Carbon dioxide miscible flooding is known as a very efficient and challenging enhanced oil recovery (EOR) method. Besides the high oil recovery efficiency, the asphaltene precipitation and deposition is believed to be triggered by a perturbation of the thermodynamic equilibrium present in the reservoir. Asphaltene deposition results in wettability alteration and plugging in the reservoir as well as affecting the production facilities. The complicated mechanism of phase separation in asphaltene-containing systems makes it crucial to study the effects of different parameters on the aggregation of asphaltene particles.
In this study, a novel high-pressure visual cell equipped with a high-resolution microscope along with the image processing software was prepared to investigate the growth of asphaltene particles on a sample reservoir rock. The quantity of asphaltene deposition was determined at several pressure depletion steps and different temperatures with and without CO2 injection. This would help to evaluate the kinetics of asphaltene flocculation resulting from CO2 injection or pressure drop due to natural depletion. The results reveal that the amount of asphaltene deposition increases with increasing the concentration of the injected CO2. The results of this study demonstrated that the molecular structure of asphaltene could have a noticeable effect on the asphaltene deposition.
Behzad Hosseinzadeh, University of Tehran; Mohammad Bazargan, Sharif University of Technology; Behzad Rostami, University of Tehran; and Shahab Ayatollahi, Sharif University of Technology Summary Diversion in heterogeneous carbonate reservoirs plays the most important role to the success of acidizing. Without the use of diversion, more acid preferentially flows into the high-permeability region and leaves the low-permeability region underreacted. But a clear understanding of diverting agents, such as polymer-based in-situ-gelled acids, can help uniformly stimulate the near-wellbore region. In this paper, we correct the rheological model that was developed by Ratnakar et al. (2013) according to experimental data from Gomaa and Nasr-El-Din (2010b) by considering shear-rate effect in a two-scale continuum model. It is found that the rheology parameters and shear rate are influential parameters in diversion. In addition, the amount of acid required for the breakthrough is found to be strongly dependent on rheology parameters and permeability in single-coreflood simulation. In our study, the viscosity of the spent acid is found to be the key parameter for diversion efficiency. We have constructed a mechanistic model similar to that in Panga et al. (2005) that simulates the acid injection in two dimensions. Then, we extended our simulation to dual-core systems with different permeability contrasts. The results show that there exists an intermediate injection rate that develops a wormhole in low-permeability core. The results suggest that the dissolution pattern in the high-permeability core is dependent on the permeability contrast. It changes from wormhole to uniform shape when the permeability contrast increases. Introduction Carbonate-matrix acidizing is widely used in oil fields to increase well productivity.
Geological sequestration of carbon dioxide through enhanced oil recovery operation has been recognized as one of the more viable means of reducing emissions of anthropogenic CO2 into the atmosphere. The objective of this paper is to find the best EOR scenario for a compositional grading Iranian oil reservoir to be fed by a giant power plant which produces huge amount of CO2 emission, through simulation study. For this purpose a three-dimensional simplified yet realistic model of the reservoir considering compositional grading was built based on long term production data. Various simulation cases to combine different injection schemes and examining the effect of injection rate were conducted to propose an injection-production strategy that can optimize the oil recovery along with CO2 storage. This study is the first attempt to investigate technical and economic aspects of simultaneous CO2-EOR and sequestration for the nominated reservoir. Besides, this approach could be used for any gas cycling and natural gas storage process into this reservoir.
The results presented in the study clearly demonstrated that continuous CO2 injection scheme through one injection and one production well, is the best scenario for simultaneous EOR and sequestration/gas storage which lead to higher CO2 storage and oil recovery efficiency. Through continuous CO2 injection, this reservoir has potential for large scale CO2-EOR and storage projects (injection of more than 240 thousand metric tons of CO2 per year with only one injection well without any field development plan). Finally an economic study is performed to confirm the best scenario.
