Quality Sandstones Research Articles

Diagenesis as a control on the tight sandstone reservoir quality of the upper Carboniferous strata in the northeastern Ordos basin, China

The upper Carboniferous tight sandstone strata are considered the most promising targets for gas exploration in the northeastern Ordos Basin. Reservoir quality is critical for the successful commercial exploration and development of tight sandstone gas. Reservoir quality of deeply buried tight sandstones is controlled by diagenesis, yet there is sparse systematic documentation on upper Carboniferous tight sandstone reservoir quality and its diagenetic link. In this study, we utilized core analysis and wireline log data, and core samples were studied using X-ray diffraction, optical light microscopy, scanning electron microscopy, porosity–permeability, mercury intrusion capillary pressure and nuclear magnetic resonance measurements. Dolomite, siderite, quartz, kaolinite, and illite are the main diagenetic cements. The upper Carboniferous sandstones pore system consists of residual intergranular pores, intragranular dissolution pores associated with feldspar grains and micropores mainly related to diagenetic minerals. Due to differences in diagenetic alterations, sandstones have significant differences in pore types and pore-filling components, ultimately leading to differences in reservoir quality. The residual intergranular porosity is closely related to the reservoir quality. Quartz cement and authigenic clay minerals lead to reduced residual intergranular porosity, but their impact on reservoir quality is relatively limited due to their relatively low content. The most significant factors contributing to reservoir quality deterioration are ductile (clay-rich) grain-influenced compaction and pervasive pore-filling carbonate cement. When sandstone contains large numbers of ductile grains, it loses a large amount of intergranular porosity due to compaction, and the pore space contains only a small number of dissolution pores and micropores, resulting in reservoir quality deterioration. Similarly, when a large amount of carbonate cement is developed in sandstone, it leads to intergranular porosity loss. The best reservoir quality sandstones preserve a percentage of intergranular porosity because they (i) have few ductile grains, resulting in low compaction, and (ii) do not have significant amounts of carbonate cements. Finally, the diagenetic variations were successfully correlated with wireline logs to evaluate the reservoir quality of subsurface upper Carboniferous sandstones. The data sets provided in this research offer insights to better evaluate and predict reservoir quality in the northeastern Ordos Basin.

Rock Mass Classification for Support System Design and Stand-up Time of Asahan 3 Hydroelectric Power Plant Tunnel (STA 7+085 - STA 7+717)

This Engineering geology research on rock mass classification to determine the support system’s design and stand-up time at the Asahan 3 hydroelectric tunnel STA 7+085 – STA 7+717 has not been thoroughly carried out in detail. This study aims to estimate the support requirements. Rock mass classification is determined through core drill observations and then analyzed by Q-system and RMR methods. The results show that the rock mass at the tunnel depth elevation consists of sandstone with good quality based on RMR and Q-system. Based on the Q system classification, good quality sandstone is obtained. Based on RMR, the suggested support system is shotcrete in the crown and rockbolt. Meanwhile, a rock bolt is the appropriate support system based on the Q-system. The use of an RMR based support system is recommended because it provides a higher level of security with the addition of shotcrete. The tunnel stand-up time is 2,200 - 2,700 hours based on RMR. The result of this research is expected to be applied in other tunnel construction having similar engineering geological condition.

Re-discovering the Gummy gas field – Gippsland Basin

Recent sub-surface studies of the Gummy Gas Field have resulted in a significant upgrade of its gas and liquids resource potential. Previous interpretations had ascribed little resource potential to the field. Shell drilled Gummy-1 in 1990, a Golden Beach (GB) Subgroup gas/liquids discovery in the eastern Gippsland Basin. The GB Subgroup was previously described as a stacked, grading to generally thin, isolated sandstone reservoir hosting limited gas volumes. In 2022, a new study integrated the interpretation of the CGG Gippsland Multi-Client 3D seismic survey dataset with a re-look at the reservoir characterisation, petrophysical properties and reservoir pressures and found that reservoir quality is better than previously thought. The improved reservoir quality is interpreted to be the result of depositional reworking, which also increases confidence that the sandstones are laterally extensive. Consideration of the impact of regional pressure depletion due to nearby production from the GBJV fields has improved the understanding of the hydrocarbon columns encountered at Gummy-1. Increased hydrocarbon column heights are interpreted, which are consistent with wireline log evaluation and regional saturation-height data. Confidence that the seal at Gummy is working as effectively or better than offset fields and reservoirs is high. The new interpretation has also significantly improved the exploration potential for underlying gas reservoirs within the middle and lower GB Subgroup. Gummy-1 reached a total depth of 3530 m MDRT in a gas sandstone reservoir with an interpreted main gas column up to 185 m. Potential exists for additional gas in reservoir quality sandstones to be discovered in deeper exploration targets – the Gummy Deep exploration prospect. Combined with the adjacent Manta Gas Field, this demonstrates the enhanced potential for future commercial development in the area.

