Two Purposes — One Independent Expert Review

A major Malaysian HPHT development required independent well verification as part of its assurance process. But limiting an experienced HPHT reviewer only to the minimum safety-critical verification scope would leave substantial technical value unexplored.

The review was therefore deliberately used for two complementary purposes:

A Living Assurance Thread — Not a Final Document Check

The tracker records issues arising from peer review of development planning since early 2020, multiple review discussions, stage-gate work and subsequent specialist engineering studies.

Verification therefore follows the engineering as it develops:

Concept → Design → Specialist Studies → Decisions → Detailed Engineering → Well Programme → Execution Readiness → Close-Out

Future key verification documents remain visible in the process until the project is mature enough for them to be reviewed.

The Tracker Turns Challenge into a Traceable Technical Conversation

Three Levels of Challenge

The Broader Peer Review Creates the Second Value Stream

Across successive HPHT wells and the development programme, the independent questions extend well beyond statutory or safety-critical verification.

They challenge subjects such as analogue selection, well architecture, casing design and setting depths, PPFG definition, thermal modelling, materials selection, completion design, annular pressure management, karst risk, PMCD contingencies, well clean-up, QA/QC, equipment qualification and operational planning.

That broader challenge can reveal opportunities for time saving, simpler well architecture, improved drilling practices, reduced NPT exposure, better contingency planning and more efficient technical solutions.

Expertise Matters More Than the Checklist

The value of the process depends heavily on the competence of the person performing it.

A checklist can confirm that a document exists. An experienced HPHT specialist can recognise when the engineering inside the document deserves challenge — and can connect an observation in one discipline to consequences elsewhere in the well.

Pressure assumptions → Casing design → Kick tolerance → MPD philosophy → Materials → Thermal behaviour → Completion loads → Barrier philosophy → Life-of-field integrity

Challenge Without Taking Ownership

The verifier does not become the well designer.

For essential RED findings, satisfactory evidence is required before close-out. For the wider peer-review observations, the project retains ownership of the engineering decision.

This preserves an important boundary:

That makes the process rigorous without turning independent review into another parallel engineering organisation.

Open Does Not Mean Failed

The development has not yet progressed through all final investment and execution stages, so a number of verification items appropriately remain open.

Some cannot legitimately be closed until final design, Basis of Design documentation, long-lead equipment qualification, detailed operational planning or other future evidence exists.

The tracker therefore keeps important questions visible rather than forcing premature closure simply to make the register appear complete.

Learning Accumulates Across Wells

The verification workbook contains trackers from earlier exploration and appraisal wells as well as successive development revisions.

That allows questions and lessons from one well to influence the next:

Question → Response → Learning → Development Design Input → Verification Requirement

The process therefore provides both independent assurance and a mechanism for transferring hard-earned HPHT learning into later wells.

Assurance + Optimisation

The Starting Point — Genuine Technical Uncertainty

A first CCS development required long-term CO₂-resistant cement systems across several well conditions, including a technically demanding high-temperature liner application at approximately 171°C BHST.

The understandable response to first-of-kind operations was increasing conservatism: more testing, more qualification requirements and additional assurance.

The real question was: what constitutes sufficient evidence that a cement system is fit for long-term CCS service?

Market Visibility Before Selection

The process began with an extensive technical market survey rather than selecting a preferred product and writing the specification around it.

Potential suppliers were challenged through detailed technical presentations and a 30-point technical market-survey questionnaire, supported by explicit critical technical acceptance criteria.

The selected provider offered the strongest overall combination of competitive pricing, a technically mature CO₂-resistant cement system and practical execution continuity with the rig programme.

From “Test Everything” to “Test What Matters”

An earlier qualification philosophy effectively treated the full range of cement properties as direct qualification tests.

That appeared conservative — but the more fundamental question was whether repeating every available laboratory test on every proposed slurry actually improved the qualification decision.

The final programme reorganised 13 parameters according to the purpose of the evidence, rather than treating every test as equally necessary.

Tier 1 — Mandatory Performance Validation

Direct testing was retained for the parameters needed to demonstrate that the actual proposed cement remained intact and mechanically stable following CO₂ exposure:

Visual integrity · Mass change · Bulk density · Carbonation behaviour · UCS retention

Acceptance was deliberately based on the overall pattern of evidence across the validation suite rather than a single isolated result.

Tier 2 — Diagnostic Investigation

SEM/CT and XRD/XRF were retained — but no longer required automatically.

