In joining technology, welding is one of the vital techniques used to make continuous pipelines in industry. The thermal and mechanical loading in the process has a profound impact on the integrity of the pipeline over its service life. An accurate and thorough assessment is needed on the associated residual stress and its effect on the structural properties of the pipeline. One of the novelties of this research is the understanding of the welded joints' temperature responses, as demonstrated by positioning high-temperature thermocouples at strategic points on the welded joints to capture the transient temperature response at different points. It is not enough to assume that the distribution of heat through the weld metal will depend on the distance from the thermocouples to the heat source only; the temperature profile must actually be studied to uncover any peculiar trends.
Hydraulic fracturing is a powerful technology being used for decades in the petroleum industry to recover and/or enhance the permeability. The fully 3-D numerical simulation of the hydraulic fracturing process is a great useful tool to analyze and optimize the designing stage of the stimulation, it, however, is a difficult challenge due to the strong nonlinearity of coupling between the viscous flow of fluid and fracture propagation. In this study, a coupled hydro-mechanical 3-D numerical model based on the finite-element method has been developed to simulate the hydraulic fracturing process in naturally fractured reservoirs (a common feature of Iranian hydrocarbon reservoirs). In addition, by taking advantage of this model, reservoirs with damaged-zone have been investigated. In this model, the fracturing process governed by a cohesive-zone-model within a poroelastic medium. Cohesive-zone-model enables us to assign individual criteria for fracture initiation and propagation for each simulation. The results revealed that hydraulic fracturing might not be always beneficial in case of reservoirs with strongly damaged-zone. This is caused due to the increase of pore pressure in damaged-zone, and the plastic flow of the fracture wall. Thus, it is recommended to improve the permeability of the damaged zone in prior to hydraulic fracturing operation with another method such as acidizing. Furthermore, the results showed that the fracture propagation stops once the fracture tip meets major natural preexisting fractures. Accordingly, the final induced-fracture length is strongly affected by the location of the natural-fracture network. Moreover, based on the results, the highest fracture-closure pressure occurs at the fracturing initiation point on the well-bore wall. This should be considered at the proppant embedment designing stage, since if the proppant resistance fails to bear this load, the reservoir connection with the well-bore through the fracture would be either poor, or lost. Hence, the hydraulic fracturing job would fail, or not be efficient.
Hydraulic fracturing is a process designed for stimulating and improving the function of oil, gas, and geothermal wells (Brown, Smith, and Potter 1972; Ernst 1977) to enhance their productions. This technology could also be applied to other type of wells such as injection or water disposal wells (Zimmermann and Reinicke 2010). Moreover, this technology is being used in nuclear industry to extract uranium sources. In technology, by injection of a high-pressure fluid (fracking fluid consists of a mixture of viscous hydraulic fluids and sorted sand, so-called proppant) into a wellbore the rock formation would be pressurized and finally fractured. The increasing pressure propagates the induced- crack whose length may exceed more than several hundred meters. Afterwards, when rock is fractured and the pressure of the injected fluid is removed the suspended solid phase, which remains inside the crack will keep the fracture open. Such a fracture provides a high permeable flow path through for the fluid to be either extracted, or injected. According to review studies hydraulic stimulation technique is the most common applied wellbore stimulation technique worldwide (Mack MG 2000; Breede et al. 2013).
Filtrate and solid invasion from drilling fluids are two key sources of formation damage, and can result in formation permeability impairment. Typically, spurt invasion of mud solids causes the evolution of an external mud cake which tends to reduce further solids and filtrate influx. However, uncontrolled spurt and filtrate invasion are detrimental because they reduce the permeability of the formation. Mud composition, formation rock's permeability and porosity, and temperature can influence both spurt and filtrate invasion. The sizes of mud solids relative to the average pore size of a rock are also important in predicting the extent of mud invasion and permeability impairment.
In this paper, a dynamic modeling approach is presented for mud solids deposition on the pores of rock samples for different lithologies. The modeling results were compared to experimental values. To simulate a close-to-real field mud invasion and damage scenario, rock samples were first subjected to a dynamic-radial fluid loss test under controlled laboratory conditions. The geometry of the simulated drill pipe and inner diameter of the cores allowed for uniform mud cake evolution around the wall of the cores. Three different rock samples (Michigan sandstone, Indiana limestone, and Austin chalk) were investigated. Two water-based mud (WBM) samples were formulated to simulate high and low fluid loss recipes. Next, scanning electron microscopy (SEM) imaging of the dry cores coupled with image processing was used to determine the porosity and pore size distribution of the internal mud cake. The structure of the porous rocks as well as the mud cake were modeled using the bundle of curved tubes approach. In addition, the deposition probability of mud solid particles was considered through filtration theories. Experimental results showed up to 40% reduction in mud invasion and damage to the rocks using the low fluid loss recipe. The model developed in this study closely matched the experimental results. The model revealed a maximum relative error of about 9.6% for one out of the six case studies, and an average relative error of 3.3% for other case studies. The novelty in this study is the quantitative utilization of SEM images by applying watershed segmentation algorithm to detect and measure the size of mud cake pore spaces. This approach can be implemented in the design of drilling fluids that can reduce formation damage.
