Below are some articles I saw from previous owners of the 5 contiguous blocks Hartshead was awarded. Perhaps others can find actual results post-drill. The obvious question is how much commercial oil is left or undiscovered.48/15b
Tuesday, July 21, 2009
Venture Production has announced the result of the Andrea gasexploration well (Venture operated -- 100% interest) located in block 48/15b inthe 'A' Fields area of the southern North Sea.
TheAndrea well 48/15b-10 commenced drilling from the Noble Julie Robertson jackupon June 6, 2009 and reached a total measured depth of 10,200 feet on July 16,2009. The well was designed to test the Leman sandstone with gas beingdiscovered in the upper sands.
Indicationsare however that the reservoir is tight and is unlikely to flow withoutstimulation. The lower sand appears to be water wet, based on an initialanalysis of the logs, although the tight nature of the reservoir makesinterpretation of the exact gaswater contact difficult. The well will now besuspended pending further analysis of well logs and core samples.
Thepotential of the Andrea gas discovery for commercial development will now beassessed, although the tight nature of the reservoir is likely to constrainrecoverable reserves to the lower end of pre-drill expectations of 3 to 44million barrels of oil equivalent ('MMboe'). Consequently, any development ofAndrea would most likely be in conjunction with the nearby Ensign field.
49/11AWelI IDDesignation Status Category of Well
49/11a-A1 Gas production Shut in PL 3-3-3
49/11a-A2 Gas production Shut in PL 3-3-3
49/11a-A3 Gas production Shut in PL4-4-3
49/11a-A4 Gas production Shut in PL 4-4-3
49/11a-A5 Gas production Shutin PL 3-3-3
49/11a-A6 Gas production Shut in PL 4-3-3
49/11a-A7 Gas productionShut in PL 4-4-3
49/11a-A8 Gas production Shut in PL 4-3-3
49/11a-A9 Gasproduction Shut in PL 3-3-3
49/11a-A10 Gas production Shut in PL 3-3-3
49/12BATP also acquired a 100% working interest inBlock 49/12B adjacent to its Wenlock property in the Southern Gas Basin in theUK North Sea. This block contains an exploratory offset location to the provedreserves at Wenlock. The company plans to develop the reserves at Wenlock in2007 with Block 49/12B slated for drilling in 2008. ATP is the operator of ShipShoal 351 and Block 49/12B.
Tumbling gas prices on the UK mainland have not deterred activityoffshore. Among those pursuing new opportunities are ATP, which last month wasset to spud a dual-purpose horizontal well from its new Wenlock platform insouthern North Sea block 49/12b. After intersecting a Rotliegend sandstonecolumn for development purposes, it was due to probe an adjacent upthrown faultblock. If successful, the well will be completed immediately and placed onproduction. ATP also is putting in two more wells to lift output at its nearbyTors development.
49/17B
VixenGas Field Project, North Sea Southern
Vixen iswholly located in block 49/17a, licence P033 in the southern North Sea,approximately 135km (84 miles) off the Lincolnshire coast in the UK.
The operator Conoco and theco-venturer BP each hold a 50% interest in the field.
Discovery
The Vixen field was originallyknown as E-Plus. It was discovered by well 49/17a-13, which was drilled andtemporarily suspended in May 1999 by the jack-up drilling rig Glomar AdriaticVI.
The well was drilled at a waterdepth of 33m (109ft).
Vixen lies between two of themost prolific fields in the area, Viking E and Victor. Its reservoir is locatedin Rotliegendes sandstone, approximately 2,844m (9,385ft) subsea.
Conoco reservoir engineers haveestimated a projected field life of six years.
However, studies indicate thatwith optimal reservoir management and development, the field has the potentialto yield significantly more natural gas than this, over a lifespan that couldbe considerably longer.
Production
Vixen contains 117 billion standardcubic feet of proved natural gas reserves, including 58.5 billion cubic feet(bcf) net to Conoco.
The planned flow rates for thefield have been put at 140 million standard cubic feet of natural gas per day,approximately 16% higher than the original design rate.
Vixennatural gas is produced from a single subsea well. The development is based onre-entering the original discovery well 49/17-13 and completing a 49° sidetrackthrough the reservoir.
The production re-entry well wasdrilled by the jack-up drilling rig Ensco 80. The jack-up was also used toinstall the subsea architecture.
The produced natural gas istransported 8.6km (5 miles) via a 10in subsea pipeline to the BD platform inthe Viking B central complex.
This has been modified to handleVixen’s output. There is also an umbilical installed for methanol supply,hydraulics power and communications.
Modifications
The modifications to the Vikingplatform include the installation of a new 10in production riser, a J tube forthe umbilical, new methanol pumps, the installation of subsea control andhydraulic packages, and metering and topside control for tie-in to theproduction separator.
Halliburton and Brown & Root,along with AMEC and DNV, were responsible for all elements of these hostplatform modifications through an SNS alliance contract.
From Viking, gas is sent 130km(80 miles) through the Viking Transportation System (VTS) subsea pipeline, tothe Conoco-operated Theddlethorpe Gas Terminal on the coast of Lincolnshire,from where production operations are remotely controlled.
Construction
Creating and installing thesubsea elements of the Vixen development involved the services of severalmanufacturers, suppliers and contractors.
Dril-Quip won the contract tofabricate and supply both the subsea tree and its 65t wellhead protectionstructure (WHPS). With a 15-year life, this structure has overall dimensions of114m x 114m and stands 6.25m-high.
It is anchored by four piles,which are 762mm in diameter and 24m-long, weighing 11.1t each.
Kvaerner Oilfield Productsdesigned and manufactured the Vixen control system upgrade at Theddlethorpe,and Coflexip Stena Offshore (CSO) was responsible for the design, supply,installation, testing and pre-commissioning of the gas-export pipeline, theumbilical, and the installation of the wellhead protective structure.
The CSO Wellservicer loaded outthe WHPS and installed it around the existing 30in conductor. The structure wasthen piled, using a 200t hammer and the top-latch mechanism was locked.
The Ensco 80 arrived in mid-2000to drill the side-track and complete the well operation that includedinstalling and testing the tree.
The Apache was then used toinstall the pipeline and test / pre-commission the project.
Final development costs were putat £24m ($36m), which were below the original budget by 11%.
Regards,
Chuck
