Onshore Trinidad: Southern Basin Province
Inniss Trinity oil field Well Participation Agreement
Trinidad lies within the Eastern Venezuelan Basin which is one of the largest oil provinces in the World. The Inniss Trinity field lies in the southern part of Trinidad where, as a result of thrust faulting during the Middle Miocene orogeny, several NE-SW trending anticlinal folds developed. Several oil fields which produce from similar age turbidite reservoirs are located along the trend, including Penal-Barrackpore, Cory Moruga, and Moruga West. The Miocene Herrera turbiditic sands are the main oil reservoirs and underlain by Cretaceous marine shales which are the main oil source rocks. Oil reservoirs occur between 500 and 3,500 feet in the IPSC area.
Oil gravities are in the range 28-38 API. FRAM currently produces approximately 160 bopd from their well entitlements under the IPSC, mainly from workovers. The field was originally operated by Texaco.
Predator entered into an agreement on 17 November 2017, the Inniss Trinity Well Participation Agreement ("WPA") which facilitated Predator Funding 100% of the cost of 2 infill production wells in the mature onshore Inniss Trinity oil field under the terms of an Incremental Production Service Contract ("IPSC") held and operated by FRAM Exploration Trinidad Ltd ("FRAM") with 100% equity. The ISPC is between FRAM and Petrotrin, the State oil company and licence holder.
The WPA was amended in July 2018 to defer Predator's participation, subject to regulatory approval, in the infill development drilling operations in the Inniss-Trinity oil field by 12 months to focus on Enhanced Oil Recovery assisted by carbon dioxide injection ("C02 EOR"). CO2 EOR operations are considered by all stakeholders to potentially be commercially more attractive and to offer the possibility of higher returns for investors for approximately the same amount of existing Predator capital as would have been deployed for executing the infill drilling programme.
Under the amended WPA, Predator shall fund the cost of acquiring and upgrading surface facilities for Pilot C02 EOR operations and the supply of a minimum of 5,400 metric tonnes of C02 to the C02 injector well and will fund all costs associated with the initial phase of Pilot C02 EOR operations up to a maximum Consideration Cap of USD 800,000.
Subject to a successful Pilot C02 EOR, the extension of the IPSC to 31 January 2022 and the Company's Pilot C02 EOR economics, Predator shall fund the cost of expanding C02 EOR operations up to a maximum Consideration Cap of USD 700,000 using production revenues generated from the Pilot C02 EOR.
The WPA allows Predator to recover 100% of its costs from anticipated production from the pilot CO2 EOR operations after deduction of State and Petrotrin royalties of 22.5% and operating costs, which are capped at US$ 10/brl, and the offset of cumulative historical FRAM tax losses against 50% Petroleum Profit Tax. In the event that realised oil price (after deduction of the Petrotrin discount) is greater than US$50.01/brl and less than US$90/brl the Petrotrin royalty increases such that the combined State and Petrotrin royalties are 29.5%. A Supplementary Petroleum Profit Tax (“SPPT”) of 18% on gross revenues less State and Petrotrin royalties also applies when realised oil is within this price range. Realised oil price is averaged over one month with SPPT returns being made quarterly. After cost recovery revenues are split 50:50 with FRAM on the above terms. Petrotrin purchases the oil for use in the local refinery at West Texas spot price less approximately 5% discount. The availability of FRAM’s historical tax losses for offset against 50% Petroleum Profit Tax is an important commercial consideration when assessing the viability of the C02 EOR project.
Rationale for Pilot C02 EOR
Predator has analysed the currently available C02 supply in Trinidad and determined that gas composition, deliverable volumes and required logistics are sufficient to support the execution of Pilot C02 EOR operations. Potential C02 supply characteristics have been matched to several areas of the Inniss-Trinity oil field that are considered to be geologically suited to C02 EOR operations and to have had a previous production history that is interpreted as offering greater potential for higher production rates compared to other parts of the oil field.
Initial Reservoir Engineering Assessment
The Company has received and reviewed the Initial Reservoir Engineering Assessment for the proposed Inniss-Trinity Pilot C02 EOR Project produced by Dr. John Tingas PhD & MSc in Petroleum and Chemical Engineering. Dr. Tingas has 44 years' of industry experience including with Shell, BP, Amoco, BG Group, OMV and Gaffney Cline. The initial assessment confirms the technical feasibility of C02 EOR operations in the Inniss-Trinity oil field.
Whilst there are technical challenges represented, for example, by the high water cuts for many of the currently producing wells in the field that have been caused primarily by a previously executed waterflood project, these challenges can be addressed by C02 injection when combined with the application of an appropriate reservoir engineering management plan. Successful C02 EOR is common in the United Sates in fields that have previously undergone waterflood.
