Petroleum Systems Analysis of the Guyana–Suriname Basin with the GLIAG methodology

Abstract

This paper formalises the GLIAG method as applied in the author’s Guyana–Suriname Basin essays and amends Revision 1.0 (Dutch, 30 October 2026). The method combines bottom-up geological reconstruction with top-down testing against published rock and fluid observations, while keeping provenance, spatial scale and uncertainty attached to every number. It does not claim to have invented petroleum-system analysis, fluid geochemistry or basin modelling, which rest on the work of Magoon and Dow (1994), Peters et al. (2005), Hantschel and Kauerauf (2009) and Pepper and Corvi (1995). The original contribution is basin-specific: a cross-border evidence base, a set of transfer rules between evidence classes, and a ledger that forces model volumes to declare what they measure.

Three applications are re-examined. The Aptian–Albian synthesis separates an older, spatially heterogeneous Aptian–Lower Albian source family from a younger regional marine system (ACT). The legacy Galibi Offshore-1 (GLO-1) well in Block 15, drilled by Elf in 1971 to 4,663 m with oil and gas shows, is read as a test of which link in the chain failed rather than as a regional negative. The mass-transport hypothesis separates an immediate pore-pressure response from a delayed thermal response; first-order consolidation and conduction solutions show the two clocks differ by two to five orders of magnitude in time.

The volume ledger is then audited. The SE Golden Lane cascade (1,455 → 949 → 171.7 → 73.3 billion boe on 22,000 km²) applies zone-average Ultimate Expellable Potentials of 10–115 MMboe/km², against GIP full-conversion potentials of 22–56 MMboe/km² and a realised median of 5.6 MMboe/km² in the active kitchen. Replacing full-conversion potential with that realised median, at unchanged efficiencies, gives about 6.2 billion boe, a figure of the same order as the USGS 2025 province mean. A further inconsistency is recorded in the cited model grid (4,498 five-arc-minute cells would cover about 383,000 km², three times the Suriname offshore domain). A KBD-3 wellhead coordinate from the Block 58 environmental record (7.224882° N, 55.854204° W) shows why surveyed wellheads must be kept apart from field centres and model release points. A fifteen-item amendment register and a limitations table define what the next data must decide.

Keywords: Guyana–Suriname Basin; Suriname; Guyana; petroleum system; Golden Lane; Block 58; Block 15; GranMorgu; Ultimate Expellable Potential; charge; mass-transport complex; overpressure; fluid geochemistry; basin modelling; uncertainty; GIP; GLIAG.

Reader guide to key terms

The definitions below describe how terms are used in this paper; specialised usage can vary between disciplines and organisations.

Research questions and contribution

Original contribution and evidential threshold

The author’s contribution is the cross-border combination of data, the geological hypotheses, the testing criteria and their consequences for exploration decisions. The underlying measurements and original publications keep their own authorship. This edition uses no new laboratory data and no unpublished operator seismic. It uses the author’s own dated essays, two GIP model generations as published, official well and licence registers from both national authorities, the Block 58 environmental record and a targeted external literature set.

The threshold for a statement in this paper is that the reader can trace it to a public document, a register record or a transparent calculation given here. Where that is not possible, the statement is labelled GLIAG judgement or marked [VERIFY].

Priority record

The method described here is documented in public, dated form. The list below records when each element first appeared in the author’s work; it makes no claim about the work of others.

1. From basin narrative to testable petroleum-systems analysis

The Guyana–Suriname Basin needs an analysis in which geological history and the hydrocarbons actually found constrain each other. A regional source-rock map does not explain why one closure holds oil, another gas and a third nothing. One oil occurrence does not define the geometry, age and productivity of its kitchen. The GLIAG method uses both directions of reasoning together and treats contradictions as research questions.

The method has a dated public record. The SE Golden Lane charge-fairway essay (13 July 2026) set out a quantified kitchen-to-trap cascade. The Aptian–Albian synthesis (27 August 2026) separated evidence classes for the Lower Cretaceous. The facies essay (4 September 2026) introduced UEP as the currency of source potential. The Block 15 essay (2 September 2026) tested a dry legacy well against its own rocks. Three molecule essays (10–12 September 2026) linked fluids to refinery questions. The Charge Architecture paper (5 October 2026), the GIP SE Golden Lane essay (14 October 2026) and two mass-transport essays (16 and 19 October 2026) carried the approach into model outputs and event stratigraphy (Chin-A-Lien, 2026a–k). The method is described here as applied in that work, not as a future proposal.

The central research question is which interpretations survive when they must fit stratigraphy, burial, maturity, fluid composition, well outcomes and event order at the same time. A second question is which new measurement has the best chance of discriminating between competing explanations. The emphasis moves from a convincing story to a repeatable process of predicting, comparing and revising.

One basin, two registers

Most public petroleum-systems work on this margin stops at a national line: Stabroek studies use Guyanese wells, Suriname block studies use Staatsolie wells, and the two rarely share a map. The USGS treats the Guyana–Suriname Basin as one assessment province (Schenk et al., 2026), and the source rocks, carriers and fluid families do not change at the maritime boundary. GLIAG’s view is that a petroleum system must be analysed at the scale of its kitchen, and the SE Golden Lane kitchen straddles that line: the Block 58 well cluster in Suriname continues the Stabroek trend in Guyana within tens of kilometres (Figure 1).

