Karly Lao 2025-09-03T13:50:50+02:00 Microsoft® Word for Microsoft 365 2025-09-03T13:50:50+02:00 Microsoft® Word for Microsoft 365 Microsoft® Word for Microsoft 365 Karly Lao Microsoft® Word for Microsoft 3652025-09-03T13:50:50+02:002025-09-03T13:50:50+02:00 uuid:98240D9C-444C-4A87-A060-F888B02E45D5uuid:98240D9C-444C-4A87-A060-F888B02E45D5 tetml={filename={D:\Drim\repository\projects\drim_66_0\metadata\f\6\f6cacb801574320f348b9335624b5512\f6cacb801574320f348b9335624b5512.tet.xml} elements={annotations=false bookmarks=false destinations=false fields=false javascripts = false} } granularity=word contentanalysis={punctuationbreaks=false dehyphenate=false} layoutanalysis={tabledetect=0 layoutdetect=0} PROJECT ALPINE Basis of Design granularity=word contentanalysis={punctuationbreaks=false dehyphenate=false} layoutanalysis={tabledetect=0 layoutdetect=0} 1 EXECUTIVE SUMMARY This document establishes the preliminary Basis of Design for the offshore production facilities and associated subsea systems forming part of PROJECT ALPINE, located within the Horizon South offshore exploration block in the Pelagia Basin. The scope addresses both topside and subsea infrastructure intended to support the commercial development of the field, including provisions for integration with the Central Nexus Facility. The content herein consolidates the current understanding of the Aurora-1 and Epsilon-4 wells, encompassing reservoir performance characteristics, produced fluid properties, and indicative well productivity profiles. It also incorporates the latest available geomorphological surveys and metocean design parameters relevant to installation and operational considerations in the northeastern seaboard waters of Valmora Island. An initial conceptual arrangement of the field development system is provided, outlining potential subsea architecture, tie-back routes, and processing options. This arrangement is intended as a baseline reference for PRIME ENERGY and its project partners—Stratos Energy Ltd. (Operator, 40% interest), Novara Petrochem (30%), and Helix GeoVentures (30%)—to support further engineering definition by prequalified tenderers. The document will be progressively refined as PROJECT ALPINE advances through its development phases. Updates are anticipated at key decision gates, including prior to Front-End Engineering Design (FEED) commencement, and following the incorporation of new data from drilling campaigns undertaken by TerraNova Drilling Co. and other service providers. 2 INTRODUCTION The hydrocarbon resource under consideration is situated within the Horizon South offshore exploration block, part of the greater Pelagia Basin along the northeastern maritime boundary of Valmora Island. Horizon South is currently under the operatorship of Stratos Energy Ltd. (40% participating interest), in partnership with Novara Petrochem (30%) and Helix GeoVentures (30%). The concession was secured under a revised production-sharing arrangement tailored to distribute investment risk among stakeholders, with contractual rights awarded in August 2019 and commercial terms becoming effective in January 2020. The first exploratory campaign in the block was executed through the drilling of the Aurora- 1 well, undertaken by TerraNova Drilling Co. The well was spudded on 21 May 2002 in granularity=word contentanalysis={punctuationbreaks=false dehyphenate=false} layoutanalysis={tabledetect=0 layoutdetect=0} water depths of approximately 2,436 feet, reaching a total measured depth of 13,441 feet (true vertical depth of 13,100 feet). Drilling operations concluded on 7 June 2002. Historical exploration in the vicinity had already indicated hydrocarbon potential, most notably through the Epsilon-4 well drilled in 2001 by former license holder BlueArc Resources. Both Aurora-1 and Epsilon-4 are positioned along the southwestern flank of the principal structural high, separated by a subsurface saddle feature that influences reservoir connectivity and development planning. 2.1 Field Development Strategy The preferred development concept foresees a subsea tie-back to existing offshore facilities, leveraging underutilized processing and export infrastructure approaching late- life production. This approach provides a cost-efficient route to commercialization while mitigating the environmental footprint of new installations. The planned connection point is strategically located in proximity to the Central Nexus Facility, thereby reducing the extent of modifications required and facilitating smooth integration into the established production network. 3 LOCAL ACTS, LAWS, RULES, AND REGULATIONS 3.1 Environmental Emission Limits Refer to [7]. Any project activities within PROJECT ALPINE that could potentially affect the surrounding environment—such as pre-commissioning or hydrotesting of subsea flowlines—shall undergo a detailed assessment in coordination with the project’s HSE (Health, Safety & Environment) team. This ensures that any relevant environmental thresholds, as established under Serandia’s legislative framework, are identified and adhered to prior to execution. 3.2 Regulatory Compliance Refer to [3] [Reference origin not found]. 