Stability Evaluation of Diversion Tunnel Portal Slopes at Lau Simeme Dam Site, Indonesia, using Limit Equilibrium Method

Construction of the Lau Simeme Dam used a tunnel as a diversion channel. Slopes at the diversion tunnel portals were prone to failure due to the tunnel excavation and earthquake. Earthquake load was not considered in the designs of the inlet and outlet portal slopes. This research evaluated stability of the tunnel portal slopes under static and earthquake loads using limit equilibrium methods of the Bishop Simplified and Morgenstern-Price. Input material properties for the slope stability analyses were obtained from evaluations of soil and rock cores, including determination of lithology type and rock mass quality based on Geology Strength Index (GSI), and laboratory testing. Evaluations of soil and rock cores indicated that the inlet portal slope consisted of residual soil, good quality tuff breccia, and good quality sandstone. The outlet portal slope consisted of residual soil, poor quality sandstone, poor quality tuff breccia, fair quality sandstone, fair quality tuff breccia, and good quality tuff breccia. The earthquake load coefficient determined by the seismic analyses based on the peak ground acceleration map for 10% probability exceedance in 50 year was 0.125 g. The slope stability analyses showed that the designed inlet and outlet portal slopes were stable under static and earthquake loads. The Bishop Simplified and Morgenstern-Price resulted in relatively similar Fs values. The Fs values of the inlet and outlet portal slopes decreased with the earthquake load application. Although Fs values of the outlet slope under static and earthquake loads met the requirements specified by SNI 8460:2017, the rock mass conditions, particularly the poor rock masses of layers 2 and 3, required special attention. Application of slope reinforcement methods, such as shotcrete, is suggested to further increase the slope stability.

Controlling factors of tight sandstone gas accumulation and enrichment in the slope zone of foreland basins: The Upper Triassic Xujiahe Formation in Western Sichuan Foreland Basin, China

The accumulation and enrichment of hydrocarbon reflect different degrees of hydrocarbon charging, which is important for hydrocarbon exploration. In this study, we discuss the controlling factors of tight sandstone gas accumulation and enrichment of Xujiahe Formation in Jinhua-Zhongtaishan area, the slope zone of the Western Sichuan Foreland Basin, Southwest China, based on the analysis of the characteristics of the area's source rock, reservoir, and fault, combined with the tectonic background. This study shows that the accumulation and enrichment of tight sandstone gas in the slope zone of foreland basins are controlled by different factors. The natural gas derived from Xu1 Member is easily accumulated in Xu2 Member sandstone reservoir by vertical migration. The high quality source rock generated a large number of natural gas, which preferentially charge into the high quality sandstone reservoir and finally accumulate at the structural high position. The accumulation of tight gas is controlled by high quality source rock (source rock coefficient >10), high-quality reservoir (reserve coefficient >110), and favorable structure (high position of the local structure). When tight sandstone gas meets all prerequisites above for hydrocarbon accumulation, high content of total organic carbon (TOC) benefits enrichment of tight sandstone gas. In addition, the type I faults could be in favor of the natural gas from Xu1 Member to migrate to the upper part of Xu2 Member high quality sandstone reservoir, especially when the natural gas is generated by the middle and lower part of Xu1 Member high quality source rock, which could significantly improve the gas accumulation efficiency and promotes the gas enrichment and high production. In that case, the enrichment of tight gas is controlled by organic matter abundance of source rock (TOC >1.1%) and favorable source-reservoir communication conditions (the development of Type I faults). As a result, the areas with high-quality source rock and sandstone reservoir, favorable structure and migration pathway will be potential targets of tight sandstone gas in the slope zone of foreland basin.