They became diagnostic tools triggered by anomalous evidence such as unexpected strength loss, abnormal carbonation behaviour, excessive mass change or visible degradation.

Tier 3 — Qualification by Analog Evidence

Porosity, permeability, tensile strength, Young's modulus, Poisson's ratio and self-healing behaviour could be demonstrated using relevant validated laboratory programmes and field experience.

But the analogue evidence had to be technically traceable: cement-system lineage, specimen preparation, curing conditions, exposure conditions, temperature, pressure, CO₂ phase, exposure duration, measured results and engineering interpretation.

If the evidence proved insufficient, direct testing remained available.

Optimising the Test Itself

Rather than spend specimens on a low-value two-week checkpoint, the agreed programme concentrated the available samples at the more meaningful one- and two-month exposure points, reducing the influence of rogue or unrepresentative results.

The programme also focused on an agreed worst-case CO₂ exposure medium, representative baseline specimens and a practical witness protocol using physical and virtual witnessing, video and time-stamped records.

A Small Technical Detail That Tells the Bigger Story

Carbonation depth initially appeared suitable for a simple numerical pass/fail criterion.

But reduced-Portland / SCM cement systems contain less free portlandite than conventional Portland cement, so phenolphthalein response does not necessarily translate directly into damaging carbonation progression.

The final criterion therefore required carbonation behaviour to be interpreted collectively with the remaining CO₂ validation evidence.

The Fixed-Price Compliance Warranty

Once the technical requirement was clear, the remaining question was commercial: who carries the consequence if the proposed cement system does not meet the agreed criteria?

The contractor warrants that the proposed CO₂-resistant system can meet the agreed acceptance criteria, with all materials, testing, engineering and QA activities required for compliance included in the tendered price.

If the proposed system fails:

Reformulate → Retest → Requalify — at the contractor's own cost.

The operator is not obliged to pay for an upgraded or premium system merely to achieve the performance originally tendered.

From Technical Selection to Practical Execution

The contracting philosophy separated specialist technical ownership from physical field execution.

The CO₂ cement specialist retained responsibility for formulation, qualification, specialist materials, QA/QC and technical sign-off, while field pumping equipment, bulk facilities and execution crews remained integrated with the rig's existing cementing operation.

In the final selection, technical capability, commercial competitiveness and execution continuity aligned rather than competing with each other.

Three Tiers — One Qualification Logic

The Starting Position

Following the sale of an offshore asset, three legacy suspended subsea exploration wells remained within the operator's Australian portfolio.

The inherited interpretation pointed towards a substantial abandonment campaign: two wells appeared to require rig-based remediation and another required subsea wellhead removal.

Do Not Treat Three Wells as One Project

Instead of immediately developing a rig campaign around the inherited scope, each well was reconstructed from the available evidence.

What was actually drilled? · What reservoir had been penetrated? · What barriers were installed? · What verification existed? · What was the credible flow path? · What did the regulations actually require?

The answers were different for every well — and the original scope began to unravel.

The Well That Wasn't There

The oldest well represented the largest apparent abandonment liability. Historic records showed it as suspended and non-compliant with modern abandonment expectations, making it the strongest driver for definite rig-based remediation.

Then an unexpected lead changed the investigation. A newly appointed project manager had direct knowledge of the previous operator. Follow-up enquiries established that the well had actually been permanently abandoned years earlier and its subsea wellhead had already been cut and recovered below mudline.

Yet the official databases and successive regulatory documents still showed the well as suspended.

Because the historic abandonment would not have met modern requirements, failure to resolve that discrepancy would still have driven the project towards a rig entry. Direct engagement with the regulator ultimately removed the well from the active WOMP and from the operator's remaining liabilities.

The “Inadequate” Barrier

A second well appeared to require supplementary deep cement because the existing barrier provided approximately 51 m of cement above the reservoir versus a nominal 60 m criterion.

Rather than accept that threshold mechanically, the well was reconstructed in detail: drilling history, reservoir penetration, logged annular cement, plug placement and tagging, fluid conditions, hydrostatics, cement shear capacity and the credible future flow mechanism.

The analysis demonstrated that the existing barrier already reduced the risk to ALARP and that additional cement would not materially improve the outcome.

The Project Changed Shape Again

The original P&A campaign had now effectively disappeared. The remaining question was no longer how to re-enter and abandon wells.

Each time a major element of scope disappeared, the project did not stop. The next remaining assumption was tested again.

Should the Wellheads Even Be Removed?

