Timan Oil and Gas plc, the AIM listed company with operations in Russia, is pleased to give the following update on its pilot production scheme in the Nizhnechutinskoye field (“NGPT field”) in the Timan-Pechora region.
Highlights:
• The NGPT Pilot Scheme has been operating since July 2007, and wells have achieved varying rates of production between 2 and 35 bopd
• Water has been injected into the NGPT Reservoir I via 4 wells since start-up, but the effects are only now starting to be seen in producing wells
• Well integrity issues such as water influx have been addressed through a comprehensive re-design of drilling practices, well casing, completion depths and completion engineering such as utilisation of open hole/gravel pack completions
• A further 150 wells (113 production, 37 water injectors) are to be drilled in 2008, subject to sufficient financing being in place.
Background:
The NGPT field is a very large, shallow oil field located near the town of Ukhta in the Timan-Pechora region of Western Russia. Numerous wells on the field have established over 1 billion barrels of oil-in-place, of which the majority (90%) is found in the shallowest of three sandstone reservoir intervals, lying only 28 m to 150 m below the surface. This interval, known as Reservoir I, contains a light, low viscosity, sweet crude oil (340 API), in contrast to the heavier oils found in the underlying Reservoirs A and II. Primary production rates and recovery from Reservoir I wells are low, due to the very low reservoir pressure found at these shallow depths, but the Company determined in 2006, in conjunction with its technical advisers, that the reservoir should respond to water injection with a significant increase in well productivity. Similar shallow oil fields in Texas have been successfully developed in this way. Accordingly, in 2006 the Company designed and constructed a pilot water injection scheme located near the center of the field, in order to test injectivity and injection configurations, and to establish the optimum balance between well rate, well spacings and maximized oil recovery.
Pilot Scheme Development:
The pilot scheme consists of 25 wells drilled in a 200 m “inverted 9-spot” grid pattern, with 4 injection wells and 21 producers. The wells were completed in Q1 2007 and thereafter 22 wells were flow tested for hydrodynamic data under natural depletion conditions, with very variable results; some wells achieved initial flow rates of up to 30 bopd, while others watered out very quickly – probably due to well completion and zone isolation problems. By the end of Q2 2007, prior to injection start up, the pilot wells were contributing around 50 bopd in aggregate.
Water injection into 4 wells began in July 2007, and continued through the rest of the year, at rates of up to 292 bpd and pressures of 80 – 147 psi. The effect on well production so far has been minimal; after 3 months of injection, production rates were stable at 3 – 15 bopd, there was very little downhole pressure increase in the reservoir (<10 psi) and there has been no sign of water “breakthrough” into any of the production wells. This is not unexpected - the analogue field in Texas took several years of water injection to achieve material production increases - and suggests that the reservoir is laterally homogeneous in the pilot area, without significant fractures providing secondary flow pathways. We therefore expect well productivity to increase only when the wider reservoir in the area has become pressurized. Our current modeling suggests that at the optimum injection rates of 150 – 230 bpd/well we should achieve around 22 psi reservoir pressure increase by the end of 2008, and this should result in increased initial well rates from current levels to 17 – 29 bopd.
Another key objective of the pilot scheme has been to optimize well design and completion techniques, prior to the scaling up to full field development. Some wells have had problems with water influx from an overlying, slightly higher pressure groundwater aquifer in the immediate subsurface (<25 m depth), which is being addressed with revised casing design (including use of PVC casing). Water influx from underlying parts of the reservoir will be reduced by completing wells only in the uppermost zone of Reservoir I, and we also plan to minimize the effects of formation damage by using open hole/gravel pack completions. We have proceeded with development drilling rather more cautiously than originally planned, while we explored and tested these various well and completion design options with our consultant contractor, BLZ Geotechnik. The 66 wells originally planned for Q4 2007 will now be incorporated into the 2008 programme, expanding the pilot scheme to the north and east.
As of February 2008, a total of 8 wells in the area are producing 25-34 bopd in aggregate. 4 wells are injecting water at a combined rate of 292 bpd.
In parallel with work on the Pilot, significant investments have been made in infrastructure development in the NGPT area, including 18 km of new roads, 1.6 km of power transmission lines, a field camp, and construction of a new 7,000 bopd oil treatment plant which currently has a capacity of 1,500 bopd.
Future Plans:
Subject to obtaining the necessary financing the Company now plans to drill a further 150 wells by the end of 2008, using the improved well designs and retaining the 200 m “inverted 9-spot” pattern. We intend to drill all future wells using PVC casing, which will reduce well costs, using designs to prevent shallow water influx. We are particularly encouraged by the enhanced productivity achieved through the completion of wells in only the top zone of Reservoir I, and by the use of open hole/gravel pack completions. We will continue to log wells to determine the pattern of higher oil saturation zones we have encountered, and use this information to optimize producer/injector locations.
Further announcements in relation to the Company’s planned drilling for 2008 and financing will be made in due course.
Conclusion:
Timan believes we are only just starting to see the effects of water injection into Reservoir I, and although we have not yet achieved the initial production rates predicted by our earlier simulation model, we still expect to achieve these targets after a delay, as the reservoir re-pressurizes.
We continue to pursue the objectives of the pilot scheme; to optimize well configurations, completion design and injection/production strategies in order to maximize recovery from this very large oil reservoir. Overall we view the result of the pilot scheme to date positively, and we look forward to increased well productivity as water injection starts to have an effect.