Upstream oil and gas performance is commonly assessed through established technical and management disciplines, including reservoir engineering, drilling and completions, major projects, production operations and financial management. Each has defined responsibilities, performance measures and methods for establishing whether its objectives have been achieved.
The more difficult question is whether satisfactory performance across these disciplines establishes that an asset is operating close to its economic potential.
A reservoir may perform in accordance with its approved development plan, a major project may be delivered within its sanctioned cost and schedule, and production operations may achieve their availability and efficiency targets. Each outcome may represent competent execution. Yet none establishes, individually or collectively, whether the underlying development choices were economically competitive against feasible alternatives.
This distinction raises a question that cannot necessarily be answered through functional performance measures alone:
How should the economic quality of upstream development decisions be established when the responsibilities for making, executing and subsequently operating those decisions are distributed across different functions?
The accompanying figure presents Fulcrium’s indicative assessment of the relative distribution of ten management responsibilities across six upstream executive positions.
The distribution illustrates a familiar organisational characteristic of upstream businesses. Specialist responsibilities are necessarily divided, while accountability for asset, development and portfolio outcomes extends across those divisions.
An Asset Manager may be accountable for overall asset performance without exercising direct organisational authority over every contributing function. A Development Director may influence reservoir development, well delivery and concept selection without controlling all subsequent capital commitments, project execution and operating decisions.
Similarly, a Major Projects Director may be responsible for delivering a sanctioned development within agreed cost, schedule and technical parameters, although the assumptions governing the original investment decision were established through a wider process.
These arrangements do not necessarily represent organisational weaknesses. They reflect the specialist responsibilities required to develop and operate complex assets.
The figure illustrates the distribution of those responsibilities. It does not establish that the resulting decisions were economically suboptimal. That question requires separate examination of the choices made, the alternatives available and their economic consequences.
The analytical difficulty arises when satisfactory performance within individual functions is treated as sufficient evidence of the competitiveness of the overall development.
Consider an asset in which reservoir performance, project delivery and production operations are all assessed as satisfactory.
The reservoir development team may have achieved recovery performance consistent with the approved plan. Surveillance may have been effective, reservoir behaviour may have remained within forecast expectations, and production targets may have been met.
The major project may have achieved its sanctioned cost and schedule commitments, with engineering, construction and commissioning completed competently.
Production operations may have delivered high facility availability, satisfactory operating expenditure and reliable production performance.
These achievements are meaningful. They provide evidence that assigned responsibilities have been discharged effectively.
They do not, however, establish whether the approved development configuration was the most economically competitive among the alternatives reasonably available.
A different well configuration, development sequence, processing capacity or recovery strategy might have produced a different lifecycle economic outcome. Equally, the selected configuration may have been the most appropriate once technical uncertainty, capital availability, execution risk and production timing were considered.
The observed functional results cannot distinguish between these possibilities.
That distinction requires examination of the development decisions themselves, rather than inference from the subsequent quality of their execution.
Development concept selection illustrates the problem because decisions made at this stage can influence asset performance for decades.
A project organisation may reasonably favour a configuration offering lower initial capital expenditure, greater schedule certainty and reduced execution complexity.
Reservoir and production considerations may favour an alternative involving higher initial expenditure but potentially superior recovery, production flexibility or lifecycle economics.
Financial management may introduce further considerations relating to capital availability, investment sequencing, portfolio priorities and risk exposure.
Each position may be defensible within its respective responsibilities.
The question is not which function has the correct perspective in isolation, but whether the competing development alternatives have been evaluated on a sufficiently comparable basis to establish their relative economic merits.
Consider two hypothetical development concepts.
Concept A requires lower initial capital expenditure and offers greater confidence in the planned execution schedule. Concept B requires additional upfront investment but provides greater production flexibility and potentially higher ultimate recovery.
If Concept A is selected and subsequently delivered within budget and on schedule, the project organisation may legitimately demonstrate excellent execution.
That result does not establish whether Concept A was economically superior to Concept B.
Nor does a subsequent observation that Concept B might have delivered higher recovery necessarily establish that Concept B should originally have been selected.
The comparison must account for the information available at the decision date, the technical uncertainties associated with each concept, capital constraints, production timing, operating expenditure and the economic consequences of risk.
The economically preferred alternative may change depending on these conditions.
A comparison that ignores them risks attributing an observed performance difference to concept selection when it may be explained by other factors.
Successful execution demonstrates the quality of implementation against an agreed basis. It does not, by itself, validate the economic quality of that basis.
Assessing the economic quality of development decisions requires distinguishing three questions that are often considered together but are analytically different.
The first question concerns the information, assumptions and constraints prevailing at the time of sanction.
A development decision made fifteen years ago should not be judged solely against information that became available subsequently.
Reservoir uncertainty may have been greater, recovery technologies less established, capital more constrained or execution risks assessed differently.
A decision that appears economically inferior with hindsight may nevertheless have been reasonable given the alternatives and evidence available when it was made.
The relevant enquiry is therefore whether the original decision was adequately supported by contemporaneous evidence, whether feasible alternatives were examined and whether the assumptions used to compare them were defensible.
The second question concerns the comparative merits of the development options.
This is not answered merely by demonstrating that an alternative configuration could have produced higher recovery, lower capital expenditure or improved facility availability.
Those outcomes must be considered within a consistent economic and technical framework.
For example, higher recovery may require additional capital, defer early production or increase operating complexity. Lower initial expenditure may reduce financial exposure but constrain later development flexibility.
The comparison must establish whether an alternative was genuinely feasible under comparable conditions and whether its expected economic advantages were sufficient to justify the associated costs and risks.
Where the evidence is observational, care is required before attributing differences in economic performance to a particular development choice. Geological conditions, commercial terms, investment timing and operating constraints may differ materially between otherwise similar assets.
An observed performance advantage establishes a question for investigation, not proof that the alternative development strategy caused the advantage.
The third question is prospective.
Even where the original development decision was reasonable, subsequent reservoir performance, technical information, operating experience or economic conditions may alter the relative merits of the remaining options.
An asset may have been developed appropriately under its original assumptions while its current development strategy no longer represents the most competitive available pathway.
Conversely, a development that appears disappointing against its original expectations may still offer limited scope for economically justified change.
The appropriate assessment must distinguish expenditure already committed from future expenditure, identify which constraints can realistically be changed and compare the incremental economic consequences of the remaining alternatives.
The original decision, the historical economic outcome and the optimal future decision are therefore separate subjects of enquiry.
Confusing them can lead either to unjustified criticism of past decisions or to unnecessary continuation of a development pathway whose underlying assumptions are no longer valid.
The boundary of a performance assessment should follow the question being investigated.
Where the enquiry concerns drilling execution, comparison of well complexity, drilling practices and delivery performance may be sufficient.
Where it concerns reservoir recovery, the assessment may need to examine reservoir characteristics, depletion mechanisms, development strategy and comparable recovery outcomes.
However, where an observed performance difference cannot be adequately explained within one discipline, the enquiry may need to extend beyond it.
A difference in reservoir recovery may be connected to well architecture, injection capacity, processing constraints, development sequencing or investment decisions.
A difference in production efficiency may reflect operational practices, but it may also arise from earlier facility design or development assumptions.
A difference in capital efficiency may reflect project execution, yet concept selection, infrastructure flexibility and reservoir uncertainty may have contributed materially to the outcome.
The purpose of extending the analytical boundary is not to make every assessment unnecessarily broad.
It is to include the decisions and constraints necessary to explain the observed performance difference.
This also requires recognising when the existing explanation may be incomplete.
