Tehrān, Iran


Tehrān, Iran
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Mehrgini B.,University of Tehran | Memarian H.,University of Tehran | Dusseault M.B.,University of Waterloo | Goodarzi B.,POGC | And 4 more authors.
50th US Rock Mechanics / Geomechanics Symposium 2016 | Year: 2016

Based on the continuing need for crude oil and its products and also the challenges associated with new reservoir discoveries, improving the recovery factor from known oil and gas fields is deemed necessary. Matrix stimulation and hydraulic fracturing (HF) are two common methods for reservoir stimulation, intended to improve the flow connection of the wellbore with the reservoir and therefore aid flow rate and usually enhance the ultimate hydrocarbon recovery factor - RF. HF is usually the most effective approach to accelerate hydrocarbon production and improve RF in many reservoirs as it can access larger reservoir volumes than other methods, particularly in the case of horizontal wells and multistage HF. HF treatment of horizontal drains is a complex engineering process with large capital investment needs; a 16-well shale gas pad in the United States or Canada can cost $USD 100,000,000 or more. Hence, to mitigate risks of inadequate HF treatment by reducing uncertainty in the design phase, HF design parameters may be better defined through laboratory tests. This study was performed on a series of specimens prepared from specimens of core from an Iranian carbonate gas reservoir. The 400 meters cored interval was first categorized into five geomechanical units (GMU) based on rock texture and fabric. Then, six intact specimens from each GMU were selected, and laboratory hydraulic fracturing tests were performed on three specimens of each GMU at three different confining pressures (5, 10 and 15 MPa). The HF test conditions (confining stress, fluid properties, injection rate and etc.) were identical in order to evaluate the lithology variation impacts, and were not intended to assess differences in viscosity, rate, or other related effects. Brazilian tensile strength tests were conducted on three samples of each GMU. By establishing the relationship between breakdown pressures and confining pressures, the HF tensile strength of each GMU was calculated. Results illustrate that there are meaningful differences between tensile strengths inferred from Brazilian tests and those back-calculated from laboratory HF tests. These differences are larger as a function of the porosity: generally, in high porosity specimens, tensile strength values derived from the HF tests are about 4-5 times higher than from the Brazilian test. Issues of defect size and poroelastic effects are invoked to explain the large differences, although proving this quantitatively remains an elusive goal. It is not apparent what mathematical modeling approach might be used to more rigorously assess the differences quantitatively, but a micromechanics fracture modeling approach based on statistical inference using micro- to core-scale tomographic input or digital micro- to macrofabric maps may allow better incorporation of the fabric elements at various scales. Copyright 2016 ARMA, American Rock Mechanics Association.

Keshavarzi B.,Sharif University of Technology | Keshavarzi B.,MAPSA Co. | Jamshidi S.,Sharif University of Technology | Salehi S.,University of Louisiana at Lafayette
Special Topics and Reviews in Porous Media | Year: 2014

This work concerns simultaneous determination of relative permeability, capillary pressure, pore size distribution (PSD), and residual oil saturation data by optimization of well testing data, and introduces a new capillary pressure relationship, based on the Weibull distribution function, for direct determination of the PSD function from capillary pressure parameters. Three consecutive injection, fall off, and production well tests are performed on a predefined synthetic reservoir through simulation, and an optimization algorithm is used to find the parameters of relative permeability and capillary pressure curves as well as the value of residual oil saturation. The PSD function is also determined from capillary pressure relationship parameters. The result shows successful application of an optimization technique using the well testing data for determination of relative permeability, capillary pressure, and PSD curves. Also, analysis of the well test scenarios shows that the three periods of injection, fall off, and production are required for generation of enough data for a successful optimization. The sensitivity analysis shows more sensitivity of objective function (OF) values for variations encountered with the water exponent in the relative permeability curve (m) and the C parameter of the capillary pressure relationship in comparison to the other parameters. © 2014 by Begell House, Inc.

Mehrgini B.,University of Tehran | Mehrgini B.,MAPSA Co. | Memarian H.,University of Tehran | Dusseault M.B.,University of Waterloo | And 4 more authors.
49th US Rock Mechanics / Geomechanics Symposium 2015 | Year: 2015

Petroleum geomechanics is a multidisciplinary branch of petroleum sciences which aims to understand, model, and control the mechanical response of subsurface geo-materials, such as reservoir rocks and cap rocks. Major geomechanical properties are usually obtained from destructive tests using standardized laboratory procedures and, for practical reasons, the mechanical characteristics of reservoir rocks should be measured at the reservoir conditions. In this study six geomechanical units (GMUs) in a carbonate reservoir in an Iranian gas field (T ∼ 90°C) were defined and then 24 plugs were taken from the cored intervals. Afterward, uniaxial compression tests were performed at 20°C and 90°C. Various geomechanical properties including unconfined compressive strength (UCS), Young's modulus (E) and Poisson's ratio (v) were determined and compared with each other. Results show that temperature may have some impact on the UCS of specimens but different GMUs show different kind of impacts and most were unaffected in this temperature range. Although E values vary from one GMU to another, temperature has almost no effect on this parameter for each GMU. Moreover, experimental results show that not only is there no significant difference among values of v for each GMU, this parameter is also not sensitive to temperature changes. We conclude that, given normal dispersion of results and heterogeneity of rocks, for this class of rocks at these conditions, it is sufficient to execute tests at room temperature for engineering design purposes. Copyright 2015 ARMA, American Rock Mechanics Association.