Study on the Relationship between Chlorite Clay Film Diagenesis and Sedimentary Facies in Reservoir Sandstones

A large amount of oil and gas has been found in Chang 6 Formation sandstones in Huaqing region of Ordos Basin. It is controversial whether the chlorite clay film is one of the main controlling factors of high quality sandstone reservoirs in this area. On the basis of previous studies, the chlorite clay film in sandstone reservoirs in the working area was studied by X-ray diffraction, casting thin section, scanning electron microscope, energy spectrum, and other analytical methods. The results show that the sandstones developed by chlorite clay films are closely related to the strong hydrodynamic deposition condition. The formation of chlorite clay film is a gradual process, and the particle coating is mainly formed in the early stage. The material source is the Fe-bearing flocculation precipitation produced when the river enters the lake. The chlorite lining is mainly formed in the later stage, and its material source is mainly iron ions produced by the dissolution of clastic particles such as feldspar or rock debris. The chlorite clay film cannot prevent the cementation and cannot protect the intergranular pores. Therefore, the better physical properties of the sandstones with the chlorite clay film in the Chang 6 Formation of the Huaqing region are related to the petrological characteristics of the sandstone deposited under strong hydrodynamic conditions and have little relation with chlorite clay film.

E&P Notes (June 2021)

E&P Notes (June 2021)

Mixed siliciclastic–carbonate systems and their impact for the development of deep-water turbidites in continental margins: A case study from the Late Jurassic to Early Cretaceous Shelburne subbasin in offshore Nova Scotia

Progradation of deltaic systems that reach the shelf edge is considered a primary mechanism to deliver sand to continental margins. Sediment bypass processes can dominate the outer shelf to upper slope transition, causing poor preservation of reservoir quality sandstones. Turbidites can carry the bulk of the coarse fraction downdip where a thicker sand pile can be deposited once the channel-to-lobe transition is reached. Predicting this lateral and vertical variability along the slope is challenging. This configuration can be further complicated when mixed siliciclastic–carbonate systems are present. The Roseway–Missisauga case study from Nova Scotia is used here to explore potential implications associated with the development of deep-water turbidites that are time equivalent to outer-shelf mixed siliciclastic–carbonate units. Two scenarios are possible: (1) The carbonate factory is dominant, and the development of carbonate reefs and pinnacles on the outer shelf prevents the passage of siliciclastic systems beyond the shelf break; in this case, the siliciclastic component is sequestered within the inner-outer shelf. (2) Favorable conditions for carbonate production gradually deteriorate by the activation of fluviodeltaic systems that prograde outboard reaching the slope region. In this last scenario, low relief and lateral discontinuous carbonate shoals are ubiquitous in the outer shelf representing the last outboard remnants of the carbonate factory. Shelf-edge deltas circumvent or breach these carbonate shoals, establishing sedimentary pathways on the shelf-break region that connect with deep-water turbidites. Observations suggest that this last scenario is the most likely in this part of the Scotian margin during the Late Jurassic to Early Cretaceous.

Reservoir characterisation of syn-rift and post-rift sandstones in frontier basins: An example from the Cretaceous of Canterbury and Great South basins, New Zealand

Abstract A paucity of well data in frontier basins presents serious challenges for reservoir characterisation studies around the world. In this paper, we provide the first regional study addressing reservoir distribution, composition and quality in the frontier Canterbury Basin (CB) and Great South Basin (GSB) of New Zealand, and show how the results can be used to help reduce uncertainties associated with reservoir presence and effectiveness. Cretaceous strata in Canterbury and Great South basins represent two stages of basin history. The oldest Cenomanian–Coniacian (mid-Cretaceous) strata are syn-rift deposits that developed in response to the breakup of the eastern margin of Gondwana, while overlying Santonian–Maastrichtian (late Cretaceous) strata are post-rift deposits that signify the start of rift–drift transgression. These Cretaceous deposits are characterised by a change in facies from predominantly alluvial–fluvial to marginal–shallow marine that is recognisable in outcrop and wells, and from seismic response. Based on our petrographic examination of 99 Cretaceous samples from well and outcrop locations, we conclude that there are significant differences in sandstone texture and mineralogy that are related to differences in depositional facies, basin stratigraphy, geographic location, and degree of diagenetic alteration. Sandstones from the earliest part of the syn-rift succession largely reflect the composition of the underlying basement geology; typically granitoid or quartzose Western Province rocks in GSB, and lithic-rich Eastern Province metasedimentary rocks in CB. Younger strata, representing part of the post-rift succession, are generally better sorted, with detrital compositions reflecting sediment mixing of several basement source areas. Based on available data, reservoir quality is directly related to sandstone texture and detrital composition (factors of provenance and facies), compaction (a factor of burial depth/temperature), and degree or type of diagenetic alteration. Best quality sandstones are predicted to occur in the late Cretaceous post-rift succession of GSB and locally in CB, either where sediment is derived from local granitoids, or where high-energy depositional processes have resulted in quartz-enriched compositions.

