Hurricane Energy plc, the UK based oil and gas company focused on hydrocarbon resources in naturally fractured basement reservoirs, provides an operational update ahead of its Capital Markets Day presentation via webcast at 10:00 a.m.
Dr Robert Trice, Chief Executive of Hurricane, commented:
“I look forward to providing an update to the market via webcast later today. As expected, the past year has proved to be transformational for Hurricane. We recognise the challenges in the market environment
currently but are pleased to report on our continued good production performance at Lancaster.
“With a significant unrestricted cash balance of $152 million as at 1 April 2020 and low operating cash costs of $17/bbl, the current oil price does not pose an immediate threat to the Company as we continue our data gathering programme at Lancaster. However, it does limit options for capital expenditure on additional operational phases. Our capital allocation framework has been revised to account for the current market environment and is focused on retaining a strong cash balance whilst meeting our licence and joint venture commitments.
“The Lancaster wells have demonstrated very high productivity, despite some unexpected production of what we are confident is ‘perched water’, and we continue our testing programme at a combined rate of up to 20,000 bopd with the objective of evaluating sustainability and long-term trends at this target rate. It will take more time to confirm the long-term potential of the reservoir, and our operations may be impacted by measures related to the COVID-19 pandemic and the resulting macroeconomic situation. However, we have sufficient confidence, based on data obtained to date, to provide current forward guidance of net 18,000 bopd.”
Lancaster Early Production System
The Lancaster Early Production System (“Lancaster EPS”) started production through the Aoka Mizu FPSO
in May 2019. Due to commissioning activities, unplanned shutdowns and subsurface testing, approximately 5 months of steady production data has been obtained so far, and reservoir behaviour has been more complex than anticipated. A more extended period of steady production is therefore required to confirm the validity of Hurricane’s geological model and define reservoir characteristics sufficiently to consider the next stages of development.
So far, well productivity is world-class, with each well exhibiting an initial productivity index (PI) in excess of 200 stb/d/psi. To provide context, the Saudi super-giant Ghawar field is reported to have had initial PIs of c. 140 stb/d/psi. This productivity is particularly impressive when considering both wells are interpreted as producing from a limited section of the horizontal borehole length close to the heels of the wells.
This well productivity is consistent with the Company’s model of a dual porosity system comprising highly permeable fractures, connected to a pervasive ‘background’ permeable fracture network. However, whilst the wells show high performance individually, their proximity, and associated interference behaviour, requires further data acquisition before the Company can be confident about optimum longterm well rates.
Having not observed water during initial drill stem testing of the two Lancaster EPS production wells, significant water production had not been expected during the EPS phase. Water production has been steadily increasing since production started, with an aggregate water cut of approximately 26% during the
month of April (1st – 21st) whilst producing an average of 18,500 bopd (net of downtime).
After retrospectively analysing the drilling and petrophysical data with the benefit of the EPS data the following conclusions have been drawn:
• a 10m high permeability water bearing zone has been identified within an interpreted 40m producing interval in the 205/21a-7Z well;
• a 10m water zone has also been identified in the 205/21a-6 well, however this water zone is more distant from the interval currently producing;
• produced water from the 205/21a-6 well is therefore interpreted as being drawn from the perched water zone intersected by the 205/21a-7Z well; and
• current individual well water cuts of approximately 46% in 205/21a-7Z and 7% in 205/21a-6 during April are consistent with this revised interpretation, noting that the 205/21a-7Z figures were impacted by high water cuts immediately after a shut-in at the start of the month.
The behaviour of produced water combined with the drilling and petrophysical data has led to an interpretation that the water produced by the Lancaster EPS is being sourced from a zone of ‘perched’ water. Perched water is isolated from the underlying aquifer and therefore has a finite volume relative to the life of the field. The perched water model would imply that once a constant production trend has been set, water production levels should stabilise over time and may eventually decline. In the meantime, the Aoka Mizu FPSO’s facilities have the capacity to safely process the produced water and the current water cut is not affecting the vessel’s ability to deliver oil production.
More data and time are required before the Company can confirm or challenge published resource ranges,
considering the complex dynamic behaviour of the Lancaster fracture system. Nonetheless, after production of over 4.7 million barrels and observation of related bottom-hole pressure trends, an initial assessment of the minimum connected reservoir volume that is being ‘seen’ by the wells at the present time can be made using simple material balance techniques. These techniques cannot provide unique answers at this stage however, recent pressure decline trends are consistent with a minimum in-place volume of around half a billion barrels. This suggests that the wells are obtaining more pressure support with increased production, progressively ‘seeing’ more of the reservoir. This additional pressure support is attributed both to connections with more distant volumes of the reservoir, and slower feed-in from micro-fractures within the dual porosity system. The net effect is that the wells are accessing more volume with time, and have yet to reach a stable decline rate from which ultimate reservoirsize can be estimated.