3.3 Order of Precedence All applicable acts, laws, rules, and regulations for PROJECT ALPINE shall align with those enforced for offshore operations within Serandia. In cases where multiple regulatory frameworks overlap, the most stringent requirement will take precedence. The hierarchy of application shall be as follows (with 1 being the highest): granularity=word contentanalysis={punctuationbreaks=false dehyphenate=false} layoutanalysis={tabledetect=0 layoutdetect=0} 1. Serandian national laws, regulations, and any international conventions ratified by Serandia pertaining to offshore exploration and production. 2. Applicable classification society requirements, vessel flag regulations, marine international standards, and certification body rules for the specific equipment category. 3. Approved PROJECT ALPINE documentation (Appendix D). 4. PRIME ENERGY corporate engineering standards (latest revision to be applied to new equipment per [3] [Reference origin not found]). 5. Internationally recognized codes and standards relevant to the scope of work. 4 PROJECT DESCRIPTION 4.1 Development Scenario The Aurora-1 gas discovery well was drilled in 2,436 ft water depth by TerraNova Drilling Co. under contract with a prior project operator, reaching total depth on 7 June 2002 at a true vertical depth subsea (TVDSS) of 13,100 ft. Following a series of unsuccessful development proposals for Aurora-1 and nearby discoveries, the acreage was relinquished. In 2019, the Serandian Ministry of Energy reoffered the block during its offshore licensing round, where Stratos Energy Ltd. (Operator, 40%), Novara Petrochem (30%), and Helix GeoVentures (30%) secured exploration and exploitation rights under the revised production-sharing framework. The proposed development of Aurora-1 provides a synergistic opportunity to extend the operational lifespan of the Horizon South asset. Declining output from nearby producing fields offers capacity in the existing infrastructure, enabling the new project to deliver incremental reserves and economic benefits to both the Government of Serandia and the project stakeholders along the gas processing and export value chain—from the subsea wellhead to the onshore terminals. The selected concept is a subsea tie-back to the Central Nexus Facility, leveraging ullage in late-life infrastructure and proximity to existing manifold clusters. The base plan comprises two new production wells tied into Horizon South Trunkline 1 via a new subsea production flowline. Production from Cluster 1 will be redirected for processing through Cluster 3, optimizing field performance while minimizing additional topside modifications. granularity=word contentanalysis={punctuationbreaks=false dehyphenate=false} layoutanalysis={tabledetect=0 layoutdetect=0} 5 GENERAL LOCATION DATA 5.1 Climatology and Metocean Data Environmental parameters for the Pelagia Basin, including seawater temperature profiles, current regimes, and wave statistics, are provided in Ref. [25]. These datasets form the baseline for offshore design criteria in compliance with Serandian regulatory requirements. 5.1.1 Water Depths The Horizon South development area spans water depths between approximately 300 m and 1,200 m below mean sea level. 5.1.2 Offshore Facility Coordinates The primary floating production unit (FPU) within the Central Nexus Facility is located at the following reference coordinates: Item X [m] Y [m] Latitude Longitude FPU Centre 572421 9860512 1° 15’ 42.868” S 117° 39’ 03.499” E Table 1 – Central Nexus Facility FPU Coordinates 5.1.3 Onshore Processing Location The coordinates for the onshore receiving and processing facilities (ORF) associated with Horizon South are as follows: • Latitude: 9,899,144 N to 9,899,370 N • Longitude: 519,077 E to 519,329 E 5.1.4 Environmental Reference Data For detailed metocean parameters—including design return periods—refer to Ref. [25]: Doc No. Document Title Revision RP_A11111v1 – Main (Feb 2012) SPS Basis of Design — Table 2 – Metocean Reference Data Design return periods applicable to offshore oil and gas facilities are governed by national regulations or industry codes. For guidance specific to PRIME ENERGY projects, refer to Company Standard 28842.ENG.OFF.STD “Meteo-Oceanographic Design Basis”. granularity=word contentanalysis={punctuationbreaks=false dehyphenate=false} layoutanalysis={tabledetect=0 layoutdetect=0} 5.2 Geophysical and Geotechnical Data 5.2.1 Geotechnical No dedicated geotechnical investigation has yet been performed for the Aurora-1 development area. A comprehensive site survey is planned in upcoming project phases to characterize seabed soils at proposed subsea structure, flowline, and umbilical installation locations. 5.2.2 Geophysical Geophysical survey data are not currently available for the Aurora-1 project footprint. A future campaign will acquire high-resolution bathymetry and shallow sub-seabed profiles to support engineering and hazard assessments. This will include seabed morphology mapping, shallow stratigraphy, and identification of potential hazards to subsea infrastructure. 