Yegane, Mohsen Mirzaie (Sharif University of Technology) | Bashtani, Farzad (PERM Inc) | Tahmasebi, Ali (Digital Core Analysis Laboratory, University of Calgary) | Ayatollahi, Shahab (Petroleum University of Technology) | Al-wahaibi, Yahya Mansoor (Sharif University Of Technology)
The application of the renewable energy sources, especially solar energy, for thermal enhanced oil recovery methods as an economical and environmental valuable technique has received many attractions recently. Concentrated Solar Power systems are capable of producing substantial quantities of steam by means of focused sunlight as the heat source for steam generation. This paper aims to investigate viability of using this innovative technology in fractured reservoirs to generate steam instead of using conventional steam generators.
A synthetic fractured reservoir with properties similar to those of giant carbonate oil reserves in the Middle East was designed by using commercial thermal simulator. The dual porosity model was used to account for differences in matrix and fracture parameters. Different cyclic and continuous steam injection scenarios using combination of both solar energy and fossil-fuel to generate steam were designed. The cyclic scenarios were different in terms of contribution of solar energy in steam generation and in case of 100% solar scenario a small nightly steam injection using fossil-fuel was suggested to prevent flow back into the wellbore.
It was assumed that total amount of injected steam in 10 year time period is the same for all the scenarios regardless of how steam was generated. Simulation results showed that nightly injection of insignificant amount of fossil-fuel-generated-steam in a 100% solar-generated-steam injection process increases the cumulative oil production compared to 100% solar-generated-steam injection system with no nightly injection. Furthermore, there was no significant difference between the final oil recoveries for all the designed cyclic injection scenarios. Although continuous steam injection scenario had the highest final oil recovery among all scenarios, a detailed economical study showed that net present value for 100% solar-generated-steam scenario is the highest. An environmental analysis on all scenarios also indicated significant reduction of CO2 emission into the atmosphere for the latter scenario.
Therefore, hybrid steam generators which utilize solar energy instead of traditional fossil-fuel for steam generation is proposed for Middle East fractured reservoirs where there is abundance of sunshine during day time. The findings illustrate high economic efficiency of solar-generated steam injection and highlight it as a green EOR method.
Application of solar energy compared to conventional gas-burning boilers for steam generation in thermal Enhanced Oil Recovery processes is a newly attended technology, which brings significant benefits to the petroleum industry through environmental and economical aspects. This technique is especially designed for the regions in which gas-burning steam generation is not viable in large scale. The objective of this study is to investigate about viability of using solar energy to generate steam instead of using conventional steam generators in a Venezuelan extra heavy oil reservoir. Limited gas production policy of the Venezuelan government is the major challenge for utilizing gas steam generators for extra heavy oil reservoirs in this country. Besides, the efficient daylight duration, economic and environmental advantages, are the main features to propose solar-generated-steam injection in Venezuelan extra heavy oil reservoirs. In this study, various scenarios of steam injection on Hamaca-Venezuelan heavy oil reservoir-have been investigated using commercial thermal simulator software and the main results of oil production for similar time periods (5 years) are compared. To compensate the energy needed for the steam generators during the night time, dual types steam generators were proposed to utilize solar and fossil energies during day-time and night time respectively. The simulation results for this extra heavy oil reservoir indicated that the oil production was not significantly improved when solar method is used regardless of the amount of the nightly injection of fossil-fuel generated steam for flow back prevention. This finding illustrated high economic efficiency for solar-generated steam injection compared to dual type (solar and fossil-fuel) steam generator method. Furthermore, the results indicated that in typical imposed cyclic steam injections in integrated solar thermal projects, there is no significant difference in oil productions in various scenarios with different pattern and rate of steam injection if the total amount of injected steam is constant. In addition, this study shows the significant reduction of CO2 and Sulfur Oxides emissions if this new technology is implemented. Besides, various scenarios (with and without natural gas backup) were designed for exact day light duration profile in vicinity of the reservoir in order to optimize the oil production as well as accurate economic and environmental evaluation for each scenario.
