The majority of polymer applications to date have targeted medium-to-high permeability sandstone reservoirs containing reservoir brine with moderate salinity and hardness. Polymer flooding for enhanced oil recovery has been field-tested in carbonates, but applications tailored towards oil-wet, low-permeability limestone rocks are uncommon. This paper contains results from laboratory core flood tests performed on four strongly oil-wet limestone rocks from the Al Shaheen field, off-shore Qatar. The rock samples investigated had 25–30% porosity and 0.3–28 mD permeability; the reservoir brine had a salinity of about 120,000 ppm of which 10,000 ppm were divalent cations. The bulk fluid testing involved fluid compatibility tests, long-term stability tests, as well as rheology measurements. Three commercial polymers were screened, one of which successfully passed all the screening criteria. Core flood experiments were subsequently performed to determine relative permeability, adsorption, inaccessible pore volume, as well as permeability and mobility reduction. The crude oil had a viscosity of 8 cP at reservoir conditions, yielding a slightly unfavourable mobility ratio for the baseline water flood. At concentrations of 500–1,000 ppm, the selected HPAM polymer gave rise to some mobility and permeability reduction, as expected, but it did not seriously plug any of the four low-permeability cores. The dynamic adsorption was very low, around 10–20 μg/g rock, the inaccessible pore volume was 15–20%, which is in line with industry experience, and the injectivity reduction was in agreement with ECLIPSE and UTCHEM simulations, which suggest that significant polymer degradation did not take place. The low adsorption is attributed to the strong oil-wetness of the rock. Since the polymer flows in the water phase, presence of a strong oil film likely prevents the polymer from adsorbing to the rock. The results from a subsequent water flood showed that inaccessible pore volume introduced by the polymer persists during the subsequent water flood; such a feature has yet to be incorporated in UTCHEM and ECLIPSE. In fact, the data revealed many features, which could not be adequately captured by numerical simulation tools. The main conclusion from the laboratory work is that polymer systems with good viscosifying power can be tailored to recover oil from low-permeability carbonate rocks, pushing the permeability limit down to around 1 mD.
In gas condensate reservoirs, considerable productivity loss occurs after the pressure near the production wells drops below the dew point of the hydrocarbon fluids. Over the years, several methods have been proposed to restore gas production rates after a decline in well productivity owing to condensate and/or water blocking. These methods such as gas recycling, hydraulic fracturing and solvent injection have shown to restore the production on a temporary basis only. Altering the wettability of reservoir rock using fluoro-chemical treatments has proved to be a viable and permanent solution to this problem. The selection of these treatments from a large pool of potentially effective chemicals requires extensive laboratory testing which requires time and money.In this paper, we present data that correlates changes in wettability with improvements in relative permeability. Imbibition, contact angle and X-ray photoelectron spectroscopy (XPS) tests along with coreflood results are used to characterize wettability changes. XPS tests, drop tests and core flood experiments were conducted and correlated with each other. It is shown that XPS analysis and imbibition tests provide a quantitative measure of chemical adsorption and surface modification, but only a qualitative measure of the possible change in relative permeability. As such these simple analytical tools may be used as a screening tool. A positive but imperfect empirical correlation was obtained with results from core flood experiments. The varying concentration of fluorine observed on the rock surface was found to be directly correlated to the wettability change in the rock, which in turn is responsible for improving the deliverability of wells in gas condensate/volatile oil reservoirs.The method discussed in this paper can be successfully used to identify chemical treatments that can change rock wettability and, therefore, relative permeability. This provides a simple and inexpensive way to screen chemicals as wettability altering agents and relative permeability modifiers. In this way the number of HTHP core floods needed is minimized which saves time, cost and effort. IntroductionGas condensate reservoirs are becoming more common as the petroleum industry goes to greater depths to explore for oil and gas. When we compare dry-gas reservoirs with gas-condensate reservoirs, there are many factors which affect the performance of gas-condensate reservoir during the exploitation process that need to be understood. As the reservoir pressure declines below the dew point of the fluid, a liquid rich phase starts to drop out of the gas phase. This liquid rich phase is termed "condensate" and the phenomenon is called "condensate banking". Since the largest pressure drop occurs near the producing wells, the formation of a condensate phase usually occurs as a near well bore phenomenon. As the pressure continues to drop, the liquid continues to accumulate occupying the rock pores leading to a decrease in the effective permeability to gas.Several cases have been reported i...
In volatile oil reservoirs, the presence of two fluid phases (gas and oil) near the wellbore is a common problem that affects well deliverability. As the pressure falls below the bubble point the presence of two immiscible phases reduces the oil relative permeability and leads to lower oil production rates. In this paper, we show that the application of fluorinated chemicals can mitigate this impairment associated with gas blocking of volatile oils. We show through laboratory experiments that the treatment not only removes the water from the treated zone, but also modifies the wettability of the rock surface to neutral wet, minimizes capillary trapping and enhances the mobility of oil and gas. The chemical treatment is effective in the presence of connate or flowing water over a range of temperatures. This technique may be used as a curative or preventive treatment in volatile oil reservoirs, potentially increasing oil production rates and recoverable reserves. High-pressure high-temperature (HPHT) coreflood tests were conducted that show that the treatment improved the relative permeability, by a factor of about 1.3 to 2.6 at a GOR of 6000 to 7000 scf/STB in sandstone and limestone cores at low capillary numbers (Nc). Wettability alteration was measured using contact angle and imbibition tests. These tests together with x-ray photoelectron spectroscopy (XPS) analysis were used to screen the selected surfactants. Since this durable enhancement is achieved by treating a small area around the wellbore, it may be applicable in a wide variety of wells.
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