Precipitation and deposition of heavy organic materials such as asphaltene inside reservoirs, processing and transportation facilities is a major concern in the oil industry. Asphaltene precipitation is one the most common problem in many reservoirs and unfortunately may lead to many safety operational issues that in end affect's oil recovery which assumes to be a major economical loss. The precipitation and deposition of asphaltene in porous media and their interactions with rock and fluids is a complex phenomenon which begs to be investigated under reservoir conditions. As yet, there have been many studies conducted on asphaltene precipitation but majority of them focused on determining precipitation onset point. It is believed, the first step in attempting to find an engineering solution to this deposition problem is to identify the conditions at which asphaltene precipitation takes place initially and conditions after that influences deposition. This paper presents an assessment of aspects that influences asphaltene precipitation and deposition. This research, attempts to understand the mechanism of asphaltene precipitation and deposition, parameters affecting the precipitation and deposition process, the effect of asphaltene precipitation and deposition on oil reservoir characteristics and performance. In addition, the research involves examining the existing thermodynamic models of asphaltene precipitation and deposition in porous media, reversibility of asphaltene precipitation and deposition, asphaltene deposition removal methods, and modelling and simulation of asphaltene by conventional simulators. Since this study is a comprehensive summary of the mentioned topics and contains all the essential information of asphaltene and its precipitation process, it therefore can be used as a reference for further exploration of this specialized field.The probability of asphaltene precipitation and deposition occurring during any EOR techniques and its effects on reservoir performance should be anticipated at earlier stages of any development project. Also it is believed that through a more comprehensive understanding of the mechanisms that lead to deposition in the first place; asphaltenes deposition if cannot be prevented fully may at least be controlled and managed.

Water alternating gas (WAG) injection has been a popular method for commercial gas injection projects worldwide. The injection of water and gas alternatively offers better mobility control of gas and hence, improves the volumetric sweep efficiency. Although the WAG process is conceptually sound, its field incremental recovery is disappointing as it rarely exceeds 5 to 10 % OOIP. Apart from operational problems, the WAG mechanism suffers from inherent challenges such as water blocking, gravity segregation, mobility control in high viscosity oil, decreased oil relative permeability, and decreased gas injectivity. This paper addresses the aforementioned problems and proposes a new combination method, named as the chemically enhanced water alternating gas (CWAG), to improve the efficiency of WAG process. The unique feature of this new method is that it uses alkaline, surfactant, and polymer as a chemical slug which will be injected during WAG process to reduce the interfacial tension (IFT) and improve the mobility ratio. In a CWAG process, a chemical slug is chased by water, preceded by gas slug and followed by alternate CO2 and water slug or chemical slug injects after one cycle of gas and water slug. Essentially CWAG involves a combination of chemical flooding and immiscible carbon dioxide (CO2) injections. These mechanisms are IFT reduction, reducing water blocking effect, mobility control, oil viscosity reduction due to the CO2 dissolution and oil swelling. CMG's STARS was used to study the performance of the new method using some of the data found in the literature. It is a chemical flood simulator that can simulate all aspects of chemical flooding, and it can also handle immiscible CO2 injection features by considering K-value partitioning. The sensitivity analysis shows that the new method gives a better recovery when compared to conventional WAG. This study shows the potential of CWAG to enhance oil recovery.

Asphaltene precipitation and deposition from reservoir fluids during oil production life is a serious problem that can cause plugging in the formation, wellbore and production facilities. Precipitation and deposition may occur during primary production, during the displacement of reservoir oil by Co2, hydrocarbon gas or WAG application. This paper describes the modelling of asphaltene precipitation and deposition in the reservoir porous media. This model is based on fluid properties of typical reservoir oil that includes asphaltene precipitation data. The pure solid model is used to model asphaltene precipitation. The fluid model part is based on the representation of the precipitated asphaltene as a pure dense phase and division of the heaviest components of oil sample into non-precipitating and precipitating components. The fluid properties data are validated and matched with equations of state. Then, it is tried to tune the equations of state based model that represent the asphaltene as pure component solid. This paper also, mentions the concept of asphaltene modeling and its related parameters by using a compositional simulation model. After tuning the equation of state (EOS) by analyzing the oil properties data and setting the asphaltene control parameters, the simulation model was built by incorporation of the equation of state for asphaltic oil properties and the other asphaltene parameters into the compositional simulation model. The model enables the simulation of asphaltene precipitation, flocculation, and deposition including adsorption, plugging, and entrainment under natural depletion and WAG application recovery processes. The model is used to investigate the effects of asphaltene on reservoir performance parameters, including wells oil production, wells bottomhole pressure, reservoir recovery factor and average reservoir pressure, also it can be used to study formation damage including reduction in porosity and permeability in each block and changes in oil viscosity and rock wettability during different recovery scenarios. Introduction Heavy organic components such as asphaltenes, resins, and waxes exist in crude oils in various quantities and forms [1–3]. Such compounds could separate out of the crude oil solution due to various mechanisms and deposit, causing fouling in reservoir, wells, pipelines and oil production and processing facilities [3]. Depositions of the heavy organics present in crude oil happen due to various causes depending on their molecular nature. Paraffin wax can deposit and form solid crystals due, mostly, to lowering of temperature. Resins are not known to deposit on their own, but they deposit together with asphaltenes [3]. Asphaltenes are arbitrarily defined as a solubility class of petroleum that is insoluble in light alkanes such as n-heptane or n-pentane but soluble in toluene or dichloromethane [4, 5]. The reasons for the asphaltenes deposition can be many factors including variations of temperature, pressure, pH, composition, flow regime, wall effect and electro kinetic phenomena [3, 6]. There are many papers that have addressed asphaltene problems during primary recovery or CO2 injection as secondary recovery stage [7–10]. Formation damage due to asphaltene deposition in the oil industry is an issue for many fields that cause reduction in production and shutting of some of the wells and a severe detrimental effect on the economics of oil recovery [1–3]. Once the asphaltene deposition occurs, it causes severe permeability and porosity reduction and wettability alteration, changing relative permeability in the reservoir and, in the severe cases plugging the wellbore and surface facilities [11–14]. It is clear that the approach taken by most operators is a remedial solution rather than preventive. The remedial measures such as chemical treatment and workover operations are disruptive and expensive [15]. Thus, the probability asphaltene precipitation and deposition occurring during any EOR techniques, its effects on reservoir performance, and preventive measures should be anticipated at earliest stages of each project. This anticipation can be reached through better understanding of the mechanisms up front that initiate such problems [10].

