Summary Matrix acidizing is used in carbonate formations to create wormholes that connect the formation to the wellbore. Hydrochloric acid (HCl), organic acids, or mixtures of these acids are typically used in matrix-acidizing treatments of carbonate reservoirs. However, the use of these acids in deep wells has some major drawbacks, including high and uncontrolled reaction rates and corrosion to well tubulars, especially those made of chromium-based tubulars (Cr-13 and duplex steel); and these problems become severe at high temperatures. To overcome problems associated with strong acids, chelating agents were introduced and used in the field. However, major concerns with most of these chemicals are their limited dissolving power and negative environmental impact. L-glutamic acid diacetic acid (GLDA), a newly developed environmentally friendly chelate, was examined as a replacement for acid treatments in deep oil and gas wells. The solubility of calcium carbonate (CaCO3) in the new chelate was measured over a wide range of parameters. Coreflood tests were conducted using long Indiana limestone cores 1.5 in. in diameter and 20 in. in length, which allowed better understanding of the propagation of this chemical in carbonate rocks. The cores were X-ray scanned before and after the injection of chelate solutions into the cores. The concentration of calcium (Ca) and chelate was measured in the core effluent samples. To the best of our knowledge, this is the first study to examine the fate and propagation of chelating agents in coreflood studies. GLDA has a very good ability to dissolve Ca from carbonate rocks over a wide pH range by a combination of acid dissolution and chelation. The addition of 5 wt% sodium chloride (NaCl) did not affect the GLDA performance at pH = 13 but significantly accelerated the reaction at pH = 1.7. Compared with other chelating agents, GLDA dissolved more Ca than ethanoldiglycinic acid (EDG) but less than hydroxyethyl ethylenediamine triacetic acid (HEDTA) at high pH values. GLDA of pH = 1.7 was able to form wormholes at 2 and 3 cm3/min. GLDA was found to be thermally stable at temperatures up to 350°F.

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Asphaltene precipitation and deposition have been a formation damage problem for decades, with the most devastating effects being wettability alteration and permeability impairment. To this effect, a critical look into the laboratory studies and models developed to quantify/predict permeability and wettability alterations are reviewed, stating their assumptions and limitations. For wettability alterations, the mechanism is predominantly surface adsorption, which is controlled by the asphaltene contacting minerals as they control the surface chemistry, charge, and electrochemical interactions. The most promising wettability alteration evaluation techniques are nuclear magnetic resonance, ζ potential, and the use of high-resolution microscopy. The integration of such techniques, which is still missing, would reinforce the understanding of asphaltene interaction with rock minerals (especially clays), which holds the key to developing a strategy for modeling wettability alteration. With regard to permeability impairment, surface deposition, pore plugging, and fine migration have been identified as the dominant mechanisms with several models reporting the simultaneous existence of multiple mechanisms. Existing experimental findings showed that asphaltene deposition is non-uniform due to mineral distribution which further complicates the modeling process. It also remains a challenge to separate changes due to adsorption (wettability changes) from those due to pore size reduction (permeability impairment).

In situ heat generation is one of the promising techniques to enhance hydrocarbon production, by removing the condensate damage from the near-wellbore region, and improve gas mobility. This technology is performed by injecting two thermochemical solutions that will react at reservoir conditions and generate heat and pressure. The use of thermochemical fluids will reduce the injection cost to within 60% compared to the solvent injection. During thermochemical treatment, a considerable alteration in the fluid phase behavior will take place. This paper presents a novel technique and the first application of using thermochemicals to eliminate gas condensation. Experimental measurements and computer modeling group (CMG) modeling were performed to investigate the effect of injecting thermochemical fluids on the gas condensate behavior. A new reactor was fabricated to study the reaction kinetics of thermochemical materials. Thereafter, the influence of thermochemical treatments on removing the condensate, reducing the capillary forces, and improving the gas production was studied. Also, the impact of energizing the condensate region with nitrogen that was generated by thermochemical reaction was emphasized. Finally, the propagation depth of the generated heat from thermochemical reaction was determined as a function of injection time. The obtained results showed that injecting thermochemical fluids will increase the reservoir temperature and pressure beyond the dew point curve. At reservoir conditions, a pressure of 1300 psi could be achieved from the thermochemical reaction. The generated pressure is higher than the dew point pressure; therefore, the condensate liquid will be converted into the gaseous phase. Calculations of capillary forces revealed that thermochemical treatment reduced capillary forces by 25–36%. An exponential relationship was observed between the injection time and the radius of heat propagation. Increasing the injection time will increase the radius of the heated area exponentially. The heat propagation model can be used to determine the injection time required to heat the condensate region inside the reservoir.

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.

A common problem that faces the oil and gas industry is the formation of iron sulfide scale in various stages of production. Recently an effective chemical formulation was proposed to remove all types of iron sulfide scales (including pyrite), consisting of a chelating agent diethylenetriaminepentaacetic acid (DTPA) at high pH using potassium carbonate (K2CO3). The aim of this molecular modeling study is to develop insight into the thermodynamics and kinetics of the chemical reactions during scale removal. A cluster approach was chosen to mimic the overall system. Standard density functional theory (B3LYP/6-31G*) was used for all calculations. Low spin K4Fe(II)4(S2H)12 and K3Fe(II)(S2H)5 clusters were derived from the crystal structure of pyrite and used as mimics for surface scale FeS2. In addition, K5DTPA was used as a starting material too. High spin K3Fe(II)DTPA, and K2S2 were considered as products. A series of KmFe(II)(S2H)n complexes (m = n–2, n = 5–0) with various carboxylate and glycinate ligands was used to establish the most plausible reaction pathway. Some ligand exchange reactions were investigated on even simpler Fe(II) complexes in various spin states. It was found that the dissolution of iron sulfide scale with DTPA under basic conditions is thermodynamically favored and not limited by ligand exchange kinetics as the activation barriers for these reactions are very low. Singlet–quintet spin crossover and aqueous solvation of the products almost equally contribute to the overall reaction energy. Furthermore, seven-coordination to Fe(II) was observed in both high spin K3Fe(II)DTPA and K2Fe(II)(EDTA)(H2O) albeit in a slightly different manner.

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