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The West Baram Delta (WBD) basin is a structurally complex region with an abundance of hydrocarbon that has been produced and yet to be discovered. Within the basin, there is a drastic increase of sedimentary thickness occurred across the growth fault, contributed to major challenges for the sequence stratihgraphic framework correlation to be established throughout the basin. Understanding the growth fault development in terms of age-based within the region is critical for better accuracy in reservoir correlation, reservoir distribution and structural trap analyses. 3D seismic mega-merge of the West Baram Delta was used to interpret the third order Tejas B (TB) stratigraphic sequences. From the structure maps of the maximum flooding surfaces (MFS) and sequence boundary (SB), thickness maps were generated for the system tracts of the corresponding sequence, mainly the highstand and transgressive system tracts. Then, structural restoration using a method of layer back stripping and fault blocks shifting were conducted to study the depositional and structural evolution of the basin. The Late Miocene to Late Pliocene sequence and structural developments of the basin were mainly controlled by growth faulting activities are divided into seven stages: 1) WBD TB3.1 (~10.6Ma-~8.5Ma), 2) WBD TB3.2 (~8.5Ma-~6.7Ma), 3) WBD TB3.3 (~6.7Ma–~5.6Ma), 4) WBD TB3.4 (~ 5.6Ma-~4.2Ma), 5) WBD TB3.5 (~ 4.2Ma-~3.8Ma) 6) WBD TB3.6 (~3.8Ma-~3.0Ma) and 7) WBD TB3.7 (~3.0Ma-~1.9Ma) sequences. The high sediment supply rate is believed to provide conducive mechanisms for the gravity-induced syn-depositional growth faults to be initiated, which observed from WBD TB3.1 until WBD TB3.4. The growth faults in the basin were developed stage by stage from the south (landward) to the north (basinward) driven by the progradation of shoreface and delta sedimentation. The Northwest-Southeast wrench-induced compression which happened in Pliocene to Quaternary has caused basin inversion in the basin, where the trending of the fold axes is in the Northeast-Southwest orientation. The wrench-induced compression deformation was prominent at the proximal part of the basin, where its deformation extends distally down to the Baram field. The deformation developed the anticlinal features and faulting within this region. The intensity of the wrench-induced deformation decreases basinward, which is the reason why beyond the Baronia field, the deformation is less prominent. The distal part of the basin is mainly controlled by the gravity-induced syn-depositional growth faults tectonic style since the wrenching is not prominent. The seven third-order depositional sequences established as WBD TB3.1 to WBD TB3.7 sequences with a complex growth-faulted structure development in the West Baram Delta give a new insight of understanding the depositional and structural evolution through time which may lead to a better stratigraphic correlation and hydrocarbon trap analyses at the field scale.

Hydraulic fracturing is often used in unconventional shale reservoirs, and 50%–95% of the injected hydraulic fracturing fluid remains in the formation due to the capillary effect. This phenomenon has been observed in the Montney shale formation, Canada, where the flowback water recovery is generally less than 25%. Surfactant is one of the hydraulic fracturing fluid additives for reducing surface tension and capillary forces to facilitate water flowback recovery. Surfactant loss due to adsorption by the reservoir rocks reduces the chemical’s efficiency, and this causes water retention in the formation and reduces water flowback recovery. The compatibility of surfactant with reservoir rock is critical to minimize surfactant adsorption on the rock surface because this diminishes the primary function of the surfactant hydraulic fracturing fluid additive and to ensure cost-effectiveness. This study evaluates surfactant efficiency to improve flowback recovery for the Montney shale formation based on IFT, surface tension, and adsorption. This study evaluates surfactant performance and performs a fluid–fluid interaction experiment and fluid-rock compatibility investigation. Several commercial surfactants are screened for low interfacial tension and surface tension. Further analysis is carried out by evaluating the fluid-rock compatibility using the static soaking test at reservoir pressure and temperature. The pre-soaking and post-soaking test fluids were analyzed for water composition, liquid–liquid interfacial tension, surface tension, and pH. Results showed that the selected surfactant is a critical determiner of the hydraulic fracturing fluid performance. SOLOTERRA 938 is an anionic surfactant that has good compatibility with Montney shale formation. Unlike other non-ionic surfactants, SOLOTERRA 938 retains the interfacial tension and surface tension after seven days of interaction with reservoir rock. The interfacial tension remained unchanged at 0.1 mN/m. The surface tension decreased from 28.4 to 27.5 mN/m with air and from 21.7 to 20.8 mN/m with hydrocarbon because surfactant behavior changes with pH change. The surfactant concentration was measured using high-pressure liquid chromatography, and the loss was 12% after seven days of interaction with the reservoir rock (from 0.1 to 0.088wt%). The adsorption calculated based on the concentration volume showed a low value of between 0.43 and 0.97 mg/g rock.

