Page 317 - Fundamentals of Gas Shale Reservoirs

ENHANCED OIL RECOVERY 297
where solvent extraction and condensing–vaporizing diffusive mix-
ing at the fracture–matrix interface. This extraction process
p Fracturepropagatingpressure within the mini frac
hf is completely different from oil mobilization in conventional
p Closurepressure reservoirs, where the injected fluids mobilize oil to form an
c oil bank ahead of the injected fluid and, then, push the oil
bank through the matrix pores to an eventual outlet.
The formation breakdown pressure p for vertical well is:
bd Hawthorne et al. (2013) conducted CO oil extraction
2
(
p bd 3 h H p T vertical well) (13.81) experiments in the laboratory at 5000 psi and 230 °F by using
millimeter‐size Bakken cuttings and centimeter‐diameter core
From a mini‐frac test, we can determine the closure plugs. They concluded that oil was extracted from the cuttings
pressure p and the formation breakdown pressure p . Then, or the core plugs because of CO miscibility with reservoir oil,
2
c
bd
we can calculate σ from Equation 13.81 if we replace viscosity reduction, and diffusion mass transfer. The exposure
H
horizontal stress σ with the closure pressure p . time was up to 96 h for the middle Bakken chips (clastic sedi-
c
h
The following two equations are useful in estimating the ment) which resulted in near‐complete hydrocarbon recovery.
formation breakdown pressure p for a well drilled in the σ However, the oil extraction experiments required smaller chips
bd
H
direction (Eq. 13.82) or in the σ direction (Eq. 83): and larger exposure time for the upper Bakken (shale). For
h
field applications, solvent extraction is very slow and modest
(
p 3 p T Horizontal wellin thedirection) because the specific surface area of reservoir matrix blocks is
bd h v very small compared to the laboratory samples used by
(13.82)
Hawthorne et al (2013). Nevertheless, these experimental
(
p bd 3 H v p T Horizontal well in thedirection) results provide the impetus to pursue EOR in unconventional
reservoirs, and numerical modeling becomes the tool to scale
(13.83)
laboratory results to field. Thus, in unconventional reservoirs,
CO , natural gas liquids (NGL), liquefied petroleum gas
The formation breakdown pressure in a horizontal well, 2
drilled in the σ direction, becomes quite large when (LPG), and NGL–CO mixture can potentially mobilize matrix
2
oil by miscibility (via condensing–vaporizing gas extraction)
h
. Unfortunately, the latter is often the situation in
H h which leads to countercurrent oil flow from the matrix. We
unconventional reservoirs.
evaluate these concepts using dual‐porosity, multicomponent,
numerical simulation of flow in the SRV.
For field implementation of fluid injection to enhance oil
13.7 ENHANCED OIL RECOVERY recovery, a possible injection‐production pattern is the zip-
per frac pattern, shown in Figure 13.12. This pattern is the
In the laboratory, we measure permeability, porosity, counterpart of the conventional five‐spot pattern for enriched
relative permeability, capillary pressure, and wettability gas or CO injection. The zipper frac pattern should improve
2
of core samples, then we conduct EOR experiments to conformance (coverage) of injected fluid and the reservoir
determine which EOR process can potentially lead to
economic success. Similarly, we conduct well tests in the
field to obtain reservoir‐scale information on permeability
and shape factor to determine macrofracture connectivity
and spacing for use in modeling primary production,
appraising EOR potential, and reservoir management HW producer
planning.
The projected maximum oil recovery of shale oil reser-
voirs, such as the Bakken, is around 10% despite the use of
long horizontal wells and reservoir stimulation by multistage HW injector
hydraulic fracturing. This is because of the ultralow matrix CO 2
permeability that significantly hinders oil flow from the
matrix into the smaller fractures and ultimately into the well-
bore. Immiscible displacement of oil by water or gas in such
tight formations is not practical because the injected fluids HW producer
can flow only through the interconnected fractures while
having a difficult time entering the tight matrix to displace
oil. Miscible gas injection, on the other hand, can potentially FIgURE 13.12 A proposed inverted five‐spot zipper frac injection‐
mobilize oil from the ultralow permeability shale matrix by production pattern for EOR in unconventional reservoirs.