Reservoir Quality Of Sandstones Research Articles

Fluvial reservoirs stacked in thin deltaic successions of the Lower Cretaceous Grand Rapids Formation, east-central Alberta, Canada

The Manatokan Field in east-central Alberta offers a unique opportunity to characterize paralic sandstone reservoirs in 3D using a dense network of well data (approximately [Formula: see text]). Within the [Formula: see text] study area, the 100-m thick Lower Cretaceous Grand Rapids Formation is dominantly composed of sediment deposited in two depositional environments: river-dominated deltas and marine-influenced fluvial rivers. Up to 33 individual fluvial bodies, occurring at five stratigraphic levels and eroding into deltaic parasequences, are identified in the oil-charged upper part of the formation. The width and thickness of fluvial bodies typically range from 50 to 9000 m and from 5 to 50 m, respectively. Examination of cores, wireline logs, and strategically located 3D seismic data indicates that fluvial bodies are dominantly filled by inclined heterolithic deposits emplaced as downflow translation point bars (PBs) separated by mud-filled abandoned channels. Although individual PBs are relatively small ([Formula: see text]), the dense subsurface data set provides the means to build facies maps that illustrate their internal architecture and the distribution of reservoir heterogeneities. Reservoir-quality sandstone occurs on the upstream portion of PBs and usually forms continuous beds along the base of fluvial bodies that extend underneath abandoned channel deposits. High reservoir connectivity along the base of these heterolithic fluvial bodies constitutes a major advantage for heavy oil reservoir production driven by gravity. Core evidences also indicate potential communication between fluvial bodies and surrounding deltaic sandstones or older underlying fluvial reservoirs, which may lead to unexpected results during field development. The Grand Rapids Formation provides a good subsurface analogue of complex marginal-marine clastic reservoirs, and its study may help to explain unanticipated production results in similar hydrocarbon areas.

Diagenesis and reservoir quality of the Lower Cretaceous Quantou Formation tight sandstones in the southern Songliao Basin, China

The Lower Cretaceous Quantou Formation in the southern Songliao Basin is the typical tight oil sandstone in China. For effective exploration, appraisal and production from such a tight oil sandstone, the diagenesis and reservoir quality must be thoroughly studied first. The tight oil sandstone has been examined by a variety of methods, including core and thin section observation, XRD, SEM, CL, fluorescence, electron probing analysis, fluid inclusion and isotope testing and quantitative determination of reservoir properties. The sandstones are mostly lithic arkoses and feldspathic litharenites with fine to medium grain size and moderate to good sorting. The sandstones are dominated by feldspar, quartz, and volcanic rock fragments showing various stages of disintegration. The reservoir properties are quite poor, with low porosity (average 8.54%) and permeability (average 0.493mD), small pore-throat radius (average 0.206μm) and high displacement pressure (mostly higher than 1MPa). The tight sandstone reservoirs have undergone significant diagenetic alterations such as compaction, feldspar dissolution, quartz cementation, carbonate cementation (mainly ferrocalcite and ankerite) and clay mineral alteration. As to the onset time, the oil emplacement was prior to the carbonate cementation but posterior to the quartz cementation and feldspar dissolution. The smectite to illite reaction and pressure solution at stylolites provide a most important silica sources for quartz cementation. Carbonate cements increase towards interbedded mudstones. Mechanical compaction has played a more important role than cementation in destroying the reservoir quality of the K1q4 sandstone reservoirs. Mixed-layer illite/smectite and illite reduced the porosity and permeability significantly, while chlorite preserved the porosity and permeability since it tends to be oil wet so that later carbonate cementation can be inhibited to some extent. It is likely that the oil emplacement occurred later than the tight rock formation (with the porosity close to 10%). However, thicker sandstone bodies (more than 2m) constitute potential hydrocarbon reservoirs.

