Data Science Enables Management of Stealth Asphaltene Flow-Assurance Risk
Authors: Carpenter Chris 
Published: November 2024

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216216, “Managing Stealth Asphaltene Flow-Assurance Potential Risk in Gas-Injection Field Based on Data Science Using Over 20-Year Accumulated Data Set,” by Hideharu Yonebayashi, SPE, and Takeshi Hiraiwa, SPE, Japan Oil Development, and Khuloud T. Al Khlaifi, SPE, ADNOC, et al. The paper has not been peer reviewed.

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Gas injection is recognized generally not only to improve oil recovery but also to increase the risk of asphaltene destabilization. The recent discovery of asphaltene deposits in a subject field motivated the operator to launch an immediate investigation to evaluate what critical risks might exist and consider appropriate mitigation. It was found that precipitated but invisible asphaltenes still can be flowable. This stealth asphaltene behavior could explain a possible mechanism of the first asphaltene observation in the upper reservoir.

Introduction

The subject giant offshore field in the Arabian Gulf has not experienced asphaltene-induced production deterioration during long-term lean hydrocarbon gas injection. The gas has been injected into the crestal area of two reservoirs (upper and lower) with peripheral powered seawater injection. Both reservoir fluids contain a small amount of asphaltenes (0.1–1.5 wt%) distributed at higher concentration at deeper locations.

In May 2022, the first discovery of asphaltene deposits from the historical no-issued area in the upper reservoir motivated an immediate investigation for risk assessment and mitigation. A resulting study captured stealth asphaltenes, which were detected by a laser-light-scattering technique while high-pressure microscopy detected no visible asphaltene solid particles.

Historical Asphaltene Data Accumulation

The permeability range and pore-throat size of the subject field are relatively low in the lower reservoir compared with the upper. Both reservoirs are under highly unstable asphaltene-stability conditions. The reservoir pressure-maintenance scheme, consisting of dump-floodwater injection followed by peripheral powered seawater injection and crestal gas injection, however, has maintained asphaltene-free production except for the gas-injection pilot (GIP) during 2005–2009. No asphaltenes have been observed in the crestal gas-injection area; however, asphaltene deposits were observed in the GIP area in 2007. The injected gas was enriched gradually by a vaporizing gas-drive process. The previous studies involving numerical modeling analysis and laboratory experiments reported that enriched hydrocarbon gas can more easily allow asphaltene precipitation compared with lean hydrocarbon gas.

GIP Asphaltene Risk Analysis (Upper Reservoir).

In 2009, an asphaltene flow-assurance risk evaluation was conducted using the single-phase bottomhole sample collected from Well 6, which is 90 ft shallower that the GIP area and far from the crestal gas-injection area. Therefore, the Well 6 reservoir fluid was not affected by injection gas. The bottomhole condition of the GIP production well was entered into the asphaltene precipitation envelope (APE) that was expanded by injection-gas enrichment but never covered by the APE without an enrichment process.

Latest Laboratory Analysis (Lower Reservoir).

In 2022, an asphaltene flow-assurance risk evaluation was conducted. After the location was narrowed to a depth range, Well 1 was selected by taking an asphaltene gradient into account.