Solan

Solan is a Jurassic oil field and is expected to produce approximately 50 million barrels of oil during its lifetime, with peak production of over 20,000 barrels of oil per day. First oil is targeted to commence in the fourth quarter of 2014.  Approval for the development of Solan was received by Chrysaor and its partner Premier Oil (Chrysaor 40%, Premier 60%) from the UK Secretary of State for Energy and Climate Change on 24 April 2012.

The oil field is located West of Shetlands within UK licence P164 covering UK block 205/26a in just 135m of water. The field was discovered by Amerada Hess in 1991 and a further three appraisal wells followed during the 1990’s.  The original 205/26a-4 vertical discovery well flowed at a maximum ESP assisted rate of 8,346bopd.  Due to low oil prices and a false perception of volumetric risk, the field remained inactive until it was rescued by Chrysaor in 2007 as part of DECC’s fallow discovery initiative. Chrysaor carried out two successful appraisal-drilling campaigns, in 2008 and 2009, before approaching potential development partners.  Premier farmed-in to the field in 2011.

As agreed at the time Premier joined the project, Premier has been appointed operator from sanction and will lead a joint team to execute the field development plan. Chrysaor will, subject to the necessary DECC consents, become production operator upon completion of the development plan. Contingent on achieving certain future economic thresholds agreed with Premier, Chrysaor also has the option to then increase its share in the field to 50%.

The West of Shetlands is becoming an increasingly important part of the UKCS and is expected to hold a material part of the UKs future prospective resource. As with Markham and CH4 Chrysaor will develop and operate the Solan facility as a hub for processing in the area. Incremental reserves tied-back to the platform should be highly profitable. This will enable the development of smaller accumulations than would otherwise be possible.

Solan

View our Solan Film

This film tells the intriguing story of Premier Oil and Chrysaor and the development of the Solan field, which is located west of the Shetland Islands, in the UK sector of the North Sea. During the life of the operation, Solan is expected to produce approximately 50 million barrels of oil.

Asset Details

Field Description

Solan comprises a combined structural/stratigraphic trap in mass-flow sands of Jurassic age whose crest lies just above 7900ft TVDSS. The total height of the hydrocarbon column within the field is estimated as 850ft and the area of the accumulation as 7.1 km2. The trapped hydrocarbon is medium-viscosity oil with an average GOR of 124 scf/stb.

Solan Oil Production Profiles

The Solan oilfield is covered by a 3D survey of some 260 km2 shot for Amerada Hess in 1993 and by a survey of some 1200 km2 shot for BP/Arco in 1995. A very strong seismic event at the Base Jurassic Unconformity, some 50 ft below the base of the Solan reservoir, allows a robust structural interpretation of field geometry while isochron mapping allows accurate prediction of the thickness and extent of reservoir as well as its structure.

The lateral pinchout of the sands to north-west, west and south provides side-seal to the Solan accumulation around the contemporaneous margins of the East Solan Basin. Top-seal is provided by the claystones of the overlying Kimmeridge Clay Formation, especially the Main Hot Unit that is the primary source rock for the accumulation. Base-seal is provided by the Lower Solan Mudstone. Dip closure north-eastwards towards the centre of the East Solan Basin completes the trap.

Near the crest of the Solan field average reservoir porosity approaches 26% and air permeability exceeds 500mD. Porosity and permeability decrease downwards through the oil column into the water leg, falling to 22% and 50mD at the top of the reservoir in the 205/26a-5 well.

The gas-oil ratio for Solan is low, averaging just 124 scf/stb over the field as a whole while oil bubble point falls within the range 620-670 psia.

In Place Volumes and Reserves

Volumetric estimates for STOIIP have been made using both software modeling and by stochastic methodology.  STOIIP estimates range from 80mmbbl (P90) up to 155mmbbl (P10). A STOIIP of 117mmbbls is consistent with a most likely case Free Water Level (FWL) of 8,750ft TVDSS.

The FDP P50 reserves estimate for Solan is 44mmbbls which is based on a conservative simulation model that includes downside fault compartmentalisation, slightly shallower oil water contact assumptions and some pore volume reduction in the parts of the model furthest from well control.  The FDP P90 estimate is 30mmbbls and the P10 estimate 64mmbbls. The latest Competent Person's Report (June 2014) produced by Senergy has a P50 reserves estimate of 52mmbls, a P90 estimate of 37mmbls and a P10 estimate of 69mmbls.