The evolution of pore-scale fluid-saturation in low-permeability sandstone reservoirs

In many tight-gas basins of the western United States distinguishing between productive and non-productive low-permeability sandstones, and predicting relative amounts of gas and water production is difficult. Comparison of gas shows, calculated water saturations, and saturation-height profiles between gas-productive and non-productive sandstones of equal reservoir quality all appear similar. Capillary pressure derived height functions are difficult to apply, and classic rock-typing procedures lack the predictive capability that is common to more traditional reservoirs. Basin reconstructions suggest the timing of petroleum charge and migration preceded maximum burial and uplift. This initial charge was likely a primary drainage displacement with reservoir porosity greater by a factor of 2-3 relative to values found today and permeability greater by 1-3 orders of magnitude. These reservoir systems became low-permeability following initial charge reflecting continued diagenesis throughout burial, subsequent uplift and erosion. With burial, decreasing pore volume caused water saturations and gas columns to increase. During uplift and erosion gas columns adjusted to changing structural configuration. In some cases this led to gas accumulations being leaked and spilled. In other cases, structural readjustment resulted in capillary imbibition and, in some cases, secondary (or higher order) drainage and imbibition. Within trapped accumulations, gas expansion upon uplift further increased gas columns. In cases where gas columns were spilled or within migration pathways imbibition led to residual or near-residual water saturations. Conventional formation evaluation is fundamentally rooted in concepts associated with primary drainage displacement. Tight-gas reservoirs that have experienced late uplift following an earlier phase of charge are unlikely to be characterized by primary drainage and are much more likely to be characterized by imbibition or secondary (or higher order) drainage and possibly imbibition. The hysteresis between primary drainage and imbibition or secondary (or higher order) drainage and imbibition in tight-gas reservoirs is significant and unlike many more traditional reservoirs does not tend to converge on a narrow range of values. Estimates of water saturation are scalar values and do not contain information that allows the saturation history and displacement direction to be deciphered. Recognition that reservoirs are unlikely to be in primary drainage equilibrium is a fundamental paradigm shift that impacts petroleum evaluation at all scales ranging from basin potential to completion decisions within a given well. Although this paper is written from the perspective of tight-gas petroleum systems, the principles are equally applicable to low-permeability oil reservoirs.

Impact of sequence stratigraphy, depositional facies and diagenesis on reservoir quality: A case study on the Pennsylvanian Taiyuan sandstones, northeastern Ordos Basin, China

The Pennsylvanian Taiyuan Formation of the Shenmu Field in the northeastern Ordos Basin of China contains tight sandstone reservoirs that have recently been commercially produced. An evaluation of the reservoir quality of the Taiyuan sandstones will play a critical role in the development of the field. An investigation was conducted to explore possible effects of the sequence stratigraphy, depositional facies and diagenetic alterations on the reservoir quality of the Taiyuan sandstones based on core descriptions, the examination of thin-sections, and core plug and scanning electron microscope analyses. The Taiyuan Formation consists of lowstand system tracts (LST), transgressive system tracts (TST) and highstand system tracts (HST). The LST sandstones are principally medium-to coarse-grained and are interpreted to have been deposited in the dominant distributary channels of a delta plain. The early TST fine-to coarse-grained sandstones were largely deposited in the underwater distributary channel and mouth bar of a delta front, and the middle TST fine-to medium-grained sandstones were deposited in the shoreface to foreshore environment. The HST silt to medium-grained sandstones were mostly deposited in the mouth bar of a delta front and shoreface to foreshore. The Taiyuan sandstones, which are composed of sublitharenites, quartzarenites and litharenites, suffered from extensive compaction that resulted in a large loss of intergranular porosity before the sandstones were further cemented severely. The sandstone cements are mostly composed of illite, ankerite, calcite and quartz. The Taiyuan sandstones have a particularly low average core plug porosity of 7.41% and horizontal permeability of 0.916 mD, which results from that most of the pores of the sandstones are micropores and secondary pores with poor connectivity. The LST dominant distributary channel, early TST underwater distributary channel and proximal mouth bar, and HST shoreface to foreshore sandstones with relatively coarser grain sizes (mostly medium-to coarse-grained) have relatively higher porosities and permeabilities than the sandstones with relatively finer grain size, which is ascribed to a widespread early dissolution by meteor water leaching and lower content of cements within the coarser-grained sandstones. However, the LST dominant distributary channel sandstones had undergone a more effectively early dissolution and less carbonate cementation than the TST underwater distributary channel and proximal mouth bar and HST shoreface and foreshore sandstones had, which lead to the relatively best reservoir quality of the LST dominant distributary channel sandstones among the Taiyuan sandstones. The study revealed that the reservoir quality of the tight Taiyuan sandstones was controlled by sequence stratigraphy framework, depositional facies, grain size and diagenetic alterations together. The sequence stratigraphy framework played a key role in controlling the reservoir quality of the Taiyuan sandstones by governing the depositional facies and corresponding diagenetic products while the grain size affected the reservoir quality of the sandstones by controlling the content of cement within the sandstones.

