A Literature Analysis of the WAG Injectivity Abnormalities in the CO2 Process

Abstract

TX 75083-3836, U.S.A., fax 01-972-952-9435. 3. 3 nitrogen-miscible projects 4. 1 hydrocarbon-immiscible 5. 1 nitrogen-and hydrocarbon-immiscible 6. 6 nitrogen-immiscible CO 2 projects continue to grow in numbers. Immiscible CO 2 projects have dropped to zero while ten new miscible CO 2 projects were planned as of January 1998. Brock and Bryan 2 presented a summary of CO 2 EOR projects and reviewed the performance of 30 full-scale field projects and field pilots up to 1987. In 1992 there were 45 active CO 2 projects in the U.S. 3 Initially the industry outlook was pessimistic; however, by 1992 most projects had been shown to be technically and economically successful. In a number of projects, the production performance has been better than was anticipated. 3 At the beginning of 1998 and based on 1997 production figures, the U.S. production from gas injected EOR was estimated at 307,544 b/d or approximately 4.7% of the total oil production in the US. Oil production from CO 2 activity alone contributed nearly 179,000 b/d, which is an increase of 4.9% over 1996 production attributable to CO 2 production and represents 2.8% of the 1997 US oil production of 6.4 MM bopd. 1 The Permian Basin of west Texas and southeastern New Mexico remains a very active area for CO 2 projects. Eight of the ten planned projects are in the Permian Basin. 1 However, new CO 2 EOR projects are possible for areas of California,

Interfacial tension of CO2 and crude oils under high pressure and temperature

“…The predicted MMP and P max of CO 2 + crude oil system are separately shown in Figs. 6 With the measured data (symbols) in Fig. 6, the measured IFT between CO 2 and crude oil A is correlated to the pressure P (MPa) by applying the linear regression in the following two pressure ranges, respectively: …”

“…It has been found that for CO 2 flooding, the oil recovery rate can be enhanced usually up to 8-16% of the original oil in place [6,7]. The oil viscosity reduction, oil swelling effect and miscibility between CO 2 and crude oil are considered main contributions for CO 2 -EOR [8,9].…”

An experimental and numerical investigation into the impact of dissolution/precipitation mechanisms on CO2 injectivity in the wellbore and far field regions

“…Such a process comprises the alternating introduction of a non-condensable, miscible gas such as carbon dioxide, with an aqueous drive fluid, e.g., brine. A survey conducted by Rogers and Grigg (2000) on CO 2 flooding indicated that loss of injectivity on WAG cycles has been a limiting factor in many projects. Based on fluid properties, it is expected that CO 2 injectivity should be significantly greater than brine injectivity since CO 2 has a much lower viscosity.…”

“…Based on fluid properties, it is expected that CO 2 injectivity should be significantly greater than brine injectivity since CO 2 has a much lower viscosity. However, a number of tertiary CO 2 pilots, such as the Levelland and Slaughter Fields in West Texas and the Denver Unit in the Wasson Field have reported a significant loss of injectivity compared to the pre-gas waterflood (Henry et al, 1981;Christman and Gorell, 1990;Rogers and Grigg, 2000). Rogers and Grigg (2000) suggested that the reduced injectivity reported in the Levelland pilot has to be considered as an in-depth phenomenon, rather than a wellbore or near-wellbore condition such as skin or high saturation around the wellbore.…”

CO2 mobility control and sweep efficiency improvement using starch gel or ethylenediamine in ultra-low permeability oil layers with different types of heterogeneity

“…However, the WAG displacement characteristics could be influenced by many factors including reservoir wettability and heterogeneity (Dijke et al, 2006;Elfeel et al, 2013b), the composition of crude oil and injected water (Kulkarni and Rao, 2005), as well as the injection parameters such as CO 2 slug size, gas/water ratio, CO 2 injection rate and voidage replacement ratio (Song et al, 2014). WAG flooding could also cause injectivity problems in some reservoirs (Rogers and Grigg, 2001). Surfactant alternating gas (SAG) flooding and foam assisted water alternating gas (FAWAG) flooding are other methods used to delay gas breakthrough during CO 2 flooding (Spirov et al, 2012;Salehi et al, 2014).…”