If a performance difference persists after reasonable allowance for reservoir conditions, project complexity and operating circumstances, the appropriate response is not necessarily to introduce additional explanatory variables indefinitely.
It may be necessary to reconsider whether the original performance objectives, development assumptions or comparison framework adequately represent the economic question being investigated.
Such an enquiry may validate the existing explanation. Alternatively, it may reveal that the explanation accounts for satisfactory performance against established objectives without establishing whether those objectives reflected what was economically achievable.
Upstream assets reflect connected decisions taken across technical, operational, financial and organisational responsibilities, often over several decades.
The individuals responsible for executing those decisions may have performed competently. The objectives against which their performance was measured may also have been appropriate within their respective responsibilities.
Nevertheless, satisfactory functional performance cannot, on its own, establish the economic competitiveness of the development choices connecting those responsibilities.
That conclusion requires a different evidential basis.
It requires distinguishing the quality of execution from the quality of the original decision, examining feasible alternatives under comparable conditions, and separating historical judgement from the question of what remains achievable.
It also requires accepting that comparative evidence may confirm the appropriateness of existing decisions rather than necessarily identifying superior alternatives.
The objective is not to demonstrate that functional performance measures are inadequate for their intended purposes. They remain essential to disciplined management.
The question is whether the evidence used to evaluate functional performance is also sufficient to establish the economic quality of the decisions that determine the asset’s overall outcome.
If every function can demonstrate satisfactory performance against its own objectives, what evidence establishes that those objectives – and the decisions connecting them – were collectively consistent with the greatest achievable economic outcome?
Accompanying figure: The Distribution of Executive Responsibilities Across Upstream Oil & Gas. Source: Fulcrium analysis.
© Fulcrium 2026. All rights reserved.
Optimisation, external performance evidence and the limits of established expectations
An industrial asset may undergo successive rounds of technical and operational optimisation, achieve its approved performance objectives and demonstrate little remaining improvement potential within its established operating framework.
The conclusion may be well supported. Reservoir forecasts may have been updated against production history, facilities constraints examined, operating practices refined and further investment opportunities evaluated. Independent technical assurance may have confirmed the integrity of the analysis.
Yet the conclusion that little further improvement is available depends not only upon the quality of the optimisation, but also upon whether the assumptions, constraints and alternatives defining it adequately represent what might be achievable.
Optimisation is undertaken against specified objectives and within defined constraints. Its results are conditional upon those definitions. The more difficult question arises when the constraints themselves are partly the product of earlier engineering, operating or investment decisions.
A development concept may have been selected from alternatives considered appropriate at the time. A facility’s operating envelope may reflect accumulated experience of equipment reliability and process behaviour. A mature field’s remaining potential may be assessed against a recovery strategy established many years earlier.
Each may be technically defensible within its original context without necessarily remaining the most appropriate basis for assessing future performance.
An organisation can therefore become increasingly confident about the best outcome achievable within its established framework without acquiring equivalent confidence that the framework adequately represents the available possibilities.
The distinction matters when determining whether an apparent performance limit is intrinsic to the asset, reflects an economically justified choice or arises from assumptions that warrant reconsideration.
Industrial performance expectations develop through successive decisions rather than a single assessment.
Initial development studies evaluate alternatives and establish technical and economic assumptions. Engineering design converts selected assumptions into physical configurations. Commissioning and operating experience subsequently inform performance forecasts, maintenance strategies and operating limits.
Over time, these decisions create an established framework for assessing performance.
This is necessary. Industrial operations cannot continually reopen every historical decision. Stable operating envelopes, engineering standards and development plans provide the basis for safe execution, accountability and continuous improvement.
The difficulty arises when an assumption originally adopted as a reasonable planning or design choice comes to be treated as an intrinsic limitation of the asset.
A facility operating constraint may have originated in a conservative commissioning assumption. A well configuration may reflect the technology and economics prevailing at the time of development. A production forecast may incorporate a reservoir-management strategy that has subsequently become the accepted reference case.
None necessarily indicates that the original decision was wrong. The question is whether subsequent evidence has altered the basis upon which that decision should now be judged.
This is particularly relevant in long-lived assets, where technology, operating knowledge, infrastructure availability and commercial conditions may change substantially.
Performance against an established expectation is an observation. Whether the expectation itself remains appropriate is a separate interpretation.
Some apparent constraints are unavoidable. Others may be technically alterable but economically justified. Still others may reflect assumptions that have not been sufficiently re-examined.
Distinguishing between these explanations requires evidence beyond the asset’s performance against its existing objectives.
Sophisticated industrial operators already recognise the limitations of internally defined performance expectations.
Major developments undergo concept selection, technical assurance, economic evaluation and independent review. Producing assets are examined through surveillance, performance analysis, redevelopment studies and continuous improvement programmes. External specialists, industry databases and comparative studies may already inform these processes.
Independent benchmarking does not introduce the idea of challenging assumptions into organisations that would otherwise accept them uncritically.
The relevant question is whether existing assessments have access to sufficiently representative external evidence, and whether that evidence has been interpreted in a manner capable of challenging the expectations under review.
Technical assurance may establish that forecasts are consistent with available data, engineering calculations are appropriate and proposed developments satisfy specified requirements. More extensive assurance can also examine alternative concepts, external comparators and underlying assumptions.
Independent comparative assessment is therefore not necessarily separate from, or superior to, established assurance. A comprehensive assurance exercise may already encompass it.
The distinction concerns the enquiry.
One question is whether a proposed decision is adequately supported by the evidence considered. Another is whether the performance expectations against which that decision is evaluated remain consistent with what relevant external industrial experience suggests may be achievable.
The additional contribution of external comparison arises where it introduces observations, alternative explanations or development possibilities not adequately represented in the existing assessment.
Its value is conditional. It may corroborate established conclusions, identify an unexplained difference or reveal that the original question has been framed too narrowly.
Its authority derives from the quality of the evidence and reasoning, not simply from the independence of the assessor.
External benchmarking can identify performance differences, but those differences acquire significance only through technically defensible interpretation.
A higher recovery factor, greater LNG throughput, lower capital intensity or shorter project schedule is not, by itself, evidence of superior operating or development practice.
The relevance of a comparison depends upon the question being examined and the extent to which material differences in circumstances can be recognised.
A comparison appropriate for reservoir recovery mechanisms may not be suitable for evaluating development economics. LNG facilities with similar nominal capacities may differ materially in feed-gas characteristics, process configuration or operating requirements. Projects with similar production capacities may involve different infrastructure and technical complexity.
Observed performance differences may reflect measurable technical conditions, development choices or circumstances not adequately represented in the available evidence.
An unexplained difference is not automatically an improvement opportunity. It may instead raise questions about the relevance of the comparison, the adequacy of the prevailing interpretation or the existence of constraints that have not been sufficiently recognised.
This is where comparative judgement becomes more consequential than ranking.
A quartile position describes where an asset sits within a selected distribution. It does not establish why the asset occupies that position or whether its performance is close to what is realistically achievable.
The distinction between internal improvement and external performance assessment has long been recognised at the highest levels of the industry.
In December 2004, Shell’s Group Chief Executive, Jeroen van der Veer, stated:
“Doing it better than yesterday is fine, but doing it better today than the competition motivates me more.”
He associated first-quartile performance with an external mindset and described the Executive Committee’s interest in monitoring the proportion of Shell assets achieving first-quartile performance.
The principle remains relevant. However, external ranking and assessment of achievable potential are different enquiries.
A first-quartile position establishes relative standing within a defined comparator population; it does not independently explain performance differences or establish what a particular asset could reasonably achieve. Equally, an asset below the first quartile is not necessarily underperforming relative to its own potential.
