American Oil and Gas Reporter - February 2017 - 66

SpecialReport: Enhanced Oil Recovery
Successful EOR projects always are based on the economical availability of an injectant. The beauty of ethane is that large
volumes of inexpensive supplies have been made available by the
development of shale plays, and a growing U.S. ethane infrastructure can deliver that ethane to locations where potential EOR targets are plentiful. Moreover, ethane has benefits over carbon dioxide in EOR applications, including having more solubility in oil,
lower minimum miscibility pressures (MMPs), and better solvent
efficiency. In addition, ethane-based EOR is operationally simpler than CO2-based projects.
The magnitude of U.S. EOR is measured in the tens of billions of barrels of additional recovery. Most of that recovery potential is concentrated in mature onshore fields in which costs are
relatively small and the geology is well understood. A U.S. Department of Energy report on "next generation" CO2 EOR found
that an estimated 60 billion barrels of oil could be recovered economically through gas EOR in lower-48 fields, and another 30
billion plus barrels could be recovered in onshore residual oil zone
applications (2012 ARI update of DOE/NETL-2011/1504).
The vast majority of U.S. oil production from CO2 EOR comes
from the Permian Basin, followed by the Gulf Coast, Rocky Mountain and Mid-Continent regions. Combined, all active U.S. projects inject about 60 million metric tons of CO2 annually (3 million cubic feet a day). The amount of new CO2 supply that would
have to be injected to develop the 60 billion barrels of reserves
in mature onshore fields is estimated by DOE to be on the order
of 17 billion metric tons (320 trillion cubic feet).
Bridging The Gap
How can the industry bridge the huge gap between available
CO2 supply and future demand to recover even a relatively small
portion of those reserves with EOR gas injection projects? One
answer is in Figure 1, which shows U.S. EOR production by recovery mechanism. The blue wedge is EOR from both miscible
and immiscible hydrocarbon gas (non-CO2) injection, virtually
all of which is located on the Alaska North Slope.
As with CO2 EOR, the engineering and economic issues and
opportunities of hydrocarbon gas EOR are well understood and
have been proven by decades of research and field experience.
But the Alaskan EOR experience is different from the lower 48
FIGURE 1
U.S. EOR Oil Production by Method
800

Operational Issues

Nitrogen Injection

700

Production (1,000s bbl/d)

600

HC Gas Injection

Flue Gas Injection

500
400

CO2 Injection

300
200

Thermal

Chemical

100

10
20
12

66 THE AMERICAN OIL & GAS REPORTER

0
Year

because there has been no market for gas produced on the North
Slope, and operators could take advantage of enriched gas injection primarily to recover more oil. The conventional wisdom has
been that hydrocarbon gas EOR is too expensive in the lower 48,
given the value of natural gas, but ethane from shale plays is changing that.
The North Slope projects have injected methane enriched with
ethane, propane and butane. The Prudhoe Bay miscible gas project makes an interesting case study. It is the world's largest enriched gas flood, with an ultimate EOR recovery expected to range
between 400 million and 500 million barrels.
A typical Prudhoe Bay miscible injectant (MI) composition
contains roughly 20 mole percent CO2 and 20 mole percent ethane
(there are no dedicated CO2 projects in Alaska; the MI contains
CO2 as part of the mix). Slim tube experiments show that the MI
is miscible at the average reservoir pressure of 3,600 psi-conditions at which CO2 is clearly immiscible. In this system, CO2 is
a carrier gas, and miscibility is provided by the ethane and propane.
At the North Slope West Sak Field, experimental work to investigate ethane and CO2 as EOR injectants for the viscous oil
showed that gas solubility and viscosity reduction were much
greater for ethane than for CO2 at similar conditions. In fact, CO2
was unable to develop dynamic miscibility with West Sak
crude at reservoir pressure and temperature conditions. Ethane
was miscible at 600 psi, while CO2 failed to achieve miscibility even at pressures as high as 6,600 psi. In this viscous oil system, ethane is far more effective as an EOR injectant than CO2.
Ethane's compositional properties give it superiority over carbon dioxide as an EOR injectant in terms of solubility, swelling
and viscosity reduction, as well as in terms of developing multiple-contact miscibility. Ethane has a molecular weight of
30.07 pounds per lb-mole and a critical density of 12.9 pounds
per cubic foot compared with 44.01 and 29.1, respectively, for
CO2. Ethane and CO2 have almost identical critical temperatures
(≈90 degrees Fahrenheit), while the critical pressure of CO2 is
roughly 50 percent higher than ethane (1,071 versus 707 psia).
To achieve a similar liquid-like state in the reservoir, CO2 requires a substantially higher reservoir pressure. This has major
implications for shallow, low-pressure reservoirs as well as for
deep, hot reservoirs such as Prudhoe Bay. Ethane may have a lower density than CO2 in the reservoir, which could influence gravity override and impact vertical sweep efficiency.

In addition to injectant supply, there are other challenges to
implementing CO2 floods. One of the most significant operational
drawbacks is the corrosive nature of CO2. Corrosion is a problem in surface facilities, pipelines, injection wells and production wells. These problems are well understood, and while successful mitigation strategies have been developed for components
such as meters, wellhead trees, valves, tubing, packers and cements, the corrosiveness of CO2 impacts project cost profiles.
In contrast, ethane is noncorrosive, and by dilution, should act
to reduce the partial pressure and corrosivity of any acid gas components that may be present in produced fluids. There are no foreseen additional metallurgical requirements to implement ethane
water-alternating-gas (WAG) injection. However, because ethane

American Oil and Gas Reporter - February 2017

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