Asphaltene precipitation and deposition problems are one of the severe problems which some reservoirs may face with them during their production life. Asphaltene deposition can affect on reservoir performance such as porosity and permeability reduction, wettability alteration, moreover it may lead to plugging of wellbore and production surface facilities. These effects can be modeled by consideration some asphaltene control parameters by activation asphaltene option in compositional simulation package. These parameters are usually estimated from core flooding experiments. This paper mentions the concept of asphaltene modeling and its related parameters and also describes the numerical study results of the effect of asphaltene precipitation and deposition control parameters on reservoir performance, by using a compositional simulation model with asphaltene modeling options. For this purpose, the real reservoir geology model and fluid data are used. After tuning the equation of state (EOS) by analyzing the oil properties data and setting the asphaltene control parameters, the simulation model is built by incorporation of the EOS for asphaltic oil properties and the asphaltene parameters into the compositional simulation model. The model enables the simulation of asphaltene precipitation, flocculation, and deposition including adsorption, plugging, and entrainment. Also, it can show the resulting reduction in porosity and permeability and changes in oil viscosity and rock wettability according some range of asphaltene control parameters. The model is used to investigate the effects of these parameters selection on reservoir performance, including oil production, recovery factor and average reservoir pressure, also, asphaltene behavior including precipitation, flocculation, adsorption, plugging and entrainment, moreover, formation damage and its effect of rock wettablity changes. The results show the effect of the asphaltene precipitation and deposition parameters selection on reservoir performance clearly, so it should correctly calibrate and carefully use them for modeling. Also, for reservoir that does not have any asphaltene core flooding experiment, they will be useful for estimating the asphaltene model input parameters and its effect on simulation results.

Average recovery factor in offshore field under discussion is relatively moderate due to wider well spacing and poor sweeping efficiency thus leaving significant volume of oil behind in the reservoir. Timely application of EOR is therefore necessary to enhance the recovery factor to a reasonable level. Among the various EOR processes and techniques of EOR screened, studies found immiscible water-alternating gas (IWAG) injection as the most suitable and viable option for this Malaysian mature offshore oilfield. Realistic estimate of incremental oil by EOR is paramount as IWAG application involves high CAPEX and OPEX project. Therefore, representative is required to be generated in the laboratory for constructing a realistic reservoir simulation model to understand the three phase flow in porous media and support the IWAG process for full field implementation. Important parameters in this case are residual oil saturations in sequential injection of displacing fluids water and gas and trapping of gas, injection volumes and frequency of alteration. Therefore, IWAG core flooding experiments under reservoir conditions need to be performed, results quantified and parameters for hysteresis modeling established.This paper addresses the challenges and strategies of IWAG core flooding experiment performed under reservoir conditions using representative composite native cores, live reservoir oil sample, field produced gas sample and synthetic formation brine water. The laboratory injection rates are considered equivalent to the field fluid advance velocity like in any standard displacement steps. Also, gravity stable injection mode is considered to achieve the best IWAG displacement performance. These challenges and strategies are drawn from lessons learned during accomplishment from earlier IWAG core flooding experiments. The IWAG core flooding experiments were performed on composite field core samples, arranged according to Langaas method, using current field production gas with 60 mole % CO2. The composite reservoir core samples were initially saturated with live oil and irreducible formation water and then flooded with formation water and seawater to residual oil saturation at reservoir conditions. Following, waterflooding, a number of water and gas cycle slugs were injected. The displacements were conducted at pressures well below the estimated minimum miscibility pressure during these experiments. Laboratory studies and numerical simulation study conducted on the applicability of immiscible WAG injection using high CO2 content produced gas indicated that 7.0 % additional oil recovery over waterflooding period can be recovered.