مجله پژوهش نفت
پیاپی 137 (مهر و آبان 1403)

In fractured reservoirs under the gravity drainage, the oil transfer between adjacent matrix blocks is one of the main factors in determining the degree of oil recovery. Communication between matrix blocks can occur by forming a liquid bridge between two adjacent matrices. Therefore, in this study, by modeling and simulating in Comsol, we investigated the characteristics of the liquid bridge formed inside the fracture and the dependency of the liquid bridge shape and the pressure difference on the fracture properties such as the fracture aperture, matrix permeability and wettability. Moreover, the initial and boundary conditions in the problem are set such that it can show physically the flow exchange between the matrix and fracture in reservoir conditions. Furthermore, the results of this simulation showed that the liquid bridge throat decreases with the size of the fracture aperture. In addition, this change in the liquid bridge causes the two-phase pressure difference to decrease with the increase of the fracture aperture, and after a critical value (for example, 1.7 mm), it becomes negative. Also, the results showed that as the contact angle increases toward neutral wettability, the more vertically liquid bridge formed and it leads to small changes (40 psi) for two phase pressure difference inside the fracture. In addition, with the increase in rock permeability and more flow entering the fracture, the throat radius of the formed liquid bridge increased from about 0.03 mm to about 0.05 mm, which it is consistent with the published laboratory data. The findings of this research can be used for better understanding how the liquid bridge changes and its effect on the of the two-phase pressure difference, which is a controlling parameter for two phase interface inside fracture.

Common field oil recovery had always been a priority for political and governance reasons. In addition to the technical factors of field development, the fisical aspects of the development is also an effective factor in the progress. One of the most important effective factors in financing aspect of IOR/ EOR is selection and adjustment fisical system of oil contracts. The current research was performed on a simulated model of a field in the Southwest of Iran, with the variables of oil production and gas injection rates , the perforation interval, and the location of new wells. The cumulative production and oil migration in the reservoir were investigated as optimization functions. The optimization of these variables to achieve the desired technical functions has been done with NSGA-II evolutionary algorithm. After obtaining a set of equivalent optimal answers (Pareto front), Net present value and government fisical income as economical functions were investigated in three fisical models of  the Buyback, Production Share Contract and Iran Petroleum Contracts. After optimization process of the technical objective functions, a hundred different scenarios have been proposed. After the technical and fisical investigations and comparison between the three contracts, it was found that the current net value of Iran Petroleum Contracts was higher than the other two types of contracts. Also, the final fisical income of the field has generally decreased from the scenarios with emphasis on cumulative production to the scenarios with emphasis on less migration. Buyback contract, the net present value is independent of technical functions. The other two types of contracts produced different net present value and the government’s earnings on different condition.

Undesired water production in hydrocarbonate reservoirs can be a major problem, if the surface facility has not been designed in a supportive way. This undesired water may cause problems for process equipment in platform, sea lines and refinery. To solve and control these problems, some root cause analysis should be done in order to maintain gas production and  control water production. To find the causes of this problem, an integrated data analysis of all probable reasons for water production in a produced gas well was performed over about one hundred wells in the field, from their first day of production till the time of the study. Water production history investigation in all of the studied wells showed that some of these wells have abnormal produced water. In order toroot cause analysis, all probable reasons were investigated; including: considering drilling history of the wells, well cleaning reports after perforation and acidizing, perforation intervals in each well, distance from gas-water contact, quality control of cements behind Liners in the reservoir by using Cement Bonding Logs (CBL-VDL), well positions in accordance to faults and fractures, Azimuth of deviated wells in accordance to the direction of maximum stress of the field.

Pigging is one of the conventional processes in the oil and gas industries, which is done in order to remove sediments from pipelines and also perform some non-destructive tests. On the other hand, due to various branches in the main pipeline, there is a possibility of stopping the pig. The right solution is to use mesh caps that not only prevent the pig from getting stuck, but also guarantee the passage of flow through all the main and secondary lines. According to the opinions of technical inspectors, there is no comprehensive information about the presence/absence of these caps in a large number of branches. The industrial radiography lacks the ability to detect the presence and absence of the cap in a fully filled pipe due to the average energy of the emitted beam and its geometrical structure. It is focused on the conceptual design of the nuclear system for investigating the possibility of pigging in the location of pipeline branches in the Monte Carlo environment. Ultimately, the results show the fact that in the situation where the source and the detector are perpendicular to the axis of the main and secondary branches and facing each other, the maximum counting sensitivity and discrimination can be achieved. Moreover, the relative difference of two states with and without the presence of metal grid for two states of filling the pipe with air and oil is equal to 53.8% and 57.1%, respectively.