5.2.3 Bathymetry Data Current bathymetric information is limited to low-resolution (12.5 m × 12.5 m grid) data obtained from reprocessed 3D seismic datasets. The development area is characterized by complex seabed topography, including multiple submarine canyons (both primary and tributary), distinct fault lines, steep escarpments, irregular slopes, and isolated mounded features. Water depths range from approximately 300 m to 1,500 m. Figure 3 – Regional morphology of the Pelagia Basin development zone. granularity=word contentanalysis={punctuationbreaks=false dehyphenate=false} layoutanalysis={tabledetect=0 layoutdetect=0} Figure 4 – Detailed bathymorphic interpretation of the Aurora-1 sector from reprocessed 3D seismic volume. 5.2.4 Geohazard Assessment No dedicated geohazard studies have been carried out to date for the Aurora-1 development area. This assessment will form part of the upcoming geophysical and geotechnical survey scope. 5.2.5 Earthquake Data Seismic design criteria for subsea structures and associated foundations shall be in accordance with ISO 19901-2. 6 RESERVOIR MANAGEMENT BASIS 6.1 Main Reservoir Data The primary reservoir identified within the Aurora-1 structure of PROJECT ALPINE is classified as T-090 (equivalent to legacy interval 3130 from the former operator’s nomenclature). This unit was encountered at depths between –2,400 m and –2,600 m true vertical depth subsea (TVDSS). Secondary accumulations include T-088 / T-086 (equivalent to legacy 3140 and 3150) and T-084 Segment-1 (equivalent to legacy 3170). The field is a Pliocene-age turbidite system, deposited approximately 3.5 million years ago as toe-of-slope fans prograding across an anticlinal structure associated with the broader Pelagia Basin Hub anticline. Hydrocarbon granularity=word contentanalysis={punctuationbreaks=false dehyphenate=false} layoutanalysis={tabledetect=0 layoutdetect=0} trapping is predominantly stratigraphic, driven by the up-dip pinch-out of turbiditic sequences into a slope valley. The T-090 interval represents the principal gas-bearing horizon, accounting for roughly 74% of the estimated gas-in-place. Seismic amplitude and envelope attribute analyses illustrate a channel-fed fan geometry sourced from the northwest. Depositional lobes display compensational stacking with evidence of lateral amalgamation, which complicates architectural interpretation. No gas–water contact (GWC) was directly observed in well control; however, amplitude cut-off suggests a contact near –2,560 m subsea level. The T-088 / T-086 reservoirs were encountered approximately 30–40 m below the primary target, comprising two distinct sand bodies identified in the Aurora-1 and Epsilon-4 wells. MDT pressure testing confirmed a consistent gas–water gradient across both wells, with GWC observed at –2,556 m in Aurora-1, while Epsilon-4 proved water-bearing. These intervals are interpreted as more channelized deposits, with two primary fairways trending NW–S and NW–SE. Localized bottom-current reworking and crevasse splays are inferred in the southeastern portion of the block. The basal T-084 reservoir constitutes the lowest sand package of the Pliocene slope-valley system. Seismic RMS amplitude extractions indicate possible channelized features near Aurora-1 and depositional lobe development to the south of Epsilon-4. Gas saturation was confirmed in Aurora-1, with GWC measured at –2,626 m TVDSS by MDT, while Epsilon-4 did not penetrate this horizon. MDT data also indicate T-084 is moderately overpressured relative to overlying sands. Petrophysical evaluation from the 2020 Integrated Reservoir Study confirmed net pay and reservoir quality in both Aurora-1 and Epsilon-4 wells across T-090, T-088 / T-086, and T- 084 intervals. The results are summarized below. Well Reservoir Gross Interval (m TVD) Net Reservoir (m TVD) NTG Avg. Porosity (PHIE) Avg. Water Saturation (Sw) Avg. Permeability (mD) Aurora-1 T-090 23 21 0.90 0.25 0.42 76 Epsilon-4 54 43 0.80 0.26 0.45 129 Aurora-1 T-088/086 72 34 0.46 0.24 0.48 109 Epsilon-4 55 24 0.43 0.25 — 177 Aurora-1 T-084 21 20 0.94 0.30 0.16 288 Epsilon-4 Not — — — — — penetrated Table 6 – Average Reservoir Properties from Aurora-1 and Epsilon-4 Wells granularity=word contentanalysis={punctuationbreaks=false dehyphenate=false} layoutanalysis={tabledetect=0 layoutdetect=0} A 3D static model has been constructed, integrating seismic, well, and analogue data to better capture reservoir architecture and original gas-in-place estimates. Case Avg NTG [%] Avg Porosity [%] Avg Water Saturation [%] Reference Case 67 27 39 T-090 75 27 41 T-088/086 43 25 44 T-084 83 33 20 Table 7 – Average Reservoir Properties from Volumetric Modeling No PVT experiments have yet been conducted on recovered cores from PROJECT ALPINE. Fluid characterization was therefore derived from MDT sampling at T-090, with analysis performed at 2,487 m depth, 3,903 psia reservoir pressure, and 151 °F reservoir temperature. Results indicate a methane-rich gas (C1 content 98.3%), with a gas gravity of 0.58 and condensate–gas ratio (CGR) of 5.8 stb/MMscf. The dataset was calibrated through an equation-of-state model (PVTi), and the T-090 fluid properties are currently applied to secondary reservoirs for preliminary design. Properties Value Reservoir Pressure (bara) 270–272 Reservoir Temperature (°C) 73–74 Table 8 – Reservoir Fluid Conditions The Aurora-2 well, drilled in May 2021, further confirmed reservoir quality in the T-090 interval. Full core and PVT analysis remain pending at the time of this Basis of Design. 