Hurricane is assessing a number of options for next steps at Lancaster. Prior to recent oil price declines, the Company was evaluating the potential to drill and tie back an additional production well (the “L8 well”) to not only increase production but also provide data to help de-risk the Company’s volumetric model. Another consideration is the potential to re-enter the 205/21a-7Z well and isolate the heel, with the objective of accessing a more productive zone and reducing the interference impact with the 205/21a-6 well. Successful isolation would have the benefit of increasing productivity without requiring the drilling of a new well or of making a significant investment in new subsea infrastructure that a new well would require. Whilst these two options continue to be reviewed in light of the oil price and Lancaster EPS performance, next steps are currently confined to:
• continuing the existing testing plan on the two Lancaster EPS wells;
• a volumetric review including a CPR in early 2021, reporting reserves and resources as at 31 December 2020;
• the Lancaster licence commitment well in 2021; and
• the decision to proceed into the next phase of the Aoka Mizu FPSO contract.
It had been planned to commission the electrical submersible pumps during Q2 2020, but COVID-19 restrictions requiring manning levels to essential personnel only have delayed this programme. These pumps are not currently required to maintain production levels, though their testing and commissioning remains a project aspiration for 2020.
Greater Warwick Area
The three well 2019 drilling campaign completed in joint venture with Spirit Energy Limited (“Spirit Energy”) (“GWA JV”) materially increased our understanding of this part of the Rona Ridge. While the 205/26b-14 (“Lincoln Crestal”) well produced oil at 9,800 bopd using an electric submersible pump (“ESP”), the other two wells had significantly poorer outcomes.
The results of the wells in the 2019 drilling programme are still undergoing analysis, but conclusions drawn
so far include:
• GWA productivity is materially less than Lancaster, illustrated by lower drilling mud losses, lower flow rates and lower productivity indices;
• there is a difference in the fault zone characteristics in the GWA compared to Lancaster;
• the GWA basement appears to have less well-developed reservoir qualities compared to Lancaster; and
• the Lincoln Crestal well successfully produced at 9,800 bopd using an ESP and exhibited a dual porosity fracture response similar to Lancaster, however the productivity index was materially lower than at Lancaster.
The above observations point to the GWA basement having less well-developed reservoir qualities compared to Lancaster, and better understanding of the control on these properties will require further wells and data. The planned licence commitment well is an important data point to this end.
Though different to Lancaster, the GWA JV is sufficiently encouraged by the 2016 and 2019 well results on Lincoln to consider the discovery commercial for development. The GWA JV is therefore seeking a field determination at Lincoln for the purpose of progressing a field development incorporating a single well tie back to the Aoka Mizu of either the Lincoln Crestal well or an alternative shallower producer.
Based on existing consents, the Lincoln Crestal well is planned to be plugged and abandoned later this year. The suspension consent, which provides the deadline for this activity, has been extended from 22 June 2020 to 30 September 2020, due to the ongoing COVID-19 pandemic. This extension also allows for the gathering of additional long-term pressure data which is expected to provide further insight into the dynamic behaviour of the Lincoln reservoir. The Transocean Paul B. Loyd Jr. semisubmersible rig, which remains under contract, is currently stationed in the Cromarty Firth and is expected to carry out this activity, although the GWA JV are also reviewing a number of alternative rig options.
Sufficient information since First Oil has been gained for Hurricane to provide forward production guidance of 18,000 bopd net for the time being, but the Company acknowledges that the current macroeconomic environment and health situation could impact Hurricane’s ability to operate as planned, and there is still much to learn about reservoir performance. Q1 production averaged 14,900 bopd due to ongoing individual well testing and gradual ramp-up to the 20,000 bopd target rate (excluding downtime). Forward guidance of 18,000 bopd therefore equates to an average expected net production rate for 2020 of approximately 17,000 bopd.
While EPS operating costs of $17/bbl combined with a strong current cash balance of $152 million (unrestricted cash at 1 April 2020), provide a relatively robust financial footing at present, the Company is conscious of current macroeconomic circumstances, with oil prices having recently hit historic lows. A sustained period of very low oil prices or unexpected operational difficulties related to COVID-19 will increase pressure on its finances.
Before the COVID-19 crisis developed, the Board had agreed a capital allocation framework designed to:
• maintain healthy minimum levels of cash;
• allocate cash flow from operations towards further strengthening of the balance sheet;
• meet future financial liabilities;
• strictly control capital spending focussed on licence and contractual obligations;
• facilitate returns to shareholders at the earliest appropriate time in the future; and
• consider other drilling options, only if maximising shareholder value uplift at minimum cost.
If the current oil price environment persists for some time, this would create challenges in meeting capital allocation goals in full. The Board will consider what additional measures may be prudent as the situation
The future capital programme also depends on ongoing discussions within the GWA JV, and the outcome of the recent request to the regulatory authorities for a field determination over Lincoln. Further updates will be provided to the market once the cost of future capital programmes has been confirmed.