Ismail Mohd Saaid

Green silica scale inhibitors for Alkaline-Surfactant-Polymer flooding: a review

AbstractAlkaline-Surfactant-Polymer flooding is a tertiary enhanced oil recovery (EOR) method designed to lower interfacial tension (IFT), water wet the formation, and decrease water mobility to produce residual oil. The ASP flood uses a combination of alkali, surfactant, and polymer to achieve these results. The use of these three fluid injection additives offers ngreat synergistic effects in terms of oil recovery and sweep efficiency. Despite its popularity as a potentially cost-effective chemical flooding method, it is not without (its) problems, one of which is the excessive formation of silicate scales. Silicate scale is a very serious problem in the oil and gas industry; which forms in perforation holes, casing surface, tubing, and surface facilities. This study reviewed and assessed some of the inhibition techniques used in the industry with regard to handling oilfield scales in general and silicates scales in particular. Besides, the inhibitors with enhanced functionality in mitigating silicate scale also have been discussed. However, the conventional scale inhibitors used are facing restrictions world over, due to their ecotoxicity and non-biodegradability, which, therefore, has led to the call for green scale inhibition in the oil and industry. Green scale inhibitors are considered as alternative scale inhibitors due to their value-added benefits to the environment with respect to the methods of treating oilfield scales.

The Roles of Polar Compounds in the Stability and Flow Behavior of Water-in-Oil Emulsions

This paper summarizes an investigation of the roles of asphaltenes and other polar compounds in forming and stabilizing water-in-oil emulsions. Two crude oils with entirely different starting properties from Canada and Malaysia were used for the study. Asphaltenes and polar compounds were isolated from the crude oils using silica columns, and emulsions were prepared with the asphaltenes-free crude oils. These investigations have confirmed that water-in-oil emulsions formed by amphiphiles with the highest molecular weight play the most important roles in stabilizing W/O emulsions. Rheological as well as stability studies were conducted for emulsions formed by the crude oils with and without asphaltenes. The study shows that the viscosity of emulsions formed by the crude oils with asphaltene at a shear rate of one reciprocal second is about three orders of magnitude greater than that of the starting oil. An unstable emulsion is formed with the asphaltene-free crude oils, and thus, the viscosity of the emulsion is not more than about 20 times greater than that of the starting oil. A stable emulsion has a significant elasticity, whereas an unstable emulsion does not. A mesostable emulsion has properties between stable and unstable, but breaks down within a few days of standing. The usual situation is that emulsions are either obviously stable, mesostable, or unstable. The type of emulsion produced is determined primarily by the properties of the starting oil. The most important of these properties are the asphaltene and resin content and the viscosity of the oil. The composition and property ranges of the starting oil that would be required to form each of the water-in-oil states are discussed in this paper.

Rheological and stability study of water-in-crude oil emulsions

The formation of crude oil emulsion is a prevalent oilfield problem that can cause significant flow assurance issues during oil production, treatment and transportation. When they occur, emulsion problems are very difficult to solve and can lead to numerous operational problems like; creating high pressure drops in pipes and/or flowlines, production of off-specification crude oil and tripping of separation equipment. These emulsions can be very stable as a result of the presence of polar compounds, such as asphaltenes and resins, that play the role of natural surfactants and also because of the occurrence of many types of fine solids that can form resistant films at the crude oil/water interface. Solid particles also play significant roles in stabilizing emulsions. The water produced during oil production is either produced as free water, and so it will settle out fairly quickly, or the water may be combined with oil in the form of emulsions. This is more prevalent when producing oil from mature oilfields, where water production is relatively large. Under standard oilfield conditions the most common form of emulsion is a water-in-oil emulsion; a dispersion of water droplets in oil. In this work, the authors studied the consequence of different water-cuts and the presence of an emulsifier on the stability of water-in-oil emulsions. The rheological properties of W/O emulsions with different water cuts (10-50 v/v %) at different temperatures (25°C – 60°C) were studied. Rotational rheology and stability of the emulsions were studied on emulsions aged for 30 days. Generally, the results revealed that the presence of an emulsifying agent, difference in water content, shear rate and temperature significantly affect emulsion stability and rheological properties