The more demanding question is whether relevant external evidence supports, challenges or leaves unresolved the assumptions underlying existing performance expectations.
LNG facilities illustrate how apparent performance limits arise from interacting process, mechanical, operational and commercial conditions.
A facility may achieve high availability, meet its production plan and demonstrate effective maintenance performance while operating within an established throughput envelope.
That envelope may reflect process design, feed-gas composition, ambient conditions, rotating-equipment capability, equipment reliability, safety requirements and contractual obligations.
Some constraints are intrinsic to the facility’s configuration. Others depend upon operating choices or assumptions that may change over time.
Consider an illustrative facility that has undergone extensive operating optimisation and debottlenecking studies. Management concludes that further sustained production increases require substantial capital expenditure.
Relevant external experience may include facilities with similar nominal capacities that have achieved higher sustained throughput.
The observation does not establish an improvement opportunity.
Differences in feed-gas composition, inlet conditions, ambient temperature, process configuration and operating requirements may explain much of the apparent performance variation.
Even where material differences remain insufficiently explained, they do not necessarily indicate avoidable operating constraints. Maintenance strategies, rotating-equipment limitations and process operating requirements may reflect legitimate technical, reliability or commercial considerations.
Nor would evidence of more favourable performance elsewhere establish that adopting another facility’s practices would reproduce its outcome. Technical applicability, reliability consequences, operating risks and economic attractiveness remain material considerations.
External evidence may nevertheless raise legitimate questions about whether particular operating assumptions continue to provide the most appropriate basis for an investment decision.
For example, an assessment concluding that additional production requires substantial capacity investment may warrant reconsideration if relevant industrial experience suggests that some established constraints are potentially alterable.
Equally, the evidence may confirm that facility-specific limitations make the proposed capital investment necessary.
The purpose is not to presume that additional production is available, but to establish whether the operating assumptions informing a consequential decision remain defensible.
Maturing hydrocarbon basins present a different challenge because recovery performance and remaining economic potential depend upon the interaction of subsurface behaviour, wells, production facilities, infrastructure and development choices.
Operators typically possess extensive knowledge of reservoir behaviour, production history and remaining resources. Nevertheless, an observed recovery difference between apparently comparable fields may not be adequately explained within a reservoir-only interpretation.
Consider an illustrative mature field whose recovery factor appears unfavourable against relevant reservoir analogues.
Geology, reservoir heterogeneity, displacement mechanisms, well spacing and injection performance may account for important differences between fields.
However, recovery outcomes can also be materially influenced by development and operating circumstances extending beyond the reservoir.
Produced-water handling capacity, artificial-lift limitations, well intervention economics, infrastructure availability and the expected remaining life of shared facilities may influence development strategy and ultimate recovery.
A field with technically attractive remaining resources may have experienced restricted development because of infrastructure or economic constraints rather than reservoir limitations alone.
Conversely, apparently superior recovery elsewhere may reflect different investment conditions or infrastructure availability.
These distinctions matter because reservoir recovery potential, technically achievable development outcomes and economically preferred development strategies are not necessarily equivalent.
The UK Oil and Gas Authority’s Recovery Factor Benchmarking report, published in September 2017, estimated that increasing recovery factors across a prioritised selection of large UK Continental Shelf oilfields could yield an additional 900 million barrels of oil.
The estimate illustrated the potential significance of recovery-factor differences, but did not establish that the additional volumes would necessarily be technically or economically recoverable in every case.
Additional production may require wells, facilities investment, extended infrastructure operation or substantially greater expenditure. The technically achievable recovery outcome is not necessarily the economically preferred development outcome.
Where external recovery experience raises questions that cannot be adequately resolved through subsurface considerations alone, the consequential issue may concern the development strategy, infrastructure assumptions or economics governing remaining production.
The question can change from how to improve reservoir recovery to whether the current development pathway remains the most defensible means of converting remaining resources into economic value.
A broader perspective is relevant where the industrial evidence warrants it, not because every recovery comparison requires examination of the entire value chain.
Field development planning illustrates the distinction between optimising a selected concept and establishing whether that concept remains appropriate.
Development concepts are selected through technical and economic evaluation of alternatives. The preferred concept is then refined through reservoir studies, well planning, facilities engineering, cost estimation and risk assessment.
The resulting plan may be extensively optimised and independently assured.
However, that does not necessarily establish the continuing appropriateness of the concept itself.
This is not an argument for repeatedly reopening concept selection. Development decisions require commitment, and alternatives legitimately rejected under established conditions should not be reconsidered without reason.
The issue arises when material changes in reservoir understanding, technology, infrastructure availability, costs or commercial conditions alter the basis of the original selection.
A concept selected when particular drilling technologies, infrastructure options or capital costs made alternatives unattractive may remain internally coherent even after those circumstances have changed.
Relevant external experience may include developments employing different well configurations, recovery strategies, production-system designs or development sequences.
Differences in reservoir conditions, objectives or commercial circumstances may explain their apparent advantages. Nevertheless, credible external alternatives can raise legitimate questions about assumptions underlying an established development concept.
Where those questions have material technical or commercial consequences, strategic reassessment may be more appropriate than further optimisation of the selected concept.
Whether to reopen concept selection depends upon the significance of the evidence, the consequences of retaining the existing concept and the cost and risk of reassessment.
The governing question is whether the evidence supporting the concept’s continued selection remains sufficiently robust.
Major oil and gas capital projects are developed and executed through engineering, cost estimation, scheduling, quantitative risk analysis and project assurance.
Once a baseline is approved, performance management concentrates on delivery against defined cost, schedule and scope expectations.
These controls are essential. They do not independently establish whether the expectations incorporated into the baseline were appropriate.
A project may be delivered within budget and schedule while its capital intensity or development duration remains materially different from relevant external experience.
Conversely, a project exceeding its original baseline may have encountered circumstances that make its eventual performance defensible against comparable developments.
Neither conclusion follows from baseline variance alone.
The approved baseline reflects earlier choices concerning project scope, development configuration, technical complexity, contracting arrangements, market conditions and execution strategy.
Some may influence eventual performance more substantially than the effectiveness of execution against the baseline.
Flyvbjerg’s work on reference-class forecasting examines how historical project outcomes can inform assessments of cost and schedule risk, including limitations of estimates developed principally from an internal project perspective.
Reference-class forecasting and independent assessment of achievable project performance are related but distinct.
Historical outcome distributions can inform the realism of cost and schedule expectations. Establishing whether a particular project could reasonably have achieved a different outcome also requires consideration of scope, technical complexity, execution conditions and development choices.
This distinction is particularly relevant before final investment decision.
An extensively assured project may have cost and schedule expectations that remain materially different from relevant external experience because of its concept, contracting approach or scope assumptions.
Comparison may confirm that those differences are justified or identify assumptions requiring further examination before substantial capital commitments become difficult to reverse.
The question is not only whether the project can be delivered against its approved baseline, but whether the baseline reflects defensible expectations given the project’s characteristics and available alternatives.
Artificial intelligence is extending the analytical capabilities available to industrial organisations.
AI-assisted methods can process extensive datasets, support forecasting, evaluate operating configurations and investigate alternatives that would otherwise be difficult or time-consuming to examine.
These capabilities may improve optimisation and the assessment of established assumptions, although better analytical performance does not automatically translate into superior engineering or commercial outcomes.
There is no inherent reason why AI must reinforce an existing operating or development framework. Its contribution depends upon the questions examined, the alternatives represented and the evidence available.
A highly accurate production forecast under an established reservoir-management strategy does not establish that the strategy is preferable to credible alternatives.
