Induction of IFNα in the upper airways via activation of TLR7 represents a novel immunomodulatory approach to the treatment of allergic asthma. Exploration of 8-oxoadenine derivatives bearing saturated oxygen or nitrogen heterocycles in the N-9 substituent has revealed a remarkable selective enhancement in IFNα inducing potency in the nitrogen series. Further potency enhancement was achieved with the novel (S)-pentyloxy substitution at C-2 leading to the selection of GSK2245035 (32) as an intranasal development candidate. In human cell cultures, compound 32 resulted in suppression of Th2 cytokine responses to allergens, while in vivo intranasal administration at very low doses led to local upregulation of TLR7-mediated cytokines (IP-10). Target engagement was confirmed in humans following single intranasal doses of 32 of ≥20 ng, and reproducible pharmacological response was demonstrated following repeat intranasal dosing at weekly intervals.

Pyrite is one of the toughest iron sulfide scales to remove, which causes major problems in oil and gas production by damaging production equipment. The use of inorganic acid in iron sulfide scale removal particularly pyrite is ineffective and produces toxic gases such as hydrogen sulfide. In this work, H2-S free formulation composed of diethylenetriamine pentaacetic acid (DTPA) combined with potassium or cesium carbonate as the converter is used. The reaction kinetics of pyrite dissolution using a specially designed rotating disk apparatus is investigated. Different characterization techniques such as SEM–EDX, XRD, and XPS were used for the characterization of the pyrite surface before and after chemical treatment. The effects of temperature, rotational disk speed, and converter type on the kinetics are studied. At 130 and 150 °C, the reaction rate increased linearly with the disk rotational speed representing mass-transfer-limited reaction, and the activation energy was 9.94 kJ mol–1. The DTPA diffusion coefficients for the new formulation at 130 and 150 °C were 1.023 × 10–9 and 1.177 × 10–9 cm2 s–1, respectively. The replacement of potassium carbonate by cesium carbonate did not produce a significant effect on the reaction kinetics. Coreflooding tests were carried out using the new formulation of DTPA with K2CO3 to simulate the real dissolution of the scale in pipes, and a solubility of 140 ppm h–1 has been attained. The estimation of the pyrite dissolution rate by DTPA is expected to support engineering design in iron sulfide removal from oil and gas wells.

In the oil and gas industry, pyrite forms one of the most hardened scales in reservoirs, which hinders the flow of fluids. Consequently, this leads to blockage of the downhole tubular, formation damage, and complete shutdown of production and operational processes. Herein, a new green formulation based on borax (K 2 B 4 O 7 ) is proposed for pyrite scale removal. The temperature effect, disk rotational speed, and borax concentration have been investigated using a rotating disk apparatus. Also, XPS and SEM−EDX analyses were conducted on the pyrite disk surface before and after the treatment with the green formulation. The new formulation showed the potential ability to dissolve pyrite without generating the toxic hydrogen sulfide (H 2 S). The dissolution rate of the scale in the new formulation is increased by 16% compared to that in a previous green formulation composed of 20 wt %DTPA+9 wt % K 2 CO 3 . Molecular modeling technique using DFT was used to study the solvation energies of Fe 2+ and Fe 3+ . The latter had a higher solvation energy than the former, which confirmed that upon using the borax-based formulation to oxidize Fe 2+ to Fe 3+ . It will aid the dissolution of pyrite scales. The new formulation achieved a corrosion rate that is 25 times lower than that of 15 wt % HCl, which is commercially used in treating scales. Finally, the proposed new formulation does not require the use of corrosion inhibitors; hence, it is expected to result in a more economical scale treatment method.

