An Experimental Investigation of Magnetized Water Effect on Formation Damage

In oil industries, water injection into oil reservoirs for pressure maintenance, oil displacement, and oil recovery is a common technique. Formation damage during water injection is a major problem in this process. Formation damage from the incompatibility of formation water (FW) and injection water (IW) causes a reduction in the permeability around the injection wells. Therefore, it is necessary that the formation damage be minimized using specific techniques such as the injection of scale inhibitors and water compatible with formation water. It has been proven that moving water through relatively weak magnetic field changes water properties. These changes involve density, electrical conductivity, salts dissolving ability, sedimentation rate of solid particles etc. This study was conducted to investigate the effect of magnetized water injection on the decline in rock permeability. Therefore, a magnetic field device was designed and combined with a formation damage setup. The results indicate that, in the presence of magnetic field, water injection causes less damage to rock, and the permeability reduction in this case is lower than when non-magnetized water is injected. In addition, the results show that a higher magnetic field flux reduces the permeability damage

Experimental Investigation of Water Based Colloidal Gas Aphron Fluid Stability

Today, the drilling operators use the Colloidal Gas Aphron (CGA) fluids as a part of drilling fluids in their operations to reduce formation damages in low-pressure, mature or depleted reservoirs. In this paper, a Taguchi design of experiment (DOE) has been designed to analyse the effect of salinity, polymer and surfactant types and concentration on the stability of CGA fluids. Poly Anionic Cellulose (PacR) and Xanthan Gum (XG) polymers are employed as viscosifier; Hexadecyl Trimethyl Ammonium Bromide (HTAB) and Sodium Dodecyl Benzene Sulphonate (SDBS) have been also utilized as aphronizer. Moreover, bubble size distributions, rheological and filtration properties of aphronized fluids are investigated. According to the results, the polymer type has the highest effect, whereas the surfactant type has the lowest effect on the stability of CGA drilling fluid. It was also observed that increasing salinity in CGA fluid reduces the stability. Finally, it should be noted that the micro-bubbles generated with HTAB surfactant in an electrolyte system, are more stable than SDBS surfactant