The default route was complete subsea wellhead removal. An alternative was therefore assessed: could the wellheads safely and responsibly remain in situ?

A formal comparative assessment considered:

Environment · Socio-economic impact · Technical feasibility · Health & Safety

The leave-in-situ option produced equal or better outcomes across the assessment criteria, with negligible environmental and socio-economic impacts and no material technical or health-and-safety disadvantage.

Then the ROV Added Another Piece of Evidence

A low-cost vessel-based ROV inspection was performed on the two remaining wellheads. Both were inspected within a single 12-hour ROV shift during the offshore campaign.

The inspection showed the structures heavily colonised by marine life — effectively functioning as small artificial reefs against an otherwise relatively featureless seabed.

That did not by itself justify leaving offshore infrastructure in place, but it strengthened the central question:

Regulation Was Part of the Engineering

The project could not be solved by engineering alone. Closure required technical evidence, ALARP demonstration, environmental assessment, stakeholder consultation, regulatory acceptance and ultimately the required approval to leave the structures in situ.

Well-barrier analysis · Regulator engagement · Comparative risk assessment · Environmental assessment · Stakeholder consultation · ROV verification · Cross-government engagement · Final disposal approval

The technical answer had to survive the entire regulatory and assurance system.

Always Keep a Fallback Path Alive

While the leave-in-situ route was being pursued, approval remained uncertain. A parallel contingency was therefore engineered rather than waiting passively.

A detailed study developed a rigless boat-based wellhead cutting and recovery option using a DP2 vessel, WROV and subsea cutting equipment.

Even the fallback was optimised: a lower-cost AHTV concept used the vessel's anchor-handling winch instead of a specialist construction vessel with a large active-heave-compensated crane.

Ultimately, the fallback was not required.

A Lean Project Operating Model

With no full permanent technical and contracting organisation remaining in-country, the project avoided rebuilding one for a temporary requirement.

A specialist local well-management organisation supplied the project execution, assurance and contracting capability, while the operator retained technical direction and decision ownership.

Progressive Scope Collapse

The Opportunity

A fleet of approximately 13 offshore drilling rigs represented a significant and recurring energy demand, with typical consumption of approximately 500 m³ MGO per rig per month.

The long-term opportunity included improved equipment and energy-efficiency requirements in future rig contracts. But the first question was more immediate:

How much could be achieved now — using the existing contracted rig fleet?

Creating Visibility

A unique fleet-wide performance system connected fuel consumption with the factors actually driving it.

8 connected KPIs combined MGO consumption, generator loading, low-load operation, generators online, high-load excursions, MGO/engine-hour, water-maker operation and estimated rig power demand.

This separated two different questions: How much power does the rig need? and How efficiently are we generating it?

AI-Assisted Performance Workflow

With recurring data arriving from the fleet, an AI-assisted analytical workflow accelerated data processing, quality checking, trend analysis and preparation of rig-performance reviews.

A fleet-wide KPI Tracking Dashboard provided rapid visibility of fleet trends, rig-to-rig comparison, KPI exceptions, generator loading, MGO performance and improvement against target.

AI accelerated the analysis; technical interpretation and operational decisions remained engineering-led.

The Opportunity Became Visible

An additional engine could remain online as operational “comfort” capacity, leaving several generators operating below their more efficient loading range.

From “Comfort Mode” to Win-Win

Changing established generator philosophy required more than a fuel-saving calculation. Contractors needed confidence that improved dispatch would not transfer additional blackout or NPT risk to them.

The case was positioned as a win-win: lower MGO consumption and GHG emissions, fewer engine running hours, reduced maintenance exposure and more efficient use of generating assets.

Efficiency without compromising reliability.

Existing Rigs First — Future Contracts Next

Existing fleet: capture low-hanging-fruit opportunities now through generator dispatch, PMS philosophy, auxiliary loads and operating practice.

Future fleet: use evidence from the existing rigs to strengthen future specifications, power-system philosophy and energy-performance expectations.

This avoided making future technology a prerequisite for immediate improvement.

The Starting Point

A relatively inexperienced operator was preparing to drill another well in a technically demanding offshore HPHT development.

Senior management recognised the need for external support and commissioned an independent peer review to provide “an informed outside pair of eyes, with both extensive HPHT & Complex Wells Experience.”

The initial scope was to review the project history, previous wells, current drilling and completion plans, modelling, subsurface information and HPHT operating instructions — then identify where additional engineering or preparation could improve the chances of delivering the well objectives.

Follow the Warning Signals

The first important discovery was that the project was indeed challenging — but HPHT was only one element.