High resolution facies architecture and digital outcrop modeling of the Sandakan formation sandstone reservoir, Borneo: Implications for reservoir characterization and flow simulation

Advances in photogrammetry have eased the acquisition of high-resolution digital information from outcrops, enabling faster, non-destructive data capturing and improved reservoir modeling. Geocellular models for flow dynamics with in the virtual outcrop in siliciclastic deposits at different sets of sandstone facies architecture remain, however, a challenge. Digital maps of bedding, lithological contrast, spatial-temporal variations of bedding and permeability characteristics make it more easy to understand flow tortuosity in a particular architecture. An ability to precisely model these properties can improve reservoir characterization and flow modeling at different scales. Here we demonstrate the construction of realistic 2D sandstone facies based models for a pragmatic simulation of flow dynamics using a combination of digital point clouds dataset acquired from LiDAR and field investigation of the Sandakan Formation, Sabah, Borneo. Additionally, we present methods for enhancing the accuracy of outcrop digital datasets for producing high resolution flow simulation. A well-exposed outcrop from the Sandakan Formation, Sabah, northwest Borneo having a lateral extent of 750 m was chosen in order to implement our research approach. Sandstone facies and its connectivity are well constrained by outcrop observations, data from air-permeability measurements, bilinear interpolation of permeability, grid construction and water vector analysis for flow dynamics. These proportions were then enumerated in terms of static digital outcrop model (DOM) and facies model based on sandstone facies bedding characteristics. Flow simulation of water vector analysis through each of the four sandstone facies types show persistent spatial correlation of permeability that align with either cross-bedded orientation or straight with more dispersion high quality sandstone (porosity 21.25%–41.2% and permeability 1265.20–5986.25 mD) and moderate quality sandstone (porosity 10.44%–28.75% and permeability 21.44–1023.33 mD). Whereas, in more heterolithic sandstone (wavy- to flaser-bedded and bioturbated sandstone), lateral variations in permeability show spatially non-correlated patterns over centimeters to tens of meters with mostly of low quality sandstone (porosity 3.4%–12.31% and permeability < 1 mD to 3.21 mD). These variations reflect the lateral juxtaposition in flow dynamics. It has also been resulted that the vertical connectivity and heterogeneities in terms of flow are mostly pragmatic due to the interconnected sandstone rather than the quality of sandstone.

Depositional environment and reservoir quality of Miocene sediments in the central part of the Nam Con Son Basin, southern Vietnam shelf