Influence of various cation valence, salinity, pH and temperature on bentonite swelling behaviour

A major issue for the oil and gas industry is the producing of high water from many fields due to massive water injection. Reducing the water production while improving oil recovery from these fields is a major challenge. Polymer gel has been widely used to shut off water-producing zones, but it is not suitable for high temperature reservoirs (> 100 °C). The aims of the present study were to investigate bentonite particles swelling properties and influence of specific ion type (monovalent/divalent) present in water in swelling behaviour, and hence their potential for plugging high water production zones. In this study series of free swelling tests were conducted on bentonite with varying salinity, pH and temperature. The study found that cation valence, salinities and pH had significant impacts on swelling performance of bentonite particles. Bentonite changed from highly swelled material to aggregate in high salinity. Test results showed that the free swelling of bentonite decreased with the increase of c...

Determination of Cementation Factor from Induced Polarization Concept

Determination of water saturation, Sw in clean sand is more or less straightforward using the Archie equation. In shaly formation where the resistivity data is affected by clay conductivity, the Archie equation is no longer valid and Sw has to be modelled using other equations. The Waxman-Smits was one of the equations that has been developed to account for the clay effect in shaly sand. Nevertheless parameters used in the Waxman-Smits equation (i.e. formation resistivity factor, ({text{F}}^{ *}) and cementation factor, ({text{m}}^{ *})) rely upon the expensive core analysis data, which is not necessarily available for the particular reservoir of interest. The current method in core analysis could also contribute to inaccurate value of the determined parameters; the issues on averaging and representation of the selected core plugs to the whole reservoir and the effect of core treatment to the rock properties. In this paper, we reviewed some previous works to understand mechanism of clay surface conductivity and induced polarization (IP) concept and proposed a potential method for determination of more accurate ({text{m}}^{ *}) using this concept.

Synthesis and evaluation of Jatropha oil-based emulsified acids for matrix acidizing of carbonate rocks

Matrix-acidizing operations have been accounted to be the most hazardous and environmentally harmful among all the well-stimulation techniques. For instance, diesel oil-based emulsified acids have been prohibited from usage due to their high level of toxicity. There is, therefore, a dire need for emulsified acids that are environmentally viable and technically competent to replace the diesel-based emulsified acids. In this study, a novel oil-based environmental friendly emulsified acid has been synthesized from Jatropha curcas oil and, then, compared against diesel and palm oil-based emulsified acids. The technical evaluation of the three acids has been done based on experimental results obtained from thermal stability, droplet size analysis, rheological study, acid solubility, and toxicity screening. In addition, core flooding experiments have been conducted to evaluate the performance of the three emulsified acids as well stimulants. The results revealed that Jatropha oil-based emulsified acid has the potential to replace diesel-based emulsified acid. Jatropha oil-based emulsified acid was found to perform better than the diesel-based emulsified acid as indicated by having greater thermal stability and more popular rheological properties at varying temperatures of ambient, 50 and 70xa0°C. Furthermore, it possessed a lower toxicity load and a higher retardation effect on acid solubility than that of the diesel oil-based emulsified acid. The core flooding results have also indicated better well-stimulation performance of Jatropha-based emulsified acid as compared with diesel-based emulsified acids.

Development of surface treated nanosilica for wettability alteration and interfacial tension reduction

