By-passed pays and plays are more common than most geoscientist
might think. Plays can be missed for two reasons: 1) Pay was missed
well that would have been economic at the time (typical for conventional
reservoirs); 2) New technology has made previously tight
economic (typical for unconventional reservoirs). Pay in a
well, Type 1 plays, can be missed for myriad
reasons: lack of data
shaley sands, dual porosity in carbonates, no DSTs or
RFTs taken over show intervals, incorrect Rw — to name a few causes.
Type 2 plays,
unconventional reservoirs (e.g., tight sands, shale gas,
shale oil) are their own class of by-passed play. They are made economic
technology (e.g., mutli-stage fracs, horizontal drilling,
etc.) and multi-discipline teamwork.
Case studies for both types are provided below. Hopefully, these case
studies will help explorationists by
showing that that while oil is first
found in the mind, its physical discovery can be elusive.
James Lime Play: Eastern GOM
The James Lime Play of the Eastern GOM is a classic example of a bypassed play created by missing a test. In 1987, a major oil company
drilled a 20,000 ft test in Mobile Bay, targeting the Jurassic Norphlet
sand. The Lower Cretaceous James Lime Formation had unexpected
shows. There was a three-fold increase in drill rate and a four-fold
increase in mud gas. The primary objective, the Norphlet, was
The well was plugged and abandoned. The James Limestone
was not tested or logged.
In 1994, Chevron offset this 1987 “dry hole” by less than 1,900 feet
to the east, specifically targeting the James Lime. The Chevron Mobil
Bay 991 tested the James Lime for
10 MMCFD. To date, eight James Lime fields have been found, and the play has produced 1/3
Total play reserves might be one TCFG.
Muddy Formation Play: Powder River Basin
In 1964, a major oil company drilled eight wildcat wells in the Powder River Basin in Campbell County, Wyoming, targeting the Minnelusa
Formation. One wildcat well was plugged after two DSTs in the Minnelusa recovered just water. This well was interpreted to condemn several
townships. However, the shallower Muddy Formation in the well was not tested because it only had 5 feet of pay sand
out-of-hand as “uneconomic.”
Anderson Oil re-entered this in 1969 and completed the Muddy for
230 BOPD. A well drilled immediately to the west flowed 7,000 BOPD.
Many of the wells immediately around the “dry hole” flowed
over 1,000 BOPD. Hilight Field (83
MMBOE EUR) was missed for lack of one
Mission Canyon Play: North Dakota
The Mississippian “Mission Canyon” play (cum: 352 BCFG, 259
O) of the Williston Basin provides classic examples of both missed
pays and a missed play. In
the late 1950s and early '60s,
Shell Oil Company drilled a dozen dry holes specifically targeting stratigraphic traps
of the now-prolific Mission Canyon formation. Many of the now-known Mission Canyon fields have Shell wells offsetting
them, or Shell “dry
in them. Shell's stratigraphic
model of prograding sabkha deposits and oil being trapped by lateral facies change was
ahead of the rest of industry. Shell's seismic
data defined the Billings Nose, a now-prolific structure. Unfortunately, Shell underestimating the
risk, and drilled too few wells to test adequately their exploration model.
Shell drilled a well in Elkhorn Ranch field in 1961, but failed to recognize the Mission Canyon pay. A former Shell geologist at CENEX
the Mission Canyon accumulation in 1974, after reviewing the cores and DSTs in the Shell well. CENEX offset the Shell well by
less than ½ mile, and completed the
well for 281 bopd from a 4-foot zone in the Mission Canyon. When the greater Mission Canyon play was
discovered in the 1970's, operators still failed to recognize the
enormous size of the fields. Operators did not lease
sufficient acreage to control
the fields. Many of the
fields were “re-discovered” by
exploration wells that ultimately were
recognized to be extensions of the existing fields.
Austin Chalk: East Texas
In the mid 1990s, Marathon geoscientists in Tyler, Texas pushed the Austin Chalk play into the dry gas window in Grime County, Texas. At
the time of the play initiation, the few scattered vertical wells drilled
in the “down-dip Austin Chalk” had encountered water-free gas
and very high pressure (15# mud). Production from the Austin
Chalk was no more than a show (~ 110 mmcfg EUR/ well). The
target zone was a 40‟ limestone of the Austin Chalk Formation, deposited in a deep-water setting, with black shale above and below.
This play was an early and very successful horizontal “tight gas” reservoir. Marathon's Austin Chalk
wells were completed in 1996 to 1999 for
about 24 mmcfgpd, and
had an average EUR of about 10 bcfg/well. Pilot holes were drilled to 15,000 feet, and had horizontal legs up to 5,000
feet. Total reserves for the play were about 100 bcfg. At the time, the play was thought
to have reached its limit. Log and production analysis
that more gas was produced than could be accounted for from only the thin, tight, fractured Austin Chalk reservoir: the excess gas was
coming from the black shales. Geologists at EOG keyed off the meaning of the field's production, leading to EOG's Eagle Ford play.