Summary Asphaltene deposition in the near-wellbore region can block pore throats, change wettability characteristics and relative-permeability relationships, and therefore, reduce oil production. Conventional aromatic solvents (e.g., toluene, xylene) alone or in combination with various dispersants are used to remove asphaltene damage from the near-wellbore region. However, these aromatic solvents are expensive and are not environmentally friendly. The objective of this work was to systematically evaluate the asphaltene-solvating power of various non conventional solvents, including deasphalted oil, using a light-scattering technique. Experimental results suggest that deasphalted oil is a strong asphaltene solvent presumably because of its native resin and aromatic contents. Addition of asphaltene dispersants also increases the solubilizing power of the deasphalted oil. Furthermore, various refinery and heavy oil upgrader streams show strong ability to solubilize asphaltenes. Introduction Asphaltenes are defined as the n-pentane insoluble fraction of crude oil. They are polar molecules that aggregate together through aromatic - orbital association, hydrogen bonding and acid-base interactions. These asphaltene molecules also contain some heteroaromatics (aromatics with nitrogen, sulphur, and oxygen atoms included in the structure). They exist as platelets and are maintained in suspension by maltenes and resins. The growth of the aggregates is limited by the association of asphaltenes with resins in solution. The molecular weight of these aggregates can grow to several hundred thousand grams per mole. Asphaltene-solubility modelling studies based on the principle of colloidal suspension have been reported in the literature. In several cases, molecular theory has also been used to predict the dynamics of asphaltene flocculation.

FIGURE 2: X-ray diffraction spectra of smectite at various temperatures.

Experiments were carried out using nanofiltration to separate salts from a hydrogen sulphide scrubber solution taken from an iron‐based liquid‐redox process. The scrubber solution used in these experiments contained organic chelating agents, iron, and various alkali metal inorganic salts (i.e., sulphates, thiosulphates, carbonates, and bicarbonates). The nanofiltration unit was equipped with monovalent ion‐selective membranes. Results indicated that the nanofiltration membranes retained organic materials and iron and allowed ionic species (e.g., SO42‐, S23‐, CO32‐, HCO3‐) to permeate. Results also indicated that the nanofiltration membranes used in these experiments preferentially removed CO32‐ and HCO3‐ over SO42‐ and S2O32‐. The nanofiltration tests did not show any sign of membrane degradation in terms of ion selectivity; however, at high total‐dissolved solids concentrations, the permeate flow rate was reduced.

Introduction LO-CAT Z autocirculation processSour natural gas produced from reservoirs contains a significant amount of impurities such as hydrogen sulfide (H2S) and carbon dioxide (CO,). Such a gas must be treated before marketing. In a sour-natural-gas sweetening facility, the natural gas is treated directly by an amine process to remove H2S and CO,. The amine solution is regenerated in an amine regenerating unit. The regenerated amine solution is recycled in the amine process, and the H,S and CO, concentrated stream from the amine regeneration unit, called acid gas, is either processed for sulfur recovery or incinerated, depending on the concentration of H,S in the acid gas.There are several commercial processes available for sulfur recovery, including the Claus process, which is suitable only for sulfur recovery of 10 tonne/day or more. Liquid-redox processes are ideal for sulfur recovery of less than 30 tonne/d. LO-CAT I autocirculation process is an iron-based liquid-redox process that is licensed by ARI Technologies Inc. (Meuly, 1977;Hardison, 1977;Thompson, 1980a; Primak, 1983;1984;McManus and Kin, 1986) and that uses a proprietary mixture of "Type A ' (ethylenediaminetetraacetic-acid (EDTA) -like) and "Type B" (sorbitol-like) chelating agents to hold iron in solution at high pH.The liquid reduction-oxidation or redox process is used to scrub hydrogen-sulfide (H,S)-containing gas streams. In this process, the gas containing H,S is contacted with an alkaline liquid phase (usually at pH 7.0 to 9.0) containing a dissolved metal-organic chelate reagent. While any polyvalent transition metal can be employed in this process, iron is most commonly used. The H2S from the gas stream is absorbed into the alkaline solution, forming hydrosulfide ions, The ionic distribution of sulfur anions is predominantly HS-, or hydrosulfide ions, at the process pH. The hydrosulfide ions react with the polyvalent metal, oxidizing the hydrosulfide to elemental sulfur and reducing the oxidation state of the metal: The metal is then oxidized with dissolved oxygen in the same vessel:The overall sulfur-producing reaction isSide reactions oxidize a portion of the dissolved hydrosulfide ions to acidic sulfur compounds, primarily sulfate (SO:-) and thiosulfate (S,O:-1. Walter (1977) indicated that above pH 7.0 from 2 to 9% of the H,S fed to a liquid redox scrubber was converted into acidic sulfur compounds. These sulfur compounds tend to lower the pH of the scrubber solution, reducing its scrubbing effectiveness. It is normal practice in these processes to maintain the pH of the scrubber solution above 7.0 by the continuous or periodic addition of alkaline chemicals such as the ammonium or alkali-metal salts of the carbonate (COf 1, bicarbonate (HCO, ), or hydroxide (OH-) anions. The neutralization of the acidic sulfur compounds results in a steady buildup of the corresponding ammonium or alkali metal salts. Overall chemical equations are given below for the two most common species formed:where M stands for an ammonium or alkali-metal cat...

Heavy‐oil‐in‐water (o/w) emulsions containing produced sand were prepared using commercially available emulsifiers. The emulsions were tested in beakers for emulsion type, quality, and sand‐retention characteristics. The apparent viscosities of the o/w emulsions were measured. The effects of polymer addition on the apparent viscosity and sand‐carrying capability of the emulsions were also studied. The results of the breaker tests indicate that most emulsifier solutions water‐wet the beaker wall and temporarily improve heavy‐oil flow characteristics. However, most of the chemicals also water‐wet the sand particles and cause sand dropout. The Flothin F2 chemical alone showed stable oil dispersion and, in combination with the Flocon 4800C polymer, showed very good sand‐retention, viscosity‐reduction, and stable oil‐dispersion characteristics.