Abstract The Nam Con Son Basin is a rift basin that formed offshore southern Vietnam at the time of opening of the East Vietnam Sea (South China Sea). The Cenozoic stratigraphy in the basin is subdivided into four megasequences based on the main tectonic stages of basin evolution: syn-rift 1, inter-rift, syn-rift 2 and post-rift. This study investigates the depositional environment and reservoir quality of the Miocene sediments in the central part of the basin, and thus discusses the later part of the inter-rift, the second syn-rift and the post-rift megasequences. We focus on seismic interpretation, sediment core analysis, biostratigraphy and well-log analysis. The Lower Miocene depositional succession is dominated by stacked, coarsening-upward/progradational packages, possibly related to the interplay between high sediment supply and fluctuating sea-levels. The depositional environment is fluvio-deltaic to paralic. The Middle Miocene depositional succession is characterized by an upward deepening trend which seems related to northeast-southwest rift propagation. During this time, several intra-rift packages demonstrate increasing rift-forming activities that resulted in deposition of footwall-derived turbidite deposits in the central grabens/half grabens and non-deposition/erosion on structural highs. Shallow marine facies dominated in the west while the deep marine settings occurred in most of the eastern part of study area. Carbonate platforms were initiated and widely developed on the structural highs in the southeast and north as a result of overall marine transgression and backstepping of the clastic shoreline toward the west. The upper bounding surface of this succession is a regional unconformity marking the boundary between the syn-rift 2 and the post-rift megasequences. During the Late Miocene, deep marine facies extended across the entire study area with extensive submarine fan deposits and submarine channels downcutting W-E and S-NE, which extended across the shelf and slope. The Miocene sandstones comprise mostly fine to very fine-grained, feldspathic litharenite to lithic arkose. Deep marine turbidite sandstones of the Upper Miocene succession exhibit the best reservoir qualities (both porosity and permeability) of all the sedimentary facies examined. Paralic sandstones of the Lower Miocene succession and footwall-derived turbidite sandstones of the Middle Miocene succession have similar reservoir qualities. Relatively good reservoir quality sandstones of the Middle and Upper Miocene successions were deposited as thick massive turbidites. However, parallel-laminated turbidites and slumps/debris flows often show poor to moderate reservoir qualities. Precipitation of carbonate cement during burial diagenesis has destroyed the reservoir quality of the Miocene sandstones.

Implications of controlling factors in evolving reservoir quality of the Khatatba Formation, Western Desert, Egypt

This paper sheds light on the role of petrophysical properties, framework grains and its textural properties, capillary pressure, diagenetic constitutions and events as controlling factors in evolving sandstone quality of the Khatatba Formation in the Western Desert, Egypt. Petrophysical analyses coupled with petrographic observations and diagentic studies have been carried out for many core samples in order to infer the controlling factors of reservoir quality. It has been observed that the sandstone quality of the Khatatba Formation have been adversely affected from well to well in the study area and from zone to zone in the same well and formation. Good- quality sandstones have been found with the porosity ranges from 10–17% and permeability ranges from 100 –1000 mD. The petrographic description indicates the presence of many open hydraulic fractures and dissolution phenomena which all took place in multiple phases during the late diagenetic stage, leading to improvement in the reservoir quality. Dramatic reservoir quality deterioration has been recorded in many zones. The reduction of permeability and fluid pathways in addition to the mechanical compaction, solid bitumen occupying many pore spaces and fractures are observed in many zones. These cause major destroy in reservoir quality that leading to lowering the oil recovery compare to the expected outcome

Proveniência dos arenitos da Bacia de Campos (Andar Alagoas) por meio da composição da granada

Neste trabalho, realizou-se um estudo da composição química da granada para a identificação das principais rochas-fonte envolvidas na proveniência dos arenitos da Bacia de Campos, Andar Alagoas. Em análises obtidas por microssonda eletrônica, dos 17 poços do segmento offshore do estudo, verificou-se a contribuição de diferentes rochas-fonte portadoras de granadas, identificadas como dos tipos A, B e C. Entre elas, predominaram as granadas do tipo B. Um refinamento dessa classificação permitiu categorizar tais granadas em granadas do tipo Bi, derivadas de rochas ígneas ácidas e intermediárias, notadamente granitoides. A ausência ou pequena incidência de zonações composicionais e de inclusões, embora não excluam totalmente as outras categorias, apontam para essa classificação. Granadas do tipo D e E não aparecem em nenhuma das amostras analisadas. A interpretação dos resultados de aproximadamente 4.000 análises das 65 amostras indicou duas contribuições principais para a proveniência desses arenitos: no setor sul da bacia, material derivado do terreno Cabo Frio (rochas metamórficas da fácies anfibolito superior a granulitos, granitos, metapelitos aluminosos e secundariamente metabasitos) e, na porção norte da bacia, derivação do terreno oriental do Orógeno Ribeira (terreno de alto grau e granitoides associados). A direção de suplemento sedimentar mais importante é de sudoeste para nordeste, interpretada como resultado da identificação dessa maior contribuição do terreno-fonte. Os arenitos localizados no setor norte, com granadas derivadas do tipo B e Bi, sobretudo, indicam a presença dominante de rochas granitoides na área-fonte. Essas rochas-fonte geram areias de composição mais quartzosas e/ou quartzo-feldspáticas, com maior potencial para produzirem arenitos-reservatórios de melhor qualidade.

