Production for the first half of 2017 was 37,015 Boepd. With prolonged commissioning leading to lower than expected operational efficiency from the Kraken FPSO vessel to date, production volumes have been lower than forecast and EnQuest’s overall average daily production for the full year 2017 is now anticipated to be as per the first half 2017 production rate, plus or minus 10%. This reduction in EnQuest’s short term 2017 production guidance, is consistent with EnQuest’s objective of bringing Kraken onstream in a phased manner in line with good reservoir management practices aimed at maximising long term productivity and value. We do not expect the current operational issues in the Kraken ramp-up to continue beyond 2017.
Net debt at the end of June 2017, was $1,922 million, compared to $1,912 million as reported as at the end of April 2017. Available cash and bank facilities amounted to $213 million as at 30 June 2017.
EnQuest CEO, Amjad Bseisu said:
“EnQuest was pleased to bring the Kraken field onstream in Q2 2017 at a substantially reduced capex spend, having delivered excellent drilling and subsea programmes. The FPSO however is a complex vessel, designed and built to manage the heavy oil from the Kraken development, and it is taking longer than expected to commission during this initial period. Nonetheless, we have been very pleased with reservoir performance and the flow rates achieved on individual wells and, we expect the field to increase production in Q4 and to achieve plateau production of approximately 50,000 Bopd gross in H1 2018.
While we have seen natural declines in EnQuest’s existing production base in H1 2017, Kraken is on course to drive a material increase in EnQuest’s production in 2018 and beyond.”
1Net production since first oil on 23 June, averaged over the six months to end June 2017
Kraken development update highlights
First oil from Kraken was delivered on 23 June 2017. To date, the four wells from drill centre 1 (DC1) and two wells out of the three wells from drill centre two (DC2), have produced at initial gross rates above expectations and with stabilised flow rates which confirm the Field Development Plan. DC1 maximum individually tested well rates have been approximately 24,000 Bopd, with stabilised combined well rates at approximately 15,000 Bopd. One DC2 well has been tested at a rate above 10,000 Bopd, demonstrating excellent reservoir properties and completion efficiency. Injection wells have also surpassed expectations. The hydraulic submersible pumps, subsea production system and turret have all performed as expected.
Commissioning of the FPSO vessel topsides equipment continues and, despite good well deliverability, has been constraining production so far. Whilst in Q3 2017, volumes are behind forecast as equipment is commissioned, we expect operational uptime to improve accordingly and to deliver plateau production of approximately 50,000 Bopd gross in H1 2018.
DC3 wells are now due to complete in Q4 2017, ahead of schedule, further facilitating the achievement of plateau performance in H1 2018.
We expect to achieve a further c.$100 million of capex savings on the project as a result of the drilling of DC3 being completed 3 to 4 months earlier than planned and lower market rates for the subsea costs of DC4. Full cycle gross project capex is now estimated to be c.$2.4 billion, 25% down on the original sanctioned cost of $3.2 billion.
Northern North Sea production
The ongoing Thistle/Deveron programme to improve the reliability of water injection continues to have a positive impact, plant uptime is also improving. At the Don fields, well performance was particularly good at Don Southwest, with high levels of production efficiency across the Don fields. Production improving chemical treatments are planned at both West Don and Don Southwest. 2017 water injection issues at Heather/Broom have impacted production year on year, offset by high levels of production efficiency.
Central North Sea Production
The work programme in the Greater Kittiwake Area (GKA) & Scolty/Crathes for 2017 continues to be focused on optimising production across the assets. Good production has been delivered from the GKA fields, with high levels of plant uptime and production efficiency. Production rates on Scolty/Crathes have been constrained due to wax build up in the pipeline. Chemical treatments have been carried out which have allowed production to continue at reduced rates. Further work is ongoing to identify longer term solutions. Evaluation of the potential from the Eagle discovery is ongoing; Dana Petroleum has confirmed its intention to withdraw from this discovery.
At Alma/Galia, the final phase of the power and also the produced and sea water injection optimisation projects have been completed on the EnQuest Producer. As expected at the time of EnQuest’s full year 2016 results announcement in March 2017, production from Alma/Galia has been lower than in 2016, given shut in wells, production outages in Q1 due to storm damage and natural declines. Discussions continue with the ESP supplier on rectification plans to address the ongoing pump reliability issues.
EnQuest continues to invest in low cost well work and facility projects to improve production efficiency, including gas compression train and power generation control system upgrades. In addition, robust inspection and refurbishment campaigns on platform topsides and structures support ongoing safe operations.
Longer term, EnQuest will extend field life through further investment in idle well restoration, facility improvements and upgrades, well workovers, new drilling and secondary recovery projects to increase ultimate recovery. Significant progress is being made in 2017 on technical studies to better define the next phase of these projects.
The Tanjong Baram field has produced with excellent operational uptime in 2017 and the focus remains on steady, safe and low cost operations.
A futher update and additional analysis will be provided with EnQuest’s 2017 half year results on 7 September 2017.