The objective of this research is to properly calculate the association energy with molecular models of asphaltenes using Molecular Dynamics (MD) simulations. Asphaltene precipitation clogs pore throats of reservoir rocks, and significantly reduces the production rate. To better understand the asphaltene precipitation, a process-modeling methodology has been developed. The cubic-plus association equation of state (CPA) (Li & Firoozabadi, 2010) is effective in the modeling, and contains only one adjustable parameter, that is, association energy of asphaltene, however, we were not able to correctly evaluate the association energy by the currently available methods. Quantitative Molecular Representations (QMR) method provides systematic structural representations of asphaltenes based on analytical data of a crude oil, from which molecular models of asphaltene can be obtained. These models will be employed in this study for calculation of the association energy. Two different asphaltene models were generated for two different crude oils (Oil 'A' and Oil 'M'). The potential of mean force (PMF) is calculated with two models of asphaltene molecules in liquid benzene for two kinds of asphaltenes using umbrella sampling method. The association energy is calculated by the difference between values at the lowest bottom of a trough and at infinity of the PMF curve. As the calculation conditions, temperature and pressure are 300 K and 100 bar, respectively. The PMF profiles for asphaltenes from Oil 'A' and Oil 'M' were obtained, and the values of association energy were estimated as -8.39 kJ/mol and -8.91 kJ/mol, respectively. Two aromatic planes of asphaltene molecules are stacked with each other at the minimum energy point. This π-π stacking is one of the main interactions to form asphaltene nano-aggregation. The results of asphaltenes from Oil 'A' and Oil 'M' have a similar tendency; for example, the distance between the centers of mass of two asphaltenes at the minimum energy points factually equal. The data obtained in this work should be used in the thermodynamic model of phase behavior of asphaltene dealing with asphaltene association and precipitation. It will improve the prediction ability of reservoir simulators with cubic-plus association equation of state.

Description: Identifying and understanding wettability alteration caused by asphaltene deposition, and its implications for field development optimization is growing in interest. In this paper, we present a field case study on the cause of an unexpected decline in reservoir productivity and simultaneous rapid increase in water production. We concluded that the decline in productivity and water cut increase were caused by asphaltene precipitation in the formation with a subsequent increase in the water relative permeability. This was caused by alteration of rock wettability from water-wet to oil-wet by asphaltene deposition.Applications: This work's findings can improve understanding of reservoir performance and help optimize reservoir management strategies for oil reservoirs with potential asphaltene precipitation problems. Results and Conclusions:All possible parameters in the reservoir simulation model was thoroughly examined and discussed. Switching the relative permeability type from water-wet toward oil-wet at the asphaltene onset pressure (AOP) yielded an excellent history match with the observed rapid water production increase. The reservoir had been depleted following primary production; the laboratory PVT data indicated that the AOP was a little below the initial reservoir pressure and hence asphaltene precipitation had been predicted.Technical Contributions: This work contributes to (1) providing a field case bridging asphaltene deposition and wettability alteration, (2) understanding phenomena such as rapid increase in water production associated with asphaltene deposition, and (3) optimizing reservoir management and field development for oil reservoirs with potential asphaltene precipitation problems.

1. Takaaki UetaniAbstract The Minami Kuwayama eld, one of the largest oil elds in Japan, began production in 2003. Severe asphaltene problems have been experienced in all wells, in both the reservoir and production tubing, and at the surface facilities. We have been operating this eld for over 10 years and learned that we could sustain the productivity through the use of chemicals and the control of production rates. This article provides our experience and major ndings.

Summary This study aims to clarify a phenomenological relationship between earthquakes and temporarily improved oil recovery for a small oil field located in a seismically active region of Japan. Our study concludes that the conditions required for an earthquake to temporarily improve oil recovery in this field are as follows: An earthquake with a seismic intensity of at least 3 hits the well. The well experiences a decline in productivity, with a flowing wellhead pressure of less than 690 kPaa (100 psia). The corresponding skin factor lies within the range of 18 to 40. The well is producing oil from a reservoir.

Many mechanisms have been proposed for low salinity waterflooding enhanced oil recovery (EOR) in carbonate rocks over the last decade, and they are still in debate. One suggested mechanism is the dissolution of anhydrite (CaSO4) mineral from a rock material, which generates sulfate ions in-situ, and subsequently acts as a wettability modifier chemically. Another suggested mechanism is the increase in permeability due to mineral dissolution. Primary objective of this work was to verify whether dissolution of anhydrite could be the key low salinity waterflooding EOR mechanism. Spontaneous imbibition tests were conducted using six rock samples from two carbonate oil reservoirs. The first reservoir rock contains anhydrite, while the second reservoir does not contain anhydrite. If anhydrite dissolution is the key mechanism, then the amount of increased oil recovery due to low salinity brine should correlate with the amount of anhydrite dissolved from the rock. Our experimental results, however, did not suggest such a relationship. Hence, anhydrite dissolution was considered unlikely as the key mechanism of low salinity EOR for the crude-oil, brine and rock (COBR) system used in this study.