The operational plan has been devised to minimise the above technical challenges whilst maximising the opportunity for miscible C02 EOR through which higher production rates and recovery factors are potentially achievable.
Initially C02 is to be injected for a short period into the AT-5X and AT-12 wells to target all or either of the Herrera #3, #4 and #5 Sands and the Herrera #1 and #2 Sands respectively. Maximum C02 injection rates will be up to 23 metric tonnes per day at an injection pressure provisionally of up to 2,000 psia. This will be required to re-pressure the reservoirs near to their original pressures.
Thereafter updip wells AT-13 and AT-4 will be injected continuously with up to 24.5 metric tonnes per day of C02 at up to similar injection pressures. AT-5X and AT-12 will cease to be injectors and become production wells.
Over 80% of injected C02 is currently forecast to remain sequestrated within the oil reservoirs therefore contributing to reducing Trinidad’s C02 emissions.
Estimates of daily C02 injection rates have been reduced by the Initial Reservoir Engineering Assessment by at least 35%, resulting in a substantial reduction in anticipated operating costs per barrel of oil produced.
This Pilot Design is considered optimum, based on the currently available reservoir data, for: increasing the pressures in the vicinity of the production wells to avoid precipitation of asphaltene and waxes; for lowering oil viscosity by dissolved C02; for generating very low water cuts; and for managing gas-oil ratios
The ability to modify the Pilot Design parameters is a part of the operational plan to accommodate additional reservoir data collected from the Pilot operations.
Forecast Scoping Production Rates
Successful implementation of the Operational Plan is forecast to result in an average P50 production rate of approximately 350 bopd from up to 5 Herrera sand intervals in two C02 EOR production wells. Recent production from these wells has been less than 50 bopd. Successful Pilot C02 EOR results are therefore forecast to increase these production rates by up to 6-fold.
By comparison average annual production from one conventional infill development well was forecast to be 50 bopd for the most recently proposed infill development well.
Production well conditions for the proposed C02 EOR wells are assumed to be sustainable for a long period because of the continuation of C02 injection updip, therefore the rapid decline rates seen in the conventional wells in the field should not be applicable.
Forecast Recoverable Resources
Recoverable resources within the AT-4 Block, which is the focus of the initial Pilot C02 EOR Project, are forecast to be 859,000 barrels for full-C02 EOR. This represents a 12.3% recovery factor based on the former operator Texaco's estimate of original oil in place. The AT-4 Block represents approximately 10% of the entire area of the Inniss-Trinity field.
Original oil in place estimates for the Inniss-Trinity field vary between 68 million barrels (Texaco 1973), 150 million barrels (Gaffney Cline CPR for FRAM Exploration Trinidad Ltd ("FRAM") 2011) and 89 million barrels (SLR Consulting CPR for the Company 2018).
Assuming the AT-4 Block Pilot C02 EOR were to be replicated throughout the field, management's estimates of potential recoverable resources for field-wide C02 EOR range from 8.12 million barrels to 15.62 million barrels based on the more recent original oil in place estimates in the CPR's.
Following initial results of the AT-4 Block Pilot C02 EOR, including history matching production performance with the various estimates of oil in place, the Company will be in a better position to commission an updated independent CPR to address resources and to narrow down the currently wide range of estimates for oil in place that may be attributed historically to the exclusion of moderate quality reservoir intervals that may respond well to being swept by a C02 flood.
C02 Supply Contract
The Company has entered into a Heads of Agreement ("HOA") with the local C02 Supplier with an exclusivity period to enter into a Gas Sales Agreement initially by 30 November 2018. The deadline for the commencement of C02 deliveries is 31st January 2019. The Company and the C02 Supplier are extending the exclusivity period to allow for analysis of the new reservoir engineering data to better determine the daily volumes of C02 to be delivered to the Pilot C02 EOR site and the plant capacity required in the short term to meet these daily requirements. The C02 Supplier will install and operate the C02 delivery system.
The main terms of the HOA are:
- Minimum daily delivery of C02 of 60 metric tonnes (if required for full C02 EOR operations);
- Start-up date for first C02 deliveries to Inniss Trinity field 31 January 2019;
- Initial Term 12 months;
- The Company has a right to extend initial term by 12 months ("Subsequent Term");
- The Company has a right to extend Subsequent Term by 12 months;
- The Company has an option to take all or any part of C02 supply greater than the minimum daily delivery rate of 60 metric tonnes;
- C02 purity not less than 99%;
There is the potential for a significant upscaling to other parts of the Inniss-Trinity field based on current expectations of forecast available C02 Supply and subject to the results of the Pilot C02 EOR in the AT-4 Block.
Sourcing surface equipment for Pilot C02 EOR operations is progressing and delivery times for delivery to Trinidad are well within the scope of the existing Project Schedule.
