It has previously been proposed that the Sibumasu block of Southeast Asia, which contains glaciomarine deposits, became detached from the Gondwana margin during the Early Permian. A combination of facies analysis and the identification of dropstones and dump structures from a Lower Permian diamictite-bearing sequence at Phuket, Thailand, and adjacent islands suggests that the sediments originated as glaciomarine and debris-flow deposits. The Lower Permian diamictite-bearing sequence in the study area corresponds to the Ko Sire and Ko He Formations, both of which consist of three principal lithofacies: diamictite, sandstone, and fine-grained facies. The low-lying Ko Sire Formation is up to 400 m thick and is characterized by laminated mudstone; the presence of dropstones and dump structures associated with Cruziana ichnofacies indicates ice-rafted sedimentation in a glacially influenced offshore area. The Ko Sire Formation is overlain by a diamictite sequence of the Ko He Formation (up to 400 m thick). Poorly and well-stratified diamictites with tabular and lensoidal geometries, in combination with resedimentation textures, indicate that the diamictites within the Ko He Formation are debris-flow deposits. The similar lithology of clasts in the diamictites and dropstones possibly suggests that the debris-flow diamictite was presumably remobilized from pre-existing glacial deposits. The evidence of a glacially influenced offshore environment supports a previously proposed paleogeographic interpretation in which the Sibumasu block was most likely located at the Northwest Australian margin of Gondwana.

Compartmentalization of reservoirs in operating fields is commonly caused by sealing of faults (Cerveny et al., 2004; Davies and Handschy, 2003;Davies et al., 2019; Knipe, 1992; Yielding et al., 1997; Yielding et al., 2010). Calibrating this seal, however, is difficult without adequate subsurface data. A local region across the central part of the Jasmine Field, Jasmine A, along the northern extent of the Pattani basin in the Gulf of Thailand, was selected in this study for detailed fault-seal analysis calibration. The objective was to present the details of the fill and spill history from a juxtaposition analysis across the faults. The large number of well penetrations with fluid and lithofacies data and the 3D models of mapped permeability distribution provided a subsurface framework to reduce the uncertainty and allow a more comprehensive analysis of the crossfault reservoir juxtaposition and fluid contact levels. Crossfault flow behavior and fill and spill history were evaluated by examining fluid contacts in a strike view of the fault, with the properties juxtaposed. The Jasmine Field is a narrow structural high that is cut by many NE-SW and NNW-NNE trending faults forming fault-bounded compartments. Reservoirs in the field are typically thin, stacked high-permeability fluvial sandstones of primarily Miocene age separated by thin shale beds that occur over a depth range of several thousand meters. Many of the sands have unique hydrocarbon-water contacts of oil or gas and water. Reservoir juxtaposition across the faults suggests that fault seal plays a major role in the trap. By comparing fluid contacts in each fault block, cases with different contacts across the fault likely represent a fault membrane seal. Contacts occurring at the same height suggest crossfault leakage. The evaluation was done by estimating permeability distributions across the fault. These results, however, were not adequately determined simply from the fluid contacts on either side of the fault: fill histories in adjacent fault blocks and lateral structural controls also had to be accounted for. The results together allowed a unique fill and spill history to be defined. The results of the juxtaposition analysis for the main faults bounding the local structural trap in Jasmine A provided a calibration for a 3D analysis of the faults, including estimation of fault-rock properties.

The Sibumasu Terrane is a continental block in SE Asia that is considered to have been attached to Gondwana before its collision with Indochina during the Triassic. The elemental geochemistry and Sm–Nd isotopic composition of mudrocks from the lower Permian Ko Sire Formation of the Phuket Group on Phuket Island (central Sibumasu Terrane), Thailand, were analysed to investigate its provenance, weathering history and palaeogeographical location prior to its separation from Gondwana. The whole-rock elemental geochemistry identified a felsic, granodioritic source rock, which is consistent with the general consensus regarding Gondwanan sediment provenance. Despite the evidence for sediment recycling, such as abundant dropstone clasts derived from sedimentary rocks, the low degree of chemical weathering and lack of zircon enrichment indicate a cold and arid palaeoclimate in its source area, which resulted in ice-rafted transportation of clasts and suspension deposition of fine-grained clastic sediments. Sm–Nd isotopic data and previously published detrital zircon U–Pb age spectra provide more detailed information on the source-rock composition, which was similar to that of the North Australian crustal element, suggesting that the central Sibumasu Terrane was located on the northern margin of north Australia during the late Paleozoic. Supplementary material : A table of trace element concentrations is available at https://doi.org/10.6084/m9.figshare.c.4877289

