Summary
Densely-fractured oil-wet carbonate fields pose a true challenge for oil
recovery that traditional primary and secondary processes fail to meet. The
difficulty arises from the combination of two unfavorable characteristics:
First, the dense fracturing frustrates an efficient waterflood; second, because
of the oil-wetness, the water pressure exceeds the oil pressure inside the
matrix blocks, thus inhibiting spontaneous imbibition of water. In the past
decade, using a new class of surfactants, enhanced oil recovery (EOR)
researchers have studied the options to chemically revert the wettability of
carbonate rock without drastically decreasing the oil-water interfacial
tension. These chemicals, termed "wettability modifiers" (WMs),
effectively reverse the sign of capillary pressure at the prevalent saturation.
With the oil pressure exceeding the water pressure, the capillary pressure
becomes the driving force for oil expulsion from the matrix and into the
fracture system.
Previous publications on chemical wettability modification focused on the
performance of different chemical wettability modifiers for a chosen
rock/oil/brine system. In some cases, they demonstrated an almost full oil
recovery from core plugs. Little attention, however, has been given to the
mechanism underlying the transport of the chemical into the matrix block and to
the proper scaling of laboratory results to reservoir size. The present study
aims to demonstrate that imbibition after wettability modification is
diffusion-limited. To this end, the recovery profiles for spontaneous capillary
imbibition, as well as for imbibition after wettability modification, are
calculated. The results are then used to compare with the data of Amott cell
imbibition experiments. It is confirmed that in both cases, the cumulative
recovery is initially proportional to the square root of time. Imbibition after
wettability modification, however, takes approximately 1,000 times longer than
spontaneous capillary imbibition into a water-wet medium. The slow recovery
observed in the case of imbibition after wettability modification is in
excellent agreement with the assumption that, in the absence of significant
spontaneous imbibition, the WM, to unfold its action, must first diffuse into
the porous medium. In any diffusion process, the time scale is linked to the
square of the length scale of the medium. Therefore, it would take up to 1,000
times longer (an equivalent of 200 years) before the same recovery is obtained
from a meter-scale matrix block as is obtained from a centimeter-scale plug in
a laboratory in 100 days.
Consequently, unless a significantly faster transport mechanism for the
wettability modifier is identified, or unless viscous forces or buoyancy enable
forced imbibition, the chemical wettability modification of fractured oil-wet
carbonate rock does not provide an economically interesting opportunity.
Introduction
Rock fractures provide comparatively highly permeable flow paths through oil
reservoirs. In a densely fractured reservoir, the permeability contrast between
the fracture network and the oil-bearing matrix can be significant. In that
case, the viscous pressure differential across individual matrix blocks can be
too small to release oil from the blocks under waterflood, thus leading to a
poor recovery. Depending on the wetting state of the matrix and its initial
water saturation, Swi , capillary action can cause imbibition
of water up to a "spontaneous" equilibrium saturation, commonly denoted
as Sspw . At this saturation, however, the capillary
pressure inside the matrix block coincides with that in the fracture, and the
recovery ceases. Experience has shown that carbonate fields often range from
intermediate-wet to preferentially oil-wet (Treiber et al. 1972; Chilingar and
Yen 1983), which is synonymous with Sspw being close
or equal to Swi ; thus, they exhibit very limited recovery
during primary and secondary production.
Recently, a new EOR technique, designed specifically to tackle the
challenges outlined previously, has been suggested by Austad and coworkers
(Austad and Milter 1997; Standnes and Austad 2000a, b). In their pioneering
work, these authors show that certain chemicals, when dissolved in the
surrounding brine, can initiate water imbibition into oil-saturated core plugs
and, hence, lead to the recovery of oil. One possible mechanism that explains
these observations is the solubilization of adsorbed hydrocarbon components
from the pore surface—as demonstrated by an atomic force microscopy study by
Kumar et al. (2005), this exposes the intrinsically hydrophilic matrix. Another
possibility is the formation of an additional chemical layer covering the
adsorbed hydrophobic material. In either case, the pore surface becomes more
hydrophilic, and the wettability of the matrix is thus modified. In a capillary
rise experiment into parallel plates, Kumar et al. also observed different time
scales for different types of wettability-modifying chemicals (2005). Using the
cationic wettability modifier dodecyl trimethyl ammonium bromide (DTAB, also
known as C12TAB), Standnes and Austad deduced that wettability
modification was achieved through the comparatively slow process of
partitioning the chemical into the oil phase, followed by desorption and
solubilization of anionic hydrocarbon components (2000a, b). Shen et al. (2006)
and Rao et al. (2006) measured the effect of surfactants on the relative
water/oil permeabilities at different interfacial tensions. Wu et al. (2006)
studied the properties and ranked the efficiency of chemical model compounds,
based on their chemical structure, to modify the wettability and enhance
recoveries. Several groups have taken initiative to model wettability
modification in numerical simulators (Adibhatla et al. 2005; Delshad et al.
2006).
So far, no significant attention has been given to time dependence and to
the subsequent upscaling of the laboratory results to matrix block scale. This
subject will be addressed in the present work. The structure of the article is
as follows: In the Theory section, the basic results for countercurrent
capillary imbibition will be briefly reviewed and compared to Fick’s law of
molecular diffusion. The oil recovery as a function of time for both capillary
imbibition and imbibition after wettability modification will be predicted. The
experimental approach to imbibition at different wetting situations will be
described in the section Materials and Preparation. The recovery results will
then be analyzed using the previously derived equations. Finally, tentative
conclusions for the upscaling will be drawn.
© 2008. Society of Petroleum Engineers
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History
- Original manuscript received:
16 February 2007
- Meeting paper published:
11 June 2007
- Revised manuscript received:
3 October 2007
- Manuscript approved:
24 November 2007
- Version of record:
20 June 2008
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