Lineynoye and West Lineynoye Oil Fields
The Lineynoye Oil Field is located in the northwestern part of Licence 61. The Lineynoye No. 1 well discovered oil within the structure in 1972. The well was drilled in the eastern part of the structure and tested oil from the Upper Jurassic ( J1 ) reservoir with a flow rate of 42 m3/day (264 bopd) on an 8 mm choke. The specific gravity of the oil is 0.835 g/cm3 or an API gravity of 38 degrees. Gas factor is 33 m3/m3. Reservoir pressure is 257 atmospheres. Russian C1 (proved) oil reserves totaling 18.3 million bbls (recoverable) were approved by the State Committee for Reserves in 1972.
Detailed seismic surveys were carried out in 1985 — 1986, leading to structural reinterpretation of the field. The revised structural interpretation at that time broke the overall structure into several structural highs.
Since acquiring Licence 61 in 2005, PetroNeft reprocessed the vintage seismic data over the Lineynoye structure and acquired an additional 515 line kms of new high resolution CDP seismic data over the Licence during the winter of 2005/2006. An additional 540 line kms of data was acquired during the winter of 2006/2007. Much of this new data has been acquired to further define the structural interpretation of the Lineynoye structure. The new interpretation, using previous drilling and new and vintage seismic, identified the West Lineynoye Prospect as potentially one oil bearing structure, above the known Oil Water Contact at −2,417 metres in the Lineynoye No. 5 well (Figure 1).
PetroNeft drilled the Lineynoye No. 6 well in 2007 to confirm the reservoir parameters and flow rates of the 1972 Lineynoye No. 1 discovery well. Lineynoye No. 6 penetrated 13.2 metres of net oil pay in the Upper Jurassic J1 interval and successfully tested at a stabilised flow of 100 bopd on a 1/8th inch choke. The well also lowered the oil water contact (owc) for the Lineynoye Field at least 10 metres which led to a reserve increase to 23.82 million bbls of proved and probable reserves. The Lineynoye No. 6 well was subsequently fitted with an Electric Submersible Pump (ESP) and put on long term test/pilot production during the first quarter of 2008 and 2009. The well produced at a stabilised flow rate of around 250 bopd during the two test periods. This production data assisted in planning the optimal well fracture programme to stimulate production and enhance long-term recovery from the field.
In 2007 a second high impact exploration well, Lineynoye No. 7, was drilled in the West Lineynoye area. This well confirmed 1.5 metres of net oil pay and a 22 metre gross oil column in the J1 reservoir interval. The well initially flow tested at an inflow of 125 bopd (raising head methodology). The well was fitted with an ESP and was put on long term test/pilot production during the first quarter of 2008 and 2009.
In 2008 the Lineynoye No. 8 delineation well was drilled to further assess the West Lineynoye discovery. Lineynoye No. 8 encountered 4.0 metres of net pay in the J1 interval which tested at an inflow of 120 bopd without stimulation or pumping.
Development
In 2010 a 60 km pipeline was constructed from the Lineynoye oil field to Kiev-Eganskoye in the neighbouring Licence 80. An oil processing facility with initial capacity of 7,400 bfpd was also built at Lineyoye. Nine production wells were also drilled from Pad 1 at Lineynoye and year round production commenced on schedule in late August 2010. The nine well were fracture stimulated in Q1 2011 and production peaked at about 3,000 bopd (Figure 2).
In 2011 the process facilities at Lineynoye were expanded to 14,800 bfpd and 14 development/delineation wells were drilled from Pads 2 and 3. Drilling to date has indicated that the field extends further north than previously estimated and that the Lineynoye and West Lineynoye fields are one connected structure. In fact the Pad 2 drilling results indicate that field wide oil water contact lies below the structural spill point between Lineynoye and the Emtorskaya high to the north providing further evidence that the field is much larger and potentially includes the Emtorskaya high structures to the north (Figures 3, 4, 5 and 6)
The Pad 1 wells have responded to the pressure maintenance programme that we initiated in June 2011. There are currently three injection wells on Pad 1 and the production decline has now halted in many wells and in some cases started to increase. We are encouraged with the water flood response on the Pad 1 wells.
A fracture stimulation programme for the Pad 2 wells was carried out in November 2011. The initial response was positive; however, production from Pad 2 wells decreased rapidly due to higher than expected well decline rates and slower than expected clean-up of water associated with the Pad 2 fracture programme.
As the Pad 2 wells have not performed nearly as well as those in Pad 1 following fracture stimulation, we have commenced a number of studies on the Pad 2 wells, including a field wide pressure transient test of individual wells in order to understand the difference in results.
In some of the Pad 2 wells the reservoir pressure has declined and is a factor in the production decline. We recently converted one of the Pad 2 wells to a water injection well with the aim of restoring some of the reservoir pressure. Additional wells will be converted as part of a normal water injection and pressure maintenance programme.
We currently expect that it will take at least six months before we can complete these studies and work programmes. The five well fracture stimulation programme planned for the Lineynoye field in Q1 2012, has therefore been postponed until we can better understand these differences and how best to deal with them.
At this stage we know that all of the Pad 2 wells were lower on the structure than the Pad 1 wells, the reservoir section was closer to the oil-water-contact and the oil saturation in the wells was lower. This resulted in a higher initial water cut in the wells than expected. It also appears the reservoirs at Pad 2 are tighter than at Pad 1, in part due to the higher water saturations, and the combination of relative permeability and fractional flow effects in the reservoir. However, this is not obvious from the log analysis. Some these problems can be avoided in the future by drilling higher on the structures and avoiding potential oil + water zones.
Reserves
Ryder Scott currently estimates the proved and probable reserves for the Lineynoye and West Lineynoye field at 32.10 million bbls. This number includes a significant reserve write-down based on the performance of the Pad 2 wells.