Petrophysical evaluation of reservoir sand bodies in Kwe Field Onshore Eastern Niger Delta

Reservoir sand bodies in Kwe Field, coastal swamp depobelt, onshore eastern Niger Delta Basin were evaluated from a composite log suite comprising gamma ray, resistivity, density and neutron logs of five (5) wells with core photographs of one (1) reservoir of one well. The aim of the study was to evaluate the petrophysical properties of the reservoirs while the objectives were to identify the depositional environment and predict the reservoir system quality and performance. The study identified three reservoir sand bodies in the field on the basis of their petrophysical properties and architecture. Reservoir A has an average NTG (61.4 %), Ø (27.50 %), K (203.99 md), Sw (31.9 %) and Sh (68.1 %); Reservoir B has an average NTG (65.6 %), Ø (26.0 %), K (95.90 md), Sw (28.87 %) and Sh (71.13 %) while Reservoir C has an average NTG (70.4 %), Ø (26.1 %), K (91.4 md), Sw (25.0 %) and Sh (75.03 %) and therefore show that the field has good quality sandstone reservoirs saturated in hydrocarbon. However, the presence of marine shales (or mudstones) interbedding with these sandstones may likely form permeability baffles to vertical flow and compartmentalize the reservoirs. These reservoirs may therefore have different flow units. Integrating wireline logs and core data, the reservoir sand bodies were interpreted as deposited in an estuarineshoreface setting thus indicating that the Kwe Field lies within the marginal marine mega depositional environment.Keywords: Estuarine, Shoreface, Reservoir, Sand, Kwe, field

Ordovician shallow-marine tidal sandwaves in Algeria – the application of coeval outcrops to constrain the geometry and facies of a discontinuous, high-quality gas reservoir

Abstract The Tiguentourine field in the Illizi Basin, Algeria, is a multi trillion cubic feet (TCF) gas accumulation, with production primarily from Late Ordovician proglacial density flow deposits with permeabilities typically in the range 100–0.1 mD. The proglacial succession is truncated by an erosive surface, above which a thin interval of shallow-marine sandstones with higher permeabilites is present in a few wells. These well-sorted, high-energy sandstones were, in turn, succeeded by Silurian-age graptolitic shales that form both the seal and the source rock. Although the shallow-marine sandstone is a high-quality reservoir interval, it is thin (&lt;12 m), discontinuous and not resolvable on seismic; it therefore represents a challenging target to predict. Coeval equivalents of the reservoir interval are exposed in the Tassili N'Ajjer, over 200 km south of the field. An erosive surface at the top of the proglacial sequence is succeeded by sandwaves with wavelengths of &gt;100 m. The geometries and facies relationships have been documented from Landsat and outcrops; they were then compared to modern marine settings. The varied facies and the localized absence of the shallow-marine unit at outcrop serve to explain why the better quality sandstone is variably developed in the subsurface and remains a high risk target.

Characteristics and identification of high quality deep-water gravity flow sandstone reservoirs in Baiyun sag, Pearl River Mouth Basin, South China Sea

Abstract The characteristics and identification methods of high quality deep-water gravity flow sandstone reservoirs in Baiyun sag of the Pearl River Mouth Basin are examined based on three-dimensional seismic and drilling data, and deep water sedimentary theory. The oil and gas discovered in the deep water of the Baiyun sag are dominantly from high quality gravity flow sandstones, including channel complexes, sheets, and channel-levee complexes. The analyses of the sediment supply, feeding channel, internal architecture of sedimentary bodies, depositional process and flow regime show that the development of three types of high quality reservoirs are controlled by sediment composition of the provenance (continental margin): Under the background of rich sand provenance, sandy debris flow is likely to form, giving rise to high quality reservoirs like channel complexes and sheets down dip the shelf-slope break. These reservoirs can be identified by seismic reflections such as incised valley, mound shape, and amplitude anomaly, and described by combining single sand body tracking with waveform recognition of sands and seismic attribute analysis. Under the background of sand-mud mixed provenance, gravity flow deposits are to occur below the shelf-slope break, where sedimentation differentiation is the key to the formation of high quality reservoirs. In the case that channel-levee complex is formed, high quality sandstone reservoirs, usually in the channel or the fan lobe below, can be identified and described by seismic features like U-shaped erosion on seismic profile, amplitude anomaly, bird-wing shaped seismic reflection, and waveform recognition.

