Raffia palm fibers are potential reinforcement materials for making cost-effective polymer-based composite. This paper presents the results obtained from a study of physical, chemical, thermal and mechanical properties of raffia palm fibers (RPFs) derived from the raffia palm tree (Raphia farinifera). The as-received RPFs had their remnant binders manually removed and was subsequently cleaned in a 2% detergent solution before drying in an air oven at 70 °C for 24 h. Evaluation of the properties of the dried samples was carried out using a combination of characterization techniques including chemical composition determination, density measurement, moisture adsorption and water absorption measurements, tensile testing, scanning electron microscopy (SEM), differential scanning calorimetry (DSC), Raman spectroscopy, X-ray diffractometry, and Fourier transform infrared spectromicroscopy. The main constituents of RPFs were found to be cellulose, hemicellulose and lignin. The average diameter and average density were 1.53 ± 0.29 mm and 1.50 ± 0.01 g/cm 3 , respectively. The average breaking strength of the fibers ranged from 152 ± 22 to 270 ± 39 MPa; it did not vary significantly with fiber length and cross-head speed during tensile testing. The results of scanning electron microscopic investigation of the fibers showed that they comprise several elemental fibers which are tightly packed together with each having its own lumen. Synchrotron-based Fourier-transform infrared spectromicroscopy of a cross-section of the fiber showed that lignin is concentrated mostly on the outside while cellulose and pectin are concentrated in the mid-section. A two-stage water sorption behavior was observed for the fibers.

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Matrix acidizing treatments are applied to gas wells to remove near-wellbore permeability impairment (formation damage). The acidizing process differs in gas wells compared with oil wells or water injection wells because of two-phase, gas-liquid flow during acid injection, and also because of the relatively low viscosity of the gas. This paper demonstrates how these differences affect the penetration of acid into the formation and the distribution of acid along the wellbore (acid placement). When acid displaces gas in the formation around the wellbore, the favorable mobility ratio between the acid and the gas will lead to a piston-like displacement of the gas by the acid. However, behind the acid front, a residual gas saturation will remain. Our study shows that the impact of the residual gas saturation increases acid penetration into the reservoir, when compared with a single-phase displacement process. The large contrast between the viscosity of the acid and the gas in the reservoir may be beneficial to a better distribution of acid along the wellbore. Because the acid is much more viscous than the gas, there will be an increased pressure drop wherever acid is placed in the formation. This can function as a natural viscous diversion - as acid enters the higher permeability zones, the increased pressure gradient can divert relatively more acid to lower permeability zones. We present modeling results that illustrate the magnitude of the viscous diversion effect in gas wells. This natural diversion precludes the use of gels or other viscous fluids for diversion in gas wells. INTRODUCTION Matrix acidizing treatments are applied to gas wells for the same general purpose as in oil wells or water injection wells - to overcome formation damage effects by restoring or increasing the permeability in the near-wellbore region. However, the behavior of an acid treatment in a gas well may differ from that in oil production or water injection wells because of two-phase gas-liquid flow during acid injection and because of the large viscosity difference between the injected acid and the reservoir gas. This paper investigates these effects which occur when acidizing gas wells that are not considerations in acidizing oil or water wells. The acid penetration distance into the reservoir is one of the key parameters for a successful matrix acidizing treatment. It is often desirable for the acid to penetrate as deep into the formation as possible in order to treat the damaged region. When acid displaces gas in the reservoir, a residual saturation of gas is left behind the injected acid front. The presence of this residual gas saturation reduces the cross-sectional area available for flow of acid, thus increasing the velocity of the acid for a fixed injection rate. This allows for deeper penetration of the acid into the formation than would occur if the formation were completely water saturated. The viscosity of acid at downhole conditions is on the order of 100 times that of a typical natural gas at the same temperature and pressure1,2. Thus, the injected gas is very viscous relative to the gas it is displacing. One result of this viscosity contrast is that the apparent skin factor of the well will increase due to the bank of relatively viscous fluid building up in the formation. It has been previously shown3 that this apparent skin increase can be accounted for with a viscous skin factor, which, when subtracted from the total apparent skin factor, reveals the true damage skin evolution during a treatment.

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