Start-up capital costs have been reduced to less than US$ 600,000, well below the Company's budgeted cash for the Pilot C02 EOR Project. This provides ample headroom to progressively upscale the C02 EOR operations over time, as additional reservoir information and production data are collected from the Pilot C02 EOR in the AT-4 Block, using surplus working capital and organic cash flow from production.
Operational and environmental meetings have been held in Trinidad to progress regulatory consents and to agree a project schedule that works for all parties given that this is the first large-scale C02 EOR project in Trinidad for a number of years. As a result a target of H1 2019 has been set for first incremental production from Pilot C02 EOR operations.
Offshore Ireland: Atlantic Margin
Licensing Option 16/26 Part-Bocks 18/24(p), 18/25(p), 18/29(p) & 18/30(p) cover 302 Km2 in water depths of 1,100 feet
Predator Oil & Gas Ventures: 50% (Operator)
Theseus Ltd: 50%
Awarded in July 2016 as part of the Atlantic Margin Licensing Round the acreage is located adjacent to the Corrib gas field and gas pipeline to shore in the Slyne Basin.
LO 16/26 contains the Corrib South Prospect.
The area of minimum closure for Corrib South is covered by the same 3D seismic survey that extends over the Corrib gas field.
The reservoir target in Corrib South are the Sherwood sandstones, the producing gas reservoir in the Corrib gas field, Mercia salt, as at the Corrib field, is expected to seal the reservoir which is also likely to have been charged from similar gas-prone Westphalian source rocks.
The size of the Corrib South structure in the maximum case, which depends on pre-2000 vintage 2D seismic coverage to the southwest, is similar to that of the Corrib gas field. Drilling and water depths are similar.
Corrib South lies only 20 kms. south of the Corrib subsea gas gathering manifold making it a candidate for a potential subsea tie-back without a standalone requirement to take the gas directly to a new landfall. Spare capacity is forecast to be available in the Corrib infrastructure within the likely time framework for drilling and potentially developing Corrib South.
Attractive geology and a clear pathway to development and monetisation provide an appealing backdrop to Predator's current farmout process.
Corrib South is an ideal fit for the Predator business strategy. Additional sustainable gas supply from the Corrib gas hub could facilitate the conversion of the Moneypoint power station in the Shannon estuary to gas from coal, potentially reducing Ireland's greenhouse gas emissions.
SLR Consulting's Competent Persons Report estimates that the chance of success for the Corrib South Prospect is 30%.
|Gross Attributable||Low Estimate (Bscf)||184.6|
|Best Estimate (Bscf)||424.8|
|High Estimate (Bscf)||904.7|
|Net Attributable to Predator (50%)||Low Estimate (Bscf)||92.3|
|Best Estimate (Bscf)||212.4|
|High Estimate (Bscf)||452.4|
Offshore Ireland: Celtic Sea
Licensing Option 16/30 Part-Bocks 49/13(p), 49/14(p), 49/15(p), 49/18(p), 49/19, 49/20 & 49/23(p) cover 799 Km2 east of the Kinsale gas field in water depths of 290 feet
Predator Oil & Gas Ventures: 50% (Operator)
Theseus Ltd: 50%
Awarded in November 2016 following an Out-of-Round application the acreage is located east of the Kinsale gas field and gas pipeline to shore in the Celtic Sea Basin.
LO 16/30 contains the Ram Head Prospect, formerly identified and drilled by Marathon in 1984.
The Ram Head Prospect is covered by many different vintages of 2D seismic data and was evaluated by Marathon’s 49/19-1 well after the Helvick 49/9-2 Gulf oil discovery.
The reservoir target are Middle and basal Upper Jurassic sandstones.
49/19-1 encountered dry gas at the time of drilling.
New technology has provided enhanced information in relation to the potential quality of proven Jurassic gas reservoirs and Cretaceous oil sands penetrated by Marathon well in 1984 in 49/19-1.
Ram Head lies only 40 kms. east of Kinsale.
SLR Consulting's Competent Persons Report estimates that the chance of success for the Ram Head Prospect is 12%
|Prospect Ram Head||Middle to Upper Jurassic Gas Reservoirs|
|Gross Attributable||Low Estimate (Bscf)||236|
|Best Estimate (Bscf)||1016|
|High Estimate (Bscf)||2740|
|Net Attributable to Predator (50%)||Low Estimate (Bscf)||118|
|Best Estimate (Bscf)||508|
|High Estimate (Bscf)||1370|
|Ram Head||Upper Purbeck Oil|
|Gross Attributable||Low Estimate (MMBmls)||64|
|Best Estimate (MMBmls)||189|
|High Estimate (MMBmls)||493|
|Net Attributable to Predator (50%)||Low Estimate (MMBmls)||32|
|Best Estimate (MMBmls)||95|
|High Estimate (MMBmls)||247|