HPHT conditions · Unconventional tight reservoir · Offshore execution · Small platform rig · High cost exposure · Limited repetitive learning · Cost pressure · Organisational inexperience

The peer review therefore widened naturally. What began as an HPHT technical review became an assessment of how the entire well-delivery system was functioning.

The HPHT “Smokescreen”

The previous well had taken approximately 206 days against 146 days planned, including substantial NPT and unplanned activity. The next well was again trending towards roughly 200 days.

The review separated genuine HPHT difficulty from removable time — conventional NPT plus Invisible Lost Time created by inefficient practices, weak critical-path management, unnecessary trips, inefficient equipment configuration and suboptimal planning.

Diplomacy Was Part of the Technical Work

Many observations challenged established decisions, practices and organisational behaviours. Simply issuing harsh findings would not create improvement.

Evidence before judgement · Questions before accusations · Demonstrate consequences rather than criticise individuals · Separate system weaknesses from personal competence · Offer practical alternatives alongside each challenge

The objective was to translate difficult technical findings into recommendations the organisation could accept and act upon.

The Review Kept Changing Direction

The warning signals led into areas that had not necessarily been expected to dominate the original review.

Differential sticking — increasing overbalance challenged drillpipe capability, jarring effectiveness and pipe-release practices.

Mud specification — a nominally compliant HPHT fluid-loss specification was challenged against the actual differential-sticking environment.

Well control — several operating practices were challenged against robust HPHT practice.

PPFG definition — insufficient focus on formation-top uncertainty and continuous pore-pressure / fracture-gradient definition was identified.

A Boston Square

The findings were converted from a long list of observations into a practical improvement programme using:

VALUE OF IMPLEMENTATION × DIFFICULTY TO IMPLEMENT

Optimise Total Value — Not the Cheapest Line Item

One recurring pattern was excessive focus on reducing individual service or equipment costs without sufficient consideration of total well value.

Relatively small procurement savings could increase operational risk or create delays many times larger than the original saving.

The Bigger-Hole Question

One example concerned the proposed 5⅞-in reservoir hole. The existing design had a logical basis, including the desired monobore completion — but the trade-off was challenged.

The smaller hole increased exposure through weaker pipe, reduced fishing capability, smaller annular clearance, higher differential-sticking risk, more limited tools and reduced kick tolerance.

A 6½-in alternative offered materially greater kick tolerance, stronger drillpipe and more standard equipment; the contemporary analysis indicated approximately 50% greater kick tolerance under the same assumptions.

Four Themes Emerged

The Challenge

A significant new gas discovery in SE Asia presented an unusual combination of well challenges.

Pressure and temperature alone placed the development within HPHT territory — but the greater concern emerged when these were combined with very high levels of corrosive and hazardous reservoir contaminants, including H₂S.

The issue therefore extended far beyond drilling the initial wells successfully.

Pressure × Temperature × Contaminants × Life of Field

Bringing the Learning Curve Forward

The development team was entering a specialist technical area where the consequences of learning primarily through experience could be extremely high.

Rather than starting that learning curve from the beginning, the peer review brought experience from previous international HPHT exploration, appraisal and development projects into the project before major development decisions became fixed.

A particularly valuable analogue was a major North Sea HPHT development that had progressed from exploration success through appraisal, development engineering and production.

Narrow drilling margins · HPHT well architecture · MPD · materials qualification · sour service · well integrity · geomechanics · completion design · QA/QC · development planning

The Peer Review Was Designed to Challenge — Not Replace

This was not an attempt to redesign the development from outside.

The review had three purposes:

Confirm what was already being done well · Identify important issues that might not yet have received sufficient attention · Expose the highest technical and financial life-of-field risks early enough to influence development decisions

Independent peer review creates most value when it combines the detailed knowledge already inside the project with experience and challenge from outside it.

Risk Impact × Difficulty to Manage

A Boston Square was used to focus engineering attention on the risks that combined the greatest potential consequence with the greatest management challenge.

The Discovery

The number itself was not the key finding. All 16 highest-impact risks were connected to life-of-field well integrity.

Most drilling risks were principally individual-well or NPT exposures. The larger consequences were concentrated around completion and long-term integrity — where failure could mean loss of production inventory, intervention, loss of containment, safety or environmental impact.

The Contaminants Changed the Equation

High H₂S and CO₂ influenced decisions throughout the well system:

Casing metallurgy · Completion tubing · Completion components · Wellhead systems · Elastomers and seals · Cement · QA/QC · Installation · Intervention philosophy · Annulus management · Long-term monitoring

This was therefore not simply a case of specifying more expensive HPHT equipment.

