Wettability Alteration Agent Research Articles

Characteristics of ethoxylated fatty amine emulsion: Effects on the wettability and permeability of silicate formation under various pH conditions

Abstract The effects of ethoxylated fatty amine emulsion on the wettability and permeability of silicate rock under various pH conditions, as well as the adsorption behavior of ethoxylated fatty amine on the silicate rock surface, were investigated using core displacement test, contact angle test and infrared spectroscopy. A new knowledge about the characteristic and mechanism of formation damage from reversible invert emulsion drilling fluids and a new method for the completion and cementing of a well drilled by reversible invert emulsion drilling fluids were proposed. Under pH of 4 to 8, exthoxylated fatty amine can adsorb on the rock surface to various degrees, resulting in the strong oil-wet condition of rock which does a serious harm to the permeability of the formation. Under pH of 10, no exthoxylated fatty amine adsorbs in the rock, resulting in the water-wet condition of the rock surface which is benefit to mitigating the damage of mud to the permeability of the formation. It is suggested removing the reversible invert emulsion drilling fluid using acidic fluids followed by basic fluids or using acidic fluids combined with wettability alteration agents.

Stability of Nanoporous Silica Aerogel Dispersion as Wettability Alteration Agent

This work studies the stability of silica aerogel aqueous dispersion for wettability alteration in enhanced oil recovery (EOR) processes. Modified silica aerogel is synthesized with cheap water glass as the precursor, and ambient pressure drying method. Brine composition, brine concentration and temperature of oil reservoirs are the most important parameters for success of wettability alteration processes in EOR. Stability of Silica aerogel aqueous dispersions in NaCl, MgCl2 and combinations of them are surveyed. Brines at different concentrations, 10000, 20000, 40000 ppm, are used to determine stability conditions. Stability at 30°C and 75°C are surveyed, and the results are reported. DLVO and non-DLVO theories are used for modeling the stability of nanodispersion.

Research and Application of Depressure and Increasing Injection Technology in Low Permeability Oilfield

In China, most of undeveloped oil reserves are low and ultra low permeability reservoirs. The total remaining petroleum reserves of CNPC is about 4.07×107m3, and the low and ultra low permeability reserves is 3.16×107m3, So it is important to reasonable develop the oil reserves to keep the petroleum output stable. Under the low permeability layer condition, it is difficult to inject water to the formation, and the output of oil well is very low. The chemical agent can solve the difficulty of injection water and enhance the oil recovery. The relative permeability experiments shows irreducible oil was reduced by the wettability alteration agents, and the mobile oil saturation increased, which enlarging the range of the two phases co-flowing and enhancing oil recovery. As a result with alteration agents, the cross-point relative permeability moves to right, and the core converts to water-wet. In daqing oil field test, the water injection pressure is reduced by 15%, and the term of validity is more than 10 months.

Modelling of wettability alteration processes in carbonate oil reservoirs

Previous studies have shown that seawater may alter thewettability in the direction of more water-wet conditions incarbonate reservoirs. The reason for this is that ions from thesalt (sulphat, magnesium, calsium, etc) can create a wettabilityalteration toward more water-wet conditions as salt is absorbed onthe rock. In order to initiate a more systematic study of this phenomenon a1-D mathematical model relevant for spontaneous imbibition isformulated. The model represents a core plug on laboratory scalewhere a general wettability alteration (WA) agent is included.Relative permeability and capillary pressure curves are obtainedvia interpolation between two sets of curves corresponding tooil-wet and water-wet conditions. This interpolation depends onthe adsorption isotherm in such a way that when no adsorption ofthe WA agent has taken place, oil-wet conditions prevail. However,as the adsorption of this agent takes place, gradually there is ashift towards more water-wet conditions. Hence, the basicmechanism that adsorption of the WA agent is responsible for thewettability alteration, is naturally captured by the model. Conservation of mass of oil, water, and the WA agent, combined withDarcy's law, yield a 2x2 system of coupled parabolicconvection-diffusion equations, one equation for the water phase andanother for the concentration of the WA agent. The model describesthe interactions between gravity and capillarity when initialoil-wet core experiences a wettability alteration towards morewater-wet conditions due to the spreading of the WA agent bymolecular diffusion. Basic properties of the model are studied byconsidering a discrete version. Numerical computations are performedto explore the role of molecular diffusion of the WA agent into thecore plug, the balance between gravity and capillary forces, anddynamic wettability alteration versus permanent wetting states. Inparticular, a new and characteristic oil-bank is observed. This isdue to incorporation of dynamic wettability alteration and cannot beseen for case with permanent wetting characteristics. Moreprecisely, the phenomenon is caused by a cross-diffusion termappearing in capillary diffusion term.

Laboratory and Field-Trial Results of Condensate-Bank Removal in Retrograde-Gas Reservoirs

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 102558, "Laboratory and Field-Trial Results of Condensate-Banking Removal in Retrograde-Gas Reservoirs: Case History," by F.O. Garzon, SPE, H.A. Al-Anazi, SPE, J.A. Leal, SPE, and M.G. Al-Faifi, Saudi Aramco, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September. Gas-condensate reservoirs experience significant productivity losses when the reservoir pressure declines below the dewpoint. This productivity loss is caused by liquid condensation near the wellbore and the subsequent decline in gas rate because of the reduced gas relative permeability. Gas-condensate wells often are fracture stimulated to reduce the drawdown and subsequent formation of a condensate bank in the vicinity of the well. The use of filtered diesel to remove the condensate bank from gas wells was investigated. Introduction Condensate banking can be mitigated or delayed by different methods. The most efficient and costly method is implementing a pressure-maintenance program to keep the reservoir pressure and the producing-well sandface pressure higher than the dewpoint pressure. This method prevents condensation (liquid drop-out) in the reservoir and, therefore, prevents creation of a condensate bank. A common method used to delay creation of this bank around the wellbore and keep the bottomhole flowing pressure above the dew-point pressure is to reduce the drawdown by fracture stimulating vertical wells or by drilling horizontal wells. Chemical treatments also can be used to restore well productivity by removing the condensate bank. Chemical treatments with solvents or wettability-alteration agents have been studied with promising results. Alcohols can be used as solvents to remove condensate and/or water blockage and enhance gas relative permeability. A methanol treatment was implemented on a gas well in the Hatter Pond field that increased gas- and condensate-production rates. Altering the wettability of the reservoir from liquid-wet to intermediate-gas-wet can reduce condensate banking. Experiments performed on Berea and reservoir cores showed that some fluorinated polymeric surfactants increased gas relative permeability and altered core wettability. In gas wells that have been fracture stimulated, the likelihood of developing a condensate bank near the wellbore is high because of a lack of pressure support and/or lower bottomhole flowing pressure in the well. The use of filtered diesel in the "X" formation was studied to investigate its effectiveness in removing the condensate bank and enhancing gas productivity. The study also ensured that the treatment had no adverse effect on reservoir permeability. Experimental Studies Coreflood experiments were performed to determine the effectiveness of treatments in removing condensate banking and enhancing gas relative permeability. Tests were conducted at simulated reservoir conditions of 230°F and 1,500 psig on reservoir cores recovered from different gas wells. Coreflood tests were divided into single- and two-phase tests. Single-phase tests optimized the concentration of mutual solvent (MS) and surfactants.