Esrafili-Dizaji B.,University of Tehran | Rahimpour-Bonab H.,University of Tehran | Mehrabi H.,University of Tehran | Afshin S.,MAPSA Co | And 2 more authors.
Facies | Year: 2015

The Sarvak reservoirs are characterized by thick rudist-dominated intervals in the south and southwest Iran. During the middle Cretaceous, rudistid communities were widely developed on the shallow parts of the Sarvak platform, mainly in the central Zagros and eastern Persian Gulf. Regional distribution and subsequent diagenesis of the rudist-dominated facies were strongly controlled by a number of paleostructures (i.e., fault-related paleohighs and salt domes) in the area. Facies analysis in 16 Sarvak reservoirs reveals the rudistid units can be classified into three main facies groups, developing thick depositional cycles in the Sarvak Formation. Integrated petrographic and geochemical data shows the rudist-dominated facies were subjected to fresh water diagenesis caused by a considerable drop in relative sea level after the deposition. Subsequently, where they were subaerially exposed over the crests and flanks of the paleohighs, the initial porosity of the rudist facies was enhanced by extensive meteoric dissolution (types A and B). Farther away from the paleohighs, same facies have poor reservoir quality, because the porosity was reduced by meteoric and shallow to deep burial cements, and mechanical/chemical compaction (type C). Despite their deep burial depth, significant amounts of porosity (>10 %) are still preserved in the rudist-dominated facies of the Sarvak Formation, especially below disconformity surfaces. Results of this study reveal the controls of early diagenesis on later diagenetic modification and porosity evolution in the Sarvak Formation, as the second important oil-producing reservoir of Iran. © 2015, Springer-Verlag Berlin Heidelberg.

Mehrgini B.,University of Tehran | Memarian H.,University of Tehran | Dusseault M.B.,University of Waterloo | Ghavidel A.,MAPSA Co. | Heydarizadeh M.,University of Tehran
Journal of Natural Gas Science and Engineering | Year: 2016

The evaporitic Gachsaran Formation consists of seven members with sequence of anhydrite, marl and salt layers. The first member (the lowest one) which is made up of anhydrite is known as the caprock of the Asmari carbonate reservoir, the most famous hydrocarbon reservoir in Iran. The geomechanical behavior of the Gachsaran Formation is the main concern of drilling and development operations in Iranian oil and gas fields. However, the chief problem is lack of deep core samples from Gachsaran sequences due to the challenging and costly coring process in the non-reservoir Gachsaran formation. In a practical approach of obtaining samples for essential geomechanical laboratory tests, caprock (anhydrite) core samples of Gachsaran Formation have been taken from depths of 80–300 m, at three dam sites. The rock physical and geomechanical properties were examined by analysis of variance (ANOVA) and Tukey's honestly significant difference (HSD) tests. The results from analysis of the properties of samples collected from Ghotvand and Chamshir dam sites showed no significant differences, but some of the characteristics of samples of Khersan dam site were considerably different from those of the other samples. Moreover, the physical properties of anhydrite samples were compared with the properties inferred from the petrophysical well logs from a depth of about 2000 m. It was demonstrated that the observed discrepancies between the measured values from Ghotvand and Chamshir samples and those from deep logs are not significant at the 95% confidence level. The investigation results illustrated that anhydrite samples taken from shallow depths can be used for evaluating the geomechanical properties of deeper anhydrites. © 2016 Elsevier B.V.

Mehrgini B.,University of Tehran | Memarian H.,University of Tehran | Dusseault M.B.,University of Waterloo | Eshraghi H.,POGC | And 4 more authors.
Journal of Natural Gas Science and Engineering | Year: 2016

Geomechanical characteristics of the reservoir and adjacent formations are important inputs to lifetime evaluation, operation and monitoring of E&P projects. Causes and cures for issues such as well instability and production decline often are found in the geomechanical behavior of the rock. Rock testing usually involves destructive tests on core samples, and it is widely acknowledged that properties should be measured at the representative conditions (T, p, σ) from which samples were taken. In this study of a well in an Iranian gas field, geomechanical units were first defined using well logs and lithological assessment. Then, based on the computed tomography images, intact samples were chosen and prepared for uniaxial and triaxial compression in both ambient (20 °C) and reservoir (90 °C) temperature conditions. The geomechanical properties at both temperatures, including uniaxial compressive strength (UCS), Young's modulus (E), Poisson's ratio (v), friction angle (φ') and cohesion (c') were compared. Porosity is observed as the main factor influencing the geomechanical behavior, and temperature affects UCS and E values of each GMU, in two distinct ways. We noted a transition porosity of 9%; specimens above this porosity respond differently to temperature compared to specimens below this porosity. It is concluded that whenever rock solid components' thermoelastic expansion is compensated by sufficient available free space (high porosity), the rock matrix will be strengthened. Finally, we noted that this range of δT has no significant effect on ν, φ' and c'. © 2016 Elsevier B.V.