Onshore Sandstone Facies Characteristics and Reservoir Quality of Nyalau Formation, Sarawak, East Malaysia: An Analogue to Subsurface Reservoir Quality Evaluation

Shallow marine sandstones are substantial hydrocarbon reservoirs located around the globe and in Southeast Asia. Understanding the internal characteristics, distribution, geometry and lateral extent of these sandstones are essential parts of successful exploration and production strategy. This study presents the first detailed work on reservoir sandstone facies including textural characteristics of shallow marine sandstones (well-exposed outcrops) of the Nyalau Formation (Oligocene–Middle Miocene), Bintulu area, Sarawak, East Malaysia. This formation is the onshore equivalent of the offshore cycles II and III. We examined five different major types of sandstone facies on the basis of sedimentological characteristics, grain size distribution, porosity (ϕ) and permeability (k). The analyzed sandstone facies are: (1) hummocky cross-stratified sandstones (ϕ = 32.07 %, k = 20.78 md; thickness from 1 to 2 m); (2) herringbone cross-bedded sandstones (ϕ = 31.31 %, k = 7.7 m; thickness from 1 to 10 m); (3) trough cross-bedded sandstones (ϕ = 35.80 %, k = 5.97 md; thickness from 0.5 to 1 m); (4) wavy- to flaser-bedded sandstones (ϕ = 19.84 %, k = 2.31 md; thickness from 0.5 to 3.5 m); and (5) bioturbated sandstones (ϕ = 8.21 %, k = 3.46 md; thickness from 1 to 2 m). By integrating these parameters, we observed that the best reservoir quality sandstones are hummocky cross-stratified sandstone and herringbone cross-bedded sandstone, because they have better porosity–permeability than that of other sandstone facies, despite having similar grain distribution with probability curves having steep trends and almost same grain size, roundness and sorting. Upon comparing the different facies, inferences can be made that porosity–permeability is distributed randomly. We conclude that there exist heterogeneities within different sandstone facies which may apply to the reservoir properties in the subsurface.

Braided river delta deposition and deep reservoirs in the Bohai Bay Basin: A case study of the Paleogene Sha 1 Member in the southern area of Nanpu Sag

Abstract Based on core description, conventional thin section, cast thin section and scanning electron microscope (SEM) analysis, combined with general physical analysis, the physical properties of the braided river delta sandstone reservoirs and the range of reservoir quality of the Sha 1 member have been analyzed in the southern Nanpu Sag of the Bohai Bay Basin. The characteristics and controlling factors of the southern provenance of Sha 1 reservoirs are examined to reveal the causes for the formation of deep, high-quality reservoirs more than 4000 m deep. Sha 1 reservoirs in the study area are made up of gravel rock, pebbled inequigranular sandstone, medium sand and gritrock. The lithology is mainly lithic feldspar sandstone, the contents of rigid particles like quartz and metamorphic rock cuttings are higher, the content of matrix is very low and the structure is supported by grains. The average porosity is 12.8%. The average permeability is 154.9×10 −3 μm 2 . The reservoir type is low porosity and high permeability. The reservoir space is mainly made up of primary and secondary pores. Parent rock type, sedimentary environment and the abnormal high pressure in the Sha 1 Member are the dominant factors controlling the reservoir properties. It is inferred that high quality sandstone reservoirs with high natural productivity of oil and gas are widely developed in the strata more than 4000 m deep in the Bohai Bay Basin, and so conventional sandstone reservoir exploration is expected to expand to these deeper intervals.

