Petroleum Chemistry最新文献

Petrophysical parameters were assessed using comprehensive log data coming from two wells (Ns-2, Ns-4) located within the Mishrif, Rumaila, Ahmadi, and Mauddud formations within the Nasiriya oil field, Iraq. The logs were digitized using Techlog 2015 software, and environmental modifications were implemented to guarantee precise interpretations. The shale volume used to be determined using gamma ray (GR) logs, subsequently leading towards the calculation of the effectiveness porosity. Water saturation is used to be calculated alongside Archie's equation. The investigation indicated that the lithology regarding the Mishrif, Rumaila, Ahmadi, and Mauddud formations happens to be predominantly limestone, alongside calcite like the principal mineral within the matrix. All formations were found to contain water like the fluid type, except within favor regarding the Mishrif formation at the 2013–2046 m within Ns-2, and 2000–2060 m within Ns-4, where hydrocarbons were identified. The top strata for these depths comprise substantial shale alongside limited effective porosity, serving like cap rock at the depths from 2013 to 2016 m within Ns-2, and 2000 towards 2006 m within Ns-4.

In order to calculate pay thickness and net/gross ratio, a set of limiting values (called cutoffs) for petrophysical parameters like permeability, shale volume, porosity, and water saturation should be defined. This paper thoroughly explains the most useful and applicable methods for calculating the cutoff values, outlining their advantages, disadvantages, and required input data. These techniques include the traditional Best fit line, Quadrant, Worthington, and Cumulative hydrocarbon methods. Khasib formation in Amara oil field is taken as a study object; the cutoff values are estimated according to the proposed methods. Considering the accuracy, the data available, and the limitations of each method. Khasib formation is divided into four units the reservoir units identified as KH2 and KH4, The cutoffs for the petrophysical properties were calculated for each reservoir unit. It was determined that the suitable cut-off value for permeability changes from one unit to another because of the different rock types that characterize each unit. The permeability cut-off for the KH2 unit is 0.01 and the estimated porosity cutoff value is 0.09. In contrast, for the KH4 unit, the permeability cut-off is taken as 0.1 and the porosity cutoff is estimated as 0.1. Furthermore, the calculated cutoffs of the shale volume and the water saturation are similar for the two reservoir units (KH2 and KH4) and equal to 10 and 60% respectively. Finally, the determined cutoffs can be applied and the net pay thickness and ratio of net/gross can be calculated for each unit in the objective formation.

In order to enhance the acid resistance and injection ability of retarded acid and to achieve a deep acidification, a low-viscosity acid-resistant retarding agent (LVAR) was synthesized via radical aqueous polymerization using 2-acrylamido-2-methyl-1-propanesulfonicacid (AMPS), [2-(methacryloyloxy)ethyl] trimethylammonium chloride (DMC), and N,N′-dimethyl hexadecyl allyl ammonium chloride (C₁₆DMAAC) as monomers. The acid, temperature, and salt resistance of LVAR, as well as its retardation and compatibility characteristics were analyzed using viscometer, scanning electron microscope, and the acid rock dissolution experiment. The results showed that the viscosity of a 1.0% LVAR-retarded acid solution was only 4.5 mPa s, which represented a low-viscosity effect. After 4 h of incubation at high temperature (90°C), LVAR-retarded acid remained clear and transparent, and showed good acid resistance. The corrosion rate of 1.0% retarded acid solution at 35 and 95°C was 37.4 and 71.2%, respectively, indicating a good retardation performance. These findings may provide new insights for the study of low-viscosity and acid-resistant retarding agents.

—This study explores the potential of creating hybrid porous materials to develop gas storage and transport technologies based on gas hydrates. The research provides a brief overview of materials used as containers for producing and storing gas hydrates. It analyzes the properties of cellulose-based hydrate carriers using FT-IR spectroscopy and scanning electron microscopy, and examines a methane hydrate growth in the proposed hybrid material based on cellulose and polystyrene. The mass fraction of water in the tested material was 44%. The rate of water-to-hydrate conversion during cyclic cooling of this material under a methane pressure of 9 MPa was 61.4%. Cellulose-based materials containing a hydrophobic component that maintains the mechanical strength of the system can be a viable carrier for the cyclic production and decomposition of gas hydrates. The obtained data are of great value for specialists involved in the hydrocarbon production and the study of gas hydrates, though also may be interesting for a broader audience.

Near-wellbore damage deteriorate oil production due to a reduction in permeability. Matrix acidizing may significantly enhance well performance by using a predefined mixture of acids concentration. After preparing core plugs (core sample cleaning), the petrographic inspection of thin sections has shown that all samples have quartz arenite rank which consists of 95% quartz mineral and little amount of clay minerals and calcite cement filling pores. The arithmetic average of measured porosity by using helium porosimeter was about 24.9%. Also, the geometric averaging permeability was 802 md measured by using core lab permeameter. Based on the technical criteria for selecting appropriate acids, HF (hydrofluoric acid) and HCl (hydrochloric acid) acids have been chosen to acidize core samples with concentrations of 3 and 12%, respectively. The high permeability of core plugs, besides mineralogical composition, is one of the reasons behind the percentages of acid concentrations of HF and HCl. Laboratory findings unequivocally demonstrate a substantial increase in oil recovery following core acidization, notably surpassing recovery rates achieved without acidization, especially in scenarios involving early water saturation. These findings underscore the significant potential of matrix acidizing as an effective strategy for mitigating near-wellbore damage and optimizing oil production in sandstone reservoirs.