6.2 Reservoir Fluid Composition The molar composition of the produced fluid from Aurora-1 (T-090) is summarized below: Component %mol MW Specific Gravity Critical Temp. (°C) Critical Pressure (bara) Acentric Factor Boiling Temp. (°C) N₂ 0.040 28.01 — –147.0 33.9 0.0400 –195.8 89.8 CO₂ 0.919 44.01 — 31.1 73.8 0.2250 –78.5 94.0 C1 98.200 16.04 — –82.6 46.0 0.0080 –161.6 99.0 Critical Vol. (cm³/mol) C2 0.200 30.07 — 32.3 48.8 0.0980 –88.6 148.0 C3 0.090 44.10 — 96.7 42.5 0.1520 –42.5 203.0 i-C4 0.020 58.12 — 135.0 36.5 0.1760 –11.8 263.0 n-C4 0.020 58.12 — 152.1 38.0 0.1930 0.5 255.0 i-C5 0.010 72.15 — 187.3 33.8 0.2270 27.9 306.0 granularity=word contentanalysis={punctuationbreaks=false dehyphenate=false} layoutanalysis={tabledetect=0 layoutdetect=0} n-C5 0.010 72.15 — 196.5 33.7 0.2510 36.1 304.0 C6 0.011 86.18 0.664 234.3 29.7 0.2960 68.8 370.0 C7 0.097 96.00 0.702 260.7 28.7 0.3371 92.0 521.9 C8 0.079 107.00 0.730 282.3 26.8 0.3740 116.8 532.0 C9 0.065 121.00 0.754 306.9 24.6 0.4202 142.3 561.5 C10 0.052 134.00 0.776 328.2 23.5 0.4627 165.9 592.4 C11 0.041 147.00 0.795 348.0 21.8 0.5007 187.3 628.0 C12 0.031 161.00 0.813 368.1 20.6 0.5428 208.4 672.2 C13 0.023 175.00 0.829 387.1 19.7 0.5837 227.3 719.9 Table 9 – Reservoir Fluid Composition (Aurora-1 MDT Sample, T-090) 7.0 DRILLING & COMPLETIONS 7.1 Overview The field development concept foresees the drilling of two production wells, provisionally designated as Well A-3 and Well A-4. 7.2 Target Coordinates The following tables summarize the preliminary wellhead coordinates as defined under current geodetic references (UTM / WGS 1984). Well A-3 Parameter Value Water depth (m) 811 RKB elevation (m) 25 Seabed from RKB (m) 836 Wellhead Coordinates – Offshore Development Area A-3 (Case B) • Northing: 9,852,056 m • Easting: 583,427 m • Latitude: 1° 20' 18.163" S • Longitude: 117° 44' 59.719" E • Datum: WGS 1984, UTM Zone 50S Well A-4 Parameter Value granularity=word contentanalysis={punctuationbreaks=false dehyphenate=false} layoutanalysis={tabledetect=0 layoutdetect=0} Water depth (m) 1103 RKB elevation (m) 29 Seabed from RKB (m) 1128 Wellhead Coordinates – Offshore Development Area A-4 • Northing: 9,851,286 m • Easting: 585,820 m • Latitude: 1° 20' 43.223" S • Longitude: 117° 46' 17.159" E • Datum: WGS 1984, UTM Zone 50S 7.3 Preliminary Casing Design As no dedicated pore pressure study has yet been finalized, the casing program is based on analogues from previous deepwater projects in the same basin. The proposed casing/liner string dimensions and metallurgy are aligned with industry practice and prior successful campaigns. Proposed Casing Setting Depths – Well A-3 • 36” Conductor – depth 906 m MD • 20” Surface Casing – depth 1486 m MD • 13-5/8” Intermediate – depth 2100 m MD • 10-3/4” Liner – TOL 2051 m MD, length 1127 m, overlap 120 m Proposed Casing Setting Depths – Well A-4 • 36” Conductor – depth 1198 m MD • 20” Surface Casing – depth 1728 m MD • 13-5/8” Intermediate – depth 2250 m MD • 10-3/4” Liner – TOL 2152 m MD, length 1150 m, overlap 120 m • 7” Contingency Liner (if required) – TOL 3182 m MD, length 1023 m, overlap 120 m Corrosion Considerations Formation fluid sampling indicates the presence of significant CO₂ partial pressure, requiring corrosion-resistant alloys for flow-wetted tubulars. The recommended material is granularity=word contentanalysis={punctuationbreaks=false dehyphenate=false} layoutanalysis={tabledetect=0 layoutdetect=0} 13Cr (or Super 13Cr) stainless steel for production liner and tubing. For casing above the packer, carbon or low-alloy steel qualified for sour service in accordance with API 5CT is considered suitable. 7.4 Completion Schematics The well-completed strategy has been developed in line with international standards and internal well design procedures, incorporating the following principles: • Compliance with HSE regulations • Delivery of forecasted production rates • Capability for gas and water injection as needed • Operational safety and equipment reliability • Well longevity over full life cycle • Optimization of rig time and cost efficiency • Use of standardized, field-proven technology • Resilience against worst-case operating conditions Completion Concepts Under Evaluation 1. Well A-3: Dual-zone completion within 10-3/4” liner, using Controlled Hydraulic Flow Profile (CHFP) and smart upper completion. 2. Well A-4: Single-zone CHFP inside 10-3/4” liner, with provision for future dual-zone configuration if required. Smart completion capability will be retained for operational flexibility. The strategy emphasizes larger completion sizes to maximize gas deliverability compared with conventional 9-5/8” liner systems. Alternative designs may be considered in later project phases. 