The GIP register makes this possible. It holds 109 wells and 47 licence polygons from the Guyana Ministry of Natural Resources and 50 wells and 25 blocks from the Staatsolie GeoPortal, all as official decimal wellheads in EPSG:4326, with field centres, block aggregates and operations polygons stored as separate geometry types (GIP register, retrieved 5 August 2026). On that common base a Suriname well can be tested against a Guyanese analogue without re-projecting, re-naming or guessing.

One evidence system, not a pile of sources

What sets GIP apart is how the material is joined up, not how much of it there is. Register data, model outputs, Basin Watch news intake, newsletters and essays are held in one platform and checked against one another. A news item is matched to the well, block and operator it concerns. An essay figure is traced to the register record or model version it comes from. A model output carries its source and an evidence status, so a reader can see at once whether it is a FACT, a MODEL result or still MISSING. When one strand changes, the others are re-checked. This paper is a product of that loop: the volume audit in Section 7 was possible because the cascade essay, the Charge Architecture paper and the GIP model run sit in the same system and could be compared line by line.

GLIAG’s judgement is that this integration, across both national registers and across data, models and published commentary, is what makes GIP unusual among basin information products for this margin. National portals publish one side of the line. Commercial databases and news services each hold one strand. Essays and newsletters are usually written apart from the data they cite. This comparison is the author’s assessment of public offerings, not a formal benchmark.

2. The GLIAG method as applied

The method starts with a concrete hypothesis at a defined scale. For a regional model, that may be the distribution of mature source intervals; for a prospect, whether mobile oil could reach a trap during the effective charge window. A claim is first tied to an area, an interval, a time window and an evidence class. Without that frame, a correct regional statement can be misused as local certainty.

Two reconstructions are then built. The forward reconstruction describes how deposition, tectonics, erosion, loading, temperature and reaction rates could bring a source rock to generation and expulsion. The backward reading records what wells, rocks and fluids actually show. Where information comes from publications, its original status as measurement or interpretation stays visible. A biomarker publication does not replace a sample analysis, but it can carry an explicit regional correlation.

Comparison targets consequences named in advance. An assumed oil migration path must fit fluid families and relative maturity, and also carrier beds, structural timing and preservation. A scenario that only works by treating every fault as an open conduit is under-constrained. A fitting model is not independent proof when the same oil data were first used for calibration and then again for confirmation.

The outcome is a bounded conclusion with a next test. On convergence, the paper records which alternatives became less likely and which uncertainty remains. On a mismatch, source, scale, timing and model assumptions are examined separately before a geological explanation is changed. Each revision is linked to the observation that required it, so that a reader can see whether understanding changed because of new data, a different model or the correction of an earlier assumption. Section 7 applies that rule to the author’s own volumes.

3. Evidence architecture and the limits of transfer

A petroleum system is not a pile of interchangeable positive signals. Source presence differs from maturity; generation differs from expulsion; a migration indication differs from prospect fill. The GLIAG method keeps these distinctions at each step from source to conclusion, and a number does not become an observation because it has been loaded into GIP.

The Aptian–Albian essay separates direct rock evidence, strong regional correlation, boundary conditions and unconfirmed interpretation. The Block 15 essay separates observed, correlated, modelled, derived and unknown data (Chin-A-Lien, 2026a, b). Figure 3 harmonises those schemes; it does not change the status of the original data.

Spatial scale matters as much as evidence type. A basin-scale oil correlation does not make every well part of one charge pulse. A geochemical similarity can allow several routes or mixing ratios. A source interval present on one platform high can be thin, absent or immature elsewhere. The question is always which transfer is justified, and which additional data would narrow it.

Dependence between sources must also be recorded. An operator release, a newspaper article that repeats it and a GLIAG essay that cites both form one original line of data, not three independent confirmations. The same applies to a model output repeated in successive essays. This rule prevents growth of the publication archive from being mistaken for growth of independent geological control, and it is the reason Section 7 treats the 1,455, 1,307 and 190 billion boe figures as three claims to be reconciled rather than three supports for a large number.

4. The Aptian and Albian systems as a first application

In The Aptian–Albian Record of the Guyana–Suriname Basin, the Lower Cretaceous section is not treated as one reservoir or one uniform petroleum system. The stratigraphic reconstruction separates synrift and transform relief, local platform growth, erosion and drowning, followed by younger marine deposition and later burial. The associated source intervals can differ in facies, organic input and thermal history (Chin-A-Lien, 2026a).

That bottom-up reconstruction is bounded by the rock and fluid data assembled in the essay. North Coronie-1 (NCO-1, 1975, TD 5,406 m, register outcome “Oil & Gas Show”) acts in that synthesis as a control on source presence, maturity and hydrocarbon indications. Other wells constrain carbonates, sandstones and older intervals. The published source penetrations and regional fluid correlations support taking an Aptian contribution seriously. They do not justify spreading one source label over the whole basin.

The result is a working model with two partly coupled families: an older Aptian–Lower Albian family in spatially heterogeneous domains, and a younger regional marine system described in the author’s work as ACT. ACT is a practical Albian–Cenomanian–Turonian grouping; parts of the synthesis extend the younger source architecture to the Coniacian. These labels must be fixed per source and stratigraphic scheme. They are not proof that all components form one geochemical family.