Diagenetic Evolution and Reservoir Quality of Sandstones in the North Alpine Foreland Basin: A Microscale Approach

Siliciclastic reservoir rocks of the North Alpine Foreland Basin were studied focusing on investigations of pore fillings. Conventional oil and gas production requires certain thresholds of porosity and permeability. These parameters are controlled by the size and shape of grains and diagenetic processes like compaction, dissolution, and precipitation of mineral phases. In an attempt to estimate the impact of these factors, conventional microscopy, high resolution scanning electron microscopy, and wavelength dispersive element mapping were applied. Rock types were established accordingly, considering Poro/Perm data. Reservoir properties in shallow marine Cenomanian sandstones are mainly controlled by the degree of diagenetic calcite precipitation, Turonian rocks are characterized by reduced permeability, even for weakly cemented layers, due to higher matrix content as a result of lower depositional energy. Eocene subarkoses tend to be coarse-grained with minor matrix content as a result of their fluvio-deltaic and coastal deposition. Reservoir quality is therefore controlled by diagenetic clay and minor calcite cementation.Although Eocene rocks are often matrix free, occasionally a clay mineral matrix may be present and influence cementation of pores during early diagenesis. Oligo-/Miocene deep marine rocks exhibit excellent quality in cases when early cement is dissolved and not replaced by secondary calcite, mainly bound to the gas-water contact within hydrocarbon reservoirs.

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.

How sandstone porosity and permeability vary with diagenetic minerals in the Scotian Basin, offshore eastern Canada: Implications for reservoir quality

The Scotian Basin is an under-explored offshore basin that has produced gas and minor oil from Jurassic–Cretaceous deltaic sandstones. Reservoir quality is an important exploration risk in the basin. This study evaluates whether there are systematic stratigraphic or geographic variations in diagenetic mineral assemblage control of reservoir porosity and permeability. Three data sets are used: a compilation of all available core-plug porosity and permeability measurements (3271 in total), a subset of 577 corresponding to thin sections with lithofacies assignments, and a subset of 35 thin sections principally from reservoir sandstones, in which modal abundance of diagenetic minerals has been determined by image analysis of scanning electron microscope backscattered electron images. Abundances above a 4% threshold of diagenetic kaolinite, calcite and ankerite correlate inversely with permeability, but chlorite and possibly siderite correlate positively. Diagenetic assemblages show no systematic variation with stratigraphy or geography, both of which may involve variable detrital supply. Permeability shows the well-known variation with grain size and depth of burial, but after correcting for these effects it is greatest in estuarine channel and river-mouth turbidite sandstones. This is because these facies preferentially develop chlorite rims on detrital quartz grains and are also the sites of enhanced flow of late basinal fluids resulting in secondary porosity. Local effects such as facies distribution, architecture of channel sandstones, fluid pathways related to complex salt tectonics, and the effects of overpressure are more important than predictable basin-wide effects in controlling sandstone reservoir quality.