Similarly, an optimisation algorithm may identify an effective operating configuration within specified constraints without establishing whether those constraints are intrinsic or economically justified.
AI can reduce uncertainty about outcomes within a defined analytical framework while leaving unresolved uncertainty about the appropriateness of that framework.
This limitation also applies to conventional engineering models, optimisation methods and project forecasts.
AI systems informed by appropriate external evidence may help challenge established assumptions and identify performance differences that warrant further consideration. Their practical significance remains a matter of evidence and technical judgement.
A model may perform reliably within its intended scope while the industrial decision requires evidence extending beyond that scope.
Independent comparative benchmarking is therefore not a substitute for model validation or AI governance. Its relevance lies in assessing whether the performance expectations informing consequential decisions remain defensible against relevant external experience.
External benchmarking cannot establish achievable potential simply by identifying superior observed outcomes.
Comparative evidence may be incomplete, relevant external experience limited and differences in operating or development circumstances difficult to explain.
In some cases, the evidence supports the existing interpretation of performance. In others, it identifies a difference warranting investigation without establishing whether a different outcome is achievable.
Occasionally, it identifies a credible alternative with sufficiently strong technical and economic support to justify reconsidering an operating or investment decision.
These conclusions should not be conflated.
The standard of evidence depends upon the decision.
A relatively inexpensive operating trial may be justified by a plausible but uncertain opportunity. A major redevelopment, capacity expansion or irreversible capital commitment requires stronger evidence concerning technical feasibility, economic consequences and risk.
The relevant question is whether the evidence is sufficient to support the decision being considered, including the decision to investigate further, retain the existing strategy or commit additional capital.
Independent judgement matters because comparative evidence does not interpret itself.
A defensible independent opinion must recognise the relevance and limitations of the comparative evidence, the credibility of competing explanations and the uncertainty surrounding established performance expectations.
Independence also requires the freedom to conclude that no material improvement opportunity has been demonstrated.
A benchmarking exercise designed to identify underperformance regardless of the evidence is no more defensible than an internal assessment designed to confirm existing expectations.
The objective is to establish what the evidence permits management to infer and where material uncertainty remains.
Industrial optimisation and technical assurance improve performance, inform investment decisions and reduce uncertainty within defined engineering and commercial frameworks.
Their sophistication does not, by itself, establish the adequacy of the assumptions defining those frameworks.
External comparative evidence provides an independent perspective on whether established expectations remain consistent with relevant industrial experience.
Its value lies not simply in identifying higher-performing assets, but in informing judgements about the assumptions, constraints and alternatives underlying consequential operating and investment decisions.
Sometimes the evidence confirms existing expectations. Sometimes it supports reconsideration of an established decision. Sometimes it reveals uncertainty requiring further investigation.
The distinction is particularly consequential where investment commitments are substantial, development choices difficult to reverse or operating strategies have remained in place over long periods.
Greater analytical sophistication, including AI, does not remove the need to establish whether the expectations governing a decision remain technically and economically defensible.
When rigorous optimisation concludes that little further improvement is available, what evidence would establish that the apparent limit belongs to the asset rather than to the framework within which it has been assessed?
Van der Veer, J. (2004). Van der Veer speech – full text. Speech delivered in The Hague, 15 December 2004. Financial Times, 15 December 2004. https://www.ft.com/content/73797c54-4ed2-11d9-9488-00000e2511c8
North Sea Transition Authority. Asset Stewardship Expectations. https://www.nstauthority.co.uk/regulatory-information/exploration-and-production/stewardship/expectations/
Oil and Gas Authority (2017). Recovery Factor Benchmarking. Published 7 September 2017. https://www.nstauthority.co.uk/news-publications/recovery-factor-benchmarking-report-published/
Flyvbjerg, B. (2006). From Nobel Prize to Project Management: Getting Risks Right. Project Management Journal, 37(3), 5–15. https://doi.org/10.1177/875697280603700302
The SPE London Distinguished Lecture, “Beyond the Hype: Transforming Subsurface & Production with AI Innovation,” explored how artificial intelligence is being applied across the energy industry, highlighting opportunities to improve decision-making, accelerate workflows and enhance engineering outcomes.
The hour-long lecture covered a range of applications, including waterflood management, history matching, accelerated field development planning and the emerging potential of multi-agent engineering.
A key theme was the importance of integrating AI within a broader engineering framework. Rather than relying on a single AI model to address every challenge, effective solutions combine data, physics-based modelling, optimisation and engineering judgement.
The field development example illustrated this approach. Full-physics simulation maintained technical fidelity, while machine learning proxies enabled faster exploration of uncertainty.
Risk analytics supported the ranking of development options, with engineering judgement remaining central to identifying robust opportunities.
This highlights an important distinction: AI does not replace engineering judgement, but can help extend its reach by enabling the evaluation of a broader evidence base in less time.
The discussion also raised questions about the role of comparative subsurface benchmarking in increasingly AI-enabled workflows.
While AI can help characterise a specific reservoir by integrating available data, physical understanding, uncertainty and potential development scenarios, comparative benchmarking offers a complementary perspective: assessing what experience from other assets can reveal about achievable performance under genuinely comparable subsurface and development conditions.
As subsurface workflows become more sophisticated and increasingly incorporate autonomous or multi-agent capabilities, the quality of the engineering context becomes ever more important.
Identifying appropriate comparators, establishing defensible reference points and understanding the limitations of available evidence can help ensure that AI-generated insights translate into credible engineering decisions.
The intersection of AI, physics-based modelling, comparative evidence and engineering judgement presents a significant opportunity for the subsurface and production community.
Further exploration of how these disciplines can be integrated effectively will be important in translating AI innovation into practical, robust and measurable value.
Recovery factor benchmarking helps identify where performance diverges. Analogue benchmarking helps establish what remains achievable and what it may take to get there. This article explores why accumulated analogue intelligence remains one of the most powerful tools available for identifying and extending recovery potential across mature hydrocarbon systems.
Across mature oil and gas portfolios, recovery factor benchmarking is often one of the first tools used to identify where additional value may exist.
It helps answer an important question:
Which assets appear to exhibit the greatest remaining recovery opportunity?
However, recovery factor benchmarking alone rarely provides the answer operators ultimately need.
It may indicate where performance diverges.
It does not necessarily establish what remains achievable, nor what it may take to realise it.
This is where analogue benchmarking becomes essential.
Recovery Factor Does Not Explain Itself
A recovery factor number, by itself, has limited meaning.
Suppose a field has achieved a recovery factor of 35%.
Is that exceptional?
Average?
Or materially below what remains achievable?
The answer depends entirely on context.
Recovery outcomes are shaped by geology, reservoir architecture, drive mechanism, development maturity, pressure support, intervention history, recovery strategy, operating philosophy, infrastructure constraints, and the decisions that have shaped the asset over decades.
The same recovery factor can therefore represent very different outcomes in different reservoirs.
Meaningful recovery factor benchmarking requires meaningful analogues.
Identifying The Gap Is Not The Same As Explaining The Gap
Recovery factor benchmarking and analogue benchmarking serve different purposes.
Recovery factor benchmarking helps identify where performance diverges.
Analogue benchmarking helps establish why that divergence exists, what remains achievable, and what may be required to realise it.
The objective shifts from:
What recovery factor has been achieved?
to:
What remains achievable?
and ultimately:
What would it take to get there?
This is where many benchmarking exercises stop too early.
The most valuable insights rarely emerge from identifying the gap itself.
They emerge from understanding what explains the gap.
The Real Asset Is The Independent Reference Point.
Many organisations possess data.
Many organisations possess technical expertise.