Lithology is an important input parameter into petroleum system modelling (PSM) as it carries information about thermal conductivity and reservoir quality. It can be obtained from the geological static model, gross depositional environment (GDE) maps, or seismic data. The objective of this study is to demonstrate the influence of lithology input on the PSM simulated models (pressure and temperature), by comparing the lithology input derived from seismic data against the one inferred from GDE maps, using S-field as case study. The derivation of lithology information (Vshale) from seismic data is attempted using extended elastic impedance (EEI) inversion followed by normalization. We performed conversion of Vshale cube into the depth domain, then upscaling prior to utilization as input in PSM for the model simulation and calibration. The results of pressure and temperature models achieved using the lithology input from the GDE maps (homogeneous lithology assumption) served as the reference. These results are compared to the simulated pressure and temperature models obtained using Vshale cube as the lithology input parameters. 3 wells (SD-2, SD-1, S-5) available in S-field (located in Malay Basin) for the study. SD-2 is the calibration whereas SD-1 and S-5 are the blind tests for pressure and temperature models. The pressure model obtained using the seismic lithology cube shows better matching with the measured pore pressure data points when comparing to the pressure model achieved from the reference input. By quantifying the average error between the pressure model and the actual pressure data, the former lithology input contributes to lower pressure error of 161psi in contrast to 232psi using the later lithology input. The results from the blind tests show consistent findings with SD-2 where the lithology input from Vshale cube indicates better agreement with the measured pressure data as compared to the one obtained from GDE maps. The average pressure error has decreased from 220psi to 140psi and from 465psi to 296psi for SD-1 and S-5 respectively. From the temperature model perspective, subtle differences observed for the models for both types of lithology inputs. Both types of lithology inputs able to match well with the recoded temperature data points. In summary, integrating seismic lithology cube into PSM able to provide improved prediction due to detailed characterization of lithology distribution. The paper has illustrated an attempt to leverage on seismic data for the derivation of lithology (Vshale) cube and using it as a lithology input for petroleum system modelling. The Vshale cube provides detailed and improve characterization of lithology distribution, which will influence the output of the simulated models from PSM as shown through the pressure and temperature models. This could be helpful information for well planning and drilling.

