Wheatstone and Iago commenced production in June 2017. Its foundation subsea system includes nine Wheatstone and Iago development wells tied back to a central Wheatstone Platform (WP) for processing. Hydrocarbons then flow via an export pipeline to an onshore processing facility that includes 2 × liquefied-natural-gas (LNG) trains and a domestic gas (Domgas) facility.

Data from subsea wells, manifolds and flowlines, along with data from WP and the Wheatstone LNG Plant are continually monitored to ensure wells and equipment are operating within allowable limits. Observed and expected performance are routinely compared to recognise any unexpected performance for further investigation.

This paper will highlight some of the key learnings in well and reservoir surveillance analysis and optimisation (SA&O) that have been developed using the data from early production. Production strategies will be discussed, along with factors that need to be considered when developing a preferred strategy through operational and production challenges. Insights will be provided in how to assess the performance and reliability of equipment, including pressure and temperature gauges, flowmeters and chokes. Discussion will also include reservoir surveillance and analysis techniques used, what information is yielded from the different analyses and what surveillance and analysis techniques and tools have worked best.

Practical examples will be shared that includes tubing and inflow trends, drawdown analysis, equipment performance, and the operational and production challenges of trunkline pressure management.

The challenges and insights presented in this paper provide a unique case study of Australia’s evolving offshore petroleum industry from a regulatory lens. It documents how a regulating agency’s unique perspective can identify opportunities to optimise recovery, contribute towards improvements in good oil practice and ultimately adapt to the changing requirements of industry.

This paper sets out the regulatory landscape, as well as the challenges that exist in managing an innovative, adaptive and evolving offshore petroleum industry. Australia’s offshore resource stewardship strategies must now respond to a more established, maturing, more ‘crowded’ and dynamic petroleum landscape. This challenges regulators to be increasingly responsive, adaptive, continuously improve practices and be well-informed regarding global trends, such as those affecting mature provinces. Opportunities to exchange ideas, collaborate and incorporate key learnings from other offshore regulatory regimes are considered key enablers towards achieving these goals.

Australia’s maturing petroleum provinces are impacted by long distances, (relatively) low infrastructure density and greater water depths; whilst increasingly challenged to integrate smaller, deeper and economically marginal resources. Conversely, emerging/recently established production areas are now facing an increasingly dense infrastructure landscape with multiple potential development pathways. In contrast to traditional system-wide blanket or "title-by-title" approaches (particularly with respect to optimal use of existing infrastructure), effective resource stewardship requires an increased level of consideration of "area" or "regional" developments. A more responsive and adaptive approach, which fosters collaboration and effective dialogue between the regulator and industry, improves regional understanding and contributes toward optimum resource recovery (via lower life-cycle costs and accelerated production opportunities).

This paper describes the extensive integrated engineering collaboration and optimization process to allow the operator to push the drilling and completion envelope to drill complex ultra extended reach drilling (ERD) wells in a mature field. The Wandoo field is located within WA-14L in the Carnarvon Basin, offshore Western Australia and is wholly owned and operated by Vermilion Oil & Gas Australia Pty Ltd (VOGA). Due to the shallow reservoir depth, extreme ERD profile and the high tortuosity requirement for the wells, significant challenges were identified during the planning stages of the campaign.

To optimize well placement, update geological information and reduce collision risk with nearby producing wells, the Reservoir Mapping While Drilling (RMWD) service was run in real-time. The primary objective of the service was to place the well in the optimum position within the reservoir, this included (1) provide early detection of moved oil water contact (MOWC) while approaching well crossings with minimum separation factor to reduce collision risk and geological uncertainties; (2) to steer azimuthally to optimize the placement of the well with respect to the field bounding fault and reduce the drilling risk associated with the intersection of the fault; and (3) to distinguish between the A3 Upper (A3U), A3 Lower (A3L), and B sands to optimize well placement.

These challenges were successfully overcome with extensive planning, integrated engineering designs, application of new state-of-the-art technology, good quality real-time data interpretation and a strong execution support from both rig site and town.

As the result of good collaborative teamwork in planning and execution, the two highly technically challenging wells were drilled and completed successfully and brought online for production. A number of drilling performance highlights captured during the execution phase were identified as having significantly contributed to the successful completion of the project.

The Greater Enfield Project (GEP) is a challenging offshore oil development, designed to produce from the Laverda Canyon, Cimatti and Norton over Laverda oil fields. Six water injection wells are required to provide pressure support and sweep oil to three production wells in the Laverda Canyon and Cimatti oil accumulations to improve oil recovery. The GEP injection wells are a critical aspect of water flood design in a complex field, new to Woodside and with limited global benchmarks.