Diagenesis and reservoir quality analysis in the Lower Cretaceous Qishn sandstones from Masila oilfields in the Sayun–Masila Basin, eastern Yemen

Lower Cretaceous sandstones of the Qishn Formation have been studied by integrating sedimentological, petrological and petrophysical analyses from wells in the Masila oilfields of eastern Yemen. These analyses were used to define the origin, type of diagenesis and its relation to reservoir quality. The sandstones of the Qishn Formation are predominately quartz arenite to subarkose arenite with sublitharenite and quartz wackes displaying a range of porosities, averaging 22.33%. Permeability is likewise variable with an average of 2844.2 mD. Cementation coupled with compaction had an important effect on porosity destruction after sedimentation and burial. The widespread occurrence of early calcite cement suggests that the sandstones of the Qishn Formation lost significant primary porosity at an early stage of its diagenetic history. In addition to poikilotopic calcite, several different cements including kaolinite, illite, chlorite and minor illite–smectite occur as pore‐filling and pore‐lining cements, which were either accompanied by or followed the development of the early calcite cement. Secondary porosity development occurred due to partial to complete dissolution of early calcite cements and feldspar grains. The new data presented in this paper suggest the reservoir quality of Qishn sandstones is strongly linked to their diagenetic history; hence, the reservoir quality is reduced by clay minerals, calcite and silica cements but is enhanced by the dissolution of the unstable grains, in addition to partial or complete dissolution of calcite cements and unstable grains. Copyright © 2015 John Wiley & Sons, Ltd.

Predictive distribution of high-quality reservoirs of tight gas sandstones by linking diagenesis to depositional facies: Evidence from Xu-2 sandstones in the Penglai area of the central Sichuan basin, China

The second member of the Upper Triassic Xujiahe Formation (Xu-2) tight gas sandstone reservoirs is the main exploration target for hydrocarbons in the central Sichuan basin in China. The Xu-2 sandstones are characterized as tight with low porosity, low permeability and strong heterogeneity. Heterogeneity in diagenetically induced reservoirs hinders the economic success of Xu-2 tight gas sandstones. Analysis of these tight reservoirs by linking diagenesis to depositional facies provides a powerful tool to predict the distribution of high-quality reservoirs. This study investigates the composition, sedimentary facies, and diagenetic history and their impact on reservoir quality of the Xu-2 sandstones. Reservoir property, lithological components, depositional micro-facies, diagenesis, and diagenetic minerals were determined through petrographic studies including X-ray diffraction, scanning electron microscope (SEM), backscattered electron detector (BSE) image analysis and core analysis. The results show that the sandstones are dominated by feldspathic litharenite, litharenite and sublitharenite. The reservoir properties of the Xu-2 sandstones are generally poor with a porosity ranging from 0.68% to 15.94% and permeability ranging from 0.001 to 274 mD, which are attributed to the significant compaction and cementation. Porosity systems of the Xu-2 sandstones are of primary and secondary origins. The primary intergranular porosity ranges from trace levels to 7.50%, with an average of 2.50%. The secondary porosity (ranging from trace levels to 8.5%, averaging 2.25%) was derived from partial to complete dissolution of framework grains and is of great importance for the Xu-2 sandstones. By linking diagenesis to depositional facies, it can be concluded that the high-quality reservoirs in Xu-2 tight gas sandstones are associated with medium to coarse-grained sandstones of mouthbar or underwater distributary channel facies, development of secondary porosity, and low content of cements such as carbonate and clay minerals. The best reservoir quality is potentially encountered in the sandstones at deeper depths, which experienced a higher degree of dissolution due to closer proximity to the underlying Xu-1 source rocks.

Reservoir quality and petrophysical properties of Cambrian sandstones and their changes during the experimental modelling of CO2storage in the Baltic Basin