The Nong Yao field is a marginal oil field that presents many challenges, both geological (thin hydrocarbon column and structural uncertainty due to shallow gas effects) and with well design (shallow depth and unconsolidated reservoirs). The field has been on production for almost five years with water cut in most wells now over 90%. The key to extending field life is identifying new infill locations, with advanced technology required to identify and drill these targets. To improve seismic image and structural definition, the seismic data was reprocessed in 2016, utilizing the latest technologies including Broadband Processing and Full Waveform Inversion. This detected local unswept structures and thin reservoirs allowing for identification of infill targets. New generation hydrocarbon saturation cased hole logs were run in wells to identify swept versus bypassed oil areas. Many infill opportunities required complex 3-D well trajectories and innovative completions. To achieve these objectives, technology such as high build rate rotary steerable systems, advanced real time survey corrections, a multilayer bed boundary detection tool, rotational friction transducer and inflow control devices were implemented. After four years of production, a key well exhibited significantly more production than expected, indicating a much larger reservoir than modelled. However, water cut in this well had reached 98%, so infill wells were required in order to extend production. The reprocessed seismic indicated that the structure extended further to the east of the existing producer than initially modelled. A cased hole saturation log was acquired in an existing well drilled near the planned landing location, which showed that the reservoir was actually swept in this area. Instead, the infill well was landed and drilled in the opposite direction in this eastern part of the structure, keeping the heel away from the water, but providing a much more challenging well path. A high-build rate rotary steerable system, advanced real time survey correction and rotational friction transducer were used to safely deliver this complex 3-D well profile and avoid collision risk from offset wells. The multilayer bed boundary detection tool was then used to ensure the horizontal well stayed as high as possible whilst remaining within the reservoir. Lastly, an inflow control device was installed in the horizontal section to delay water production. The well came online with 0% water cut and is an excellent producer. Similar methods have been adopted at other locations to identify and drill infill targets with great success. Collaboration across disciplines is key, as input is required from the geologist, geophysicist, petrophysicist, reservoir engineer, drilling engineer and completion engineer to identify, drill and produce these infill targets. Implementation of this approach continues to add new volumes and extend field life.

We present the results of a 3D fault-seal analysis across the central part of the Jasmine Field, Gulf of Thailand. Two techniques were applied; a stochastic juxtaposition analysis across thin, stacked, laterally variable reservoirs and then a comparison of fluid contacts and reservoir capillary pressure against predicted fault clay content. The two methodologies can be compared to better understand how they provide insights into reservoir behaviour. Our objective was to estimate capillary threshold pressures for fault-seal calibration in exploration prospects in the Gulf of Thailand. First, the stochastic juxtaposition analysis workflow evaluated whether known oil/water contact (OWC) levels in the key reservoir intervals could be explained by crossfault juxtaposition patterns. Second, modeling was used to calibrate fault capillary threshold pressure against predicted fault clay content. Fault clay content is estimated from the shale gouge ratio (SGR) and compared to the reservoir capillary pressure estimated from known OWC levels and fluid densities for each reservoir interval. The maximum capillary threshold pressure for a given clay content can be estimated and calibrated to trend curves for fault seal across the basin. For 12 key reservoir zones examined, stochastic juxtaposition analysis cannot explain observed OWC levels by crossfault juxtaposition for all reservoir intervals. Therefore, control by structural spillpoints and/or capillary membrane sealing across faults is required. Estimated capillary pressure information is combined with measured mercury-air capillary threshold pressure from Jasmine A reservoir samples and published data to create clay content-capillary threshold pressure curves to estimate fault-sealing capacity across the Jasmine Field. The results can be applied to other fields and prospects in the Gulf of Thailand. Fault-seal analysis and estimation of fault properties in areas with multiple stacked, laterally variable reservoirs is notoriously problematic because of the large uncertainties involved. Our approach of stochastic juxtaposition analysis combined with capillary pressure modeling allows the uncertainties to be addressed while providing concise and usable input to decision-making.