The top-down test has a clear task here. If oils and gases from different domains do carry different source contributions, biomarkers, isotopes, maturity indicators and mixing ratios must be compatible with that. If the differences can arise from maturity, phase behaviour, biodegradation or fractionation alone, an extra source family is not needed. The number of families cannot be read from a colour change on a model map.

The method blocks two common leaps. An Aptian or Albian penetration is not proof of a productive carbonate reservoir, and an oil-bearing younger sandstone does not prove the source lies directly beneath the well. The Ranger analogue discussed in the essay bounds the possibility of an older carbonate play; it does not prove a regional commercial Albian reef play.

5. Block 15 and the information value of a non-commercial well

The Block 15 essay, Before the Bit Turns, starts from a geological tension. The legacy well Galibi Offshore-1 (GLO-1) was drilled by Elf in 1971 to 4,663 m and was not commercial, while the GeoAtlas information used in the essay describes good Aptian and Albian sandstones and Aptian bitumen (Chin-A-Lien, 2026b; Staatsolie register). The interpretive question is which link in the petroleum-system chain failed to deliver a commercial accumulation, not whether the area is simply positive or negative.

The question is current. Block 15 covers 2,544 km² in 75–150 m of water; its production-sharing contract was signed on 13 September 2024 with PetroChina as operator (70%) and Staatsolie’s subsidiary Paradise Oil (30%) (Staatsolie, 2024). PetroChina expects to begin shallow-water drilling in 2027 (Reuters, 24 June 2026).

Bottom-up, source facies, burial, maturity, carriers, trap geometry and timing are examined. Top-down, reasoning runs back from the rocks, bitumen and well outcome. Bitumen supports that petroleum processes operated, but without more geochemistry it does not fix source, migration direction or timing. Residual petroleum can reflect migration, earlier fill, leakage or alteration.

The proximity of Block 52 is a regional boundary condition, not prospect-specific certainty. Block 52 holds the Sloanea-1 (2020), Roystonea-1 (2023) and Fusaea-1 (2024) discoveries, together about 500 MMboe recoverable (Rystad Energy). A working system in a neighbouring block supports the presence of petroleum-system elements in the wider province. It does not prove that a Block 15 structure shares the same source, pressure history, fluid phase or migration connection. The method turns proximity into a question of transferability.

A well-documented non-commercial well can constrain a play strongly; a poorly evaluated one leaves several causes open. The statement in the Block 15 analysis that the evaluation must be able to explain failure gains a methodological meaning: uncertainty reduction becomes an explicit result alongside any discovery.

6. Mass transport and the difference between pressure and heat

When the Margin Fell introduced the GLIAG hypothesis that rapid emplacement of mass-transport deposits can cause an immediate mechanical disturbance and a later thermal response. The 19 October essay set that hypothesis in a wider frame of sediment routing, burial, migration and preservation (Chin-A-Lien, 2026c, d). The contribution is the explicit link between event order and separately testable mechanisms.

A young mass-transport deposit cannot have supplied sand to a much older Cretaceous reservoir. It can influence the later loading, pressure state, temperature, fault activity or preservation of that reservoir and its kitchen. Older mass-transport events can instead control the supply and deposition of younger reservoirs. The age of the event decides which mechanism is possible at all.

The mechanical argument starts from added vertical load. Under rapid, poorly drained loading, part of the load is carried as excess pore pressure, and effective stress changes differently from a drained system (Terzaghi, 1943; Osborne and Swarbrick, 1997). Magnitude and duration depend on drainage, compressibility, permeability, geometry and emplacement rate. The thermal effect needs time for heat to move and for organic reactions to respond. Pressure rise and extra generation must not be assumed to be simultaneous.

Figure 5 quantifies the point at first order. With a 3 km conduction path, the thermal response reaches half its final value after roughly 10⁵ years; the pressure response is effectively instantaneous and, for a mudstone-dominated column, can persist for 10⁵ to 10⁷ years. The two signals therefore leave different records: pressure in present-day overpressure and possibly fault-valve behaviour, heat in maturity and charge timing.

The top-down part asks whether the predicted event appears in pressure data, temperature and maturity indicators, fluid mixing, charge phases and leakage. A spatial coincidence of an MTC and a seep is relevant but not a complete causal test. A seep can show an active leak route without proving which deep source or which charge event supplied it.

A suitable comparison contains a model with continuous sedimentation and an alternative with separately dated MTC loading and erosion, both tested against the same independent pressure and maturity controls. A third variant can test time-dependent fault behaviour. A pressure disturbance may survive while extra maturation is not supported; that is a refinement, not a failure. A shared migration corridor toward Tambaredjo also depends on carrier continuity, trap-before-charge and geochemical consistency; an unmapped Main Basin Fault cannot be introduced as a proven conduit.

7. Quantification without confusing volume concepts

A professional method must not only explain why a process is possible; it must also guard which volume is being calculated. This section applies the testing cycle to the author’s own numbers. The result is the main amendment of this edition.