The objectives of this study were (1) to review current recommendations on storage reservoirs and classify their quality using experimental data of sandstones of the Deimena Formation of Cambrian Series 3, (2) to determine how the possible CO2 geological storage (CGS) in the Deimena Formation sandstones affects their properties and reservoir quality and (3) to apply the proposed classification to the storage reservoirs and their changes during CGS in the Baltic Basin. The new classification of the reservoir quality of rocks for CGS in terms of gas permeability and porosity was proposed for the sandstones of the Deimena Formation covered by Lower Ordovician clayey and carbonate cap rocks in the Baltic sedimentary basin. Based on permeability the sandstones were divided into four groups showing their practical usability for CGS (‘very appropriate’, ‘appropriate’, ‘cautionary’ and ‘not appropriate’). According to porosity, eight reservoir quality classes were distinguished within these groups. The petrophysical, geochemical and mineralogical parameters of the sandstones from the onshore South Kandava and offshore E6 structures in Latvia and the E7 structure in Lithuania were studied before and after the CO2 injection-like alteration experiment. The greatest changes in the composition and properties were determined in the carbonate-cemented sandstones from the uppermost part of the South Kandava onshore structure. Partial dissolution of pore-filling carbonate cement (ankerite and calcite) and displacement of clay cement blocking pores caused significant increase in the effective porosity of the samples, drastic increase in their permeability and decrease in grain and bulk density, P- and S-wave velocity, and weight of the dry samples. As a result of these alterations, carbonate-cemented sandstones of initially ‘very low’ reservoir quality (class VIII), ‘not appropriate’ for CGS, acquired an ‘appropriate’ for CGS ‘moderate’ quality (class IV) or ‘very appropriate’ ‘high-2’ reservoir quality (class II). The permeability of the clay-cemented sandstones of ‘very low’ reservoir quality class VIII from the lower part of the E7 reservoir was not improved. Only minor changes during the alteration experiment in the offshore pure quartz sandstones from the E6 and E7 structures caused slight variations in their properties. The initial reservoir quality of these sandstones (‘high-1’ and ‘good’, classes I and III, respectively, in the E6 structure, and ‘cautionary-2’, class VI in the E7 structure) was mainly preserved. The reservoir sandstones of the Deimena Formation in the South Kandava structure had an average porosity of 21%, identical to the porosity of rocks in the E6 structure, but twice higher average permeability, 300 and 150 mD, respectively. The estimated good reservoir quality of these sandstones was assessed as ‘appropriate’ for CGS. The reservoir quality of the sandstones from the E7 offshore structure, estimated as ‘cautionary-2’ (average porosity 12% and permeability 40 mD), was lowest among the studied structures and was assessed as ‘cautionary’ for CGS. Petrophysical alteration of sandstones induced by laboratory-simulated CGS was studied for the first time in the Baltic Basin. The obtained results are important for understanding the physical processes that may occur during CO2 storage in the Baltic onshore and offshore structures.

Open versus closed mesogenetic systems in Cretaceous fluvial and tidal sandstones, Sirt Basin, Libya

ABSTRACT This study constrains factors controlling the distribution of diagenetic alteration and their impact on reservoir quality of the Cretaceous sandstones from the Al-Bayda Platform, located in the southern Sirt Basin (Libya). These factors include the presence of early cements as well as the influx of hot basinal brines. The studied samples come from two blocks in the Khalifa Field, which are dislocated by a major normal fault. The deep-burial (mesogenetic) alteration includes the partial to pervasive replacement of early (eogenetic) dolomite and calcite cements by ferroan-dolomite, ankerite and siderite, precipitation of grain-coating chlorite, and cementation by quartz overgrowths, barite and anhydrite, particularly in the downthrown block. The association of quartz overgrowths with barite suggests that deep burial was influenced by the influx of hot basinal brines through faults. Conversely, deep-burial alteration in braided fluvial deposits of the Nubian sandstones of the upthrown block include: illitization of eogenetic smectite, quartz cementation and formation of chlorite. This study shows that deep burial of the studied sandstones did not occur in a closed system, but was affected by the influx of hot basinal brines through faults, which formed during basin rifting. This interpretation is supported by the relatively high homogenization temperatures (100–110°C; corrected to 110–125°C) of primary fluid inclusions within quartz overgrowths, which exceed the maximum burial temperatures experienced by the Cretaceous succession, and by the high salinity of these inclusions.

