Asaadian, Hamidreza (Petroleum University of Technology) | Soltani Soulgani, Bahram (Petroleum University of Technology) | Rezaei Gomari, Sina (University of Teesside) | Soltani Soulgani, Bahador (PetroPersian)
Gas and liquid outlets length Study and its effect on Gas/liquid Cylindrical Cyclone (GLCC) separator performance. Gas body column length Study and its effect on GLCC separator performance. Inlet diameter Study and its effect on GLCC separator performance. Study of body column diameter and its effect on GLCC separator performance. Study of gas and liquid outlets diameter and its effect on GLCC separator performance.
Gas and liquid outlets length Study and its effect on Gas/liquid Cylindrical Cyclone (GLCC) separator performance.
Gas body column length Study and its effect on GLCC separator performance.
Inlet diameter Study and its effect on GLCC separator performance.
Study of body column diameter and its effect on GLCC separator performance.
Study of gas and liquid outlets diameter and its effect on GLCC separator performance.
An experimental GLCC separator was designed and built in laboratory to determine its domain. The best operational domain is where the equilibrium liquid level placed below the inlet and between 1 L/D and 3 L/D of separator column. If it pass the inlet it causes liquid carry over and if it settles below the 3 L/D it creates gas carry under in the separator. Thus the equilibrium liquid level was measured for different range of liquid and gas flowrates. In this work the gas superficial velocity was set between 0.3 and 6 meter per second and for each gas superficial velocity, liquid superficial velocity was from 0.3 to 3.3 meter per second. Moreover, different parts of test separator was changed and their effects on the separator operating domain was studied. These changes are 12.7 mm reduction in inlet diameter size, 5 mm reduction in liquid outlet diameter size, 5 mm reduction in gas outlet diameter size, 0.12 meter reduction in gas column length, 25.4 mm reduction in column diameter size and 1.4 meter increment in outlet length.
Based on this work the following results were obtained: Reducing the inlet diameter improves the GLCC separator performance. It allows more gas and liquid flowrates enter the separator for total separation by enhancing the centrifugal effect on liquid and gas phases. Reducing the liquid outlet diameter has negative effect in GLCC flowrates domain but this reduction can be used to control the equilibrium liquid level by a gate valve in liquid outlet leg. Reducing the gas outlet diameter has negative effect on GLCC performance. But in some situations controlling the amount of accumulated gas in GLCC can avoid liquid carry over in the system. Reduction in gas column length shows no effect on the separator flowrates domain. Increasing in length of outlet legs increases the friction force and limited the separator performance. Reduction in separator body diameter raises the chance of liquid carry over and gas carry under and has negative effect on flowrates domain.
Reducing the inlet diameter improves the GLCC separator performance. It allows more gas and liquid flowrates enter the separator for total separation by enhancing the centrifugal effect on liquid and gas phases.
Reducing the liquid outlet diameter has negative effect in GLCC flowrates domain but this reduction can be used to control the equilibrium liquid level by a gate valve in liquid outlet leg.
Reducing the gas outlet diameter has negative effect on GLCC performance. But in some situations controlling the amount of accumulated gas in GLCC can avoid liquid carry over in the system.
Reduction in gas column length shows no effect on the separator flowrates domain.
Increasing in length of outlet legs increases the friction force and limited the separator performance.
Reduction in separator body diameter raises the chance of liquid carry over and gas carry under and has negative effect on flowrates domain.
These findings from GLCC performance give the main guideline to design more efficient separator design for oil and gas fields. Proper designing makes separator performance domain wider whereas it creates separators more compact which in turn minimizes the cost of construction accordingly.
Hosseini, Seyed Moein (Petroleum University of Technology) | Kord, Shahin (Petroleum University of Technology) | Hashemi, Abdolnabi (Petroleum University of Technology) | Dashti, Hossein (University of Queensland)
The main problem during field scale implantation of low salinity water injection (LSWI) is the decline in injectivity versus time. Moreover, the actual mechanisms that result in incremental oil recovery are not completely known. In previous studies, the geomechanical effects have not been considered, and pore volume changed while bulk volume is still constant which in turn can bring uncertainty to the simulation results. In this paper, both geochemical and geomechanical models have been coupled with the flow model. For coupling geomechanical model, three equations have been solved simultaneously in each time step. Then, the geochemical model has been coupled by adding the necessary aqueous and mineral reactions and ion concentration of both formation and injection waters. Increasing the Ca2+ concentration in the injected brine cause a reduction in the ultimate oil recovery. Also, increasing SO42− concentration in the injected brine up to about 70 ppm, resulted in increased oil recovery, while increasing the concentration caused a reduction in oil recovery. Injection above formation parting pressure (FPP) is beneficial but, there is a high uncertainty during injection above the FPP that can affect ultimate oil recovery and net present value. The results of this study show that geomechanical and rock parameters have intensive effects on the simulation results and rough estimating them in the simulation process can result in major errors and uncertainties. Further, it is very important to precisely include the dominant mechanisms of low salinity or smart water process during simulation studies.
