Chelating agents show very effective performance in different applications in the upstream oil and gas industry. This study presents a critical review of the application of chelating agents in acidizing, scale removal, filter cake removal, wettability alteration, enhanced oil recovery (EOR), and hydraulic fracturing treatments. The advantages and disadvantages of using several types of chelating agents for improving the well/reservoir productivity and enhancing the oil recovery from sandstone and carbonate reservoirs are discussed. Also, detailed comparisons between different chelating agents and their applications in many oil and gas areas are presented. Moreover, the combination of chelating agents with different chemicals to achieve better performance is addressed. Hydroxy amino carboxylic acids [such as ethylenediaminetetraacetic acid (EDTA) and glutamic acid diacetic acid (GLDA)] have replaced conventional acids, such as hydrochloric acid (HCl), hydrofluoric acid (HF), and organic acids, at high temperature and salinity conditions to stimulate carbonate and sandstone reservoirs without any side effects on the formation integrity. Furthermore, diethylenetriaminepentaacetic acid (DTPA) and GLDA are effective in removing different types of scales, such as carbonate, sulfate, and sulfides, without releasing hydrogen sulfide (H 2 S) and using corrosion inhibitors. Also, DTPA, EDTA, and GLDA are very active in dissolving filter cake layers formed by different drilling fluids. Aminopolycarboxylic groups can be injected into sandstone and carbonate reservoirs to adjust the wettability conditions and enhance oil recovery. Chelating agents, such as GLDA, EDTA, and DTPA, optimize the fracture conductivity and, meanwhile, minimize the number of additives in hydraulic fracturing, which significantly cut the cost of the operation. Overall, chelating agents are economically attractive chemicals for various upstream operations since produced, and seawater can be used without further treatment.

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Fine, small-size, drilled cuttings, if not properly separated using mud conditioning equipment at the surface, are circulated with the drilling fluid from the surface to the bottom hole. These drilled cuttings have a significant effect on the drilling fluid properties and filter cake structure. During drilling long lateral sandstone formations, different cuttings with varied properties will be generated due to sandstone formations being heterogeneous and having different mineralogical compositions. Thus, the impact of these cuttings on the drilling fluid and filter cake properties will be different based on their mineralogy. In this paper, the effect of different sandstone formation cuttings, including arenite (quartz rich), calcareous (calcite rich), argillaceous (clay rich), and ferruginous (iron rich) sandstones, on the filter cake and drilling fluid properties was investigated. Cuttings of the mentioned sandstone formations were mixed with the drilling fluid to address the effect of these minerals on the filter cake thickness, porosity, and permeability. In addition, the effect of different sandstone formation cuttings on drilling fluid density and rheology, apparent viscosity (AV), plastic viscosity PV), and yield point (YP) was investigated. High-pressure high-temperature (HPHT) fluid loss test was conducted to form the filter cake. The core sample’s petrophysical properties were determined using X-ray fluorescence (XRF) and X-ray diffraction (XRD) techniques and scanning electron microscopy (SEM). The results of this work indicated that all cutting types increased the rheological properties when added to the drilling fluid at the same loadings but the argillaceous sandstone (clay rich) has a dominant effect compared to the other types because the higher clay content enhanced the rheology. From the filter cake point of view, the ferruginous sandstone improved the filter cake sealing properties and reduced its thickness, while the argillaceous cuttings degraded the filter cake porosity and permeability and allowed the finer cuttings to penetrate deeply in the filter medium.

Filter cake occurs intentionally during the drilling operations to prevent fluid losses to the formation and allow good circulation for drilling fluids from the bottom hole to the surface. The filter cake composition depends on a well-designed drilling fluids and additives. The filter cake should allow for minimum filtration, prevent solid invasions to the formation, and withstand high differential overbalance pressures. This work involves a detailed discussion for the most important filter cake properties such as filter cake thickness, porosity, permeability, and filter cake mineralogy for both oil-based and water-based drilling muds. Moreover, it provides measuring methods for these filter cake properties and the range of accuracy in each method. The effect of each filter cake property on drilling operation and health of the drilled wellcan be investigated. The survey was found to provide a comprehensive study for filter cake properties and methods. The reader can easily use this paper to benchmark the produced data or select the right method.