7.1 Three totals, one province

Three GLIAG generation figures for offshore Suriname are in the public record:

The first figure is larger than the second for an area one-sixth the size; the third is seven times smaller than the second for a slightly larger area. A subset cannot exceed the whole within one mass balance, so at least two of the three use different definitions, inputs or masks. Choosing the largest figure would not be an uncertainty analysis.

7.2 The definitional error in the cascade

The cascade source states its own formula: UEP = source density × thickness × TOC × original HI × TR × expulsion efficiency, integrated over kitchen area (Chin-A-Lien, 2026e). Pepper and Roller define UEP as the petroleum a source rock can expel on complete maturation (Roller and Pepper, 2017; Pepper and Roller, 2021). Multiplying UEP by area therefore gives an expellable potential at TR = 1, not a volume generated. Applying a second set of expulsion efficiencies (75, 70, 55, 40 and 15%) to that potential mixes two definitions, and calling the 1,455 Bboe “generated” overstates realised generation wherever TR is below 1. The “nearshore immature margin” zone is the clearest case: an immature source has generated almost nothing, whatever its potential.

The zone densities also sit high against benchmarks (Figure 6). The Golden Lane belt is assigned 85 MMboe/km² and the deep-axis core 115 MMboe/km². The GIP essay of 14 October 2026 gives source potential at full conversion of about 50–56 MMboe/km² in the A3/A4 kitchens and about 22 MMboe/km² for Blocks 52, 58 and 14–15, and a realised median of 5.6 MMboe/km² in the active kitchen, 0.8 in Block 52 and 0.4 in Block 58 (Chin-A-Lien, 2026f). Mean UEPs for the Tuwaiq Mountain and Bazhenov formations, two world-class sources, are about 30 MMboe/km² (Roller and Pepper, 2017).

7.3 The arithmetic, reproduced

The cascade arithmetic is internally consistent and was reproduced exactly for this edition:

Σ A_i · UEP_i = 4,000×115 + 6,500×85 + 5,500×55 + 4,000×30 + 2,000×10 MMboe = 1,455 Bboe

Expulsion efficiencies of 75/70/55/40/15% give 949.1 Bboe; trap efficiencies of 15/22/18/10/5% give 171.7 Bboe; the stated recovery gives 73.3 Bboe (oil 26.2, condensate 17.9, gas 29.3 Bboe, about 170 Tcf at 6 Mcf/boe, 2026e). Overall, recoverable is 5.0% of the starting figure and 42.7% of trapped.

GLIAG’s view is that the error lies in the starting quantity, not in the arithmetic. If the realised P1 median of 5.6 MMboe/km² (GIP, 14 October 2026) is applied to the same 22,000 km² with the same downstream efficiencies, the cascade gives about 123 Bboe generated and about 6.2 Bboe recoverable. This is an illustration, not a new estimate: the P1 median is a kitchen-wide statistic and the efficiencies were never calibrated. It shows that the result is controlled by the choice between potential and realised generation by a factor of about 12.

7.4 External benchmark

The USGS 2025 assessment of the Guyana–Suriname Basin gives fully risked, technically recoverable undiscovered means of 7,912 MMbo (F95 3,039; F5 15,068), 19,480 Bcf of gas and 534 MMbbl of natural-gas liquids, about 11.7 Bboe at 6 Mcf/boe for the whole province (Schenk et al., 2026). The 2012 assessment gave 13,608 MMbo and 32,032 Bcf (USGS, 2012). Discovered volumes for comparison include about 11 Bboe gross in Stabroek and more than 750 MMbbl recoverable in GranMorgu (TotalEnergies, 2024).

The SE Golden Lane yet-to-find of 65.5 Bboe for one part of Suriname is 5.6 times the USGS mean for the whole province and more than four times its F5 oil case. The two estimates use different methods and risk bases, so the comparison does not prove either wrong. It does mean the GLIAG figure cannot be cited externally as “recoverable” until the gap is explained.

For any consistently defined petroleum volume, a share of generated material may be expelled, a share of that may reach a trap, and only part of the retained volume is technically and commercially producible. In multiphase systems, conversions, gas solution, phase change and losses must be booked on the same mass or molar basis before volume factors are applied. The quantitative part of the GLIAG method is therefore not a fixed efficiency factor for the whole basin; it is a traceable ledger in which each step has a definition, spatial domain, time window and uncertainty.

8. Fluids as a constraint on the geological model

The geochemical side of the method is broader than comparing API gravity or sulphur. A fluid carries information on organic origin, thermal conversion, mixing, migration and later alteration, but not every property separates those processes equally well. It must be stated in advance whether an observation refers to a downhole sample, a separator fluid, a stabilised export grade or a blended cargo.

The author’s molecule essays link petroleum-system interpretation to oil properties and refining questions (Chin-A-Lien, 2026i–k). Within the method this is a useful extension: one geological history can carry through to fluid quality and process choice. It does not mean that a refinery assay yields a unique geological birth certificate. API, sulphur, metals and distillation cuts allow several geological and operational explanations; source age or migration route needs additional geochemical and stratigraphic control (Peters et al., 2005).

For top-down testing, several indicator groups should be used together. Molecular patterns and isotopes can bound source affinity; maturity indicators can test relative conversion; gas composition and gas isotopes can examine mixing and phase history; reservoir temperature, pressure, saturation pressure and composition support the interpretation of phase behaviour. No line automatically replaces another, and transport, sample handling and analytical method can also create differences.

