Warwick duster in the West of Shetlands

Hurricane Energy plc, the UK based oil and gas company focused on hydrocarbon resources in naturally fractured basement reservoirs, provides an update in relation to the 205/26b-13Z ("Warwick Deep") well.

Following completion of drill stem testing of the Warwick Deep well, the decision has been made to plug and abandon the well.

The Warwick Deep well was drilled to a total depth of 1,964m TVDSS and included a 712m horizontal section of fractured basement reservoir. Initial analysis indicates that the well intersected a poorly connected section of the fracture network within the oil column. The well did not flow at commercial rates producing a mixture of drilling brine, water, oil and gas.
The Company and its contractors are currently evaluating the drill stem test data and fluid samples with the objective of providing an update on this preliminary analysis at Hurricane's Capital Markets Day, scheduled for 11 July 2019.

The rig will now undertake work to permanently plug and abandon the Warwick Deep well and will then move to the 205/26b-B 'Lincoln Crestal' well, the second well of a three-well programme on the Greater Warwick Area. Hurricane has a 50% interest in the Greater Warwick Area following Spirit Energy's farm-in to the P1368 South and P2294 licences in September 2018.

Dr Robert Trice, Chief Executive of Hurricane, commented:

"It is disappointing that the Warwick Deep well did not flow at commercial rates. We were initially encouraged by hydrocarbon shows and gas ratio analysis indicative of light oil, however drill stem testing has clearly demonstrated that Warwick Deep cannot be considered suitable as a future production well and therefore the well will be plugged and abandoned.

"I look forward to commencing operations on the second well in the three-well programme, Lincoln Crestal. This is now the preferred candidate to be tied back to the Aoka Mizu FPSO, where Lancaster EPS production operations remain in-line with guidance."

See also: Spirit Energy farms in to Hurricane's Greater Warwick Area

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Guyana's upcoming drilling

Tullow and its partners have upcoming drilling in Guyana over the summer over two blocks.

The blocks are:

• Orinduik: Tullow (60% operator), Total (25%), Eco Atlantic (15%)
• Kanuku: Repsol (37.5% operator), Tullow (37.5%), Total (25%)

In August, the Stena Forth drill ship will arrive on Orinduik for a two well campaign to drill the Jethro and Joe prospects.

In October, Repsol is scheduled to drill the Carapa prospect on Kunuku.

Guyana remains an exciting place to watch following the success of ExxonMobil, Hess and CNOOC on the Stabroek block.

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Zama resource increase

Talos and Premier Oil have announced the successful appraisal of Zama in Block 7 offshore Mexico under the Zama-3 well. Premier has indicated a P90-P10 resource range of 670-970mmboe with P50 of 810mmboe. This further reaffirms the resource base and provides an upgrade to the previous 600mmbbl (oil) estimate.

The Zama-3 well follows:

• The initial Zama-1 discovery in 2017
• Zama-2 appraisal in January 2019
• Zama-2ST1 sidetrack well in April 2019

Zama-3 was drilled 2.4km from Zama-1 and logged 228m of gross pay. The net-to-gross was consistent with prior penetrations. The Zama-3 well was completed 9 days ahead of schedule and on budget.

The entire 3 appraisal well programme finished 39 days ahead of schedule and under budget.

The Zama field is planned to be developed from a single drill centre with drilling from the platform. Three production platforms are envisaged, each with capacity of up to 100mbopd. Produced oil is planned to be transported via a pipeline to the Dos Bocas terminal located onshore, c.70km away from the field.

The Zama partners are: Talos (35% operator), DEA (40%) and Premier Oil (25%).

Premier Oil also has a non-operated interest in Block 30 which could see Mexico transform into another important leg of its portfolio.

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Kurdistan steps up efforts to eliminate gas flaring

The Kurdistan Ministry of Natural Resources ("MNR") has asked the Shaikan field partners (Gulf Keystone and MOL) to re-submit a revised FDP for the field to address additional MNR requests on gas management.

The next well planned on the field will now be used to assess the feasibility of gas reinjection into the Jurassic formation, rather than as an originally planned Jurassic production well.

Whilst a key driver to be reservoir management and ultimate recovery rates, it is noted that the MNR is keen to eliminate flaring in Kurdistan.

Gulf Keystone has previously stated that the elimination of gas flaring is the single most complex and expensive component of the field’s development, and additional gas-handling capacity would be required to handle the gas-rich light oil in the underlying Triassic reservoir.

At nearby DNO’s Tawke field, work is scheduled to begin later this year on building the gas-gathering and processing facilities to enable reinjection of Peshkabir’s associated gas into the Tawke field, to reduce flaring and increase the latter recoverable reserves; this gas-gathering and injection system is forecast to be operational in early 2020.

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Dry well in the Barents near Korpfjell

The 7335/3-1 exploration well on Production Licence 859 has drilled a dry well.

The partners on the licence are: Equinor 65% operator, Lundin 15%, DNO 20%.

The licence lies in the Barents Sea and the 7335/3-1 well is located c.8km southeast of the Korpfjell gas discovery.

Both the primary and secondary exploration targets encountered sandy and poor reservoirs. The well was drilled by the West Hercules drilling rig to 4,268m below the sea surface and water depth was 239m The well has not been permanently plugged and abandoned.

The West Hercules rig will now move to drill a wildcat well 7324/6-1 in PL855 in the Barents Sea.

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Woodside's Pluto LNG restart delayed

Source: RBC

Woodside's restart from its planned Pluto LNG turnaround will be delayed until the end of June after initial restart efforts were unsuccessful. Vibration in the refrigerant compressor has delayed restart.

In the interim, Woodside will be purchasing cargoes from the market to fulfill its contractual obligations. However Woodside are making a healthy margin of  c.USD5/mmbtu with the current lull in Asian spot LNG prices due to subdued summer demand.

Spot LNG prices are c.USD5/mmbtu and Woodside's contractual supplies have achieved c.USD10/mmbtu.

#LNG

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PGNiG acquires Total's 22.2% stake in King Lear

Total has sold its 22.2% stake in King Lear to PGNiG. This follows AkerBP's acquisition of Equinor's 77.8% stake in the field in October 2018 for USD250 million.

In October 2018, AkerBP noted that King Lear is one of the largest undeveloped discoveries in Norway and that it planned to develope the field as a satellite to Ula. Ula is operated by AkerBP (80% with DNO as 20% partner) and the tie-back will improve capacity utilisation at the Ula facilities. Importantly, King Lear will also provide signifcant gas volumes for injection into the Ula field for increased oil recovery. Net recoverable resources at King Lear is estimated at c.100mmboe and is gas weighted.

PGNiG notes that the development of the field is planned to commence in 2021 with first production in 2025.

The King Lear development has stalled since its initial discovery as it was originally expected to be part of the Greater Ekofisk Area project which would have seen King Leat, Tommeliten Alpha and Tor tie back to Ekofisk. However gas processing capacity constraints at Ekofisk meant the project was not sanctioned.

With PGNiG entry into King Lear, and also ownership of Tommeliten Alpha (acquired from Equinor in October 2018) could see the latter now being routed to King Lear.

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