The challenge is rarely a lack of information.
The challenge is maintaining valid comparison across large populations of hydrocarbon systems that have evolved under different geological conditions, recovery mechanisms, development philosophies, infrastructure architectures, operating environments, and maturity states.
The value of analogue benchmarking does not lie in just identifying fields that appear similar.
Its value lies in maintaining valid comparison across systems that differ in important ways while remaining sufficiently comparable to establish what remains achievable.
This requires accumulated analogue intelligence.
Not assembled.
Accumulated.
Developed through long-term observation of hydrocarbon systems across operators, basins, recovery mechanisms, maturity states, and development pathways.
The real asset is the accumulated analogue intelligence behind the benchmark.
Why This Matters
The greatest long-term value losses in sophisticated hydrocarbon systems rarely arise through obvious operational failure.
More often, they emerge when accepted interpretations gradually become embedded within recovery expectations, development plans, infrastructure pathways, investment decisions, and optimisation frameworks.
Over time, these interpretations influence what is considered realistic.
They influence what is pursued.
And ultimately, they influence what is achieved.
The most significant opportunities often emerge where accepted interpretations no longer reflect what remains achievable.
Identifying and Extending What Remains Achievable
Recovery factor benchmarking helps identify where performance diverges.
Analogue benchmarking helps establish what remains achievable and what it may take to get there.
Together they provide one of the most effective mechanisms available for identifying and extending what remains achievable across mature hydrocarbon systems.
Because the objective is not simply to understand performance.
The objective is to extend it.
Benchmarking is the discipline of establishing what world-class looks like under comparable conditions – and understanding how far performance remains from that potential.
It provides an independent reference point for what remains achievable.
As systems evolve across field life, development phases, operating conditions, and changing business priorities, benchmarking helps maintain visibility of what world-class performance continues to look like – and what it may take to achieve it.
Recovery factor comparisons also have implications for the wider development strategy. FDP Benchmarking provides a broader comparative examination of development assumptions, concept choices and alternatives, while distinguishing what external evidence supports from what requires further operator-specific technical appraisal.
AI is rapidly becoming embedded across reservoir management, production systems, and facilities operations.
From subsurface modelling and well placement to process optimisation and predictive maintenance, AI is improving how decisions are made.
Across Middle East NOCs, this is already translating into:
The direction is clear. And the progress is real.
But as AI becomes more capable, a different question begins to emerge.
Not how quickly decisions can be made –
but how those decisions are anchored.
AI learns from data:
But it does not define what “best” looks like.
It does not determine:
Two systems may be optimised using AI – and arrive at very different outcomes:
But neither necessarily reflects best-in-class performance.
This is where a deeper distinction emerges.
Between:
Across reservoirs, facilities, and integrated systems, performance is shaped by context:
AI can optimise within that context.
But it does not establish whether that context itself reflects what is achievable.
This creates a subtle but important gap.
One that is not immediately visible – particularly as systems become more data-rich and more responsive.
Without a consistent basis for comparison:
Over time, this limits how far performance is extended.
Not because capability is lacking –
but because the reference point is not clear.
The challenge, then, is not only to improve performance.
It is to define it.
This is where benchmarking operates.
Not as an alternative to AI – but as a foundational layer.
Providing an independent, consistent, validated basis for understanding performance across systems, over time, and as conditions evolve.
Best-in-class performance does not immediately reveal itself.
It exists – but it is not obvious.
Benchmarking is the discipline of establishing what world-class looks like under comparable conditions – and understanding how far performance remains from that potential.
It provides an independent reference point for what remains achievable.
As systems evolve across field life, development phases, operating conditions, and changing business priorities, benchmarking helps maintain visibility of what world-class performance continues to look like – and what it may take to achieve it.
Reservoir engineers routinely draw on experience from other fields when evaluating development decisions. Yet observing that another carbonate development has achieved a different recovery or production outcome does not establish what caused that difference, still less whether the result can be replicated. A useful comparison must distinguish the observed outcome from the explanation offered for it.
Consider carbonate developments exhibiting materially different recovery or production outcomes. Differences in reservoir architecture, fracture connectivity, pore structure, wettability, fluid properties or aquifer behaviour may explain part of the variation. Development maturity, well configuration, pressure support, injection strategy and operating history may explain more. Production-system constraints can also influence what the reservoir is able to deliver.
Where the available evidence does not adequately explain a material difference, the enquiry changes. The question is no longer simply which operator performs better, but what have we failed to explain?
Comparative evidence can be valuable precisely because it tests whether the explanations currently used to understand reservoir performance are sufficient. An unexplained difference is not, by itself, an improvement opportunity or evidence of superior practice. It is a reason to examine the interpretation more closely.
There is no single population of comparable carbonate reservoirs suitable for every engineering enquiry. A comparison relevant to well productivity may be inappropriate for sweep efficiency. Developments useful for examining pressure depletion may not be the right comparators for waterflood response, infill performance, recovery efficiency or late-life redevelopment.
This distinction matters particularly in carbonates. Reservoirs with apparently similar geological descriptions can behave differently, while reservoirs that are not close geological analogues may nevertheless provide useful evidence about a particular production or development response. Comparability must be judged in relation to the behaviour being investigated, rather than assumed from a broad reservoir classification.
Reservoir performance may also be influenced by circumstances beyond the reservoir itself. For example, produced-water handling limitations can affect which wells remain on production, while injection capacity and processing constraints may influence the development choices available to an operator.
In such circumstances, a comparison confined to the reservoir would give an incomplete account of the observed outcome. For some questions the reservoir remains the appropriate boundary; for others, the relevant unit is the reservoir-development system – including wells, development decisions, facilities and operating constraints.
Suppose one carbonate development appears to achieve higher recovery than other developments considered relevant to the question. It may be tempting to attribute that outcome to better reservoir management. Yet higher recovery does not, on its own, establish that interpretation. Reservoir characteristics, development maturity, well density, completion architecture, pressure support, surveillance, intervention history and production constraints may all influence the result.
The observation that an operator used a particular practice and subsequently achieved a favourable outcome establishes an association. It does not establish that the practice caused the outcome.
The engineering question is whether the available evidence adequately supports the proposed explanation. Differences initially attributed to operating practices may also reflect reservoir characteristics, development configuration or production-system constraints.
Even after considering relevant differences between developments, some observations may remain insufficiently explained. Such differences warrant caution: they may reflect limitations in the available evidence, uncertainties in interpretation or factors not yet understood.
An unexplained difference is not evidence, by itself, of superior operator practice or previously unrecognised reservoir behaviour. Its value lies in the questions it raises.
Sometimes those questions concern development choices or surveillance. Sometimes they concern the interpretation of reservoir behaviour. Where relevant external experience remains inconsistent with an established explanation, that explanation may warrant reconsideration.
What if the unexplained difference is telling us something about the reservoir rather than the operator?
Cross-operator comparisons are generally based on observational evidence, not controlled experiments. Even where a particular practice is associated with a favourable outcome, other reservoir and development differences may have contributed to that outcome.
Attribution therefore requires disciplined language. The available evidence may support an explanation, make it more plausible or challenge competing explanations without establishing a single cause with certainty. An observed advantage should not be assigned to operator behaviour simply because it remains after the most obvious differences have been considered.
An asset team may understand its own reservoir in considerable detail while having limited visibility of how other developments have responded under different conditions and decisions. Wider comparative evidence can expose observations that are difficult to recognise within one field history. Its contribution is not merely a ranking of operators, but a more demanding test of what the observed differences permit us to infer.
Even where the explanation for a favourable outcome is credible, a separate question remains: would the same practice be appropriate elsewhere?