A gas–oil ratio is only comparable when measurement conditions and production basis are clear. An export blend can show a different component ratio from an individual reservoir fluid. A model percentage of gas in cumulative generated petroleum (about 11% gas and 2% condensate in the 14 October GIP sampling) cannot be compared directly with a measured production GOR: the first describes source conversion through time, the second the phases produced under specific conditions.

Suppose a regional model predicts mainly late gas charge while representative fluids show a dominant oil component and little sign of the assumed late mixing. That gap raises questions about burial, source kinetics, migration losses, earlier fill, phase fractionation or preservation. The correct response is to compare those alternatives, not to move the source map. The reverse also holds: a geochemically consistent oil family does not prove every trap is equally filled, because closure height, capillary threshold, pressure, carrier geometry and leakage decide where petroleum stays.

9. Reproducibility and the limits of model calibration

The 19 October essay describes the GLIAG basin model as calibrated against available public and open data and lists an offshore grid, burial-maturation columns, sediment thickness, bathymetry, a depth-to-ACT framework, a heat-flow history and a kinetic set (Chin-A-Lien, 2026d). That is a real model base with recognisable input categories.

One input statement fails a simple check. Revision 1.0 cites “4,498 offshore cells of five arc-minutes”. A five-arc-minute cell at 7° N measures about 85 km², so 4,498 cells would cover about 383,000 km², three times the 122,906 km² offshore domain. Staatsolie’s own five-arc-minute reference grid holds 2,484 cells over about 210,500 km² (84–85 km² each; Staatsolie GeoPortal download, retrieved 30 October 2026). The 14 October GIP essay instead describes 4,398 nodes at about 5.5 km spacing, near three arc-minutes and about 29.7 km² per node (Chin-A-Lien, 2026f). The likely explanation is a transcription error in the cell count or resolution; it is recorded as [VERIFY] until the GIP run log confirms the grid. The Charge Architecture paper itself states that licensed kinetics are still needed for full calibration (Chin-A-Lien, 2026g).

Reproducible review needs more than the general word “calibrated”. For each control point it must be visible which quantity was measured, which model version was used, which parameter was adjusted and what residual remained. A separate set of observations must then be held out of that adjustment; only that separation allows a test of predictive power. A published maturity map partly based on the same wells as the GIP calibration is not a fully independent validation set, and a good match with present-day temperature does not uniquely constrain past heat flow (Hantschel and Kauerauf, 2009).

The method therefore asks first for a frozen hypothesis and model version. Predictions are then recorded for quantities that can be observed: relative maturity, fluid family, phase distribution, pressure regime or the effective charge window. Only then are new or held-back data compared. Where several models explain the same data equally well, that non-uniqueness is a result. This paper claims no error analysis, blind prediction or statistical performance test that has not been carried out.

10. Spatial precision as part of the method

A petroleum-system interpretation can only be tested when it is clear where an observation lies. Public datasets mix field centres, proposed wells, final wellheads, seismic control points and locations chosen only for environmental models.

The Block 58 environmental record gives a concrete case. The Environmental Post-Operations Survey Report for KBD-3, prepared by Benthic Solutions for TotalEnergies and included in EIS Appendices Volume 03, gives the final well location in its Table 1.1 as Easting 626,501 m and Northing 798,768 m, WGS 84 / UTM zone 21N; the proposed location has the same Easting and Northing 798,769 m, one metre apart (TotalEnergies EP Suriname and BSL, 2024). KBD-3 is the Krabdagu-3 appraisal well, drilled in 2023 by the Transocean Development Driller III, which extended the Krabdagu resource 14 km from the discovery (Hart Energy). It is an existing appraisal well, not a GranMorgu development well.

Conversion of the final location from EPSG:32621 to EPSG:4326 with pyproj gives 7.224882° N, 55.854204° W (the proposed location converts to 7.224891° N). The six decimals are arithmetic display, not a claim of survey accuracy. The same appendices contain numerical locations for environmental models: in the cuttings-dispersion model, a deep-water discharge point was moved about 8.5 km north to obtain representative deep currents (TotalEnergies EP Suriname and RSK, 2024). Such a point must not be published as a wellhead, and an FPSO model position cannot stand for a reservoir or an individual well.

The development programme raises the stakes. GranMorgu, sanctioned on 1 October 2024, develops the Sapakara and Krabdagu fields (more than 750 MMbbl recoverable) through a 220,000 bbl/d FPSO, at about USD 10.5 billion, with first oil planned for 2028 (TotalEnergies, 2024). Noble Corporation’s fleet status report of 26 October 2026 lists the drillship Noble Valiant and the semi-submersible Noble Discoverer for TotalEnergies in Suriname from December 2026 to Q4 2029, 16 firm wells each and four shared option wells (Noble Corporation, 2026). No complete numerical wellhead table for those 32 planned wells was found in the environmental record reviewed. GIP therefore stores no exact coordinates for them; none are constructed from layouts or field centres.

A GIP location record must hold object type, original position, CRS, transformation, source, date and status. Distance to a kitchen, fault, carrier or sensitive seabed zone can change an interpretation, so the method ties geological testing to the precision and meaning of the object tested. KBD-3 was approved for GIP integration on 30 October 2026 and is not yet in either national register, which is itself a reminder that official registers lag development drilling.

