Canacol Energy Ltd.

Canacol Energy Ltd.

May 03, 2010 06:00 ET

Canacol Energy Ltd Announces Commencement of Drilling and 3D Seismic Programs at Its Capella Heavy Oil Discovery in Colombia

CALGARY, ALBERTA--(Marketwire - May 3, 2010) - Canacol Energy Ltd. ("Canacol" or the "Corporation") (TSX VENTURE:CNE) is pleased to announce the spud of the Romero A1 well, the first of a 7 well drilling program at its Capella heavy oil discovery in Colombia. The Corporation has also commenced the acquisition of 185 square kilometers of 3D development seismic over the field. The Capella discovery is located on the Ombu E&P Contract in the Caguan – Putumayo basin of southern Colombia. The Corporation, through a farm in with Emerald Energy Plc., now Sinochem Corporation ("Sinochem"), earned a 10% working interest in the Contract through the drilling of the Capella 1 discovery well in July 2008. Throughout 2008 and 2009, the Corporation participated in the drilling of 6 successful wells into the discovery. Canacol also has a 100% operated working interest in 2 offsetting exploration contracts awarded directly to the Corporation in 2009, and holds over 1.2 million net exploration acres directly offsetting the Capella discovery.

Charle Gamba, President and CEO of the Corporation, comments "We are very pleased with the progress of the 2010 work program at Capella to date, and the efficiency that the operator, Sinochem, has demonstrated. The consortium plans to spend US$ 42 million gross on the Capella program in 2010, which will result in an increase in both production and reserves. The information gathered in 2010 will be used to formulate the full field development drilling program for the field going forward. Aside from developing the potential in the Capella discovery, the Corporation is positioned to execute a significant exploration program on its 2 offsetting operated exploration blocks going forward."

Romero A1 Well

The Romero A1 well spud on April 28, 2010, and is the first of 7 wells that the Corporation plans to drill at Capella in 2010. The Romero A1 well is located approximately 4 kilometers ("km") to the northeast of the Capella E8 well, the northeastern most producing well in the field. Romero A1 is designed as a vertical well that is planned to be drilled to economic basement at a depth of approximately 3,250 feet measured depth. The objective of the well is to test the productive Mirador reservoirs at the structurally highest position in the field. It is anticipated that the well will take approximately 3 weeks to drill and complete, after which the reservoirs will be flow tested with a progressive cavity pump, as is the current practice within the main producing part of the field. The drilling program includes extensive coring of the reservoir intervals. Upon completion of the drilling and testing program, the rig will be mobilized to the Capella F-10H location to commence drilling of the first horizontal well in the field.

3D Seismic Program

The Corporation commenced the acquisition of a 185 square km seismic program in March 2010. The contract for the 3D seismic program was awarded to Petroseismic S.A., with operations commencing in March, 2010. It is anticipated that acquisition of the 3D seismic program will be completed by June, 2010. The seismic will be used to optimize the future development drilling program for the field.

2010 Work Program Summary

The 2010 work program at Capella consists of 1) the drilling of 4 delineation wells and 3 development wells, including the Romero A1 well, 2) the acquisition of 185 square km of 3D seismic within the main development area, 3) commencement of a steam injection pilot utilizing one of the existing wells, 4) the construction of an early production facility to handle 2,000 barrels per day of fluid per day and the laying of flow lines to all producing wells, 5) the upgrading of existing roads and bridges and 6) the drilling of a water disposal well.

The primary objectives of the 2010 work program at Capella include 1) continued appraisal of the discovery to determine its size through the drilling of appraisal wells and a resulting increase in production, reserves, and resources, 2) formulation of a full field development plan for the discovery by year end through the acquisition of a 3D seismic program, the quantification of horizontal well performance on oil rate and recovery, and the quantification of the steam injection pilot in terms of oil rate and ultimate recovery, and 3) installation of an early production facility, flow lines, and upgrading of roads and bridges to increase the overall volume of oil sales from the field and accelerate monetization of the early production volumes.

This press release contains certain forward-looking statements within the meaning of applicable securities law. Forward-looking statements are frequently characterized by words such as "plan", "expect", "project", "intend", "believe", "anticipate", "estimate" and other similar words, or statements that certain events or conditions "may" or "will" occur, including without limitation statements relating to estimated production rates from the Corporation's properties and intended work programs and associated timelines. Forward-looking statements are based on the opinions and estimates of management at the date the statements are made and are subject to a variety of risks and uncertainties and other factors that could cause actual events or results to differ materially from those projected in the forward-looking statements. The Corporation cannot assure that actual results will be consistent with these forward looking statements. They are made as of the date hereof and are subject to change and the Corporation assumes no obligation to revise or update them to reflect new circumstances, except as required by law. Prospective investors should not place undue reliance on forward looking statements. These factors include the inherent risks involved in the exploration for and development of crude oil and natural gas properties, the uncertainties involved in interpreting drilling results and other geological and geophysical data, fluctuating energy prices, the possibility of cost overruns or unanticipated costs or delays and other uncertainties associated with the oil and gas industry. Other risk factors could include risks associated with negotiating with foreign governments as well as country risk associated with conducting international activities, and other factors, many of which are beyond the control of the Corporation. 

A barrel of oil equivalent (boe) is derived by converting gas to oil in the ratio of six thousand cubic feet of gas to oil and may be misleading, particularly if used in isolation. A boe conversion is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead, especially in various international jurisdictions.

Neither TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

Contact Information