an equivalent effective thickness of 46%. A coiled tubing (CT) mud acid treatment was performed recovering approximately 65% of the transmissibility lost and decreasing formation skin from 16 to 9. This intervention delivered an instantaneous oil production benefit of approximately 7,000 STBOD. This analysis approach has been recommended to determine potential benefit of future intervention candidates. This paper presents an innovative approach to consider fractional flow as part of pressure transient analysis interpretation. This level of integration is not a common practice because PTA theory was developed for single phase and most of the commercial software products do not consider multiphase interpretations in analytical PTA. These limitations leave out the actual effect of relative permeability in the estimated transmissibility values.
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