Integrity Starts Before the Well Is Installed

Long-term integrity depended not only on design, but on the entire chain:

Design → Qualification → Manufacture → QA/QC → Transportation → Installation → Verification → Operation → Monitoring → Intervention → Abandonment

The review repeatedly returned to equipment qualification, traceability, third-party inspection and flawless installation practice.

Thinking Beyond First Gas

The peer review deliberately extended beyond initial development drilling and completions.

Reservoir depletion · Compaction and changing geomechanical stresses · Thermal cycling · Differential depletion · Infill drilling around producing sour-gas wells · Well intervention · Annulus behaviour · Cement integrity · Eventual abandonment

Reservoir depletion and compaction were treated as life-of-field integrity issues, requiring integrated reservoir and geomechanical modelling rather than a drilling-phase-only response.

From Risks to Development Capability

The review did not simply produce a risk register. The findings pointed toward the capability the development needed to build around itself:

HPHT Casing & Tubing Design · HPHT Well Integrity · HPHT Well Operations · HPHT Annulus Management · HPHT Well Intervention · HPHT Cementing

Alongside multidisciplinary expertise, appropriate external specialists, qualification programmes and rigorous QA/QC.

The Challenge

A major international operator was executing an extensive deepwater development programme using established well designs, engineering standards and experienced drilling and completion teams.

There was an understandable starting assumption: with mature operations already subject to continuous optimisation, how much additional opportunity could really remain?

The unusual advantage was detailed operational knowledge of three major operators working in comparable deepwater Angola environments. The wells faced many similar fundamental conditions — yet the operators were often solving them differently.

Going Beyond Benchmarking

The study compared well designs, drilling programmes, operating procedures, operational reports and established practices across the three operators, following the well through its principal drilling and completion phases.

Identify differences · Understand why · Validate existing good practice · Challenge assumptions · Identify alternatives · Quantify potential value

The comparison extended across well architecture, drilling, BOP and rig maintenance, directional capability, technical-limit performance, casing and inventory strategy, wellbore strengthening, clean-up practices and completion design.

The Discovery

The study revealed considerably more variation than initially expected. Different operators had developed different solutions to very similar deepwater challenges.

Some existing practices were validated. Others were challenged. Some external practices offered relatively straightforward efficiency improvements, while several observations opened larger strategic questions around well architecture, extended step-out capability, casing elimination and future development concepts.

A Boston Square

A Boston Square became the mechanism for separating an interesting idea from an actionable opportunity:

VALUE OF IMPLEMENTATION × EASE OF IMPLEMENTATION

From 22 Ideas to Decisions

Each opportunity was evaluated against potential time/cost prize, value, ease of implementation, operational applicability, recommendation and engineering feedback.

This was not an exercise in copying another operator. Every idea was brought back through the operating organisation for technical challenge and validation.

Even among the seven not immediately applicable, four were retained for consideration in the Basis of Design of future deepwater developments.

The Prize Was Not One Big Idea

The study also exposed opportunities whose potential value extended considerably beyond routine well-cycle efficiency.

Extended step-out capability, alternative well architecture and other development choices could influence whether difficult targets were technically achievable and potentially avoid significant additional infrastructure or well-construction requirements.

Operational efficiency → Well design → Development concept

From Comparison to an Optimised Design

The exercise did not finish with 22 observations. The strongest features identified across the different operators were brought together to develop a provisional optimised deepwater well design, which was then sense-checked against future requirements.

The Challenge

MPD experience was accumulating across multiple offshore rigs and vendors, but valuable knowledge remained fragmented between wells, teams and service companies.

An operator MPD Guideline established the technical baseline. The next step was to turn continuing field experience into better engineering, better execution and measurable performance improvement.

The Approach

An operator-owned continuous-improvement system connected field observations directly to engineering and operations.

26+ strategic Lessons Learned were developed across 7 learning threads and 5 improvement themes. Learning was implemented as it emerged rather than simply recorded.

Problems were investigated — but so was exceptional performance: Why did this work so well — and how can we replicate it?

The Discovery

Benchmarking moved beneath the headline numbers to compare drilling practices, hole cleaning, MPD connections, rollover, tripping with surface backpressure and the engineering and operational behaviours behind them.

The Hidden Driver

A deeper differentiator emerged: high-performing teams created a positive reinforcement loop.