Rohaninejad M.,MAPSA Company | Tavakkoli-Moghaddam R.,University of Tehran | Vahedi-Nouri B.,Bu - Ali Sina University
Procedia Computer Science | Year: 2015

The redundancy allocation problem is among the most interesting and difficult problems in the system reliability design. In this paper this concept is considered to enhance reliability in projects network scheduling with stochastic activity duration. In order to determine the optimal manner of redundancy allocation, a new mathematical model is developed. Then, by simulating the problem in the form of a game-theoretical pattern, it is shown that the Nash-equilibrium points of the problem are very close to optimal solutions of original model. Therefore, an algorithmic approach is developed for the calculation of Nash equilibria. Finally, several computational experiments are executed and their results are analysed. The comparison of equilibrium outcomes with the optimal policy justifies the efficiency of Nash equilibria for increasing the projects network reliability. © 2015 The Authors. Published by Elsevier B.V.

Mehrgini B.,University of Tehran | Eshraghi H.,Pars Oil And Gas Company | Memarian H.,University of Tehran | Ghavidel A.,MAPSA Co. | And 2 more authors.
3rd Sustainable Earth Sciences Conference and Exhibition: Use of the Sub-Surface to Serve the Energy Transition | Year: 2015

Reservoir geomechanical evaluation provides powerful insights to understand and more precisely predict the lifetime behavior of reservoir regarding to the given or desired development plan. Any geomechanical evaluation is directly based on the rock mechanical data which is taken from experimental destructive tests on intact rock samples. However in some situations preparing required undisturbed and intact rock samples is impossible, technically or financially. Investigating the relationship between some microstructural properties and key geomechanical characteristics may lead to develop some models to estimate those geomechanical parameters by thin section studies instead of destructive tests. In this study which is done on 15 carbonate plugs of Iranian gas field, first qualified plugs were chosen based on the CT-Scan images to investigation. Second thin section studies were carried out on each trim of plugs both qualitatively and quantitatively. In the next step, uniaxial compression tests were performed on the samples. Investigations results illustrate that microstructural parameters including porosity, mud percentage and anhydrite cement content are the main affecting features on unconfined compressive strength (UCS) and Young's modulus (E) of studied carbonate samples.

Ashrafizadeh M.,Sharif University of Technology | Ahmad Ramazani S.A.,Sharif University of Technology | Sadeghnejad S.,MAPSA Co.
Energy Exploration and Exploitation | Year: 2012

The main purpose of this paper is modeling and simulation of in-situ releasing of smart nano-sized core-shell particles at the water-oil interface during polymer flooding. During the polymer flooding process, when these nano-particles reach the water-oil interface, migrate to the oil phase and the hydrophobic layer of them dissolves in this phase. After dissolution of this protective nano-sized layer, the hydrophilic core containing a water-soluble ultra high molecular weight polymer diffuses back into the water phase and with dissolving in this phase, dramatically increases viscosity of flooding water in the neighborhood of the water-oil interface. In this study, two different time-dependent dissolution models are implemented. A swellable-chain disentanglement model with concentration-dependent diffusion coefficient is considered for dissolution of the core polymer into the aqueous phase, whereas, surface chain disentanglement with constant diffusion coefficient is considered for dissolution of the shell polymer in the oil phase. Using finite difference scheme, the governing equations are numerically solved by defining some dimensionless parameters for the main parameters as well as the moving boundaries. In addition, some experimental flooding tests in micromodel were carried out to experimentally investigate the recovery factor of using these particles compared to those of the conventional polymer flooding.

Dalvand M.,Mapsa Company | Ashrafzadeh A.R.,Mapsa Company | Ahmadi Z.,Mapsa Company
Journal of Micropalaeontology | Year: 2015

Biostratigraphical observations in different locations and horizons of carbonate strata from four oil wells drilled in the Persian Gulf Basin document three new ichnospecies of crustacean microcopro-lites. Favreina irannensis n. sp. occurs in Valanginian-hauterivian strata of the Buwaib Formation (Gadvan Formation), Palaxius asmariensis n. sp. in the Lower Miocene strata of the Asmari Formation, and Palaxius minaensis n. sp. in the Aptian strata of the Dariyan Formation. © 2015 The Author(s). Published by The Geological Society of London for The Micropalaeontological Society.

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