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 2D 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.
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 was 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 3.0 metres of net pay in the J1 interval which tested at an inflow of 120 bopd without stimulation or pumping.
In 2010 a 60 km pipeline was constructed from the Lineynoye oil field to Kiev-Eganskoye in the neighboring Licence 80. An oil processing facility with initial capacity of 7,400 bfpd was also built at Lineynoye. Nine production wells were drilled from Pad 1 at Lineynoye and year round production commenced on schedule in late August 2010. The nine wells were fracture stimulated in Q1 2011 and production peaked at about 3,000 bopd.
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.
The Pad 1 wells responded to the pressure maintenance programme that we initiated in June 2011. Today there are three injection wells on Pad 1.
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 higher than expected water cut after the Pad 2 fracture programme.
As the Pad 2 wells did not perform nearly as well as those on Pad 1 following fracture stimulation, we conducted 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 had declined due to Pad 1 production, and is a factor in the production decline. We have now converted four of the Pad 2 wells to a water injection wells with the aim of sweeping additional oil and maintaining the reservoir pressure.
As a result of the Pad 2 performance studies, 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 was not obvious from the log analysis. It is also possible when the Pad 2 wells were fracture stimulated that the fractures extended into deeper water sands that contributed to the initial high water cuts. Some these problems can be avoided in the future by drilling higher on the structures and avoiding potential oil + water zones.
Ryder Scott currently estimates the proved and probable reserves for the Lineynoye and West Lineynoye field at 32.10 million bbls in April 2013. This number includes a significant reserve write-down based on the performance of the Pad 2 wells.
West Lineynoye Development
In January 2014, the L-9 delineation well, located on the westernmost L-9 lobe of the Lineynoye field, was completed. The well confirmed about 2.0 m of oil in the primary J1-1 reservoir interval. The well also confirmed a thicker than expected J1-2 sandstone (10+ metres), however it was water bearing at the L-9 location. The L-9 delineation well was an obligation well recommended by the Russian authorities during the pre-development review of the field.
The L-10 well (Pilot and Horizontal segment) at West Lineynoye L-8 lobe was successfully completed with a horizontal segment of about 282 metres in the Upper Jurassic J1-1 horizon in August 2015. Today we estimate that of the 282 metre horizontal segment approximately 58 metres is effective net pay. The well was brought online on 4 August and the average flow rate of about 230 bopd. The adjacent L-8 vertical well is producing about 50 bopd from the same reservoir interval and the L-10 confirms the ability to use short segment horizontal drilling to greatly increase the flow rates.
The L-10 horizontal segment was drilled with a standard Russian exploration rig without a top drive unit. With some changes to the well design, we are confident that we can effectively drill and successfully complete horizontal production wells with 500 m horizontal segments with similar drilling rigs. This along with some other changes to the bottom hole drilling assembly should allow us to significantly increase the net pay in future wells and thereby the flow rates. There are over 9 locations similar to L-10 that could be developed in the coming years with one or two well drilling programmes adjacent to existing infrastructure. The very good result of L-10, both from a drilling and production performance perspective, is a significant step in developing these reserves that are close to existing infrastructure in a highly cost effective manner.
Updated March 2016