Predicting the spatial distribution of rock properties is the key to a successful reservoir evaluation for hydrocarbon potential. However, a reservoir with a complex environmental setting (e.g. shallow marine) becomes more challenging to be characterized due to variations of clay, grain size, compaction, cementation, and other diagenetic effects. The assumption of increasing permeability value with an increase of porosity may not be always the case in such an environment. This study aims to investigate factors controlling the porosity and permeability relationships at Lower J Reservoir of J20, J25, and J30, Malay Basin. Porosity permeability values from routine core analysis were plotted accordingly in four different sets which are: lithofacies based, stratigraphic members based, quartz volume-based, and grain-sized based, to investigate the trend in relating porosity and permeability distribution. Based on petrographical studies, the effect of grain sorting, mineral type, and diagenetic event on reservoir properties was investigated and characterized. The clay type and its morphology were analyzed using X-ray Diffractometer (XRD) and Spectral electron microscopy. Results from porosity and permeability cross-plot show that lithofacies type play a significant control on reservoir quality. It shows that most of the S1 and S2 located at top of the plot while lower grade lithofacies of S41, S42, and S43 distributed at the middle and lower zone of the plot. However, there are certain points of best and lower quality lithofacies not located in the theoretical area. The detailed analysis of petrographic studies shows that the diagenetic effect of cementation and clay coating destroys porosity while mineral dissolution improved porosity. A porosity permeability plot based on stratigraphic members showed that J20 points located at the top indicating less compaction effect to reservoir properties. J25 and J30 points were observed randomly distributed located at the middle and bottom zone suggesting that compaction has less effect on both J25 and J30 sands. Lithofacies description that was done by visual analysis through cores only may not correlate-able with rock properties. This is possibly due to the diagenetic effect which controls porosity and permeability cannot visually be seen at the core. By incorporating petrographical analysis results, the relationship between porosity, permeability, and lithofacies can be further improved for better reservoir characterization. The study might change the conventional concept that lower quality lithofacies does not have economic hydrocarbon potential and unlock more hydrocarbon-bearing reserves especially in these types of environmental settings.

Modelling of meandering fluvial reservoirs with point bars and crevasse splays is very challenging. The conventional modelling approaches, especially for meandering fluvial reservoirs, are mainly controlled by wells, which have contributed to uncertainties in lateral variations between and away from well control. Integration of the improved sedimentology, geophysics and 3D reservoir geomodelling techniques of fluvial reservoir system are proposed in the study. In stratigraphic and structural framework building, the improved methodologies included 3D seismic geobody extraction, stratal slicing and high order architectural elements interpretation. 3D geobody extraction and stratal slicing technique enhanced interpreter ability to visualize fluvial features at specific time-equivalent stratigraphic surface. In lithofacies modelling, more refined high-order architectural elements were modelled using methodologies included 3D facies seismic probability, local varying azimuth and dip angle to capture lateral accretion of point bars inside the channels for better facies distributions following point bar architectures. In property modelling, porosity was populated using Gaussian Random Function Simulation constraint to lithofacies trend to control the distribution of porosity away from wells. This methodology resulted in the porosity distributions being well controlled following the lithofacies trend. The proposed workflows and methodologies enable geomodeller to produce a more geological realistic meandering fluvial reservoir model with internal lithofacies and property distribution honouring well data and input distribution.

The Oligo-Miocene West Crocker Formation in the Kota Kinabalu area, West Sabah, is often described as a sand-rich turbidite system. A field programme was undertaken to study the sedimentary facies of the West Crocker as a possible analogue for the deepwater reservoirs of the NW Sabah Basin and elsewhere. The formation consists predominantly of thick-bedded sandstone facies (beds are commonly >1 m thick) deposited by high-density turbidites. In places, there are the “classical” flysch-like, thin-bedded turbidite sequences deposited on the basin floor. In the thick-bedded successions, sandstone beds are commonly 1.5-3 m thick, while ‘megabeds’ may reach anomalous thicknesses of up to 35 m. The presence of amalgamation surfaces within some of the megabeds suggests that they were produced by multiple flow events. Despite the abundance of thick sandstone beds, there is a general lack of large-scale channelized scours, even