Productivity Decline in Oil Wells Related to Asphaltene Precipitation and Emulsion Blocks

The ideas of open and closed-boundary systems are explored to investigate the technical limits of storage capacity of subsurface porous media, as required for the CO2-mitigation technology of carbon capture and storage (CCS). In particular, the effects of reservoir characteristics as well as the nature and mix of fluids that originally saturate the porous media are elucidated. An improved analytic method, premised on the concept of in-situ fluid displacement and replacement, of estimating the storage capacity of open systems is proposed and evaluated.For closed systems, our analyses show that the general order of attractiveness (technical storage capacity) of potential sites is aquifer < water-depleted oil < undepleted oil < gas-depleted oil < depleted gas < undepleted gas formations. However, owing to the complexity of microscopic and macroscopic events, similar simple conclusion can not be drawn on the relative attractiveness of various open-boundary sinks.As a case study, we examine the applicability of CCS in Nigeria. From first-order estimates of the pore volumes and other reservoir-fluid properties in Nigeria, we quantify the limits and time-scale of "available" geologic sinks to accommodate current and future loads of anthropogenic CO2 emissions from the Nigerian fossil-fired power sources.Due to the relatively poor storage capacity of the potential sites compared to the anticipated CO2 load from power plants, which is just one of the CO2 sources, sequestration into underground formations may not, on its own, be a sustainable technical solution for Nigeria. Additionally, for the open systems, which define the upper limits of storage capacity, the potential challenges of managing displaced formation brine (and other less valuable fluids) may be overwhelming. As a complement, we offer some potential outlets for CO2 generated from these captive and other sources. Finally, long-term carbon-mitigation strategies hinged on mixed solutions are enumerated.

Section: Resultsmentioning

confidence: 99%

An Improved Estimation of the Storage Capacity of Potential Geologic Carbon-Sequestration Sites

Lawal¹

2011

“…Asphaltene related production problems are widely reported in the literature in various parts of the world (Garcia et al, 2001;Garcia et al, 2003;Al-Qabandi and Al-Naqi, 2003;Kokal et al, 2003;Lightford et al, 2008;Sanada and Miyagawa, 2006). The problems of asphaltene precipitation and deposition can be encountered anywhere during the production ranging from near well-bore, completions, tubing, riser and surface facility.…”

Section: Introductionmentioning

confidence: 99%

Systematic Evaluation of Asphaltene Formation Damage of Reservoir Fluids from Lake Maracaibo, Venezuela

Memon

Borman

García³

et al. 2014

One of the most concerning areas for asphaltene deposition is the near-wellbore region, where such deposition causes formation damage. The reservoir fluid of the Lake Maracaibo region is known to experience operational problems due to asphaltene deposition inducing production losses. A detailed asphaltene formation damage investigation was performed on the live oil samples from the Lake Maracaibo area. An unusual asphaltene precipitation envelop was observed for this fluid and reported in an earlier publication (Gonzales et al., SPE 153602, 2012). In the current paper, we focus on the systematic evaluation of asphaltene formation damage using stacked composite core samples. A special coreflood system was designed for an asphaltene formation damage study using reservoir core samples and sourlive reservoir fluid samples. The effect of flocculated asphaltene in the porous media was evaluated as the reservoir pressure decreases below the asphaltene onset pressure (AOP). Live samples were collected and flooded through the stacked composite core plugs under reservoir conditions. Progressive pressure reductions were performed to induce asphaltene precipitation in the porous media. Oil permeability changes were measured to evaluate the effect of this phenomenon in the reservoir using composite core. Significant impairment of composite core was caused by the depressurization of the reservoir fluid below AOP. The inlet pressures of the composite core stack were maintained just above AOP and the outlet pressure approximately 50 psi above saturation pressure throughout the core flood experiment. Thus, asphaltene precipitation onset occurred inside the composite core.This experiment showed significant permeability loss in the composite core after sufficient flooding of live oil fluid. Following the core flood experiment, the core stack was depressurized, and the remaining hydrocarbon was extracted from individual core plugs. Detailed chemical analyses were performed on the extracted hydrocarbon deposits from individual core plug with various analytical techniques, such as asphaltene content, simulated distillation, optical density, and thin-section analysis. These analyses' results confirmed that the observed oil permeability loss was indeed due to the formation of asphaltene deposit inside the porous media, and the asphaltene deposition was somewhat more extensive in the tighter core sections.

“…Productivity and injectivity decline caused by asphaltene deposition is a well-documented operational problem in petroleum engineering (Kokal et al, 2003;Cenegy, 2001). Despite its role in defining the bulk properties of crude oil, the chemistry of asphaltenes is poorly understood (Badre et al, 2006;Jamaluddin et al, 2002).…”

Section: Introductionmentioning

confidence: 99%

Modelling Asphaltene-Induced Formation Damage in Closed Systems

Lawal

Vesovic

2010

This paper implements a simple one-parameter semi-analytic model for asphaltene-induced reduction of porosity, pore-radius and permeability in closed systems. By treating sedimentation as the dominant deposition mechanism, dynamics of asphaltene deposition under "stagnant" conditions is provided, elucidating the dependence of damage rate on the size of asphaltene aggregates as well as rock and fluid properties. Parametric studies indicate that while the rate of formation degradation depends on rock and fluid properties, ultimate severity of impairment is primarily controlled by in-situ asphaltene content. The proposed model has been used to explain the general observation that light oil systems are more vulnerable to asphaltene damage, than the heavy oil systems. Validity of proposed model is demonstrated by comparing with available experimental datasets that include both sandstone and carbonates. In all cases, experimental results have been matched within 7% accuracy using the proposed model with a single adjustable parameter. Furthermore, thermal simulation studies conducted on a hypothetical but representative heavy oil reservoir highlight the detrimental effects of impairment on field-scale oil recovery and thermal efficiency. Both the models and results presented should be useful for studying impairments induced by asphaltene and other deposits.