Guyana’s offshore: Facts, Risks and Challenges

Feb 03, 2020 Letters

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DEAR EDITOR,

In 2015 ExxonMobil struck oil in 2 out of 3 exploratory wells in Liza prospect, offshore Guyana, Stabroek block. Appraisal work has placed Liza asset under an estimate of 450 MMBOE to 1.200 MMBOE range recoverable resources. Although much smaller, additional volume was found later during 2017 in the Payara prospect, propelling total reserves expectation towards 1.400 MMBOE. Exxon and the Guyana government claim 15 additions in total, including the latest Tilapia, Haimara, and Yellowtail prospects further south-southeast within the same block, for a total of nearly 8.000 MMBOE of recoverable resources in place, as per latest information. Important to understand, that these are recoverable resource base; not commercially recoverable reserves as such yet.
Establishing the difference between resource and reserve is critical to understand the real potential for the assets. While resources refer to an estimate of the amount of hydrocarbon that “might” be technically recovered if production were not “constrained by economics”, reserves refer to an estimate of the amount of hydrocarbon that “can technically and economically” be expected to be produced. In any case, estimates of reserves will develop, decrease or improve with increasing exploration, appraisal and/or development drilling. Normally, resource estimates are larger than reserves estimates in at least one 1/3 to ½ of the initial figures as rule of thumb.
Facts: Promises forecasting production increase from Guyana offshore assets have been made since 2015, with the discovery of “Liza and Payara” fields. The plan, according to Guyanese authorities comprises for Phase 1 Liza prospects, a 2020 yearend production of 120.000 B/D, with preliminary breakeven margin of $35 per barrel. For phase II a peak production of 180.000 to 200.000 B/D has been sanctioned for 2022, with a $25 per barrel breakeven margin (preliminary). As per corporate press releases, Exxon expects to produce at a maximum output of 750.000 BPD in the mid to long term.
Unfortunately even before the first drop of oil was actually produced, local government seems to be already committed to pay, somewhere between $850 to $950 million to Exxon in pre-contract costs. For the small Guyanese economy, whose 2018 GDP was just a little over $3.000 million, it means a sizable 30+% load exposure.
Exxon claims production was actually initiated on December 20, 2019. The first crude oil cargo of nearly 975.000 barrels was shipped on January 19th, whereas the second is scheduled by the end of January in a similar volume. Assuming all 8 producers are active, per well outflow has reached nearly 8.000 BPD, still far from expected 15.000 B/D per well originally planned.
Unless the 120.000 B/D plateau is reached during 2020, monetization of Guyana’s proven oil and gas reserves will not be likely for the short term. Considering the investment plan with over $4 to $6 billion in CAPEX, and the financial expectations of agreed 2% royalty over the whole extracted volume of crude oil, plus a 50% of the 25% cut remaining after a gigantic 75% Exxon take supposedly assigned to cost recovery, the Net Present Value for the project won’t be positive for Guyana in the near term, but beyond the 7th to 8th year, only under the assumption of 100% success rate, which is seldom the case for most; if not all green (immature) projects.
The most likely scenario is that reserves are ending around 3 to 4 billion equivalent barrels and stabilized per well production sets around 6 to 8 MBD, placing total output for Liza phase I to a maximum of 64.000 BOED. If this was the case, total net present value for the project could be exposing around $6 billion, propping the breakeven point beyond the 10 year window for Guyana.
Regarding the gas reserves, field development plan for Liza phase I calls for a portion of the produced gas, to be recycled for pressure maintenance purposes. No official information has been given about how the government of Guyana will be compensated for the produced and/or reutilized gas. Initial figures suggests that at likely output the value of the produced gas alone would be around $550.000 per day, whereas at full production (120.000 B/D) the value could be above $1.000.000 per day, both at current gas price (Henry Hub).
Risks and Challenges: A number of production and operation challenges and risks are expected during start up and normal operations for these very sensitive assets. The offshore Stabroek project has lots of intangibles which could easily turn the value into read, plus the economics have lot of preliminary assumptions with not firm technical basis to support it. Without accounting for the operational and inherent asset deliverability challenges, Stabroek is an important green field area, costly to develop. Liza and Payara reservoirs are located to a depth of over 17.800ft (>5,400mts) deep in a water column exceeding 5,700 ft (>1.700+mts). There are sensitive environmental challenges, operational complexities, and concerning potential reservoir complexities.