Factors controlling reservoir properties and hydrocarbon accumulation of lacustrine deep-water turbidites in the Huimin Depression, Bohai Bay Basin, East China

Lacustrine deep-water turbidite plays are a novel area for exploration in the Huimin Depression, Bohai Bay Basin. Turbidites in the Shang 847 block, a typical turbidite play in the Huimin Depression, provide an opportunity to study the factors controlling the reservoir properties and hydrocarbon accumulation in lacustrine turbidite sandstones. The reservoir quality of turbidite sandstones (very fine-grained, moderately to well sorted, mainly lithic arkose) in this study area are mainly controlled by the distribution patterns of carbonate cements and pseudomatrix. Significant inverse relationships exist between the volume of carbonate cement and both porosity and permeability of the turbidite sandstones. Carbonate cement is located preferentially near the margins of the sandstone bodies. Sandstones with distance from the sandstone–mudstone contact surface less than 0.7 m or with thickness less than 1.2 m are commonly tightly cemented (carbonate cement >15%) with low porosity and permeability (lower than 10% and 0.1 mD, respectively). The source of carbonate cement was most likely external, probably derived from the surrounding mudstone. Most pore-filling carbonate cements occurred during late diagenesis at burial depths greater than 2200 m. The petrophysical properties of turbidites have a positive relationship with the content of kaolinite and chlorite, but have a negative relationship with the content of illite. 2-D and 3-D reconstructions of non-oil bearing and oil-bearing layers indicate that dissolution of carbonate cement, feldspars and unstable rock fragments was more developed in oil-bearing layers than in non-oil bearing layers and hance oil-bearing layers have higher porosity and larger pore sizes. Petrophysical property appears to have a significant effect on the hydrocarbon accumulation in the turbidite sandstones. Sandstones with porosities lower than 9% and/or permeabilities lower than 0.78 mD are not prone to contain oil.

Petrography, diagenesis and reservoir characteristics of the Pre-Cenomanian sandstone, Sheikh Attia area, East Central Sinai, Egypt

The diagenetic influence on reservoir characteristics was investigated for the Pre-Cenomanian (Early Paleozoic and Early Cretaceous) sandstone sequence in the Sheikh Attia area, East Central Sinai. This sequence can be distinguished into four formations: Sarabit El-Khadim Formation (Cambrian) at the base, Abu Hamata Formation (Cambro-Ordovician), Adedia Formation (Ordovician-Silurian) and Malha Formation (Early Cretaceous) on the top. The sandstones of Pre-Cenomanian sequence in the Sheikh Attia area are dominantly quartz arenites and subarkoses, where the quartz grains constitute about 82.3–98.4% of the framework composition with an average value of approximately 94% of the framework composition. Feldspars range in abundance from 0% to14.2%, with an average value of about 3% of the framework composition. The rock fragments constitute up to 9.8% of volume percent of framework grains, with an average of about 2.7%.Diagenetic events identified in these sandstones include compaction, cementation by calcite, quartz, clay minerals and iron oxides, dissolution and alteration of unstable clastic grains, and tectonically induced grain fracturing. Unstable clastic grains like feldspars suffered considerable alteration to kaolinite.The Pre-Cenomanian (Early Paleozoic and Early Cretaceous) sandstones possess good reservoir characteristics because they retain sufficient porosity and permeability in some intervals. These sandstones are characterized by porosity ranges between 3.80% and 27.60%, and have a permeability range from k⩽0.03mD, for tight sandstones to k⩾50mD, for the more permeable parts. The Pre-Cenomanian sandstones can be classified into four petrophysical flow units (megaport, macroport, mesoport and microport) with varying reservoir performances and are distinguished by comparable ranges of R35.Petrographic observations showed that the Early Paleozoic sandstones are texturally immature owing to the abundance of angular grains, non-uniformity of grain size, high amounts of matrix clay mineral, and high amounts of feldspar grains. The Early Cretaceous sandstones have low amounts of rock fragments, clay minerals, and feldspars grains. Statistical analysis of the petrophysical data confirms that the reservoir quality of Early Cretaceous sandstone is higher than that of Early Paleozoic sandstones (the reservoir quality index of Early Cretaceous sandstone is 0.383μm and for Early Paleozoic sandstones is 0.205μm).

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.

The Relevance of Mineral Mobilization and -Dissolution on the Reservoir Quality of Sandstones in CO2 Storage Sites

Rotliegend siliciclastic formations are important reservoirs in central Europe. These sediments consist of pristine red coloured and bleached, high porous and permeable sandstones. To evaluate the relevance of distinct fluids and their fluid-rock alteration reactions on such bleaching processes laboratory static batch experiments under reservoir conditions were conducted. Thereby mineralogical, petrophysical and (hydro-, geo-) chemical rock features were investigated by different analytical methods before and after the experiments. The achieved results suggest that during such fluid-rock interactions a complex interplay between mineral detachment and mineral dissolution processes will control the porosity and permeability of reservoir sandstones.