11. Exploration decisions and the next discriminating observation

The practical yield of the method is a different way to rank exploration questions. Where source presence is uncertain, refining a recovery factor has little value. Where source and reservoir are regionally supported but charge access is unknown, migration geometry and timing must lead. Where fluids diverge, targeted geochemistry can discriminate more than a new regional volume estimate.

A positive exploration decision then needs scale and deliverability as well as geological plausibility; that commercial assessment is a separate step. A fitting charge model does not prove productivity, a flow test does not prove a durable plateau and a recoverable scenario is not a financeable project. The method supports that transition by keeping technical assumptions traceable.

For the basin as a whole, the learning value of new wells matters most. Expectations recorded before drilling can be confronted with real outcomes, and a disappointing outcome then has a place in the knowledge base. With 32 firm development wells planned in Block 58 from December 2026 and a shallow-water well in Block 15 expected in 2027, the next three years will test more pre-registered GLIAG predictions than the previous fifty.

12. Discussion

The GLIAG method recorded here makes explicit a practice already in use. Its individual techniques are not new; the author’s contribution is the basin-specific combination, the hypotheses and the way evidence, scale and decisions are linked, on an evidence base that spans both national registers.

The applications show that positive and negative data are needed together. The Aptian–Albian synthesis limits over-broad stratigraphic and geochemical generalisation. The Block 15 analysis separates petroleum presence from commercial fill. The MTC hypothesis separates a fast mechanical response from a slow thermal one. The volume audit shows why larger generation totals need not be stronger independent confirmation, and why the method must be applied to its author’s numbers with the same rigour as to anyone else’s.

Confirmation bias remains the main risk. An oil occurrence can be so attractive that an interpreter keeps adjusting the model to it, and a large generated volume can reinforce that bias. The remedy is to record in advance which observation would weaken the model. Not every mismatch needs a new source rock or an extra fault; sometimes an existing interpretation must be withdrawn, as the cascade label is withdrawn here. The history of successive versions belongs to the method.

Amendment register (Revision 1.0 → 1.1)

13. Limitations and open verification items

14. Conclusions

First, the GLIAG method is demonstrably present as an integrated interpretation practice in the author’s dated corpus since 13 July 2026. The name describes that application; it is not a priority claim on top-down or bottom-up analysis in general.

Second, petroleum-system elements stay separate questions of evidence. Presence, maturity, generation, expulsion, migration, fill, preservation and producibility cannot be merged into one positive verdict, and numerical models must respect the same limits as qualitative essays.

Third, applied to its author’s own volumes, the method catches a definitional error and a domain inconsistency. Until reconciliation, the defensible GLIAG anchor for offshore Suriname is about 190 Bboe realised generation and about 2–19 Bboe trapped at 1–10% accumulation efficiency; the 73.3 Bboe cascade output is a full-conversion scenario ceiling, not a recoverable estimate.

Fourth, the Guyana–Suriname Basin must be read as one province. GIP’s single register of 159 wellheads and 72 licences across both jurisdictions is the precondition for testing a Suriname prospect against its Guyanese analogues, and for testing GLIAG’s models against both.

The geological aim is not to write uncertainty out of the basin, but to make it smaller and easier to decide with each new observation.

Research integrity, data and AI disclosure

This manuscript combines the author’s previously published essays, GIP model outputs as published, official well and licence registers, the Block 58 environmental record and transparent first-order calculations. No new field, well, laboratory or seismic data were acquired. The cascade arithmetic, the coordinate conversion, the grid-area check and the curves of Figure 5 were recomputed for this edition with Python (pyproj, NumPy, SciPy). Figures 2–8 were drawn for this study. Figure 1 is a screen from the author’s GIP platform, with third-party imagery attributed in its caption.

Conceptual interpretation, the GLIAG method and all judgements are attributed to Marcel P.T. Chin-A-Lien. Perplexity Computer, an AI agent system, assisted on 30 October 2026 with reference verification, recalculation, figure drafting, translation from the Dutch Revision 1.0, editing and document preparation. The system is not an author, and its output is not geological evidence. The named author remains responsible for every claim, calculation, citation and interpretation. This manuscript has not been peer reviewed and makes no claim of institutional approval.

References

The author’s dated corpus

Chin-A-Lien, M.P.T. (2026a). The Aptian–Albian Record of the Guyana–Suriname Basin. GLIAG-SIS-2026-AALB-002, Rev. 4, 27 August 2026. Petroleum & Energy Insights. https://petroleumenergyinsights.com/aptian-albian-insights-exploring-guyana-suriname-basin-potential/

Chin-A-Lien, M.P.T. (2026b). Before the Bit Turns: PetroChina’s Block 15 Well and the Geological Test of Suriname’s Eastern Shallow-Water Margin. GLIAG-ESSAY-2026-PCIS-B15-001, 2 September 2026. https://petroleumenergyinsights.com/petrochinas-block-15-well-geological-insights-and-investment-outlook/

Chin-A-Lien, M.P.T. (2026c). When the Margin Fell: Mass-Transport Loading, Overpressure, Delayed Maturation and Pulsed Charge from the Suriname Kitchen to Tambaredjo. GLIAG-GGR-2026-1016-MTC-001, 16 October 2026. https://petroleumenergyinsights.com/mass-transport-effects-on-surinames-petroleum-systems/

Chin-A-Lien, M.P.T. (2026d). Mass-Transport Complexes and Petroleum-System Evolution. GLIAG-GGR-2026-1019-MTC-002, 19 October 2026. Public URL [VERIFY].