A specific drilling and completion fluid system (Reservoir drilling fluid, completion fluid and chemical filter cake breaker) combined with a unique clean up and displacement technique have been adopted to provide high and sustainable matrix injection performance. While filter cake breakers have been previously used in the industry, they are typically combined with a flowback for filter cake removals. Filter cake clean up by means of flowback was discounted for GEP due to cost and the inability of some wells to naturally flow during early life.

All GEP injection wells were completed in 2018-2019, one of which is globally the longest horizontal water injection well completed to date based on the Rushmore data base. Fieldwide injection commenced in July 2019 with favorable results. This paper summarises the key design aspects adopted to deliver successful matrix injection performance, presents the improvements implemented during offshore execution and provides an insight into the early life injection performance.

There was always the challenge to match Permeability estimated from logs to Permeability derived from well tests. The main reason for this is the difference in scale, both vertically in the borehole (net contributing sands) as well as radially out into the formation. The well test that takes into consideration many hours of fluid flow into the borehole was always deemed more representative than permeability derived from logs that measures a smaller area and volume. However, this perception should not relegate log-derived permeability to an insignificant parameter within dynamic models. When wells are stimulated prior to well test (e.g. under-balanced perforation or chemical stimulation for clean-up), it is expected that the permeability from the well test be enhanced as seen in Iago-2 and Gorgon-3 wells.

This paper takes core data from wells in the Carnarvon Basin, create log relationships to predict permeability that match these core data, and compare these to wireline formation tester mobility and to well tests. The results are very promising, and the workflow proposed can be applied to any well in the basin. One of the objectives of this paper is to create a workflow that can be replicated easily and to use raw logs that are available across all wells, in order to reduce the uncertainty in the predicted permeability.

The reservoir sands of the Mungaroo formation are easily recognised by the cross over in the neutron-density logs, in both gas zones and water zones. This is the criteria used by operators to obtain formation pressure tests (MDT/RFT) and this is the same criteria used in this paper to define reservoir sands. Only those core data acquired in reservoir sands are used as the "Learning" dataset to predict permeability. Several learning datasets were created, and these were blind tested on other wells that were not part of the learning dataset. The results of these predicted permeabilities were cross plotted against core permeability that have been over-burden corrected and depth shifted to wireline logs. Where the match is not satisfactory, new learning datasets are derived and this step of the workflow is repeated. At the end, there are four groups of learning datasets that are used as the final results.

These four groups of datasets are associated with four sets of equations and these provides a very good match between the predicted log-derived permeabilities and core plug permeabilities. When compared to mobilities from formation pressure testers, the predicted permeabilities are a very good match. These were then compared to well test permeabilities showing an overall good match. This gives confidence that the predicted permeabilities from the four sets of equations are good and can be applied to any new well targeting the Mungaroo Formation in the Carnarvon Basin.

The Wheatstone gas field located in the Northern Carnarvon Basin offshore Western Australia achieved first gas in mid-2017. All seven foundation producers are equipped with permanent downhole gauges (PDHGs) for real-time pressure monitoring. Data from these gauges have been instrumental in understanding dynamic reservoir performance and reducing static uncertainties. The scope of this paper specifically covers the use of pressure and rate transient analyses (PTA and RTA) and the insights that have been gained during the first two years of production.

Significant offset distances exist between each PDHG and the reservoir. Corrections were developed to convert the gauge pressure to a reservoir datum, which primarily account for frictional and gas density changes with varying rates and temperatures within the wellbore. Other physical constraints and effects have been found to be more challenging to overcome, limiting the quality and interpretability of the pressure transients, particularly in the middle-time region. These include interference from non-reservoir pressure signals such as liquid fallback during shut-in, extremely low signal-to-noise ratios in the higher quality formations, and proximity to boundaries that render a short infinite-acting radial flow (IARF) period that could be masked by wellbore storage.

Attempts to circumvent these issues have included the use of drawdown transient analysis to complement build-ups. The step-rate test can eliminate liquid fallback entirely, which allows for better resolution of the IARF period. Rapid choke movements were also trialled to boost the reservoir response in some instances. Interpretations using the drawdown data were further verified in one producer through analysis of the buildup data acquired following a routine downhole safety valve closure, which benefitted from the trapping of condensed liquid above the closed valve. This provided the cleanest PTA data seen outside of drill stem testing during field appraisal. While successful in the example presented, no methods have yet been found to reliably increase IARF interpretability in those wells producing from the best quality sands.

Regarding RTA, the authors have found very few documented cases in the literature of applying this technique to conventional gas fields. To field-test its applicability in such an environment, evaluations of drainage volume by producer were performed and found satisfactory when compared with other estimates of gas in-place. It is hoped that a presentation and discussion of this finding will be additive to the reservoir engineering toolkit.