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.
Kostarelos, Konstantinos (University of Houston) | Martin, Clint (University of Houston) | Tran, Kyo (University of Houston) | Moreno, Jose (University of Houston) | Hubik, Aaron (University of Houston) | Ayatolli, Shahab (Sharif University of Technology)
Asphaltenes represent the heaviest fraction of crude oil, which are known to precipitate when the crude is added to aliphatic solvents such as n-pentane or n-heptane and yet remain soluble in light aromatic solvents such as benzene or toluene (Gawrys et al. 2006; Borton et al. 2010). They are characterized by highly complex structures that contain multiple aromatic rings and have a large hetero-atom content (e.g., nitrogen, oxygen, and sulfur) and metal content (e.g., vanadium and nickel) (Yarranton 2000; Hashmi and Firoozabadi 2012).
Asphaltenes tend to self-associate on a molecular level, depending on the composition, temperature, and pressure of the system. Precipitation of the particles out of solution results in flocculation, where they begin to deposit on hydrophobic surfaces such as metal pipes and surface equipment used for the production and transportation of crude oils (Khvostichenko and Andersen 2009). These tendencies result in reduced flow or complete blockage of producing wells and surface equipment, including pumps, pipelines, and separators.
Currently, the only methods of treatment are through the use of chemical dispersants and inhibitors, which increase the stability of asphaltenes to prevent deposition. Once asphaltene deposition has occurred, running a “pig” through the pipeline is often the method used to scrape the solids that accumulated on the walls of the pipe. It is known that asphaltene molecules can be polarized, gaining an electric charge by introducing an electrostatic field (Hashmi and Firoozabadi 2012; Khvostichenko and Andersen 2009; Khvostichenko and Andersen 2010; Hosseini et al. 2016). The polarity of the asphaltene particles is directly related to its hetero-atom content, with a higher hetero-atom content giving increased levels of polarity and a higher rate of aggregation (Hosseini et al. 2016).
Experimental DeviceOur ultimate goal is to build a device (Fig. 1a) that would remove asphaltenes from crude oil near the point of production, using electrokinetics. Thus, a scaled-down device (Fig. 1b) was fabricated and tested using a model oil to prove the concept and study some of the parameters that would influence the design of a larger-scale device.
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.
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.
Kahrobaei, Siavash (Delft University of Technology) | Habibabadi, M. Mansoori (Delft University of Technology) | Joosten, Gerard J. P. (Sharif University of Technology) | Van den Hof, Paul M. J. (Shell Global Solutions International) | Jansen, Jan-Dirk (Eindhoven University of Technology)
Classic identifiability analysis of flow barriers in incompressible single-phase flow reveals that it is not possible to identify the location and permeability of low-permeability barriers from production data (wellbore pressures and rates), and that only averaged reservoir properties in between wells can be identified. We extend the classic analysis by including compressibility effects. We use two approaches: a twin experiment with synthetic production data for use with a time-domain parameter-estimation technique, and a transfer-function formalism in the form of bilaterally coupled four-ports allowing for an analysis in the frequency domain. We investigate the identifiability, from noisy production data, of the location and the magnitude of a low-permeability barrier to slightly compressible flow in a 1D configuration. We use an unregularized adjoint-based optimization scheme for the numerical time-domain estimation, by use of various levels of sensor noise, and confirm the results by use of the semianalytical transfer-function approach. Both the numerical and semianalytical results show that it is possible to identify the location and the magnitude of the permeability in the barrier from noise-free data. By introducing increasingly higher noise levels, the identifiability gradually deteriorates, but the location of the barrier remains identifiable for much-higher noise levels than the permeability. The shape of the objective-function surface, in normalized variables, indeed indicates a much-higher sensitivity of the well data to the location of the barrier than to its magnitude. These theoretical results appear to support the empirical finding that unregularized gradient-based history matching in large reservoir models, which is well-known to be a severely ill-posed problem, occasionally leads to useful results in the form of model-parameter updates with unrealistic magnitudes but indicating the correct location of model deficiencies.
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.