Heidari, Mohammad A (Islamic Azad University Science and Research branch) | Habibi, Ali (University of Tehran) | Ayatollahi, Shahab (Shiraz University) | Masihi, Mohsen (Sharif University of Technology) | Ashoorian, Sefatallah (Sharif University of Technology)
Dilute Surfactant flooding is one of the significant processes in chemical flooding. Many oil reservoirs became appropriate candidates for surfactant/water flooding when screening criteria developed. Injected surfactant tries to mobilize the residual oil that was trapped in interstice. The main contributing mechanism for oil recovery improvement by surfactant flooding is rock wettability alteration. Wettability is a one of the proper index in choosing the best approach for a successful surfactant flooding which tiny change in wettability alteration will lead to improve oil recovery.
This experimental study investigated the effect of different aging time and temperature on wettability alteration with exact soaking time to find the optimum condition. Afterwards, coreflooding experiments were performed to determine the impact of dilute cationic surfactant slug with huff ‘n’ puff(cyclic 7 days) method on displacement sweep efficiency in the carbonate core from one of the Iranian oil field. Besides, contact angle and interfacial tension (IFT) measurements were done to provide the supplementary data for a surfactant/waterflooding. The optimum concentrations of C19tab, were determined by measuring interfacial tension values of the crude oil in contact with surfactant solutions, which were prepared from synthetic saline water.
The results obtained from laboratory showed a reduction in residual oil saturation by changing contact angle and IFT reduction between oil and water. Aging is known as important parameter for researcher to alter the wettability. Furthermore it proves effect of wettability alteration is more than IFT reduction.
M. Ahmadi, SPE, A. Habibi, SPE, and P. Pourafshary, SPE, Institute of Petroleum Engineering, University of Tehran; and S. Ayatollahi, SPE, EOR Research Center, School of Chemical and Petroleum Engineering, Shiraz University (now with Sharif University of Technology) Summary Fines migration is a noticeable problem in petroleum-production engineering. Plugging of throats in porous media occurs because of detachment of fine particles from sand surfaces. Thus, the study of interactions between fines and pore surfaces and the investigation of governing forces are important factors to consider when describing the mechanism of the fines-release process. The main types of these forces are electric double-layer repulsion (DLR) and London-van der Waals attraction (LVA). It may be possible to alter these forces with nanoparticles (NPs) as surface coatings. In this paper, we present new experiments and simple modeling to observe such properties of NPs. A zeta-potential test was used to examine changes in the potential of the pore surfaces. Total interaction energy was then mathematically calculated to compare different states. Total interaction energy is a fitting criterion that gives proper information about the effect of different NPs on surface properties.
Golabi, Elyas (Islamic Azad University-Omidieh) | Seyedeyn Azad, Fakhri (University of Calgary) | Ayatollahi, Shahab (Shiraz University) | Hosseini, Nooradin (Petroleum University Of Omidieh) | Akhlaghi, Naser (IAU Science & Research Branch)
The water flooding in the carbonate fracture reservoir is low efficiency because of higher permeability in fractures than in matrix, and water will not imbibe spontaneously into the matrix due to a negative capillary pressure. Spontaneous imbibition of water into carbonate fracture reservoir is a very important issue in secondary oil recovery method. However, almost more than 80% of the entire known carbonate reservoir can be categorized as oil wet. It is therefore important to find methods to alter the wettability from oil-wet to water-wet conditions that are effective in order to improve the recovery from carbonate fracture reservoir. So far, two methods have been developed wettability alterations: 1) addition of certain chemical surface active agent to the injection water, and 2) thermally wettability alteration by steam injection.
In this study, an oil sample with 20 API was used to investigate the effect of the understudied surfactants on wettability alteration in the oil-water-limestone system.
Understudied surfactants were SDBS (sodium dodecylbenzene sulfonate), C12TAB (dodecyl trimethyl ammonium bromide), C16TAB (hexadecyl trimethyl ammonium bromide) and Triton X-100 that were utilized at 0.5, 1.5 and 2.5 wt% concentrations. The experiments were performed several times (0, 1, 6, 12, 24, 48, 72, 96 h) after injection of oil drop under limestone rock sample at reservoir temperature of 80oC.
