The effect of fracture characteristics on reduction of permeability by asphaltene precipitation in carbonate formation

Dynamic displacement experiments, simulating temperature and pressure conditions of an oil-bearing formation during primary production stage, were carried out to investigate the processes of asphaltene-induced precipitation and deposition during pressure depletion on a core sample and their effects on the absolute permeability. A representative monophasic-bottom-hole fluid sample and one core of consolidated Bedford limestone were used in coreflood tests. To identify the pressure and temperature conditions at which the asphaltene will begin to precipitate, as well as the bubble-point pressures of the reservoir fluid sample, the light-scattering technique solid detection system (SDS) using a variable volume, visual P V T cell was used. The coreflood test results indicated that the in situ asphaltene precipitation and deposition on porous medium damage absolute permeability and reduce effective porosity as reservoir fluid pressure is reduced until a point near bubble-point pressure. Core impairment, resulting from asphaltene deposition, was found to cause a 24% and 20% loss of initial oil permeability and effective porosity, respectively. A mathematical model, based on the transport of stable particulate suspensions in porous media, for asphaltene deposition was developed and validated directly with experimental results obtained in this investigation, as well as those found in the literature. On the basis of the developed mathematical model, two distinct mechanisms were identified as a consequence of the deposition process, namely, asphaltene adsorption and trapping. The porous medium was represented as a network of sites and bonds, with pore bodies identified as sites and pore throats as bonds. A satisfactory qualitative agreement was observed with the experimental results.

Section: Introduction and Reviewmentioning

confidence: 99%

Asphaltene-Induced Precipitation and Deposition During Pressure Depletion on a Porous Medium: An Experimental Investigation and Modeling Approach

Cruz¹,

Argüelles‐Vivas²,

Matías-Pérez³

et al. 2009

“…Asphaltenes are the heaviest components in crude oil . Their aggregation and interfacial activities pose serious problems during oil production, such as changing the wettability of the oil reservoir, choking the pore throats, and stabilizing the interface between water and oil. ,,,− Spontaneous aggregation of asphaltenes is mostly studied in toluene, in which asphaltenes are by definition soluble. It was observed that, above the critical nanoaggregate concentration (CNAC), on the order of 100 mg/L, nanoaggregates are formed each containing a small number of molecules (<10).…”

Section: Introductionmentioning

confidence: 99%

Probing the Effect of Salt on Asphaltene Aggregation in Aqueous Solutions Using Molecular Dynamics Simulations

Sun

Jian

et al. 2018

The presence of salts in different processes of oil production has attracted wide attention because of its effects on asphaltene aggregation, stability, interactions of emulsions, etc. In this work, molecular dynamics simulations were employed to study the effect of salts on aggregation of model asphaltenes. Four types of polyaromatic compounds possessing key structural features of continental-type asphaltenes were dispersed into NaCl solutions of different concentrations. These models have the same polyaromatic core but different lengths for the side chains. In the two models with relatively long side chains, the hydrophobic association among side chains is the main driving force for aggregation. The effect of salt on aggregation is therefore closely tied to its influence on the hydrophobic interaction: the salt ions promote the hydrophobic interaction at a low salt concentration while suppressing it at a high salt concentration. For the model with an intermediate side chain length, the hydrophobic interaction between side chains becomes less dominant and the salt has mutual influences on the core–core, chain–chain, and core–chain interactions. For the model with the shortest side chains, although the core–core and core–chain interactions are more important, the side chains still play a role in aggregation when the salt is present. Our results provide new insights into the fundamental understanding of the influence of salts on the aggregation and interaction behaviors of polyaromatic compounds in an aqueous environment.

“…Several studies observed asphaltene deposition on the core scale while using a hydrocarbon solvent for heavy oil recovery. − Such studies cannot directly observe the mechanisms involved in asphaltene deposition. However, Arciniegas and Babadagli observed the asphaltene deposition on glass beads under a microscope after solvent injection.…”

Section: Introductionmentioning

confidence: 99%

Dynamic Behavior of Asphaltene Deposition and Distribution Pattern in Fractured Porous Media during Hydrocarbon Solvent Injection: Pore-Level Observations

Telmadarreie

Trivedi

2017

Precipitation and deposition of asphaltene in reservoir rock can cause formation damage and reduce the fluid mobility, resulting in significant loss of hydrocarbon production. A detailed study on asphaltene deposition behavior in porous media improves the understanding of asphaltene-induced formation damage and provides the possible solutions for preventing and/or controlling formation damage. For advancements in understanding asphaltene deposition in fractured porous media, asphaltene deposition behavior was analyzed with the help of pore level observations during hydrocarbon solvent injection. Three types of hydrocarbon solvents (nC5, nC7, and nC12) were used for solvent injection for extra-heavy oil recovery (30 000 cP at 22 °C). A uniquely designed heterogeneous-fractured micromodel imitating the fractured porous media was used for pore level observation. A high-quality camera along with a microscope was utilized to capture images. SEM analysis was also performed on precipitated asphaltene to visualize the difference in the structure of the asphaltenes precipitated with different solvents. Observation through this study revealed that besides the amount of asphaltene deposition, the distribution pattern of asphaltene deposition could also be different when using various types of solvent. Besides decreasing the amount of asphaltene precipitation, the deposited asphaltene distributed more widely in the studied porous medium as carbon number of solvent increased (C5− C12). Moreover, it was noted that asphaltene could be deposited in different shapes that may or may not block the pore throat. The dominant flow mechanism (either diffusion dominant or viscous dominant) will affect the shape of deposited asphaltene. Asphaltene can be deposited perpendicular or parallel to the flow direction, which is in the form of parallel rope-shaped deposits. The perpendicular deposits (usually in dominant diffusion flow), mainly observed in small pore throat, can block the diffusion path. However, the parallel deposits (typically in viscous dominant flow) will not significantly impede the flow path. The results of this study improve our understanding of different aspects of asphaltene-induced formation damage in the fractured reservoirs such as susceptible locations of asphaltene deposition, different shapes of deposition which may or may not result in pore blocking, and the effect of flow behavior and heterogeneity on asphaltene deposition and formation damage.