Iron Sulfide scale is a significant problem in oil and gas industry where the iron sulfide depositions have adverse impact to the production operations. Typically, iron sulfide scale formed as result of the reaction between the hydrogen sulfide and iron. Iron sulfide scale has several forms; pyrrhotite (Fe7S8), troilite (FeS), pyrite (FeS2), greigite (Fe2S4), and mackninawite (Fe9S8). Pyrite, which has good thermal stability, tends to deposit at shallower places downhole and is inert to acid. Other iron sulfides react with acids. Thermal stable species are much harder to be removed by acids. Thus the iron sulfide downhole are mainly pyrrhotite, pyrite, marcasite and mackinawite, in which pyrite cannot be removed by acid treatment. Both pyrite and marcasite have very low solubility in HCl, and the only available method of removal in the oil industry is to mill these types of scale. In this paper we introduced new formulations that can be effectively used to remove the pyrite and marcasite scales with removal efficiency reaches 85%. The new formulation will not release H2S during the removal of pyrite scale or any other iron sulfide scale as HCl, therefore, no need for H2S scavenger and also no HSE consideration are required during the removal because the new formulation can be considered as environmentally friendly. No need for additives such as corrosion inhibitors because these fluids pH is above 11 and they are not corrosive. The new formulation consists of high pH chelating agents such as DTPA (di ethylene tri amine penta acetic acid) at pH range from 11 to 14 and catalytic or converting agent such as potassium carbonate (K2CO3), (Cesium Carbonate) Cs2CO3, or (Cesium formate) CsCOOH. The optimum concentration of the chelating agents is 20 wt % DTPA and 7 wt% for the catalyst/converter. In the oilfield treatment water wetting surfactant or solvent should be injected first to remove the organic scale that covers the iron sulfide scale and then DTPA/Converting agents can be injected. No gases will be released during the scale removal process and this will not increase the pressure of the well during the treatment process. Currently the removal efficiency of the pyrite scale type is maximum 20 % by HCl. Using the new formulations the solubility of actual field samples of pyrite reached 85%. The new formulation can be used effectively to remove all types of iron sulfide scales especially those cannot be removed by HCl. One more advantage of the new formulation is that the H2S will not evolve during the treatment and that will cut the cost of safety considerations bedside the cost of H2S scavengers.

The filter cake evaluation involves many comprehensive testing and procedures to determine the filter cake properties such as thickness, mineralogy, porosity, permeability, and filtration to design the optimal mud program. For the maximum reservoir contact (MRC) and extended reach (ER) wells where the horizontal section could be 3000 ft or more in those wells, the filter cake formed by the drilling fluid varied from one section to another in the long horizontal section. Therefore, the process of filter cake removal in maximum reservoir contact and extended reach wells should consider the variation in the filter cake properties to achieve an efficient removal process. This research focuses on evaluating the filter cake porosity and permeability profile through the horizontal wells. Moreover, the impact of the filter cake porosity and permeability on the removal process is presented in this work. To achieve the objective of this work, high pressure high temperature (HPHT) fluid loss test was conducted to form the filter cake using actual drilling fluid samples. The compositional and structural analysis of filter cake was carried out using scanning electron microscopy (SEM), X-ray diffraction (XRD), and X-Ray Fluorescence (XRF). The drilling fluid studied samples were collected from real field rig while drilling the horizontal section. The results showed that the drilling operation was initiated with drilling fluid that was capable of forming a filter cake with low porosity (5 %) and permeability (0.01 md) to minimize the filtration volume. In the first part of the horizontal section the filter cake porosity and permeability increased sharply as more feet of horizontal section drilled. The porosity increased to about 35% and permeability to 0.25 md. After that it remains stable with slight decrease. This growth in the filter cake porosity from 5 to 35% reduced the liquid to solid ratio in the removal process from 28 gm per 500 ml up to 18 gm per ml. The result of this work linked the filter cake properties (thickness, porosity, and mineralogy) in the maximum reservoir contact and extended reach wells with solid to liquid ratio needed to be used in the filter cake removal process. This work will help to reevaluate the filter cake removal and stimulation recipes that were designed based on constant filter cake properties.