The effectiveness of an intervention may depend on fracture behaviour, mobility ratio, pressure conditions, well configuration, development maturity, surveillance capability or facility capacity. A practice associated with improved performance in one development may be ineffective – or unsuitable – in another.
Attribution asks why an apparent advantage occurred. Transferability asks whether the conditions associated with that advantage exist elsewhere.
The distinction matters because identifying a credible explanation for another operator’s performance is not the same as establishing a development option for one’s own reservoir. The latter requires judgement about the local reservoir and production system, the proposed intervention and the consequences that can reasonably be expected.
The same discipline applies when comparing the use of AI, advanced surveillance, digital workflows or more sophisticated reservoir models. The fact that another operator adopted a technology establishes little about its engineering consequence.
A more useful enquiry is whether the technology changed what the operator understood or decided. Did it reveal previously unrecognised connectivity, alter infill placement or injection allocation, overturn an existing interpretation, or reduce uncertainty sufficiently to change a development decision? Did earlier recognition of reservoir behaviour lead to a different intervention?
Even where decisions changed, a further distinction remains between the decision and the subsequent reservoir outcome. Have materially different decisions associated with these technologies produced materially different results, and what evidence supports that interpretation? Comparative experience may help examine that question, but technology adoption alone cannot answer it.
Across Fulcrium’s comparative reservoir work, apparent performance differences have sometimes become less straightforward as they are examined more closely. Outcomes initially associated with reservoir-management practice may also reflect reservoir characteristics, development configuration or production-system constraints. At times, a material difference remains without a sufficiently supported explanation.
An unexplained difference is not a conclusion. It is a reason to question whether the prevailing interpretation adequately accounts for the evidence.
These observations draw on Fulcrium’s comparative reservoir work involving approximately 15 international and national oil companies, considered in the context of wider full-value-chain benchmarking experience across approximately 90 oil and gas operators. These are descriptions of the scope of experience, not a statistical sample from which general reservoir-performance relationships are claimed.
A useful comparison may change how a reservoir team interprets a performance difference, which explanation it tests next, or which development option it regards as credible. That consequence does not necessarily depend on identifying the highest-performing operator or a practice to copy. Sometimes the more consequential result is discovering that the existing interpretation does not adequately account for the evidence.
The question then becomes whether another operator is doing something we have not understood – or whether the comparison is revealing something about reservoir behaviour that we have not yet understood.
And sometimes the most valuable thing we can learn from another operator is not what to replicate.
It is what to question in our own reservoir.
When you step into a supergiant field such as Ghawar, Burgan, or Rumaila, it becomes immediately clear that no two reservoirs are alike – even when production levels appear similar on paper.
Differences in structure, drive mechanisms, fluid systems, development history, and operating strategy all shape how performance is expressed over time.
In these environments, performance is not defined by a single metric.
It is the result of how multiple factors interact:
pressure support, sweep efficiency, well placement, completion design, and the timing and sequencing of interventions.
Across large-scale reservoir systems, this complexity is well understood.
Significant capability has been built – in modelling, surveillance, data integration, and increasingly in the application of AI – to better characterise behaviour and support more informed decisions.
As a result, performance is continuously being improved.
But as capability increases, the nature of the question begins to shift.
It is no longer only about how to improve performance within a reservoir.
It is also about how that performance is anchored against what is fully achievable under comparable conditions.
Two reservoirs may exhibit similar production profiles, while operating at different levels of recovery efficiency.
Two development strategies may deliver comparable short-term outcomes, while diverging materially over the life of the field.
And two assets may both be improving – while progressing toward different performance horizons.
These differences are not always immediately visible.
Not because they are hidden – but because they are expressed through the interaction of many variables over time.
Best-in-class performance does not immediately reveal itself.
It exists – but it is not obvious.
As a result, the interpretation of performance becomes increasingly important.
Not just within a reservoir, but across reservoirs.
This is where benchmarking plays a distinct role.
Not as comparison alone, but as a discipline that maintains valid, comparable interpretation of performance across fields, reservoirs, over time, and as conditions evolve – helping ensure that performance is anchored against what is fully achievable, and that insight can be applied without distortion.
Best-in-class performance is not obvious – but it exists, can be identified, and applied within and across oil & gas systems.
In LNG systems, performance is not constrained by individual components, but by how tightly integrated systems operate under continuously shifting conditions.
On the surface, trains within the same complex often look similar – comparable output, comparable efficiency.
But over time, that similarity starts to drift. Not dramatically. Not all at once. Just enough to matter.
Small differences begin to show up:
Individually, none of these raise concern. Collectively, they start to shape how performance evolves.
What makes this more complex is that LNG trains don’t operate in isolation.
So what you’re seeing isn’t just train performance – it’s system behaviour. And this is where things get interesting.
Two trains can sit side by side, deliver similar results, yet behave very differently when conditions change. Over time, that difference becomes more than noise. It becomes structural.
Later trains often reflect improvements – design refinements, operational learning, adjustments based on earlier experience.
But those improvements are shaped by what has already been seen. And just as importantly, what hasn’t.
What works in one context doesn’t always carry across cleanly to another.
This is where benchmarking starts to shift in meaning. It’s no longer just about comparison. It’s about understanding what actually holds up.
The reality is, large-scale LNG operations already have data. They have visibility. They have highly capable teams.
Benchmarking itself isn’t new. It happens internally, across joint ventures, and with external providers.
And yet, outcomes vary. Not because of a lack of effort – but because maintaining comparability as systems evolve is far from straightforward.
What matters is not just what is measured, but how performance is interpreted in context.
When you look across LNG systems in this way, patterns begin to emerge.
These differences are rarely visible from within a single system.
What distinguishes more advanced approaches is access to unbiased data, and the ability to assess performance across systems, and over time, and in a way that remains consistent.
At that point, benchmarking becomes something different.
Not a comparison exercise –
but a discipline through which performance can be understood, tested, and extended…
…beyond the limits of any individual system or organisation.
Best-in-class performance does not immediately reveal itself.
It exists – but it is not obvious.
Benchmarking is the discipline of establishing what world-class looks like under comparable conditions – and understanding how far performance remains from that potential.
It provides an independent reference point for what remains achievable.
As systems evolve across field life, development phases, operating conditions, and changing business priorities, benchmarking helps maintain visibility of what world-class performance continues to look like – and what it may take to achieve it.
In large-scale facilities systems, performance is not defined by individual units, but by how the system behaves as a whole.
Across gas-oil separation plants, central processing facilities, compression systems, stabilisation trains, and export networks, processing is tightly coupled – often across long-life, high-throughput assets.
At this scale, capacity on paper is only a starting point.
Throughput depends on how constraints are understood and managed across the system.
This is where facilities systems become more dynamic.
A compressor operating slightly off design conditions, a separator approaching its limits, or variability in upstream fluids can introduce effects that propagate across the system.
Individually, these effects are familiar. Collectively, they shape how performance is expressed.
Across Middle East NOCs, significant capability has been built to manage this complexity.
Advanced process control, real-time monitoring, integrated workflows, and increasingly AI-enabled optimisation are improving visibility, responsiveness, and operational precision.
As a result, facilities performance continues to evolve.
As systems become more capable and more integrated, the nature of the question begins to shift. It is no longer only about how to improve performance within a facility.
It is also about how that performance is anchored against what is fully achievable across comparable systems.
Facilities with similar configurations and nominal capacities can perform differently in practice.
Not because of a single defining factor, but because of how constraints are managed, how systems are operated, and how decisions are sequenced over time.
These differences are not always immediately visible. They are expressed through the interaction of the system.
