GEOPARK MAKES OIL FIELD DISCOVERY IN COLOMBIA
GeoPark Ltd., an independent Latin American oil and gas
explorer, operator, and consolidator with operations and growth
platforms in Colombia, Chile, Brazil, Argentina, and Peru, has
discovered a new Curucucu oil field in the Llanos 34 block
(GeoPark operated with a 45% WI) in Colombia.
GeoPark drilled and completed the Curucucu 1 exploration
well to a total depth of 14,600 feet. A production test conducted
with an electric submersible pump in the Guadalupe formation
resulted in a production rate of approximately 1,700 barrels of
oil per day, of 15. 8 degrees API, with 0.4% water cut, through
a choke of 100/64 inches and wellhead pressure of 70 pounds
per square inch. Additional production history is required to
determine stabilized flow rates of the well. Surface facilities are
in place and the well is already in production. Petrophysical
log analysis during drilling also indicated the presence of potentially productive hydrocarbons in the shallower Mirador
To minimize surface construction costs and share production
facilities, the Curucucu 1 exploration well was drilled from an
existing well pad in the recently discovered Jacamar oil field.
The well was drilled with a horizontal extension of more than
9,000 feet; representing a record for the Llanos 34 block. Curucucu oil field is located on a new fault trend to the east of Tigana/
Jacana fault trend, adjacent to the Jacamar oil field. It is the
eleventh oil field discovered by GeoPark since acquiring the
prolific Llanos 34 block in 2012, and one of three new oil fields
added in 2017.
GeoPark plans to drill approximately seven wells in the Llanos
34 block during 3Q2017 with a focus on further delineating the
southern Jacana and northern Tigana oil fields.
HANSA HYDROCARBONS CONFIRM GAS DISCOVERY
Hansa Hydrocarbons Limited (Hansa) and its partners reported
a gas discovery from the N05-1 exploration well drilled offshore
Netherlands on the GEms licences. The well encountered gas
in the target basal Rotliegend sandstones. Hansa and its partners Oranje-Nassau Energie BV (ONE) and Energie Beheer
Nederland BV (EBN, the Dutch State entity), further appraised
the reservoir distribution and delineated the structure with a
downdip geological side-track which also encountered gas.
The reservoir interval was cored throughout and 24m of net
sand was encountered with high permeability. This was confirmed by the DST in the vertical well which was flow tested at
a maximum sustained flow rate of 53 million standard cubic
feet per day, which was the limit of surface equipment. The
results of the well exceeded pre-drill expectations.
The Ruby discovery extends across the N04, N05, N08, and
Geldsackplate licences in the Dutch and German North Sea
sectors respectively in a water depth of 28m. The N05-1 well
was drilled as a joint well between the N05 and Geldsackplate
licence groups, with Hansa participating at a 40% working in-
terest. The well was operated by ONE and drilled with the
Paragon Offshore Prospector- 1 rig, which moved off location
on August 30, 2017.
Hansa is operator of both the Dutch and German GEms licences, Blocks N04, N05, N8 and N07c in the Netherlands, with
interests post-EBN participation of 25% to 30%, and the Geldsackplate licence in Germany with an interest of 50%.
NEW ASSESSMENT TARGETS MARKETABLE OIL
AND GAS RESOURCES IN ALBERTA’S DUVERNAY SHALE
The National Energy Board (NEB), together with the Alberta
Geological Survey (AGS), released a new resource assessment
for the Duvernay Shale in central Alberta that adds significant
quantities of marketable light oil resources in the province as
well as natural gas and natural gas liquids (NGLs).
Using geological and in-place hydrocarbon data provided
by the AGS, the NEB estimates the Duvernay Shale contains
3. 4 billion barrels of marketable light oil and field condensate,
or 17 years of Alberta’s annual production. It also shows marketable gas resources equivalent to nearly 25 years of Canada’s
The Duvernay Shale covers nearly 20% of the province,
stretching from just below Grande Prairie to just north of Calgary
and east of Edmonton. Companies have been drilling the
Duvernay for shale gas and oil since 2011, and the region has
extensive existing pipeline infrastructure.
Deposited about 370 million years ago, the Duvernay Shale
is rich in organic matter and ranges from about one kilometre
to more than five kilometres deep. The Duvernay generally
starts getting prospective for oil and gas production below 2. 5
km, with the formation generally oily in areas shallower than 3
km and gassier in areas deeper than 3 km.
Although most of current development has focused on the
Duvernay’s West Shale Basin, such as the Kaybob Field north-west of Edmonton, recent provincial land sales show increasing
industry interest in the Duvernay’s East Shale Basin.
A resource assessment of a formation’s marketable petroleum
estimates the total amount of sales-quality oil, natural gas and
even NGLs that can potentially be recovered from a formation
with existing technology. Resource assessments are based on
a number of factors such as the geology of the reservoir and
production from existing wells.
The NEB will be releasing a second report later this fall
examining the economics of the Duvernay Shale resource.
The National Energy Board is an independent federal regulator of several parts of Canada’s energy industry. The Alberta
Geological Survey (AGS) is a branch of the Alberta Energy
Regulator (AER) and provides geological information and advice
to the Government of Alberta, the AER, industry and the
MURPHY ENTERS DEEPWATER BRAZIL BLOCKS
Murphy Brazil Exploração E Produção De Petróleo E Gás Ltda.,
a wholly owned Brazilian subsidiary of Murphy Oil Corp. (NYSE:
MUR), has entered into a farm-in agreement with Queiroz