Gas sales agreement All gas produced from the Ninotsminda Field, with the exception of that required by the field operator for its own use, will be made available under the gas sales agreement. The parties to the agreement include NOC and Georgian Oil, the state oil company, as the seller parties and Georgian Gas Transportation Co., the state-owned gas transmission company, as the buyer. The buyer in turn will deliver the gas to the state-owned Gardabani gas-fired thermal power plant. The delivery point under the agreement will be the gas gathering facility located on the Ninotsminda Field and the buyer, at its cost, has agreed to undertake to repair and maintain the 25-mile (41-kilometer) pipeline that will deliver the gas from Ninotsminda to Gardabani.
Gas will be supplied under the agreement on a seasonal basis--generally October to May--to coincide with the operation of the thermal power plant. The sales agreement has a 2-year term, with first delivery due to commence at the end of September 2006. The price of gas to be supplied at the delivery point on the field is $1.27 per million standard cubic feet (MMscf) ($45 per thousand cubic meters (MCM)) with the initial planned minimum contract quantity being 7.06 MMscf (200 MCM) per day. NOC plans to increase significantly the quantity of gas to be delivered by performing workovers on existing wells. The buyer will effectively underwrite this workover program by providing NOC with a bank guarantee for $250,000 as security against payment for first gas deliveries.
There are a number of wells on the Ninotsminda Field with potential to produce gas at high rates including the horizontal wells N22H and N100H2. The latter was completed in late-2005 and tested gas at a flow rate of 13.07 MMscf (370 MCM) per day and 301 barrels of condensate per day on a 63/64-inch choke. This well has remained largely shut-in since this time while awaiting execution of the gas sales agreement and repairs to the pipeline. As such the commencement of gas production will also bring an increase in liquids production.
N97H horizontal well The N97H horizontal sidetrack well on the Ninotsminda Field targeting oil volumes un-drained by previous development wells was put on production test post-completion in March 2006. The well produced initially with a high water cut, approximately 70%, and an oil rate that peaked at 385 barrels of oil per day (bopd) before declining. Subsequent pressure surveys run with downhole gauges suggested that the N97H well was in communication with the offset N4H well. The most likely assumed scenario was then some of the fracture sets encountered at the end of the N97H well were drained by the N4H well and were hence water-filled. Once a very high-permeability connection is established with the aquifer, water will flow in preference to any oil-filled fractures or matrix of lower permeability.
On the basis of the test data and due to the fact that the N97H well is approximately 36 feet (11 meters) structurally higher than the N4H well, which is still producing oil, it was decided to attempt to isolate approximately 500 feet (152 meters) of the horizontal section furthest from the vertical well bore and closest to the N4H well. A water shutoff chemical was pumped using coiled tubing and the well was placed on gas lift production at the beginning of June. Having completed this procedure, the well has continued to produce with a high water cut with no appreciable increase in oil flow. On the basis of these test results, it can be assumed that the treatment did not successfully isolate the water zones.
It is now planned to run a production log in the well in an attempt to determine the source of the water flow before attempting a further water shut off operation by means of placing a cement plug in the horizontal section and doing a cement squeeze.
MK72 exploration well In the Norio MK72 well, a total of 322 feet (98 meters) of net sands in the Oligocene formation were perforated over the interval 12,096 feet (3,687 meters) to 13,622 feet (4,152 meters). These sands, which formed a secondary target in the well, had good oil shows while drilling, with oil to surface and with hydrocarbons being interpreted on the electric logs that also indicated a substantial thickness of net pay sands. Following an extensive testing program over the past 3 months, the well has sustained flow on a small choke size with low average gross fluid rates of approximately 13 barrels per day consisting of light 48.6Ã¯Â¿1/2API oil, gas and water.
A number of surge clean up flows have been attempted, but these have not improved reservoir deliverability. It is believed that the current flow is limited to a thinner, less-permeable, interval while the better-quality reservoir remains isolated due to reservoir damage caused by the invasive fluid damage of the drilling mud. The lower zones in the well, which would have been in communication with the Oligocene interval through the well bore, were drilled with a 1.9 to 2.2 Specific Gravity (SG) mud due to anticipated reservoir pressures while the results from the testing program indicate that the mid interval reservoir pressure for the Oligocene while still over pressured, is lower at 1.7 SG equivalent. As a result of possible mud damage, the current perforations may have not penetrated deep enough beyond the damaged zone to allow proper communication between the more permeable formations and the well bore.
Over the course of the next 2 weeks, it is planned to carry out a limited re-perforation of the well over selected intervals using larger perforating guns to see if inflow is improved. If this operation proves successful, then the whole of the Oligocene reservoir interval will be re-perforated with the larger guns.
Other options, including a potential sidetrack well, to increase production from the thicker Oligocene sand zones are also being considered.
At the same time, the potential of the deeper Middle Eocene interval that was the primary target in the MK72 well continues to be evaluated. Oil and gas was encountered in this interval but could not be tested due to operational constraints. It is planned to drill an appraisal well at a later date to appraise this large prospect which now has significantly reduced geological risk.
M12 appraisal The M12 appraisal well to the Manavi M11 Cretaceous oil discovery is currently drilling ahead in a 12 ¼-inch hole at 10,748 feet (3,276 meters). This section of the hole is being drilled using oil-based mud. The next planned casing point is at the top of the Middle Eocene interval, which is currently prognosed at approximately 12,300 feet (3,750 meters) where 9 5/8" casing will be run. The well is targeting the Cretaceous limestone reservoir at a prognosed depth of 14,272 feet (4,350 meters), and it is anticipated that the well will reach total depth in August, after which testing is planned.
"We are extremely pleased to have executed this gas sales agreement,” said Vincent McDonnell, CanArgo’s executive director, chief operating officer, and chief commercial officer. “This agreement allows us to put the N100H2 well into production which will result in increased revenue for the company from both gas and liquids sales. The agreement together with the fact that the State of Georgia is undertaking the repairs to the pipeline highlights the government's desire to encourage the development of its domestic gas resources. This ability to sell gas in Georgia together with the Memorandum of Understanding concluded with the Ministry of Energy of Georgia in March 2006 gives us comfort to move ahead with the appraisal of the potentially large Kumisi gas prospect later this year."
Commenting on operations, McDonnell said: "The Manavi M12 appraisal well is progressing well and we hope to be testing this well by late August. In the meantime, we continue with our efforts to restore oil production from our latest horizontal well N97H, and continue with our testing program of the Norio Oligocene sands which has the potential to be a significant oil discovery."
CanArgo is an independent oil and gas exploration and production company with its oil and gas operations currently located in the Republic of Georgia and in Kazakhstan.
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