Operationalization of Advanced Mud Gas Logging in Development Drilling: Examples From the Recent HPHT Infill Campaign in the Central North Sea

Standard mud gas logging has served the drill-engineering discipline foremost in executing safe well delivery. Additional subsurface insights are often considered less important when commissioning this service. Consequently, standard mud gas (SMG) logging remains routine despite the advances in quantifiable advanced mud gas (AMG) logging capability. Such advances make it more operationally feasible to deploy AMG and thereby markedly enhance the acquired subsurface insights. This was demonstrated during a recent high-pressure/high-temperature (HPHT) infill campaign in the Central North Sea (CNS). Wells targeting deep Jurassic formations have used AMG technology for continuous compositional analysis while drilling. For a mature field experiencing production-related changes to reservoir fluid, the main objective of collecting AMG data is to aid early assessment of downhole hydrocarbon variability. Operationally this is being performed while drilling in liner (DIL) and in the absence of logging while drilling (LWD). For example, identifying reservoir tops, fluid dissimilarities, and an independent saturation flag is critical operational information. These help to guide decisions on completion strategy and logging behind casing, which in turn aids rig time optimization and offsets the deployment costs. Post-drill systematic integration with other geochemistry data (e.g., gas isotopes, mineralogy, and kerogen compositions) and independent petrophysical techniques (such as triple combo) enables the identification of possible missed pay zones furthermore. Once the “field” is calibrated, the AMG data increase fluid phase interpretation confidence in support of near-time operational decisions and overall reservoir management. An example is the confirmation of new flow unit contributors to perforations for future well interventions/abandonment consideration. Further value upside and differentiation are achieved by collecting the AMG data across the overburdened chalk. The latter provided the first-time in-field granularity on chalk fluid facies, reservoir architecture, and connectivity. In addition, we highlight the added value of information, practical applicability, and consideration for future ultradeep HPHT developments. We advocate the increasing feasibility and appropriateness of progressing AMG to a more routine deployment state in similar field settings and beyond. In the medium term, the quantitative mud gas records acquired by continuous physical sampling may further improve our understanding of vertical fluid evolution in the present-day overburden. Understanding this deep subsurface sediment-(hydro)carbon, i.e., rock-fluid interactions, offers additional potential subsurface solutions. Effects such as active cycling of carbon-bearing phases during fluid migration under post-burial prereservoir conditions could be addressed. These remain challenging in carbon capture underground storage (CCUS) project implementation. 1. Support collection of AMG data in a brownfield to aid early assessment of downhole hydrocarbon fingerprinting while DIL and in the absence of LWD log in the HPHT environment 2. Support the identification of wellbore breathing, reservoir tops, fluid properties, and independent saturation flag to aid decisions on completion strategy and behind-the-casing logging 3. Assessment of chalk fluid facies, reservoir architecture, and connectivity in the field AMG samples the mud at the surface, extracts light hydrocarbon, and quantifies the composition. Three data processing steps convert measured hydrocarbon into gas volume per unit of rock drilled. They are corrected for extractor response, contamination, and volume changes due to variations in drilling parameters. The corrected data are used for compositional analysis, identification of pay zones, and deriving saturation flags. AMG has proven to be a pragmatic, independent additional fluid assessment technology tool during this infill campaign. It carried low operational risk compared to downhole logging/sampling in HPHT. It has proven an inexpensive methodology to maximize data acquisition outside the primary reservoir objective at a minimum cost. Hence the recommendation is to employ this technology as standard with additional benefits in the absence of not being able to acquire logging data. Systematic and routine AMG in a mature field development drilling may thus far prove to be a means of an inexpensive pseudo-production logging tool (PLT) analyzing dynamic filed performance and determining the zonal contribution (in case of co-mingled stacked sands or multiple pays or swept zones) in the total production. Detecting fluid (dis)similarities and linking these to subseismic faulting or juxtaposition would further allow corroborating 4D seismic interpretations and aid infill drilling strategy. Furthermore, amendments to well trajectory/well placement for improved sweeping efficiency, section TDs/casing shoe depth (gas cap expansion), completions, or front-end design are some examples of effective mitigation of downside risk contribution through improved fluid understanding from AMG if deployed routinely on infill wells.