Water-oil emulsion formation is commonly observed at wellhead chokes and topsides control valves, with the impact mitigated by chemical injection. The presence of emulsions downhole in Pyrenees wells was inferred from their significant production rate impact and confirmed by the uplift observed from downhole chemical injection. The Pyrenees fields are located in the Exmouth sub-basin offshore Western Australia. Through analogy between individual Inflow Control Device (ICD) orifice elements and wellhead chokes, ICDs were suspected as the source. This paper describes experimental confirmation of emulsion formation by orifice type inflow control devices in Pyrenees field horizontal well completions and proceeds to characterise the emulsions formed. A purpose built flow rig combined Pyrenees crude oil and produced water under low shear, simulating reservoir flow conditions, before flowing through an orifice element at rates equal to peak and mid-life production. With liquid flow rate held constant, water cut was increased in 10% steps from 0 to 100% water content. A key component of the experimental system is a benchtop Nuclear Magnetic Resonance spectrometer equipped for non-invasive Pulsed Field Gradient measurement of the Droplet Size Distribution of the emulsions formed. Droplet size distribution is a fundamental fluid property that significantly impacts emulsion rheology. The heavy end component of the crude oil was characterised by a novel Enhanced Saturate Aromatic Resin and Asphaltene analysis procedure to facilitate benchmarking of Pyrenees with emulsion formation tendencies of other producing assets. This quantitative demonstration of emulsion formation by orifice type ICDs at near reservoir conditions is novel, as is observation of partial emulsification, and represents initial steps towards generalisation of models for emulsion formation and their transport properties.

In 2019, Australia led all Liquified Natural Gas (LNG) exporters in incremental growth (IGU World LNG report, 2019), supported by the start-up of the Wheatstone and Ichthys LNG projects. Production and economic recovery of gas are affected by the association of chemical compounds naturally present at low to trace levels within natural gas such as carbon dioxide, hydrogen sulphide and mercury. These contaminants generate a cascade of costly treatments and waste recovery efforts. If the level of mercury in a produced gas stream is higher than expected, the treatment process in the LNG plant rapidly reaches capacity and may cause shut-down of the facility or rejection of gas supply resulting in significant profitability impacts. There may also be long term consequences that could impact on the decommissioning of industrial infrastructures in the future.

High mercury levels in produced gas have been reported in South East Asia and Australia (Chalkidis et al., 2020; Black and Saunders, 2018; Zeeshan and Manikandan, 2017). However, currently there are no standard method to accurately quantify the presence of mercury in gas in the reservoir. The highly absorbent and multi-speciated nature of mercury makes reliable gas sampling difficult and generally leads to gross under-predictions of quantity. The spatial distribution of mercury within the reservoir means mercury may not appear in the initial production phase and its presence in fluids may vary over the lifetime of the field.

Understanding the source, the transport mechanism and the distribution of naturally present contaminants in the subsurface is critical for lowering their impact in industrial activity through avoidance. High mercury levels of about 1000 microgram per cubic meter (µg/Sm³) were reported in reservoir gas samples from a sand unit of the Gorgon gas field in the Northern Carnarvon Basin, Australia (Chevron Australia, 2014). Other gas samples from different depth intervals in the same well delivered readings below 20 µg/Sm³. The closest exploration well to GOR-1D (about 2.5 km), North Gorgon-1, has provided abundant core materials that were investigated to detect and understand the distribution of mercury in the rocks. Our research seeks to address some of the significant but remaining geoscientific knowledge gaps on the generation and distribution mechanisms of mercury in rocks, from source to accumulation in the subsurface. In this paper, we provide an assessment of the workflow by examining preliminary analytical results on the detection and quantification of mercury in rocks.

Africa (Sub-Sahara) An initial drillstem test on the Mzia-2 well in Block 1 flowed at a maximum rate of 57 million ft3 of gas per day, increasing the estimated recoverable resources from the field to 4.5 trillion ft3. This is the first test carried out on a Cretaceous discovery in deepwater offshore Tanzania. BG (60%) is the operator in partnership with Ophir Energy (40%). Asia Pacific Production has begun from the Wei Zhou 6-12 oil field in the Beibu Gulf basin in the north part of the South China Sea. The project has 10 producing wells drilled at an average water depth of 29.2 m. CNOOC has a 51% operating interest in partnership with Roc Oil, Horizon Oil, and Oil Australia. Salamander Energy signed production-sharing contracts for the Northeast Bangkanai and West Bangkanai license areas, onshore central Kalimantan in Indonesia. Each area covers approximately 2,214 sq miles.