7.5 Preliminary Metallurgy & Elastomer Selection A dedicated completion material and elastomer compatibility study has not yet been undertaken. Based on analogues from prior basin developments, 13Cr (or enhanced grades thereof) is anticipated to be the baseline metallurgy for cost and corrosion considerations. This selection will be revisited during subsequent project phases once reservoir fluid characterization is further refined. granularity=word contentanalysis={punctuationbreaks=false dehyphenate=false} layoutanalysis={tabledetect=0 layoutdetect=0} 8.0 FLUID DATA AND PRODUCTION CHEMISTRY 8.1 Reservoir Fluid Properties Given the combination of high pressure and relatively low temperature expected during both steady-state and transient operations, the reservoir fluids are predicted to be susceptible to hydrate formation. Hydrate risks will be mitigated under all scenarios through continuous injection of lean MEG solution (80% wt). A supplementary injection of methanol will be applied during start- up and restart operations to counteract low-temperature excursions and hydrate risks. No issues are anticipated with asphaltenes, foaming, or emulsion stability. However, scale formation potential is assumed to be present, consistent with analogue reservoirs in the basin. 8.2 Reservoir Fluid Composition Reservoir fluid composition is referenced in Section 7.2. 8.3 Scale Potential Scaling tendencies are considered comparable to neighbouring developments within the basin. Preventive strategies will be aligned with established operating practices for carbonate-rich produced water systems. 8.4 Wax Formation and Rheology No wax deposition, foaming, or emulsion challenges are expected under reservoir or production conditions (see Section 9.1). 8.5 Hydrate Equilibrium Curves Hydrate equilibrium curves were generated for reservoir fluid composition (Section 7.2), saturated at reservoir conditions of 30 bar and 74°C. Figure 5: Hydrate formation curves (to be inserted). 8.6 Hydrogen Sulphide The reservoir fluid is expected to be free of H₂S. 8.7 Asphaltenes No asphaltenes are expected in the produced hydrocarbons. 8.8 Material Selection granularity=word contentanalysis={punctuationbreaks=false dehyphenate=false} layoutanalysis={tabledetect=0 layoutdetect=0} 8.8.1 CO₂ Corrosion Produced fluids exhibit CO₂ partial pressure sufficient to cause sweet corrosion in the absence of H₂S. Dissolution of CO₂ into condensed water is expected, with concentrations proportional to partial pressure and temperature. The material and corrosion-control philosophy emphasizes maintaining integrity across the design life while minimizing cost and fabrication delays. Mitigation methods include: • Corrosion-resistant alloys and/or corrosion allowance • Protective coatings • Chemical inhibition programs • Cathodic protection systems • Continuous monitoring and inspection Design corrosion allowances: • Process equipment and piping: 3–6 mm • Pipelines: up to 8–10 mm, depending on service Uninhibited corrosion rate: estimated 0.9 mm/yr → ~8.8 mm wall loss over 20 years With inhibition: reduced to 0.1 mm/yr (based on analogous fluid classification studies) Formation Water Case • Max corrosion rate: 2.0 mm/yr • Inhibited rate: 0.2 mm/yr • Corrosion allowance (15 years, 95% CI inhibitor availability): 4.35 mm Condensed Water Case • Max corrosion rate: 2.8 mm/yr • Inhibited rate: 0.2 mm/yr • Corrosion allowance (15 years, 95% CI inhibitor availability): 4.95 mm Flowline material basis: Carbon steel + 5 mm corrosion allowance, assuming >95% inhibitor availability. 8.9 Flow Assurance Flow assurance considerations are detailed in Section 9.1. granularity=word contentanalysis={punctuationbreaks=false dehyphenate=false} layoutanalysis={tabledetect=0 layoutdetect=0} 8.10 Flowing and Shut-In Conditions 8.10.1 Flowing Wellhead Pressure The forecasted flowing wellhead pressures (FWHP) for the development wells are presented in Table 12. Date Project-4 (barg) Project-3 (barg) Sep-26 206 196 May-27 152 134 Jun-28 125 110 Dec-29 97 85 Jun-30 90 80 Jun-31 78 66 Jun-32 68 57 Jun-33 61 51 Jun-34 56 46 Jun-35 47 48 Dec-36 38 40 Jan-37 – 46 Table 12 – Unconstrained Case, Flowing Wellhead Pressure (FWHP) 8.10.2 Flowing Wellhead Temperature Forecasted flowing wellhead temperatures upstream and downstream of the pressure control valves are summarized in Tables 13 and 14. 8.10.3 Topside Arrival Conditions For the base case, wells are produced in hybrid HP/LP mode, with arrival fluid temperatures expected between -2°C and +10°C depending on flowrate. 8.10.3.1 Operating Cases Base Case: two new development wells are tied back via a 12” subsea production line into the existing trunkline system, routed through an intermediate cluster before reaching the central production hub. 8.10.3.2 Inlet Flowrate at Host Facility Representative production cases for host facility inlet conditions are summarized in Table 15. These cases are used to confirm processing and slug catcher capacity. 8.10.3.3 Target LP Max Flowrate • 616 MMSCFD max flow in LP mode (per production profile) granularity=word contentanalysis={punctuationbreaks=false dehyphenate=false} layoutanalysis={tabledetect=0 layoutdetect=0} • With minor modifications, 600 MMSCFD is achievable • With debottlenecking, 720 MMSCFD can be managed in LP mode (up to ~8,400 m³/h seawater consumption) 8.11 Product Specifications 8.11.1 Produced Hydrocarbons Produced gas and condensate will be processed at the host facility. Applicable sales specifications are: Property Specification HC Dew Point ≤ 12°C at any pressure between 52 barg and max export pressure Water Dew Point ≤ 9°C at max export pressure Water content ≤ 9 lb/MMSCF (Table 17: Produced Gas/Condensate Specifications) 8.11.2 Produced Water Produced water will be treated onboard the host facility. Key discharge specifications: • Max HC content: 15 ppmv (30-day avg), 42 ppmv (daily peak) • Max MEG content: 3,500 ppmv • Max discharge temperature: 40°C Discharge streams will be continuously monitored per applicable national and environmental regulations. 