Best-in-class performance does not immediately reveal itself. It exists – but it is not obvious.
As a result, the interpretation of facilities performance becomes increasingly important.
Not just within a single asset, but across facilities.
This is where benchmarking plays a distinct role.
Not as comparison alone, but as a discipline that maintains valid, comparable interpretation of performance across facilities, fields and reservoirs, over time, and as conditions evolve – helping ensure that performance is anchored against what is fully achievable, and that insight can be applied without distortion.
Best-in-class performance is not obvious – but it exists, can be identified, and applied within and across oil & gas systems.
An FDP may be technically rigorous, internally assured and robust across the development assumptions and uncertainty ranges examined. That does not necessarily establish that the assumptions, ranges and alternatives themselves remain adequate.
This distinction becomes consequential when a mature field approaches a major Field Development Plan (FDP) revision, redevelopment concept selection or substantial infrastructure commitment.
Operators routinely examine alternative development concepts, optimise production strategies and test the sensitivity of development economics to uncertain reservoir and operating conditions. The more difficult question is whether the appraisal has adequately represented the development possibilities and evidence relevant to the decision.
Does continued optimisation of the existing FDP offer the most defensible development choice, or does the available evidence warrant strategic reassessment?
The question does not presume a deficiency in the operator’s technical capability or assurance processes. Sophisticated operators already possess substantial development experience, field-specific knowledge, external analogue information and established investment decision procedures.
Rather, it concerns the limits of what an appraisal can establish from the assumptions and alternatives it contains.
An appraisal may be internally consistent and its preferred alternative robust across the uncertainty ranges examined. Yet additional field-specific information, relevant external experience or changes in development conditions may still raise questions about the completeness of those ranges, the plausibility of particular assumptions or the development alternatives considered.
The technical task is to distinguish an opportunity for further optimisation from evidence that may justify reconsidering the development strategy itself.
An established FDP is not necessarily an exhausted development strategy.
Opportunities may remain through improved well placement, completion design, injection management, reservoir surveillance, production allocation and facilities performance.
At Upper Zakum, ADNOC and its partners, including ExxonMobil and INPEX/JODCO, adopted a development architecture combining artificial islands and extended-reach drilling. In 2022, ADNOC reported that further extended-reach drilling could access previously undeveloped resources, potentially increasing production capacity by 15,000 barrels of oil per day without additional infrastructure.
This illustrates how an established development architecture can continue to offer opportunities as technology and technical understanding advance.
Other fields may encounter constraints that incremental improvement cannot adequately address. Ageing infrastructure, changing distributions of remaining hydrocarbons, well configurations or development sequencing may warrant materially different approaches.
In gas developments, the relevant constraints may extend across reservoir deliverability, wells, gathering, compression, processing and export infrastructure.
The Schiehallion–Loyal Quad 204 redevelopment illustrates the breadth of alternatives that may be examined during redevelopment planning. A published technical account describes an appraisal involving 16 customised depletion plans, combining four development options with four offtake-rate cases. The development options included refurbishment of the existing FPSO, a new FPSO with subsea development, a tension-leg platform and a semisubmersible concept.
These examples illustrate different forms of development choice. They do not establish that either operator overlooked an alternative or pursued an inappropriate strategy.
The distinction between optimisation and strategic reassessment concerns the development choices being examined, not simply the physical scale of an intervention.
Optimisation seeks additional value within the strategy being pursued. Strategic reassessment reconsiders material assumptions, objectives or choices underlying that strategy, including recovery approach, depletion sequencing, development configuration, infrastructure commitments or investment timing. A major FDP revision may involve both.
The economic task is to compare feasible development choices on a consistent basis, considering remaining-field value, uncertainty, risk and the operator’s applicable strategic and investment criteria.
Higher recovery, increased production capacity and extended field life may contribute to an attractive development outcome, but none necessarily maximises economic value.
Remaining-field net present value (NPV) is an important measure, although production-capacity commitments, resource stewardship, domestic supply obligations, infrastructure dependencies, emissions requirements and portfolio considerations may introduce additional objectives or constraints.
A technically attractive development alternative is therefore not necessarily the preferred investment choice.
Development alternatives may also differ in the flexibility they preserve. Staged investment, deferred commitments and adaptable infrastructure can allow subsequent decisions to respond to improved reservoir understanding or changing economic conditions. Their value must be assessed alongside production performance, capital requirements and the consequences of irreversible commitments .
Strategic reassessment is not justified merely because another operator has achieved higher recovery, greater productivity or adopted a different development approach.
The relevant question is whether new understanding, changed circumstances or comparative evidence raises a material question about the development choices currently being pursued.
Three conditions are particularly important.
A material development question. There must be a credible reason to reconsider an existing assumption, reassess the relative merits of alternatives or investigate a development possibility not adequately represented in the current appraisal. This may arise from improved reservoir understanding, new technologies, changing infrastructure constraints, revised economics or relevant experience elsewhere.
Technical relevance. The evidence must be sufficiently applicable to the subject field to justify examination. Geological characteristics, fluid properties, reservoir architecture, recovery mechanisms, wells, facilities and implementation requirements must be considered. Success elsewhere does not establish local feasibility.
Potential decision consequence. The question must have sufficient prospective significance, relative to the costs, risks and uncertainties of further examination, to warrant appraisal. Its consequence may concern the selected development concept, investment scale, sequencing, implementation conditions or the evidence required before commitment.
Strategic reassessment does not necessarily require additional data acquisition. Existing evidence may be sufficient to justify reconsidering the alternatives or assumptions defining the decision. Where additional information is proposed, its value depends on whether it could improve the decision sufficiently to justify the associated cost, delay and risk .
These conditions do not require proof that a different strategy will outperform the existing FDP. They require a defensible basis for believing that further examination could materially affect the decision.
The practical distinction is whether the question can be adequately addressed by optimisation within the existing strategy, or whether the development choices and assumptions underlying that strategy themselves require reconsideration.
A change in injection strategy, well configuration or facilities capacity may constitute optimisation within the existing FDP. However, where evidence raises a material question about the recovery approach, allocation of development capital, depletion sequencing or infrastructure strategy, broader reassessment may be warranted.
This distinction is not a rigid threshold. Several individually modest changes may collectively justify a different development strategy, while a substantial capital investment may remain consistent with the original approach.
Strategic reassessment need not involve reopening the entire FDP. Its scope should follow the assumptions and choices affected by the evidence.
Where no material question is established, continued optimisation may remain the appropriate course.
Major operators already undertake uncertainty analysis, sensitivity testing and comparative evaluation of development alternatives.
These established practices can demonstrate whether a preferred strategy remains robust across the assumptions and uncertainty ranges examined. They do not, solely through internal consistency or sensitivity analysis, establish that those assumptions, ranges and alternatives adequately represent all material development possibilities.
The adequacy of those boundaries may already have been examined through field-specific evidence, external analogues and independent assurance. Further comparative examination is justified only where a material question remains insufficiently resolved.
External observations become useful only when their relevance and limitations are understood. Independent comparative judgement must remain accountable for the conclusions it draws, including what the evidence cannot establish.
Independence does not compensate for inadequate evidence or analytical capability. Nor does external information necessarily improve an appraisal that already contains sufficient relevant evidence.
Where a consequential evidential question remains, external experience may bear on development assumptions, the relative merits of alternatives or the range of development choices considered.
FDP appraisals depend on assumptions about reservoir behaviour, recovery, well productivity, production decline, operating performance, development costs and uncertainty.
Appropriately selected external analogues may support, qualify or challenge performance expectations underlying the appraisal.
For example, a comparison may reveal differences in well productivity or decline behaviour that remain unexplained after accounting for relevant reservoir, completion and operating characteristics.