ABSTRACT The present study examines and compares the effect of surface treatments of nano-silica using internal olefins sulphonates (IOS20–24 and IOS19–23), anionic surfactants. The effect of surface modification on colloidal stability, wettability alteration and oil-water interfacial tension reduction were analyzed. Silica nanoparticles were characterized using Field Emission Scanning Electron Microscope (FESEM) and integrated energy-dispersive X-ray spectroscopy (EDX) before and after surface treatment. Using Turbiscan classic, the optimal nanosilica concentration and inspection of the coated particles dispersion stability with the help of light transmission behavior through the nanofluid was carried out. The stability was found to be enhanced as the mean light transmission declined only after surfactant treatment in both IOS coated nano-silicas but IOS19–23 O-342 coated dispersions proved to be more stable among all three. RAME-HART Goniometer was used to perform interfacial tension (IFT) and contact angle measurements. IFT was found to be reduced by 48% after the surfactant treatment in case of IOS19–23 O-342 coated nanosilica. Both surface treatments of nanosilica and increasing silica concentration caused significant reduction and altering wettability towards more water wet. The results revealed that IOS coatings improved the efficiency of NPs dispersion in terms of altered wettability and reduced IFT that mimics their potential for EOR applications. GRAPHICAL ABSTRACT

An Optimization Study of Polyacrylamide-Polyethylenimine-Based Polymer Gel for High Temperature Reservoir Conformance Control

This paper presents optimization formulation of organically crosslinked polymer gel for high temperature reservoir conformance control using response surface methodology (RSM). It is always desirable to approach an optimal polymer gel formulation study with adequate performance information related to viscosity and gelation time to minimize excessive water production. In this paper, the effects of polymer and crosslinker concentrations and their influences on gelation time and viscosity were investigated. Central composite design (CCD) was used to determine the optimized organically crosslinked polymer gel formulation. Concentrations of two main raw materials, namely, polyacrylamide (PAM) and polyethylenimine (PEI), were varied in a suitable range. This was to obtain the formulation with the desirable two vital responses, which are viscosity and gelation time. It was found that the results fitted the quadratic equation. Statistically, the quadratic model is reliable and adequate perfectly the variability of the responses obtained from the experimental data. In addition, gelation time and gel viscosity may be controlled by adjusting both polymer and crosslinker concentrations. The optimum formulated organically crosslinked polymer gel with significant desirability factor conditions was achieved at 1.5% w/v of PAM and 0.3% v/v of PEI.

Quantification of Clay Mineral and Log Response Toward Reservoir Rock Properties

Clay minerals are fine grained which compose of complex aluminum silicate with definite crystalline structure. They are divided into four major important groups which are kaolinite, illite, montmorillonite (smectite), and chlorite. The effect of clay minerals on formation evaluation and reservoir performance depends on its morphology, cation exchange capacity, and swelling properties. The occurrence of clay minerals leads to inaccurate values of porosity, water saturation, and permeability. In addition, the impacts of clay minerals during drilling, water injection, and acid stimulation are investigated as it leads to formation damage near wellbore or deep into formation. The current study aims at investigating the effect of clay minerals on log response and reservoir characteristics and to compare its impact on reservoir performance against reported works. Methodology used in the present research involves log interpretation, clay mineral characterization and to analyze the effect of clay on water relative permeability, water saturation, and capillary pressure curve. Results were discussed and benchmarked against selected literatures. Based on the effects of clay minerals, there are reduction in water relative permeability due to fine migration and swelling of clays. In addition, it was found that accurate value of water saturation can be obtained by using Waxman–Smits model. Moreover, it is shown that capillary pressure curve is reflected by the heterogeneity and bimodality of the reservoir. In this project, it is shown that the effect of clay minerals on reservoir can lead to the inaccuracy of determining reservoir characterization and its effect on reservoir productivity.

Finite Element Analysis of Casing Material Behavior in Steam Injection Well Operations

Casing design is one of the most important parts of the well planning in the oil and gas industry. Various factors affecting the casing material needs to be considered by the drilling engineers. Wells partaking in thermal oil recovery processes undergo extreme temperature variation and this induces high thermal stresses in the casings. Therefore, forecasting the material behavior and checking for failure mechanisms becomes highly important. This paper uses Finite Element Methods to analyze the behavior two of the frequently used materials for casing - J55 and L80 steels. Modeling the casing and application of boundary conditions are performed through Ansys Workbench. Effect of steam injection pressure and temperature on the materials is presented in this work, indicating the possibilities of failure during heating cycle. The change in diameter of the casing body due to axial restriction is also presented. This paper aims to draw special attention towards the casing design in high temperature conditions of the well.