8.11.3 H₂S Content Reservoir fluids are expected to be free of H₂S. 8.11.4 CO₂ Content Reservoir CO₂ content is ~0.92 mol%. 8.12 Field Flowrates for Design Basis Table 19 summarizes the design case flowrates used for facility capacity verification. Fluid Inlet Gas [MMSCFD] Condensate [Sbbl/d] Water [Sbbl/d] HP Mode 223.6 1303.5 0.68 (Table 19 – Development Design Cases) granularity=word contentanalysis={punctuationbreaks=false dehyphenate=false} layoutanalysis={tabledetect=0 layoutdetect=0} 9.0 FACILITIES 9.1 Subsea, Umbilical and Flowlines The following section provides an overview of the subsea architecture for PROJECT ALPINE, covering subsea production hardware, umbilicals, subsea control systems, and flexible flowline arrangements. 9.1.1 Floating Production Unit (FPU) For the overall process description of the Floating Production Unit, refer to [22]. 9.1.2 Design Life The subsea production and control system shall be designed for a service life of 20 years. 9.1.3 Maximum Water Depth All subsea equipment shall be rated for an installation water depth of 1,200 m. 9.1.4 Main Subsea Equipment A preliminary list of key subsea components and associated design parameters is provided below. Table 20 – Preliminary List of Main Subsea Equipment Item Quantity Design Pressure Design Temperature Production Xmas 2 10,000 psi Upstream choke: Tree -18 / +121 °C Downstream: -48 HIPPS System 1 (i) 270 bar header from HBV1 to inboard connector; header from TIV1 to inboard connector, incl. hot stab lines (ii) 421 bar for remaining header sections, valves and chem. injection lines ALPINE Manifold Structure Subsea Hub Structure 1 270 bar for header; 650 bar for branch up to branch valve (valve included) 1 520 bar across structure except header connectors (270 bar) / +121 °C -20 / +70 °C -20 / +70 °C -29 / +70 °C granularity=word contentanalysis={punctuationbreaks=false dehyphenate=false} layoutanalysis={tabledetect=0 layoutdetect=0} Umbilical Termination Assembly (UTA) Flowline End Termination (FLET) Notes: 4 (2 per — — umbilical system) 1 TBD TBD 1. Xmas Tree conditions in line with ALPINE field specification. 2. MEG pump design pressure: 340 barg (PSV set point). Including hydrostatic head at 1,200 m = ~470 barg. See [32] for pressure definition under MEG packing conditions. 3. Subsea structure pressure defined by wellhead shut-in pressure (WHSP) × 1.1 = ~270 bar. 4. Design temperature includes operating maximum (55 °C) plus contingency margin (+15 °C). 5. A new FLET is anticipated for connecting ALPINE Cluster 1 with Cluster 3 through a new interconnecting line. 9.1.5 Umbilicals A dedicated electro-hydraulic umbilical system will be deployed to provide hydraulic power, chemicals, electrical supply, and control signals to the subsea production equipment [12]. Umbilical Deployment Scenario (Cluster 1): • The existing Cluster 1 Main Umbilical (UMB1) will be extended to support ALPINE subsea facilities. • UMB1: Flying leads will connect UTA-A to the Cluster 1 SDU and to the HIPPS. UTA-B will connect to Well ALPINE-3B and to UMB2 UTA-A. • UMB2: Configured in daisy-chain from UMB1. UTA-B will connect to Well ALPINE-4 via flying leads. Block diagrams and detailed layouts are provided in [2] and [31]. Where practical, existing spare umbilicals from previous developments will be utilized to optimize design and reduce customization. For ALPINE UMB2, the spare infield UM1C from the LOCATION asset will be repurposed. granularity=word contentanalysis={punctuationbreaks=false dehyphenate=false} layoutanalysis={tabledetect=0 layoutdetect=0} 9.1.6 Control System Each Xmas Tree and HIPPS unit will be operated by a dedicated Subsea Control Module (SCM). Flying leads will distribute power and control between UTAs and host subsea structures. • The subsea control system shall be fully compatible with the existing ALPINE host system. • Design shall comply with COMPANY standard ENG.STA.STD.18010, with HIPPS designed to standard ENG.STA.STD.28746. • Communications will be via COPS (Communications on Power). • Hydraulic system design: closed-loop with return to the host facility. Topside integration will be through the existing ALPINE control system. Hardware modifications (one channel at a time) may be performed without shutting down Cluster 1. Software updates, however, could require temporary production shutdown. See [30] and [31] for integration details. 