The observation does not establish that the subject field could reproduce another operator’s outcome. Nor does it establish that the original development assumption is incorrect.
It identifies a question requiring further examination.
The explanation may lie in reservoir characteristics, well design, operating conditions, measurement conventions or factors not adequately represented in the comparison. In some cases, the evidence may challenge not merely an assumed parameter value, but the adequacy of the explanation or model used to derive it.
Differences between fields can have many explanations. Even an unexplained difference does not, by itself, demonstrate an opportunity or justify changing an FDP. Its significance depends on the strength and relevance of the evidence and on the decision at issue.
The usefulness of external evidence depends on the question. Development practices, productivity outcomes and cost relationships may be amenable to comparison, while reservoir connectivity and field-specific subsurface behaviour may depend predominantly on proprietary information and detailed modelling.
External evidence cannot automatically provide statistically reliable probability distributions or substitute for field-specific reservoir models.
An operator may already have evaluated several technically credible development alternatives.
Their relative attractiveness depends on assumptions about production profiles, recovery, capital requirements, operating costs, implementation risks and uncertainty.
Consider an appraisal comparing continued infill drilling within existing infrastructure with a more substantial redevelopment involving different well configurations and facilities investment.
The preferred alternative may depend materially on expected well productivity, decline behaviour, recovery and infrastructure performance.
Relevant external evidence might indicate that a productivity assumption warrants reconsideration under comparable reservoir and completion conditions.
The operator can then examine the consequences through its field-specific technical and economic appraisal.
The significance of the comparative finding depends not simply on the size of the observed difference, but on the sensitivity of the development decision to the assumption being examined.
A substantial discrepancy may have limited decision significance if the preferred strategy remains robust across plausible values. Conversely, a relatively modest discrepancy may be consequential where it changes the relative attractiveness of development alternatives.
Even where comparative evidence does not change the preferred concept, it may influence investment timing, development sequencing, contingency provisions, implementation safeguards or the further evidence required before commitment.
The value of comparative evidence lies in its ability to inform a material development judgement, not merely to establish that two fields have performed differently. This example is illustrative, not a reported project outcome.
External experience may identify a credible development configuration or approach not adequately represented in the current appraisal.
Changes in technology, reservoir understanding, infrastructure constraints or economics may also justify reconsidering an option previously rejected.
This does not establish that the operator overlooked an alternative or made an incorrect earlier decision. Such conclusions require examination of the original appraisal, its assumptions and the circumstances prevailing when the decision was made.
The technical question is whether the evidence identifies a development possibility that remains feasible and potentially consequential under current conditions.
A previously rejected alternative may warrant renewed examination because the circumstances affecting its feasibility or economics have changed. Equally, an approach successful elsewhere may remain unsuitable for the subject field.
Comparative evidence may confirm the existing strategy, qualify its assumptions or warrant further examination of development choices. It need not result in a different preferred FDP.
Consequential development decisions cannot always be resolved through conventional performance indicators. Independent comparative judgement may contribute where relevant external experience bears on a material question that remains unresolved in the development appraisal. Its usefulness depends on the quality, applicability and limitations of the available evidence.
Comparative evidence must be evaluated against the characteristics relevant to the question being investigated.
Differences in recovery performance or development outcomes are not self-explanatory. Reservoir characteristics, recovery mechanisms, development histories and operating conditions can materially affect their interpretation. Historical associations may inform an appraisal but do not, on their own, establish causation.
A performance gap is therefore a starting point for investigation, not a measure of recoverable opportunity.
The question is what the evidence permits one to infer about the subject development, including the uncertainty and limitations of that inference.
Reservoir performance cannot always be understood independently of wells, facilities and infrastructure.
In a mature waterflood approaching its produced-water handling capacity, changes to injection strategy may affect sweep, water production, facilities utilisation, infill well productivity and the economics of additional drilling or processing capacity.
Removing an apparent constraint does not necessarily increase economically recoverable production. Other constraints may remain binding, production may shift between periods, or the additional output may not justify the expenditure required.
Similar interactions arise in gas developments, where reservoir deliverability, wells, compression, gathering, processing and export infrastructure jointly influence production capability and economics.
These interactions illustrate why a purely disciplinary view may be insufficient for a consequential development decision.
Relevant external experience may inform development assumptions and the evaluation of alternatives, but the operator’s field-specific technical and economic appraisal remains essential. A defensible independent opinion should make clear the extent of its evidential support, its material uncertainties and the limits of the conclusions reached.
The purpose is not to replace the operator’s development appraisal with an external benchmark. It is to establish what comparative evidence can legitimately contribute to the assumptions and choices underlying that appraisal.
The operator retains responsibility for developing the FDP and making the development and investment decision.
An independent comparative institution is responsible for the independence, evidential basis, methodology, limitations and defensibility of its own opinion. That responsibility does not constitute comprehensive technical verification or certification of the FDP, reservoir model or reserves estimates.
Fulcrium’s independent comparative perspective draws on accumulated cross-operator experience across reservoirs, wells, drilling, facilities, capital projects, operations and costs.
Where the evidence cannot responsibly support the intended conclusion, the appropriate outcome may be a qualified opinion, additional evidence, revised scope or no opinion.
The balance between continued optimisation and strategic reassessment cannot be determined by a general rule.
For some fields, the greatest remaining economic value lies in improving the existing strategy. For others, changes in reservoir understanding, technology, infrastructure economics or remaining resource distribution may justify reconsidering material elements of it.
The distinction becomes particularly important before a major FDP revision, redevelopment concept selection, material recovery-strategy change or substantial infrastructure commitment.
Four questions follow from the preceding analysis:
Are the material performance and economic assumptions underlying the preferred development concept consistent with sufficiently relevant evidence?
Have credible development alternatives been examined using assumptions and uncertainty ranges that remain defensible?
How sensitive is the development decision to plausible changes in the assumptions that matter most?
Could relevant comparative evidence change the assessment of alternatives, the conditions under which investment proceeds or the need for further appraisal?
These questions do not presume that the existing FDP is deficient or that redevelopment is preferable to continued optimisation.
They concern the evidential boundaries within which the development decision is being made.
An appraisal may demonstrate that a preferred development strategy is robust across the assumptions and alternatives examined. That is a meaningful result, but its significance depends on whether those assumptions and alternatives adequately represent the material possibilities relevant to the decision.
Those boundaries may already have been examined and found defensible through the operator’s own technical work and assurance processes. Where a material question remains unresolved, relevant comparative evidence may help support existing assumptions, explain observed differences, challenge an interpretation or identify development possibilities warranting further appraisal.
The contribution of independent comparative judgement is conditional on the relevance and sufficiency of the evidence, the quality of its interpretation and its potential significance to the decision.
A defensible FDP decision requires both a robust appraisal of the development choices examined and an adequate evidential basis for the boundaries within which those choices were evaluated.
Independent FDP Benchmarking provides an external comparative basis for examining development assumptions, evaluating relevant analogues and identifying where optimisation may need to give way to a more fundamental reassessment of the development strategy.
Fulcrium provides independent benchmarking and comparative judgement to the oil and gas industry.
Its work draws on accumulated cross-operator experience and complementary benchmarking disciplines spanning reservoirs, wells, facilities, operations, capital projects and commercial performance.
Fulcrium brings independent comparative evidence and cross-system perspective to consequential technical, operational and investment decisions, while recognising the boundaries of what external evidence can establish.
Fulcrium’s independent benchmarking opinions are governed by institutional standards addressing professional relationships, independence, evidential sufficiency, methodological integrity and professional responsibility.
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