Comparison of Laboratory- and Field-Observed CO2 Tertiary Injectivity
Authors: Christman Peter G. , Gorell Sheldon B. 
Published: December 2007

Summary
Although CO2 injectivity should be significantly greater than brineinjectivity because CO2 has a much lower viscosity than brine, this behavior isnot always seen, as shown in a Denver Unit field test. This paper examinesfeatures that cause differences in CO2 injectivity with a model that usessimple non-dispersive flow with a series of constant-composition slugs toapproximate the analytical solution (normally a sequence of shocks and tails)in a sequence of noncommunicating layers. Because of its simplicity, this modelidentifies the primary features that result in the different observed CO2injectivities more clearly than the finite-difference model. This paper showsthat the qualitative differences between Cedar Creek anticline corefloods andfield behavior result solely from differences in geometry. That is, a singleset of centrifuge-measured, quasi-native-state, secondary-drainage relativepermeabilities can be used to predict both laboratory and field behavior. Primary factors that contribute to the differences between the two field testsare fluid/rock properties, effective wellbore radius (or skin), andheterogeneity in the layering.

Introduction
In the past decade, Shell Western E and P Inc. has conducted two tertiaryCO2 Pilots in carbonate reservoirs. The first was in the Denver Unit (Wassonfield). It experienced CO2 injectivity that was surprisingly lower than thepreflood brine injectivity. CO2 injectivity in the second pilot at the SouthPine Unit (Cedar Creek anticline) was significantly higher than brineinjectivity. Ironically, this behavior was also surprising because of both theDenver Unit experience and the laboratory experiments conducted on South Pinecore material before CO2 injection. The Denver Unit pilot was history-matchedwith a simulator featuring permeability reduction factors similar to modelsused by Claridge, Todd et al., and Chase and Todd. Without the permeabilityreduction factors, this model predicted CO2 injectivity greater than brineinjectivity. The majority of the Denver Unit tertiary CO2 corefloods alsodisplayed CO2 injectivities greater than the brine injectivity. Fig. 1 showsthe normalized injectivity of 20 tertiary CO2 corefloods conducted in DenverUnit core. (Details about these experiments are found in Ref. 4.) Only two ofthese corefloods displayed low CO2 injectivities consistent with the pilotbehavior. The simulator curve plotted in Fig. 1 represents a linearfinite-difference simulation with pilot-tuned reduction factors of a coreflood. Patel et al. showed that mixed wettability, and the resultingrelative-permeability hysteresis, was the critical property in the only twocorefloods that displayed low CO2 injectivity. Before CO2 injection at theSouth Pine pilot, tertiary corefloods were conducted to study CO2 injectivity. Frozen core material, taken from the pilot injection well, was mounted incoreholders, and every effort was made to preserve the native-wettabilitystate. As Fig. 2 shows, these experiments displayed lower CO2 injectivitiesthan brine, in qualitative agreement with the mixed-wettability Denver Unitcounterparts. When the South Pine Pilot CO2 injectivity was much higher thanthe brine preflood injectivity, it seemed to be completely at odds withcoreflood results and the Denver Unit pilot (assumed to be a good analog). Tounderstand fully the differences in the CO2 injectivity observed here, it isnecessary to examine both the fluid/rock properties and the flow behavior inthe geometries involved in the different tests. In this paper, we compare themixed-wettability Wasson relative-permeability curves with a set ofquasi-native-state, secondary-drainage relative permeabilities that weremeasured in Cedar Creek core material. Then we discuss a model that considersthe flow of constant-composition slugs in a noncommunicating layered system toshow that the rather surprising CO2-injectivity behavior is caused primarily bydifferences in flow geometry and tertiary oil-bank properties. Throughout thispaper, properties that are representative of the field (such as API gravity androck type) are referred to by their field designation (Wasson or Cedar Creek). Results specific to the pilot or injectivity test are identified by theappropriate operating unit name (Denver Unit or South Pine Unit).

Fluid Mobilities
Clearly, any study of injectivity must begin with relative permeabilitybecause it directly affects the fluid-bank mobilities. Patel et al showed thatmixed wettability and the resulting relative-permeability hysteresis explainedthe low CO2 injectivity observed at the Denver Unit (Wasson field) pilot. Theimbibition (waterflood) and secondary-drainage (CO2 flood) curves for SanAndres rock in the Wasson field are presented in Fig. 3. Similar curves weremeasured by Schneider and Owens on native-state San Andres rock by asteady-state method. The major characteristic of the hysteresis in Fig. 3 isthe increase in the immobile water saturation from 15 % on imbibition to 25 %on secondary drainage. This increase occurs because the water is displaced bysecondary drainage from oil-wet pores in a mixed-wettability medium; i.e., partof the water, the nonwetting phase, is trapped by the wetting oleic phase. Wehave directly observed this behavior in 2D mixed-wettability glass models onsecondary drainage.
JPT
P. 226⁁