Click here to read the Senergy CPR.

Development Plan

The approved field development plan comprises:

  • Two Production wells with ESPs and two Water Injection wells
  • Associated subsea flow-lines and control lines
  • Jacket and topsides
  • Subsea storage tank
  • Export via shuttle tankers
Solan Field Development Schematic

 

The development concept is conventional and fit for purpose. This has many benefits including a well defined capex base and much lower routine operating costs when compared to any alternative development, such as a leased FPSO, for example. The key benefit though is in when the facility becomes not normally manned the risk to personnel will be dramatically less than alternative concepts.

Facilities are designed to process up to 28,000 bopd of dry oil and 35,000 bopd of total liquids. The facilities have accommodation for 30 men and will be manned for the first year only. In subsequent years the platform will not be permanently manned and only monthly visits will be made to the platform for routine maintenance and inspection.

Surface facilities for the field development will be located on a conventional piled steel jacket with oil stored in a sea bed tank before export by offshore loading. All produced fluids will be either sold to market or reinjected back into the reservoir. By storing the crude on the seabed the risk to the environment due to damage caused by the extremely harsh weather to a surface storage facility is hugely reduced.

The Solan field platform has the in-built capacity and sufficient loading allowances to accommodate third party business via a tie-in. This could facilitate any future satellite field developments.

The base case development drilling plan commits to the drilling of 2 sub-horizontal producers, each equipped with a dual ESP completion in order to accelerate production and maximise total recovery. Reservoir pressure in these producers will be supported by water injection through two sub-horizontal injectors. All base case development wells will be drilled from a location close to the facilities, completed with subsea wellheads and tied back with individual flexible flowlines.

View the Solan Development Plan

Tax Status

The Solan field was determined after 15 March 1993 and therefore is not liable to Petroleum Revenue Tax.

Solan qualifies as a new field under the small field allowance introduced in Finance Act 2009 and subsequently increased to £150m in the March 2012 Budget. The maximum allowance will be available for fields which have
reserves in place of 6.25 million tonnes (approximately 45 mmbbl) or less, tapering to no allowance at 7 million tonnes (approximately 50 mmbbl). A new field is defined as one that has development consent on or after 21st March 2012. Solan development consent was received on 24th April 2012.

Solan Triassic - Strathmore

Underlying the Solan Jurassic oil field is a thick Triassic reservoir known as the Otter Bank Sand. Hess exploration well 205/26a-3 drilled in 1990 discovered a 570ft column of 23-24o API oil within this reservoir but it only tested at rates of 240 BOPD with nitrogen lift. Chrysaor’s WI at this deeper level is also 40% and subject to the same 10% option rights as Solan.  This Triassic discovery is known as Strathmore.

In 2007, Chrysaor rescued the Strathmore discovery from fallow status by extending Solan appraisal wellbores 206/26a-7 and 7z downward and proving its extension under the northern part of the Jurassic accumulation. As part of its work on the Solan Field, Chrysaor has also studied the technical feasibility of producing the Strathmore reservoir. The main conclusions of the study are:

  • With the mapped 155mmbbls STOIIP and an effective reservoir permeability in line with the 205/26a-3 test, potential recovery from a single vertical producer stimulated with staged propped-fractures is expected to be some 3mmbbl oil over a five year test period under pure depletion drive.
  • At the end of the test period the well would either remain in production as a low rate depletion producer ultimately recovering up to 6mmbbls or be incorporated into an extended development.
  • An extended development might comprise up to four producers plus a water injector for pressure support. Recovery efficiency would be greatly improved
    if reservoir properties prove to be better than those interpreted for the 205/26a-3 test.

Based on the above five year extended test period continuing for the life of the well as a low rate producer, Chrysaor estimates net 2C reserves to be around 3mmbbls. There are no committed firm plans for the development of Strathmore at the current time but the option is highly economic. Chrysaor therefore expects there will be opportunity to develop Strathmore through the Solan facilities and includes the single depletion well recovery in its core base valuation.