Geochemical Variations in Hydrocarbon Components Distribution in a Prograding Deltaic Sequence: A Case Study of the Baram Delta, Offshore Sarawak Basin, Malaysia

Studies on hydrocarbon distribution have evolved from basic reservoir characterization to complex studies today involving the interactions between oil components and clay minerals and sequential extraction studies on hydrocarbon extracts in reservoir rocks. Findings from such studies include the discovery of variations in oil fractions in reservoirs such as adsorbed oil and free oil. The theory that first oil charge preferentially interacts with clay minerals occurring in pores and as coatings in reservoirs was also proposed by some researchers. Despite, all these studies some aspects of variations in the composition of hydrocarbons in reservoir rocks still need to be investigated further. This study has been carried out particularly because the qualitative and quantitative composition of aromatic and aliphatic components of hydrocarbons in terms of the presence and quantities of hydrocarbon functional groups and how they relate to hydrocarbon migration have not been exhaustively discussed. This study uses Ultra-Violet visible light (UV-vis) and Fourier Transform Infra Red (FTIR) to characterize variations in hydrocarbon distribution in reservoir quality sandstones from three fields namely BD01, BD02 and BD03 in the Baram Delta, offshore Sarawak and to deduce how these variations relate to differential migration patterns in hydrocarbons. Hydrocarbon extraction was done in the ultra vilolet visible (UV-vis) experiment using 0.1M sodium pyrophosphate as solvent whereas in the Fourier Transform Infra Red (FTIR), the experiment was done on very fine powdered samples of the sandstones. Results from both the UV-vis and FTIR experiments indicate a dominance of aromatic functional groups in the samples. Most of the samples have E4/E6 ratio of more than 1 which indicates a high degree of aromacity. The BD01 field sandstones with a maximum porosity of 32% has the highest average E4/E6 ratio of 1.21, followed by the BD02 field sandstones with a maximum porosity of 29% and average E4/E6 ratio of 1.19 and the BD03 field with a maximum porosity of 20% and an average E4/E6 ratio of 1.09. The dominance of aromatics in the samples is interpreted as a possible indication of episodes of migration of aliphatics in the past leaving the aromatics behind with the variations in E4/E6 ratio reflecting the micro heterogeneities in the samples.

Seismic stratigraphic relationships within a lowstand reservoir system: examples from the Barrow Group, Southern Exmouth Sub-Basin, NW Australia

The Late Jurassic–Early Cretaceous Eskdale and Macedon members of the lower Barrow Group comprise some of the main oil-bearing reservoirs in the Exmouth Sub-basin. These high quality sandstones form the reservoirs in the Stybarrow and Eskdale oil fields. Understanding the architecture of these deepwater successions is important in both exploration and development projects. This paper documents detailed stratigraphic relationships and depositional geometries as defined on high quality seismic data sets and associated well data. An initial phase of lowstand deposition (Eskdale Member) is recorded by the development of two main canyon systems; the Eskdale and slightly younger Laverda canyons. These systems are remarkably well imaged on 3D seismic data, allowing for detailed definition of channel morphology and associated fill and spill facies. Channel complexes are up to 1 km-wide and 100 m-deep, and display evidence for multiple phases of erosion and in-channel aggradation. Overbank/spill facies are also identifiable, including crevasse lateral lobes and ‘chute’ channels. These canyon systems fed contemporaneous downdip basin floor fans that display a variety of classical fan morphologies and depositional elements including terminal lobes, fan pinchout edges, distributary channel systems and localised outflow facies. The distribution and morphology of the Eskdale and Laverda canyons and associated fan intervals can be related to topographic gradient changes within the basin (i.e. from shelf to slope to basin floor). These topographic changes are in turn a response to regional tectonism, in particular active rifting along basin margins. An ensuing phase of less confined, shelf-slope turbidite deposition (Macedon Member) records late-stage lowstand processes. Detailed well and seismic control from the Stybarrow Field and surrounding areas has identified multicyclic sands recording deposition of stacked turbidite lobes. These lobe complexes are more laterally continuous than the canyon facies and are comprised of amalgamated sheet sands and lower-relief channel sands, and are generally between 15–25 m thick. In the greater Stybarrow area the original lobate geometries have been subsequently modified by a phase of late-stage erosion. Outcrop analogues for the Macedon Member can be seen in the lobe complexes from the Tanqua Fan intervals of the Karoo Basin, which are similar in both scale and morphology. These lobe complexes extend laterally for tens of kilometres with constituent individual lobes often displaying evidence for compensational depositional processes. This paper was originally published in the Proceedings of the West Australian Basins Symposium 2013, which was held from 18–21 August 2013 in Perth, Australia.