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.
Moghaddas, Hamidreza (Petroleum University of Technology) | Habibnia, Baharam (Petroleum University of Technology) | Ghasemalaskari, Mohammad Kamal (Petroleum University of Technology) | Moallemi, Seyed Ali (Enhanced Oil Recovery Institute for Oil and Gas Reservoirs, Tehran, Iran)
One of the most important parameters in understanding static modeling of reservoir are having facies and their distribution in the reservoir zone. Since in the most of reservoirs facies distribution directly related to the permeability and porosity variation, therefore having these parameters can gain an estimate of the distribution of reservoir parameters. To determine lithofacies in wells and in reservoir there are different methods. One of the common method is to use the core drilling based on geological study. Recently with the image logs one can measure fracture distribution and it is a powerful tools for studying lithofacies as well. As a new work done one can determine a method to predict facies types and facies variations using image logs. Formation Micro Imager, FMI, log is the tool for illustrating geological markers through wells. FMI log could provide 80% coverage of well by high-resolution data. In this study, South Pars gas field is studied. First, Fullset logs and cross plot are generated, in order to formation evaluation, then the amounts petrophysical parameters such as saturation and effective porosity are estimated for different zones. Section K1, K2 and K4 are the reservoir areas and hydrocarbon contained zones are determined. After Lithofacies classification based on core – fullset log data and processing of FMI datasets. Finally, Lithofacies based on FMI log data modeled and clustered, this model gives satisfactory results when compared to core-log and core observed reservoir facies.
This paper has been withdrawn from the Technical Program and will not be presented at the 87th SEG Annual Meeting.
Sedaghatzadeh, M. (Petroleum University of Technology) | Shahbazi, K. (Petroleum University of Technology) | Ghazanfari, M.H. (Sharif University of Technology) | Zargar, G. (Petroleum University of Technology)
In this paper, the impact of three parameters including nanoparticles geometry, particles aggregation and borehole inclination on induced formation damage from water based drilling fluids were investigated by means of experimental studies. Accordingly, we designed a dynamic filtration setup capable to rotate and change well inclination. Nano-based drilling fluids consisting of spherical, cubical and tubular shapes nanoparticles as fluid loss additives were used. Mud cake quality, core permeability impairment and degree of formation damage at various well inclinations were examined. The cluster structure of aggregated particles were determined using fractal theory and applying dynamic light scattering technique. For this purpose, drilling fluids were circulated at different well inclinations and at a constant differential pressure against a synthetic core. Field emission scanning electronic microscopy images taken from mud cakes confirmed the proposed cluster structures of nanoparticles. The experimental results show that the mud cake quality and degree of damage are functions of produced structure of aggregated particles. Moreover, by increasing the well inclination, the skin factor increases. However, this trend is intensively depended on particle geometry. Real time analysis of pore throat size to particle size ratio during mud circulation shows the tendency of particles to create external/internal filter cake is mainly related to well inclination and particle shape. The results can be used to optimize the size and shape of selected macro/nanoparticles as additives in drilling fluids to reduce formation damage in directional and horizontal wells during drilling operation.
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.
Zohoorian, A. H. (Petroleum University of Technology) | Moghadasi, J. (Petroleum University of Technology) | Abbasi, S. (Research Institute of Petroleum Industry) | Jamialahmadi, M. (Petroleum University of Technology)
Water injection is applied as a well-established process in different reservoirs for pressure maintenance and oil recovery enhancement in the petroleum industry. Scale formation is a common challenging issue in the water injection process. In this paper, mixed salt scaling, especially that of the typical sulfate salts, is studied.
Scale formation is resulted from incompatible interactions between the injection and formation water. Precipitation of the unwanted solid materials on a surface is responsible for some problems as the formation damage, and short life of the completion equipment and surface facilities. In this experimental study, through static and dynamic tests, co-deposition of various salts during water injection is examined. Static tests are performed so as to obtain properties of the mixed salt precipitation. Further dynamic tests are conducted with different variables like the pressure, temperature, concentration, and the degree of salinity.
Several studies conclude that the success of the water injection process is mainly dependent on both fluid-rock and fluid-fluid interactions. They have also mentioned the coexistent precipitation of the salts in the water systems; nevertheless, the referred studies focus on the single salt than mixed salts due to the complexity of the process. Permeability reduction is affected by different parameters such as the mixing ratio of the injected water to the formation water, concentration, salinity, temperature, pressure, pH, and injection rate.