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Gas condensate reservoirs experience significant productivity losses as reservoir pressure drops below the dewpoint due to condensate accumulation and the subsequent reduction in gas relative permeability. One potential way to overcome this problem is to alter reservoir wettability to gas-wetting to reduce condensate accumulation in the near-wellbore and maintain high productivity. The aim of this study was to evaluate the effectiveness of various chemical treatments in altering wettability of gas-condensate reservoirs from liquid wetting to intermediate gas wetting. Coreflood experiments were conducted on carbonate and sandstone reservoir cores and Berea cores at simulated reservoir conditions. Several chemicals (fluorochemical and silane) were screened in this study to determine their capability in removing the trapped condensate from cores, enhancing gas relative permeability, and delaying condensate accumulation. The results of coreflood tests showed that the effectiveness of fluorochemical surfactant is affected by treatment volume, aging time, core permeability and temperature. Sandstone cores treated with 1.25 wt% silane chemical showed repellency to liquids (water and condensate) and an enhancement (up to 42%) in gas relative permeability. It was found that core permeability plays a role in wettability alteration agents' effectiveness. Wettability tests showed that contact angle on treated cores is 116° for water and 114° for condensate, indicating wettability alteration from liquid to intermediate gas wetting. Environmental Scanning Electron Microscope (ESEM) analysis performed on silanes-treated cores gave a conclusive evidence of wettability alteration at the pore scale. Introduction Maintaining production from gas reservoirs is a challenge due to the dropout of condensate and accumulation in the near wellbore region when the bottom hole flowing pressure decreases below the dewpoint pressure. Condensate flows along with the gas phase in the reservoir only when its saturation reaches or exceeds the critical condensate saturation. Gas well productivity starts to decline as condensate bank forms around the wellbore area. Without pressure maintenance (for example, gas cycling), condensate banking cannot be prevented. It may be delayed by using the proper exploitation methods, such as fracturing and horizontal completion.1–7 Condensate can be mobilized from the near wellbore region by either reducing capillary pressure or increasing drawdown pressure (viscous forces). Capillary pressure can be reduced by either decreasing the interfacial tension, wettability alteration. Solvents have been used to remove condensate banking from gas wells by decreasing interfacial tension and increasing liquid vaporization rate, but their effectiveness is temporary due to solvent flowback.8,9 Since most of reservoirs are preferential liquid wet, altering their wettability using chemical treatments to intermediate or gas wet reduces condensate entrapment and helps to maintain or increase gas production. Achieving this objective, chemicals are required to have certain properties such as longevity, non-damaging, thermally stable and low cost.

Iron Sulfides scale has been a critical problem for oil and gas wells for several decades. One of the best candidates to remove these scales is tetrakis(hydroxymethyl)phosphonium sulfate (THPS). Most studies on the dissolution of iron sulfide scale using THPS have been done at neutral or acidic medium. Such conditions lead to a high corrosion rate when THPS is used in tubular wells. However, this work aims to give a holistic view on the pH effect, especially in alkaline medium, on the ability of THPS to dissolving iron sulfides. A combined approach of experimental and computational methods is used to get a better understanding of the pH effect on THPS ability to dissolve pyrite. Both experimental and theoretical techniques suggest that the pyrite dissolution ability of THPS decreases as pH increases. Conversely, combing THPS with EDTA (Ethylenediaminetetraacetic acid) proved effective in dissolving a mixture of different iron sulfide field scales. EDTA is a basic chelating agent which gave a pH of 8 when combined with THPS giving a slightly alkaline solution. For the field scale the combined formulation of THPS and EDTA yielded more than 70 % scale solubility however, for pure pyrite it was less than 10%. This implies that THPS and EDTA combination is effective in dissolving other iron sulfide scales, such as pyrrhotite (Fe7S8) and troilite (FeS) which are more soluble in comparison with pyrite. Also, THPS with Di-ethyline Tri-amine Penta Acitic acid (DTPA) formulation was tested and resulted in slightly lower solubility compared to THPS/EDTA formulation. Moreover, oilfield scales are usually a mix of a variety of minerals and not only pyrite. Hence, using THPS in combination with EDTA to attain a basic pH would reduce the corrosion rate and subsequently reduce or eliminate the need for corrosion inhibitors.

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Rock mechanical parameters of reservoir rocks play an extremely important role in solving problems related to almost all operations in oil or gas production. A continuous profile of these parameters along the depth is essential to analyze these problems which include wellbore stability, sand production, fracturing, reservoir compaction, and surface subsidence. The mechanical parameters can be divided into three main groups, viz., elastic parameters, strength parameters, and in-situ stresses. Even the profile of in-situ stresses with depth is estimated using logs with elastic parameters as an essential input. The focus of this work is on the prediction of elastic parameters and their variation with the depth of a given reservoir. For an isotropic medium, there are two independent elastic parameters, viz., Young's modulus and Poisson's ratio. Generally, logging data consisting of density, compressional and shear wave velocities are used to estimate these parameters. However, these data provide dynamic elastic properties which are different from static values, especially in case of Young's modulus. To get continuous rock samples throughout the depth of the reservoir and conduct triaxial tests to determine the static values of these parameters is extremely expensive. Consequently, static values of Young's modulus and Poisson's ratio obtained from laboratory testing on rock samples acquired from selected intervals are used to calibrate the dynamic data obtained from logs. However, since the rock layers vary in their properties with depth, a realistic estimation of static elastic values of the rock is still a challenge. The problem is more prominent in limestone rocks compared to sandstone rocks. Further, shear velocity data is not always available from well logs, making the problem more difficult. An extensive experimental program was carried out first to obtain the static values of elastic parameters of reservoir rock samples at reservoir conditions of high pressure. Log data consisting of different variables such as density, velocity, and porosity from the same wells were also obtained. Three artificial intelligence methods viz. Neural Network, Fuzzy Logic and Functional Network, were used to obtain a continuous profile of static elastic parameters along the depth. The results obtained from these approaches were compared using log inputs. The strengths of each of these approaches are also discussed.