This study aims to predict Yamama layers formation permeability of five wells: N1, N2, N3, N4, and N5, each containing Yamama, Yamama B and Yamama C layers. The permeability was calculated through two methods, namely the basic analysis and well-log techniques. The basic analysis method was conducted in the laboratory using a PERL-200 device. The results obtained using this method were more accurate as they matched the well-log results. Employing Matlab software, a neural network predicted permeability for 14 layers of 5 wells, with the second and fifth wells having only two layers. By constructing a 13-layer neural network, an appropriate network configuration can be achieved to discover the relationship between the input and output and produce a matching target result.

A series of experimental tests were carried out to study and assessment of the geotechnical properties of the Fatha formation rocks in the Zurbatiyah region in eastern Iraq, the physical and mechanical characteristics have been studied in the study area of two types of rocks are represented by gypsum and limestone rocks. The physical results and tests helped to explain the mechanical behavior of the rock specimens that were studied. Several destructive and non-destructive tests were conducted on rock samples collected from various zones. Uniaxial compressive strength, point load, and Brazilian tests were tested on 60 intact rock specimens. The results of uniaxial compressive strength show that the maximum value of the compressive strength of the gypsum specimens was 35.08 MPa, while the maximum value in limestone specimens, was 38.095 MPa. In the indirect point load test, the maximum point load strength index I_S(50) was 2.810 and 6.428 MPa for gypsum and limestone rock specimens respectively. In the indirect Brazilian test, the maximum tensile strength (σ_t) values were 4.66 and 7.36 MPa for gypsum and limestone rock specimens respectively. A new correlation with a high value of the regression coefficient R² is presented, linking the uniaxial compressive strength (UCS) versus the rebound number of the Schmidt hammer (N).

Accurately estimating fracture pressure is a critical factor in the success of the oil field industry. Fracture pressure is used in various applications, including increasing production and injection processes, making it essential to determine precisely. This study aims to predict the fracture pressure for Iraqi oil field using artificial intelligence techniques, such studies are crucial in optimizing oil field production and minimizing risks. Artificial intelligence (AI) methodologies employed a dataset comprising approximately 13 000 data points for different logs parameters. The input layer is employing the input parameter (neutron, density, gamma ray, rock strength (UCS), true vertical depth (TVD), Young’s modulus (E), and Poisson ratio (v). The obtained results should be remarkable R² of 0.86. The optimal approach entails utilizing readily available log data, including sonic logs compression and shear (DTC, DTS) commendable R-squared value of 0.84. Artificial neural networks (ANN) have the upper hand over empirical models, as they require important data, only surface drilling parameters, which are easily accessible and use it from any well. In addition, a new fracture pressure correlation depended on artificial neural networks (ANN) has been created, which can accurately predict fracture pressure. The findings of the study can provide valuable insights for the oil and gas industry in predicting fracture pressure accurately and efficiently.

Asphaltenes are a solubility class that is thought to be the heaviest and polar component of the petroleum product. Asphaltene precipitation (AP) and deposition during oil production, processing, and transportation are key concerns for the oil industry. The current study analyzes the phase envelope of fluids and asphaltene precipitation of a real-live oil sample (bottom hole sample) from a well that was drilled in the Mishrif reservoir formation—Buzargan oil field in the Missan governorate in south-east Iraq. The study emphasizes a number of essential approaches for simulating asphaltene phase behavior using the Peng‒Robinson-78 advanced equation of state model for AP by using Multiflash software. The asphaltene precipitation envelope (APE) is the output of the equation of state, from which the authors may predict the operation conditions to avoid asphaltene precipitation. Prediction of these situations can improve reservoir performance and production systems ability to decrease asphaltene precipitation by regulating reservoir factors.

Wellbore instability occurs when an open well cannot maintain its size, shape, or structural stability. It is a common issue especially in shale sections and can be caused by both mechanical factors, such as poor drilling technique or weak rock, and chemical factors, such as interactions between the rock and drilling fluid. This problem can lead to costly and dangerous complications. In this study data from three wells in Nahr Umr Oil Field (NR-10, NR-12, and NR-14) in southern Iraq were analyzed to determine pore pressure and rock strength parameters, as well as in situ horizontal stresses. The results showed an increase in pore pressure and horizontal stress in shale units, and various geomechanical parameters were also estimated. The study showed the fault regime in the area is a strike-slip fault and suggested the estimated pore pressure values while drilling hole sections to prevent problems at abnormal and subnormal formations.