The obtained results showed that the increasing each of the surfactant could cause wettability alteration of the rock from oil-wet towards water-wet situation by passing of time. This alteration was very sharp at the beginning, but it was increases slightly at the time. It was observed that Triton X-100 was more efficient than C16TAB, C12TAB and SDBS to alter the wettability of the rock.
About half the world's discovered oil reserves are in carbonate reservoir forms and many of them are naturally fractured (Roehl and Choquette, 1985). The Total oil recovery does not exceed generally 30%. Such reservoirs are often characterized by high-permeability fractures and a low permeability matrix medium. Most of the injected water will pass through the fracture network and displaces only the oil residing in the fracture (Cuiec, 1984; Treiber et al., 1972). Spontaneous imbibition of water from the fractures into the matrix takes place if the reservoir is water-wet. However, up to 65% of carbonate rocks are oil-wet and 12% are intermediate-wet (Chillingar and Yen, 1983). Most of the oil reservoirs are found in carbonate rocks, many of which contain fractures with high hydraulic conductivity surrounding low-permeability matrix blocks that are mixed-wet to oil-wet (Allan and Sun, 2003; Roehl and Choquette, 1965; Salehi, et al., 2008).
Enhanced Oil Recovery techniques are gaining more attention worldwide as the proved oil reserves are declining and the oil price is hiking. Although many giant oil reservoirs in the world were already screened for EOR processes, the main challenges such as low sweep efficiency, costly techniques, possible formation damages, transportation of huge amounts of EOR agents to the fields especially for offshore cases, analyzing micro-scale multi-phase flow in the rock to the large scale tests and the lack of analyzing tools in traditional experimental works, hinder the proposed EOR processes.
Our past experiences on using nanotechnology to the upstream cases, especially EOR processes, revealed solutions to some of the challenges associated with old EOR techniques. This method that utilizes particles in the order of 1 to100nm brings specific thermal, optical, electrical, rheological and interfacial properties which are directly useful to release the trapped oil from the pore spaces in the order of 5 to 50 microns of tight oil formations.
Laboratory tests using nanoparticles as the EOR agent, developing nano computational models to explore the surface properties and utilizing nano-scale analyzing tools such as atomic force microscopy (AFM), scanning electron microscopy (SEM) and X-ray photoelectron spectroscopy (XPS) mostly for nanoparticles distribution in the pore spaces and on the surfaces for wettability alteration studies are the main parts of this investigation.
This paper summarizes new findings from several different theoretical, analytical and experimental works which shows the effectiveness of traditional methods when assisted by this new technology. Ultimately, based on the past experiences, a roadmap will be proposed to avoid the ongoing trial and error practice in this area.
In this study, gas-oil gravity drainage process and steam-gas assisted gravity drainage processes for heavy oil recovery from fractured models were investigated experimentally. For each test, six oil- wet saturated outcrop cores, 8.7 cm in diameter and 15 cm length, were stacked in a long core holder. In the first step, gas injection was started into the model at reservoir condition that results in oil production under gas-oil gravity drainage mechanism. In the second round of tests when no more oil was produced by gas injection, the tests were continued using steam-gas assisted gravity drainage process. In this stage, gas was injected together with specific steam/gas ratio at saturated temperature condition. In the course of experiments, oil and water productions, pressure and temperatures of system were monitored carefully. The experiments were performed using three different combination of gases consist of pure CO2, pure N2 and mixture of 15 % CO2 and 85% N2 as synthetic flue gas. The results showed that after gas breakthrough and fracture depletion, the ultimate oil recovery for CO2 injection was 58.4 % (14.8% for gas injection and 43.6 % for steam-gas co-injection), in the case of flue gas injection, it was 73.8 % (9.8 % for gas injection and 64% for steam-gas co-injection) and for N2 injection was 47% (13.5 % for gas injection and 33.5% for steam-gas co-injection). The results indicate the high performance of flue gas injection for heavy oil recovery from fractured reservoirs during gas-oil gravity drainage and steam-gas assisted gravity drainage processes.