9.1.7 Flowline System Flexible pipelines have been selected for the ALPINE development. The table below summarizes preliminary design inputs for the flexible pipeline system and associated routing analysis. Table 21 – Flexible Pipeline Design Inputs Parameter Value Standard 23020.ENG.SSE.STD International Codes API 17B / API 17J Flowline 1 & 2 ID 12” (304.8 mm) Flowline 3 ID 11.5” (292 mm)* Flexible Jumper ID** 12” (304.8 mm) Well Jumper ID 8” Interconnecting Flowline ID 8” Design Temperature 70 °C Design Pressure Flowline 1 & 2 270 bar Design Pressure Flowline 3* 520 bar Design Pressure Interconnecting Line 205 bar Design Pressure Flexible Jumper** 205 bar Water Depth 1,200 m * Flowline 3 will reuse spare 11.5” flexible pipe from prior project inventory. ** Jumper required to connect the existing Cluster 1 manifold to the new FLET. granularity=word contentanalysis={punctuationbreaks=false dehyphenate=false} layoutanalysis={tabledetect=0 layoutdetect=0} Flexible Well Jumpers: • Design Pressure: 520 bar • Design Temperature: 70 °C • Length / Quantity: ~90 m / 2 units Flexible solutions were confirmed during concept selection for suitability under mechanical, operational, and environmental conditions at 1,200 m water depth. Rigid alternatives were evaluated but flexible lines were selected due to advantages in cost, schedule, and install ability. 10.0 HEALTH, SAFETY, AND ENVIRONMENT (HSE) The Project shall be developed in alignment with applicable national regulations and corporate HSE requirements, taking into account international standards such as: • ISO 14001 (Environmental Management Systems) • ISO 45001 (Occupational Health and Safety Management Systems) • OHSAS 18001 (Occupational Health and Safety) Corporate HSE policies and internal standards are used as the basis for defining the project HSE requirements. Preliminary HSE Philosophy has been prepared for the Concept Definition Phase, with the aim of ensuring an inherently safe design that: • Minimises the likelihood of hazardous events. • Reduces the potential consequences of accidental events. • Ensures a safe working environment for all personnel. • Provides adequate escape and rescue provisions in emergencies. • Includes sufficient protective systems and redundancy to detect, isolate, and control accidental releases of flammable or toxic substances. • Ensures effective fire detection, control, and extinguishing systems. • Minimises potential environmental pollution. HSE development will be supported by a formal risk-based assessment process (e.g. HAZID, HAZOP, ESHIA, and other safety studies). The goal is to identify hazards, evaluate risks, and implement effective mitigation and control measures. granularity=word contentanalysis={punctuationbreaks=false dehyphenate=false} layoutanalysis={tabledetect=0 layoutdetect=0} 10.1 Safety Criteria The objectives of the Safety Criteria are to: • Minimise the likelihood and consequences of accidental events. • Reduce the potential for hazardous occurrences. • Maximise the effectiveness of protective measures. • Provide redundancy and safety devices to contain uncontrolled releases. • Implement fire protection systems capable of controlling foreseeable fire scenarios. • Ensure safe escape and rescue from all areas. • Limit environmental pollution from accidental releases (spills, flaring, venting). • Reduce construction-phase risks, including work in brownfield areas. The overall design approach shall aim to eliminate intolerable risks and reduce tolerable risks to a level that is demonstrably ALARP (As Low As Reasonably Practicable), through: • Sound decision-making based on safety considerations. • Containment of hydrocarbons and prevention of ignition. • Reduction of ignition likelihood. • Fire and gas detection and prevention of escalation. • Ensuring personnel protection and evacuation provisions. 10.2 Health Considerations The Project shall comply with all health and regulatory requirements, ensuring that the health of employees and contractors is protected during design, construction, commissioning, and operations. The health risk-based approach will include: • Identification and evaluation of occupational and community health risks (e.g., exposure, infectious disease, accommodations, water, food, vector-borne illness, medical support). • Implementation of risk mitigation measures. • Communication of health risk information. • Medical fitness-for-duty programs. granularity=word contentanalysis={punctuationbreaks=false dehyphenate=false} layoutanalysis={tabledetect=0 layoutdetect=0} • Health assessments for potentially exposed workers. • Regular inspections and monitoring, including industrial hygiene programs. Additional health-related design considerations include: 1. Facility noise level design criteria. 2. Medevac arrangements. 3. Emergency shower and eyewash stations. 4. Safe design for hazardous material storage and handling. 10.3 SIMOPS (Simultaneous Operations) SIMOPS refers to conducting multiple activities concurrently (e.g., hydrocarbon production alongside drilling, construction, commissioning, or maintenance). While SIMOPS allow production continuity and reduce downtime, they introduce additional operational complexity and risk, including: • Higher probability of hazards due to concurrent activities. • Increased ignition risks from hot work (e.g., welding, cutting) in areas near hydrocarbon systems. Effective planning and control are required to manage SIMOPS risks while maintaining production. 