The Cased, Cemented, and Perforated (CCP) completion method is considered one of the superior well completion methods in sand-prone reservoirs due to its execution safety and cost-effectiveness compared to alternative techniques. In the design of perforation configurations, the number of shots aligns with the requisite hydrocarbon production volume. Consequently, the optimization of the phase angle (phasing) emerges as a critical design parameter, typically deployed to forestall overlap within the impacted zones surrounding neighboring perforations and curtail their interaction. In light of the absence of constraints and the ease of establishing a single helical perforation pattern compared to alternatives, this study is dedicated to exploring the optimal phase angles within this pattern using a pythonic brute-force search approach. Moreover, emphasis is placed on achieving the minimum spacing between adjacent perforations, and the analysis is geared towards identifying the most optimal phase angles for 6, 9, and 12 shots per foot across three common wellbore diameters. Innovations of this study include the consideration of more than three consecutive wraps of perforations in determining the optimal phasing, as well as the simultaneous impact of perforation stability and uniform flow distribution around the wellbore in reducing the likelihood of sand production. The uniform distribution of perforations has been achieved by introducing a parameter known as the Equilateral Likeness Score (ELS), where its minimum value signifies the most uniform arrangement of adjacent perforations. The optimal phasing angles are determined by drawing inspiration from two distinct perspectives: maximizing the spacing between adjacent perforations and achieving the highest possible phasing values. A comparative analysis of the outcomes derived from the presented theory and existing ones underscores the potential for significant variations in the determined phasing values for certain shot densities. Ultimately, the optimal phase angles for the aforementioned shot densities are projected as 127, 130, and 97 degrees for a 41/8-inch wellbore, 130, 97, and 143 degrees for a 61/8-inch wellbore, and 97, 143, and 77 degrees for an 81/2-inch wellbore.

Formation damage in the near-wellbore area has become one of the significant obstacles in the path of production from oil wells today. One neglected aspect of formation damage is the damage caused by the invasion of drilling fluid filtrates into the formation. Water-based drilling fluid, due to the presence of polymers and micrometer-sized compounds, causes changes in the electrostatic and flow properties of the rock surface upon invasion into the formation, resulting in various consequences such as reduced hydrocarbon fluid production, increased produced water cut, alteration in reservoir wettability, and changes in relative permeability of the reservoir rock. In this study, processed reservoir rock samples from southern Iran were obtained, and using real crude oil samples, reservoir environment and oil-rock contact were simulated in the laboratory environment using a core flooding apparatus. The drilling fluid sample, based on the commonly used formulation for oil and gas wells and approved by the Petroleum Industry Research Institute, was prepared and its filtrate was injected into the reservoir using a filter press device. The investigation conducted on clean core properties, core contaminated with crude oil, and core soaked with filtrate revealed that the commonly used drilling fluid filtrates cause alteration of the rock surface wettability from oil-wet to water-wet and significantly reduce the capillary force applied to hydrocarbon fluids and the relative permeability of the oil phase, leading to decreased oil production from reservoirs. However, a new formulation of drilling fluid replaced based on the presence of amine functional groups instead of hydroxyl groups showed improved wettability alteration upon filtrate injection into the reservoir. Additionally, the new drilling fluid sample will not negatively impact the hydrocarbon fluid flow within the pore and fracture networks, and the use of alternative materials will increase oil production from reservoirs.

This paper focuses on the simulation and exergy analysis of flare gas recovery systems and their consuming resources in a gas processing plant, with the aim of minimizing environmental pollution and maximizing energy utilization. During the extraction and processing of oil and gas, significant amounts of unused gases are typically directed to flares, resulting in both environmental pollution and economic waste. Through simulation, it has been determined that approximately 28,700 kg/hour of flare gases can be recovered from the refinery’s flare network, operating at a pressure of 9 bar and a temperature of 25 degrees Celsius. To optimize the consumption of the recovered gases, exergy analysis has been conducted for different consumption scenarios. Two distinct scenarios for the consumption of flare gases are presented. In the first scenario, the recovered gases are compressed to a pressure of 70 bar and injected into the gas sweetening unit of the refinery. Moreover, the calculated exergy efficiency for this scenario is 69%. In the second scenario, the recovered gases are directed to the compressors available in the gas condensate unit. The calculated exergy efficiency for this scenario exceeds 78%. Ultimatly, based on the simulation and exergy analysis results, it is concluded that injecting the recovered flare gases into the compressors of the gas condensate stabilization unit offers the most optimal utilization of the recovered gases. This finding highlights the potential for reducing environmental pollution, minimizing waste, and maximizing the economic resources available in the gas processing plant.