This research is carried out in realistic conditions so that the permeability reduction is precisely and appropriately measured by well-designed equipment. This study considers the mixed salt composition which could give a better insight into the permeability reduction than the former works, especially those which only investigated the single salt scaling. At last, a better understanding of the mechanism of inorganic scale deposition on the rock surface is provided.
Eshraghi, Ehsan (Institute of Petroleum Engineering of Tehran University) | Moghadasi, Jamshid (Petroleum University of Technology)
Electrical resistivity measurement is widely used to estimate porosity and water saturation. Archie equation is not easy to apply to carbonate rocks because formation parameters (a, m, n) are functions of changes in the pore geometry, clay content, tortuosity of the pores, as well as formation pressure. The Archie equation is also valid only when the rock is strongly water wet and clay free, which is not the case in carbonate rocks, therefore cannot be generalized over the entire carbonate reservoir, so the straightforward application of that in carbonate rocks has severe limitations.
In this paper, we discuss a new method using saturation analysis data to derive the correct form of the Archie equation that can be applied to carbonate rocks. Correlations among resistivity, and porosity derived from 108 actual core data of 18 core samples (10 dolomite and 8 limestone samples) in 6 different overburden pressures. The generalized equations can then be applied to any carbonate formation with varied geometry and clay content. The results of this comparison showed that the new developed model gave the best accuracy with average absolute errors of 20.4% and 10.9% for dolomite and limestone samples respectively, while the other common models are ranked, according to their accuracy in the following order to be Humble, Archie, and Shell, with average absolute errors of 26.0%, 26.7%, and 32.6% respectively for dolomites samples and in order to be Archie, Humble, and Shell with average absolute errors of 12.2%, 22.3%, and 26.2% respectively for limestone samples.
The advantages of this model is improving the accuracy of formation resistivity calculations by exerting the overburden pressure effect and specially usage of each formula for each mineral type.
Sulphate and carbonate scale are the most important types of inorganic scales that can be observed in majority of reservoirs which encounter scaling problem during water injection.[8-9-10-11] Precipitation of these scales may ends to dramatic permeability reduction during water injection and due to their relative hardness and low solubility there are limited processes for their removal and prevention measures such as ‘squeeze' inhibitor treatment has to be taken. In this regard, it is important to have a proper understanding of the kinetics of scale formation and trend of scale precipitation with considering the effective parameters on the phenomenon. This paper presents an experimental and theoretical study of calcium sulphate precipitation.
A series of experiments were carried out to investigate the effect of different parameters on precipitation of calcium sulphate such as temperature, concentration of brine and flow rate. In addition, three different sets of experiments with the same procedure and different experimental condition were analyzed, compared and contrasted. The functional form of permeability reduction due to effect of different parameters in all experiments persuaded us to device a method to predict precipitation trend. Finally an artificial neural network was developed based on the data that obtained from experimental works. The network can predict permeability with considering effective parameters in each section of precipitation with very good accuracy and because of wide range of entrance data it can be considered as a reliable substitute for time/expense consuming experimental works in different range of time, flow rate, temperature and brine concentration.
The success and economic justification of a water injection process depends on good recognition of process and having the ability of forecasting the possible damages. One of the serious damages that occur during water injection is deposition of scales due to blend of fluids containing incompatible brine solutions. Among different kind of scales, carbonate and sulfate scales are the most important ones that we encounter in oil field.[18-19] stable 1 shows the various types of scales that are commonly found in oil field 
For the past several years the possible benefits of GPU acceleration for reservoir simulation have been the subject of intense study by many researchers. To date results have been somewhat mixed in that the promise of using hundreds of processors available on the GPU did not achieve the anticipated parallel speedups. The reasons for this are many, but the question still remained as to whether GPU acceleration could become a viable solution for reservoir simulation. To attempt to answer this question an experimental investigation of GPU acceleration was undertaken. Experimental parameters included not only simulation model size but also the number of GPUs. Models varying up to millions of gridblocks were accelerated with up to four GPUs each with hundreds of processors. A highly parallel simple linear equation solver was the main focus of the study. Results for a single GPU indicated that speedups from approximately 25-45 could be easily achieved on the GPU if attention is paid to the use of shared memory, allocation with reduced bank conflicts, warp synchronization, coalescence, and efficient use of registers. When increasing the number of GPUs from one to four, it was noted that poor scalability occurred for the smaller simulation problems due to the dominance of overhead. Finally, a unique mixed precision algorithm showed excellent promise for improving GPU performance and scalability to greater than a factor of one hundred with four GPU accelerators. The mixed precision algorithm utilized single precision for the preconditioning with orthogonal acceleration and update being performed in double precision resulting in higher processor performance and lower memory access requirements.