Chin-A-Lien, M.P.T. (2026e). SE Golden Lane: A Dual Oil and Gas-Condensate Basin. The Charge Fairway of the SE Golden Lane Blocks 52 & 58. 13 July 2026. https://petroleumenergyinsights.com/se-golden-lane-a-dual-oil-and-gas-condensate-basin/

Chin-A-Lien, M.P.T. (2026f). Exploring Suriname’s South-East Golden Lane Petroleum System (GIP). GLIAG-ESS-2026-GIP-SEGL-001 v1.4, 14 October 2026. https://petroleumenergyinsights.com/exploring-surinames-south-east-golden-lane-petroleum-system/

Chin-A-Lien, M.P.T. (2026g). Charge Architecture of the Guyana Suriname Basin. GLIAG-GSB-CA-2026-1005-001, 5 October 2026. https://petroleumenergyinsights.com/evaluating-petroleum-generation-and-migration-in-suriname/

Chin-A-Lien, M.P.T. (2026h). Why Facies Matter in the Guyana–Suriname Basin’s Petroleum Systems. 4 September 2026. https://petroleumenergyinsights.com/why-facies-matter-in-the-guyana-suriname-basins-petroleum-systems/

Chin-A-Lien, M.P.T. (2026i). Liza Birth Certificate and Crude’s Geological Journey From Source to Refinery. 10 September 2026. https://petroleumenergyinsights.com/liza-birth-certificate-and-crudes-geological-journey-from-source-to-refinery/

Chin-A-Lien, M.P.T. (2026j). The Golden Molecule (published as Golden Lane Crude: A Game Changer for Caribbean Refineries). 11 September 2026. https://petroleumenergyinsights.com/golden-lane-crude-a-game-changer-for-caribbean-refineries/

Chin-A-Lien, M.P.T. (2026k). Reading the Molecule (published as Analyzing Liza and Suriname’s Oil Properties for Better Insights). 12 September 2026. https://petroleumenergyinsights.com/analyzing-liza-and-surinames-oil-properties-for-better-insights/

Foundational and methodological literature

Carslaw, H.S. and Jaeger, J.C. (1959). Conduction of Heat in Solids, 2nd ed. Oxford: Clarendon Press.

Hantschel, T. and Kauerauf, A.I. (2009). Fundamentals of Basin and Petroleum Systems Modeling. Berlin: Springer. https://doi.org/10.1007/978-3-540-72318-9

Magoon, L.B. and Dow, W.G. (eds.) (1994). The Petroleum System: From Source to Trap. AAPG Memoir 60. Tulsa: AAPG. https://doi.org/10.1306/M60585

Osborne, M.J. and Swarbrick, R.E. (1997). Mechanisms for generating overpressure in sedimentary basins: a reevaluation. AAPG Bulletin, 81(6), 1023–1041. https://doi.org/10.1306/522B49C9-1727-11D7-8645000102C1865D

Pepper, A.S. and Corvi, P.J. (1995). Simple kinetic models of petroleum formation. Part I: oil and gas generation from kerogen. Marine and Petroleum Geology, 12(3), 291–319. https://doi.org/10.1016/0264-8172(95)98381-E

Pepper, A.S. and Roller, E. (2021). Ultimate expellable potentials of source rocks from selected super basins: what does “world class” look like? AAPG Bulletin, 105(6), 1069–1097. https://doi.org/10.1306/11092020077

Peters, K.E., Walters, C.C. and Moldowan, J.M. (2005). The Biomarker Guide, 2nd ed. Cambridge University Press. https://doi.org/10.1017/CBO9780511524868

Roller, E. and Pepper, A.S. (2017). Estimating the ultimate expellable potential of source rocks: defining “world class” for aquatic organofacies. AAPG Annual Convention and Exhibition, Houston, 2–5 April 2017. Benchmark values as tabulated at https://www.apt-int.com/glossary/ultimate-expellable-potential

Terzaghi, K. (1943). Theoretical Soil Mechanics. New York: Wiley. https://doi.org/10.1002/9780470172766

Assessments, operators and registers

Guyana Ministry of Natural Resources. Well Activities register and Oil Blocks map. Retrieved 5 August 2026. https://petroleum.gov.gy/well-activities/ ; https://petroleum.gov.gy/oil-blocks/

Hart Energy (2023). APA Corp’s confidence grows in developing Suriname oil hub. https://www.hartenergy.com/exclusives/apa-corps-confidence-grows-developing-suriname-oil-hub-206060

Noble Corporation (2026). Fleet Status Report, 26 October 2026, pp. 3, 5. https://noblecorp.com/download/noble-corporation-fleet-status-report-4/?wpdmdl=4015

OilNOW (2024). TotalEnergies sees more oil potential in Suriname’s Block 58. https://oilnow.gy/featured/totalenergies-sees-more-oil-potential-in-surinames-block-58/