at the bases of the megabeds. Almost all the sandstone beds have tabular or sheet geometries. Evidence of channel-fill deposits is found only in the innermost (eastern) part of the system. This suggests that the West Crocker Formation, at least in the vicinity of Kota Kinabalu, represents the non-channelized deposits of a basin-floor fan. The internal architecture of basin-floor fan succession are governed by the vertical (and possibly lateral) distribution of the three dominant facies types. Each facies type is the product of gravity flow events, identified in outcrop as turbidite, debrite and slump. Turbidite beds are dominated by massive to poorly laminated sandstone (Bouma Ta/Tb divisions), which are relatively mud-poor and normally graded with common dewatering features. The beds fine upward into parallel and ripple laminated heterolithics (Tc/Td), which are sometimes burrowed. More commonly, the massive beds have ‘floating’ shale clasts near or at the top, indicating deposition by high-density turbidity currents. Debrite beds generally consist of internally chaotic mud-rich units with scattered shale/mud clasts. They generally have sharp bases and directly overlie the massive sandstone beds, often filling hollows or subtle topographic lows at the top of the massive sands. Debrite beds, of varying thicknesses, tend to overlie turbidite beds with sharp, and often irregular, contacts. A third facies type is slump, which comprise generally muddy or shaly intervals displaying pervasive softsediment deformation (folding and faulting) and remobilization of pre-existing deposits. All three facies types are intercalated with thin ‘distal’ turbidite (Bouma Tc/Td) and hemipelagic shale intervals. Reservoir architecture and, consequently, heterogeneity of basin-floor fan succession, are ultimately governed by the distribution of these different facies types. Predictive depositional models for these facies types are important for effective reservoir characterization. We observe that the sand-rich West Crocker outcrops around Kota Kinabalu span a distance of 40 km along strike of the Kinabalu coastal plain, and we interpret them as representing the medial part of a basinfloor fan system, which is dominated by the thick-bedded sheet sandstones. Although there may be stratigraphic repetition in this steeply dipping succession, due to the thrust-related deformation, it is estimated that the outcrops represent a minimum total thickness of 5000 m of stacked mid-fan section. Since there is evidence for major channelization only in the most “updip” (eastern) outcrop, we speculate that the upper/proximal to base-of-slope part of the West Crocker system must occur east of our studied outcrops. By the same token, the lower/distal parts of the system must lie to the west beneath the coastal areas and beyond, and may possibly crop out on the islands off Kota Kinabalu and Klias peninsula. Hence, the West Crocker Formation is indeed sand-rich (estimated net-to-gross ratio > 70-80%) only insofar as the outcrops around Kota Kinabalu represent the exposed medial fan lobes, and are not necessarily representative of the entire West Crocker depositional system. Further characterization of both updip and downdip sections relative to the more exposed and accessible medial fan belt is required for a more complete understanding of the West Crocker depositional system.

A petroleum systems review of West Africa deepwater, from Cameroon to Angola, was undertaken with the view of assessing the remaining potential and to determine areas for further investigation. With the wealth of exploration/production data available internally and from the public domain, a systemic approach was taken to obtain a ‘bird’s eye view’ of the geology of the margin and its petroleum systems. The study was also a means for identifying data and knowledge gaps where future studies may be focused. A chrono-stratigraphic chart for the entire West African margin provides the framework for further analysis. The chart was compiled mainly from public domain data, detailing out the main source, reservoir and seal rock units in a tectonostratigraphic context. Information such as hydrocarbon occurrences (fields and discoveries) and wells drilled are pasted on the chart (both in printed and digital forms) for easy viewing. In its digital form, tabulated data for fields and discoveries are provided as hyperlinks to worksheets. Petroleum systems are defined by linking the reservoirs to their respective source rocks. A total of 24 petroleum systems, both proven and hypothetical are identified in all the major basins along the margin, from north to south: Rio del Rey, Douala, Rio Muni, Gabon, Lower Congo, Kwanza, and Namibe). Each petroleum system is illustrated in folio sheets, which provide details of the petroleum systems elements: source, reservoir, migration and trapping mechanism and timing, complete with a petroleum systems events chart. Besides the proven major petroleum systems, a number of hypothetical petroleum systems have been identified, which needed further investigation and validation. The chronostratigraphic charts and petroleum systems folios are used in conjunction with a comprehensive GIS database that was established to aid further analysis of the margin.