To drill and complete such offshore-deep-wells require at least 120 days, and around $60 to $80+ million. For phase I, a 17 well drill center including 8 producer, 6 water injectors, and 3 gas injectors was considered. With concurrent operations, and considering only a 3% decline rate per year, the 120.000 B/D target is feasible assuming 100% efficiency, no operational problems/delay, and a 15.000 B/D per well rate, which in essence seems unsustainable and unrealistic in practice for this type of assets. For phase II, some 30 wells will be needed, including 15 injectors.
Looking at the acceleration criteria, in situ reserves will be depleted at 4% during phase I, and 6% during phase II, taking into account the upper bound for the recoverable reserves of 1.200 MMBOE (Full scope: Liza asset), whereas at 10% and 16% respectively for the lower end reserves scenario (450 MMBOE).
Discovery wells for both prospects targeted similar reservoirs, the most prolific belonging to the Upper Cretaceous. It has also been confirmed that discovery wells have significant free-gas volumes, possibly over 2 trillion cubic feet, as well as intrinsic early production problems leading to formation dislodging. These observations pose beyond doubt, a significant threat to offshore Guyana future development which needs to be considered.
Liza and Payara reservoir fluid is likely to be described as light-volatile or retrograde gas condensate. In any case, assuming as accurate that initial pressure conditions places the main pool at/or below saturation pressure, further complications should be expected, all leading to added costs (gas flaring, fluid disposal, etc) and accelerated productivity decay.
As per confirmed information, both Liza and Payara reservoirs are preferentially volumetric, meaning they have little or no additional-significant pressure support besides fluid & rock expansion. Accelerating these assets at such rate of over 4%; and even more 16%, will ensure a very short-live expectancy under primary production, reducing reserves expectation (in situ trapping), and demanding additional pressure support from project inception (assisted/EOR/IOR, recycling, etc). That’s the main reason why Exxon considered water/gas injectors.
For the water injector wells, most likely seawater will be used, which poses an additional environmental hazard as potential reservoir souring can become likely, if not properly treated. Reservoir souring occurs when the sulfate dissolved in the seawater promotes the growth of sulfate reducing bacteria generating hydrogen sulfide and other harmful sulfur compounds. This has to be taken very seriously as there are a number of precedents, particularly in the North Sea. All of these elements bring additional capital and operating costs to the project.
At required flow rates of 15.000 B/D per well during initial production, superficial and interstitial supersonic “erosional” velocities, particularly for the upper gas phase will force operations towards high OPEX intensive. In spite of well architecture and type of completion (i.e.: vertical, highly inclined or multilateral), supersonic velocities and “erosional” forces will reduce well life expectancy even with costly and specific metal alloy grades. Irrespective of borehole completion schemes, it will also consistently and gradually destabilize near wellbore region, leading to borehole collapsing adversely impacting flow properties, well deliverability, and ultimately reducing both, overall production and margins.
Regardless of the claim about a number of new prospects including the latest Tilapia, Haimara, and Yellowtail, in reality these are medium to small offshore deep pockets of hydrocarbon, which require large capital investments and high risks to develop. With the exception of Liza, Maku, Snoek, and latest Uaru, most of the assets are isolated among them, turning very costly capitalizing on neighboring infrastructure because of the large distances involved.
In terms of in situ reserves volume, geologically speaking the potential for more commercially attractive reservoirs is limited to, and “possibly” reduced to an aerial strip trending N-NW to S-SE beyond which either the hydrocarbon biodegrades, or the reservoir thins out, and the seawater depth surpasses the 4.000 to 5.000 meters deep.
This whole picture describing inherent risks clearly explains the reason why Exxon made sure to get the 75% share initially mentioned at front as costs recovery. Let’s not forget that this company has been facing a sustained loss of value since mid’2014, when it reached over $105 per share. Recently, price per share has dropped to under $64.6; losing nearly 40% of its whole value so far.
The government of Guyana needs to take time to rethink strategies for pending or future licenses and SPA’s, including the review of royalty figures, renegotiation of pre-contract costs, share per barrel produced, as well as diversification from current stakeholders. One of the actions the government of Guyana should also consider is to make sure to negotiate “future” SPA’s based on investment, and percentage of actually in situ reserves recovered, instead of a simple per barrel produced based contract, incrementing the operator share as most investment and exposure is made and not at front. The government should also consider retaining a fee to the operators, to create a fund accounting for any unexpected offenses against the environment.

Millan Arcia Einstein:
Senior Upstream Oil & Gas Global Adviser and SME

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