The study of reservoir quality in carbonates requires a detailed investigation of sedimentology and diagenesis processes. In this paper, the factors controlling the reservoir quality of Asmari-Jahrum formations from the Nargesi oil field in the framework of sequence stratigraphy were evaluated by a comprehensive petrographic study to identify the microfacies and diagenesis processes. By studying 209 microscopic thin sections in the NI-06 well, 14 microfacies were introduced in the sub-environments of the intertidal zone, lagoon, shoal, and middle ramp, which have deposited along a homoclinal ramp. Petrographic evidence indicates the occurrence of two diagenesis stages (eogenesis and mesogenesis) and three diagenesis environments (marine, meteoric, and burial) in the paragenesis sequence of the studied formations. The obtained results showed that the dissolution and fracturing processes have increased the reservoir quality. Still, the compaction, cementation, and anhydritization processes have decreased the reservoir quality in the studied formations. Sequence stratigraphic studies using the Transgressive-Regressive sequence method, investigation of sedimentary characteristics and early diagenesis, and examining the variations of petrophysical logs show six third-order sedimentary sequences in the Asmari-Jahrum formations from the Nargesi field. Also, the rock types (Wineland, Lucia, and Flow Zone Index), sedimentary sequences, diagenetic processes, facies, and petrophysical logs variations imply 8 different zones (e.g., reservoir, speed, and baffle zones) in the Asmari-Jahrum reservoir. The influence of sedimentary microfacies, the diversity of diagenesis processes in each zone, and considering their position in the sequences corroborate the observed changes trend of the reservoir characteristics in the identified zones. In general, the Asmari Formation in Zones#1, 2, and 3 (upper part) in the Nargesi oil field has a better reservoir quality than the Jahrum Formation, and this indicates that the diagenesis processes, especially fracturing, played a vital role in controlling the reservoir potential of the Asmari Formation. In the Jahrum Formation in Zone 7, mud-dominated microfacies are abundant in the lagoon and middle ramp environments. Dissolution in the form of vuggy porosity, microfracture, and intercrystalline porosity caused by dolomitization has had the most critical effect in improving the quality of this reservoir zone.

Estimating the flow rate in oil wells of a field is a vital and practical process. However, the flows extracted from oil wells are multiphase, and their accurate estimation is highly challenging and costly. Virtual flow meters, compared to multiphase flow meters and well-testing methods, are an economically viable option that can accurately predict future flow rates by leveraging existing data and artificial intelligence algorithms. Therefore, data-driven virtual flow meters have recently received significant attention. This paper estimates the production flow rate of a well using three machine learning algorithms: 1- k-nearest neighbors (k-NN); 2- gradient boosting (GBR); and 3- decision tree (DT), using pump data. Pearson and Spearman statistical analyses were used to select appropriate features as the algorithm inputs. Moreover, the dataset under investigation pertains to one of the wells of a southern oil field in Iran. The available dataset has a small volume and insufficient diversity, but despite this, the results show that the proposed algorithms perform well. The k-NN method, with an accuracy of 0.9494, performed better than the other two methods in estimating oil flow rate. Ultimatly, to examine the performance of the algorithms against noisy data, one percent of standard deviation noise was added to the input data. Moreover, the investigations showed that the k-NN model, with an accuracy of 0.9257, performed better than the other two methods and was least affected by the noise.

The mechanisms that enhance oil recovery through low-salinity waterflooding can be categorized into two main groups: fluid-fluid interactions and rock-fluid interactions. Fluid-fluid interactions have been less explored in the existing literature. One significant effect of these interactions is the maintenance or increase of oil phase connectivity, which boosts the relative permeability and production rate of oil from the reservoir. This research aims to deepen the understanding of these effects and their time scales by examining the coalescence of two adjacent oil droplets in presence of saline water. A novel device and method were developed in this study. In this method, two oil droplets (one hanging from the top and one from the bottom) are placed near the desired brine. After an aging period, they are brought together to initiate contact. The time it takes for the droplets to merge, known as the “coalescence time,” is recorded. The results show that coalescence time increases with aging time, however starts to stabilize after about 15 minutes. Additionally, the coalescence time of two oil droplets exhibits a nonmonotonic relationship with salinity, peaking at an intermediate salinity level. The maximum coalescence time occurs at lower ionic strengths in brines with divalent salts like calcium, magnesium, and sulfate compared to monovalent salts. The specific values for sodium chloride, magnesium chloride, calcium chloride, and sodium sulfate brines are 0.5, 0.05, 0.05, and 0.01 M, respectively. Ultimatly, this study indicates that there is an optimal salinity for the fluid-fluid effects in low-salinity waterflooding, and understanding these effects on oil recovery necessitates further waterflooding experiments.