Reuters (2026). PetroChina to begin shallow-water drilling in Suriname next year, executive says. 24 June 2026. https://www.reuters.com/business/energy/petrochina-begin-shallow-water-drilling-suriname-next-year-executive-says-2026-06-24/

Rystad Energy (2024). GranMorgu FID holds promise for Suriname’s deepwater ambitions. https://www.rystadenergy.com/insights/gran-morgu-fid-holds-promise-for-suriname-s-deepwater-ambitions

Schenk, C.J. et al. (2026). Assessment of undiscovered conventional oil and gas resources of South America and the Caribbean, 2025. USGS Fact Sheet 2026-3066. https://doi.org/10.3133/fs20263066 ; https://pubs.usgs.gov/publication/fs20263066/full

Staatsolie (2024). Staatsolie signs offshore production sharing contracts with PetroChina. http://www.2026.staatsolie.com/en/news-media/news/staatsolie-signs-offshore-production-sharing-contracts-with-petrochina/

Staatsolie. GeoPortal: Licensing Blocks, Wells and Grid 5 min Suriname downloads. Retrieved 30 October 2026. https://geoportal-staatsolie.hub.arcgis.com/

Staatsolie. Data Catalog 2.0 (external). https://www.staatsolie.com/media/y1khja3s/data-catalog_2-0-external.pdf

TotalEnergies (2024). TotalEnergies announces Final Investment Decision for GranMorgu development. 1 October 2024. https://totalenergies.com/system/files/documents/totalenergies_Suriname-TotalEnergies-announces-Final-Investment-Decision-for-GranMorgu-development_en_pdf.pdf

TotalEnergies EP Suriname B.V. and Benthic Solutions Ltd (2024). Environmental Post-Operations Survey Report, Block 58 KBD-3. BSL2303_TEEPSR_KBD3_EPOS_01, May 2024, Table 1.1, p. 4. In EIS Appendices Volume 03. Register: https://sites.google.com/view/nma-mea-eia-repository/recent-studies

TotalEnergies EP Suriname B.V. and RSK (2024). Environmental Impact Statement, Offshore Block 58 Development, Volume I (2 August 2024) and Appendices Volume 01, Cuttings Dispersion Modelling, Table 1, p. 8. Register as above.

USGS (2012). Assessment of undiscovered conventional oil and gas resources of South America and the Caribbean, 2012. Fact Sheet 2012-3046. https://pubs.usgs.gov/fs/2012/3046/fs2012-3046.pdf

Map data

EOX IT Services GmbH. Sentinel-2 cloudless (contains modified Copernicus Sentinel data 2016). CC BY 4.0. https://s2maps.eu/

OpenStreetMap contributors. Map labels. Open Database Licence. https://www.openstreetmap.org/copyright

Related work by the author

Chin-A-Lien, M.P.T. (2026). Two Clocks Beneath the Leeward Antilles: Petroleum Systems and Potential of the Bonaire Basin. GLIAG-BB-2026-PS-005, Rev. 1.1, 29 October 2026. Zenodo. https://doi.org/10.5281/zenodo.23771523

About the author

Drs. Marcel P.T. Chin-A-Lien, MBA, M.Sc., Ing., geologist, is Principal Founder and Chief Architect of GLIAG. AAPG Certified Petroleum Geologist #5201-1996; EFG European Geologist #92-1996; AIEN Energy Negotiator. He works from Zoetermeer and Paramaribo on the petroleum systems, fiscal design and development strategy of the Guyana–Suriname Basin.

Figure provenance and competing interests

Figures 2–8 are original GLIAG work drawn for this edition. Figure 1 is a GIP screen (Rev 0.22.110, 24 October 2026) showing register data from the Guyana Ministry of Natural Resources and Staatsolie on Sentinel-2 cloudless imagery by EOX (CC BY 4.0) with OpenStreetMap labels. Staatsolie GeoPortal items carry no stated licence; they are used here with attribution for research. The author leads GLIAG, which develops GIP and offers advisory services to governments, national oil companies and investors. GLIAG is not a sponsor of, or equity investor in, any licence or project discussed. This is not a reserves report, drilling forecast or investment advice.

Copyright, licence and citation

© 2026 Marcel P.T. Chin-A-Lien. Released under the Creative Commons Attribution-NonCommercial-NoDerivatives 4.0 International licence (CC BY-NC-ND 4.0), https://creativecommons.org/licenses/by-nc-nd/4.0/. Third parties keep their rights in data and publications cited. GLIAG, GIP and Golden Lane are trade names of the author.

Cite as: Chin-A-Lien, M.P.T. (2026). Petroleum Systems Analysis of the Guyana–Suriname Basin with the GLIAG methodology. GLIAG-PS-GSB-20261030-001, Revision 1.1, 30 October 2026. Zenodo. https://doi.org/10.5281/zenodo.23815989

Text and data mining. The author expressly reserves the rights of reproduction and extraction of this work for text and data mining, including the training of artificial-intelligence systems, under Article 4(3) of Directive (EU) 2019/790.

Research use limitation. Analytical screening only. Volumes are not reserves or resources under SPE-PRMS, and nothing here is a recommendation to invest, drill or transact. Correspondence: info@gliag.com.