10.4 Risk Identification During the current Project Phase, the following structured studies will be performed: • HAZID (Hazard Identification): Systematic early-stage review of potential external threats with the potential to create health, safety, environmental, asset, or reputational risks. • HAZOP (Hazard and Operability): Detailed review of design and operations for new or modified process/utility systems, ensuring compliance with safety and operational standards. The purpose of these assessments is to identify risks early and define mitigation actions. granularity=word contentanalysis={punctuationbreaks=false dehyphenate=false} layoutanalysis={tabledetect=0 layoutdetect=0} Table 21: Example of Qualitative Risk Matrix Consequence \ Likelihood Rare Unlikely Possible Likely Almost Certain Insignificant Low Low Low Medium Medium Minor Low Low Medium Medium High Moderate Low Medium Medium High High Major Medium Medium High High Extreme Catastrophic Medium High High Extreme Extreme Note: This qualitative risk ranking is subject to project-specific calibration. All recommendations raised during the studies shall be tracked, assigned, and closed prior to completion of the Project Phase. 10.5 Environmental, Social and Health Impact Assessment (ESHIA) An ESHIA has been developed during the FEED phase. The results of the study will be provided to the Contractor for incorporation into detailed design. 11.0 Greenhouse Gas (GHG) Emissions and Climate Change Mitigation The Project is committed to reducing greenhouse gas (GHG) emissions throughout all phases of development and operation. Emission reduction will be achieved through the adoption of appropriate technologies, optimization of energy consumption, and application of best industry practices across the asset lifecycle. General Requirements Requirement Description Flaring Routine flaring is not permitted at any stage. Non-routine flaring shall be strictly minimized. Venting Continuous venting of CO₂ or methane is not allowed under normal operating conditions. Gas Metering Metering systems shall be installed for all gas streams. Stationary Combustion 11.1 Water Management Emissions from stationary sources shall be minimized by prioritizing: (i) low energy intensity processes, (ii) high-efficiency fuel-gas-based power generation, or (iii) connection to local grid, where feasible. Water management is a core element of environmental protection. The following design and operational requirements apply: granularity=word contentanalysis={punctuationbreaks=false dehyphenate=false} layoutanalysis={tabledetect=0 layoutdetect=0} Requirement Description Water Use Water use shall be minimized; re-use is preferred over recycling; Reduction recycling is preferred over discharge. Flow Flow meters shall be installed on all intake and discharge streams. Measurement Water Discharge Any water contaminated with hydrocarbons, chemicals, or other pollutants must be routed to treatment facilities before final disposal. 12.0 Regularity and Operations The Project’s operational strategy aims to ensure continuous and reliable production while prioritizing safety, cost efficiency, and environmental protection. Key objectives include: • Uninterrupted production operations. • Safe and ergonomic facility design. • Optimization of operational lifecycle costs. • Protection of asset integrity. • Reduction of accident risks and worker exposure. Compliance will be ensured through management systems aligned with international standards, industry best practices, and applicable national regulations. Asset lifecycle processes will be governed under the Development Management System (DMS) and the Operations Management System (OMS). Operational Staffing Facility Manning Strategy Floating Permanently manned with rotating shifts. Accommodation Production Unit facilities shall include living quarters, recreational areas, first aid, (FPU) and helideck. Onshore Facilities Designed for unattended or periodically manned operations. Staffing Principles • Leverage support infrastructure to optimize staffing levels. • Ensure high levels of competence across operational teams. • Adopt empowerment approaches for efficient work execution. granularity=word contentanalysis={punctuationbreaks=false dehyphenate=false} layoutanalysis={tabledetect=0 layoutdetect=0} • Implement continuous competence development and assurance. • Utilize contracting plans to supplement workforce with specialized expertise. • Align workforce planning with local content requirements. 13.0 SIMOPS and CONOPS Requirements This section outlines requirements for Simultaneous Operations (SIMOPS) and Concurrent Operations (CONOPS) in relation to new project developments near existing or operating facilities. SIMOPS During installation and commissioning, the following activities may be conducted concurrently, introducing additional complexity and risk: SIMOPS Activity Potential Concurrent Operations Drilling & Well Completion Installation or commissioning of new facilities Ongoing Production Operation of nearby production units handed over earlier Risk assessments shall be carried out to evaluate interactions between simultaneous activities and define mitigation measures. CONOPS For the Floating Production Unit (FPU), it is assumed that certain activities under the Engineering, Procurement, Construction, and Installation (EPCI) scope may occur concurrently with production operations. Further studies will determine: • Criticality of simultaneous execution. • Benefits and risks of maintaining concurrent operations. • Alternative strategies if concurrent execution is deemed unsuitable. 0.00