An Integrated Rock Typing Approach for Unraveling the Reservoir Heterogeneity of Tight Sands in the Whicher Range Field of Perth Basin, Western Australia

Tight gas sands in Whicher Range Field of Perth Basin show large heterogeneity in reservoir characteristics and production behavior related to depositional and diagenetic features. Diagenetic events (compaction and cementation) have severely affected the pore system. In order to investigate the petrophysical characteristics, reservoir sandstone facies were correlated with core porosity and permeability and their equivalent well log responses to describe hydraulic flow units and electrofacies, respectively. Thus, very tight, tight, and sub-tight sands were differentiated. To reveal the relationship between pore system properties and depositional and diagenetic characteristics in each sand type, reservoir rock types were extracted. The identified reservoir rock types are in fact a reflection of internal reservoir heterogeneity related to pore system properties. All reservoir rock types are characterized by a compacted fabric and cemented framework. But distribution and dominance of diagenetic products in each of them depend on primary depositional composition and texture. The results show that reservoir rock typing based on three aspects of reservoir sandstones (depositional properties, diagenetic features and petrophysical characteristics) is a suitable technique for depiction of reservoir heterogeneity, recognition of reservoir units and identifying factors controlling reservoir quality of tight sandstones. This methodology can be used for the other tight reservoirs.

Control factors on tight sandstone reservoirs below source rocks in the Rangzijing slope zone of southern Songliao Basin, East China

Abstract Based on the analysis of reservoir characteristics, this paper studies on the control factors on quality of the tight sandstone reservoirs in Fuyu oil layer below source rocks in Rangzijing slope zone in the Southern Songliao Basin from 5 aspects, i.e. base level cycle, deposition, diagenesis, tectonic activity and CO 2 filling, so as to identify the sweet spots in the reservoirs. The following results are obtained: (1) base level cycle and deposition condition control the relation of source rocks and reservoirs, stacking pattern of reservoirs and original property of reservoirs; (2) compaction is the main factor making the reservoirs tight, and cementation exacerbates the tightness; (3) the secondary pores produced by organic acids migrating downward into reservoirs improve the reservoir quality to some extent; (4) tectonic activity plays a positive role in improvement of reservoir quality in three levels, and (5) CO 2 filling can improve the percolation of local reservoirs, but it is adverse for the formation of effective reservoirs. In the study area, the formation of high-quality tight sandstone reservoirs is controlled by the coupling of base level cycle, main sedimentary facies, dominant corrosion zone and tectonic uplifting area.

Analysis of the reservoir electrofacies in the framework of hydraulic flow units in the Whicher Range Field, Perth Basin, Western Australia

Reservoir characterization and recognition of the main factors controlling the reservoir quality has a significant share in presenting a real picture of the reservoir properties. In this study, by examining a set of reservoir well log data and their clustering based on mathematical and statistical principles, reservoir electrofacies are identified for the tight sands of Willespie Formation in five wells from the Whicher Range Field in Western Australia. These internally homogenous and externally heterogeneous clusters are truly a reflection of geological (sedimentary and diagenetic) and petrophysical properties of the reservoir. In this study, reservoir electrofacies (EF) were determined using clustering of well logs and along with porosity and permeability data in two individual sedimentary and petrophysical approaches. In the sedimentary approach, three EFs were identified that coincide with clean sands, dirty sands and shaly intervals. They are mostly related to the sedimentary texture and lithological properties indicating high reservoir heterogeneity. In the second approach, four EFs were determined in relation to the petrophysical properties of sandy packages within the reservoir. In addition, in order to find a good connection between EFs and production zones within sandy packages, five hydraulic flow units (HFUs) were introduced. The results show that low quality HFUs (i.e. A, B and to some extent C) in all petrophysical electrofacies are mainly related to the fine grained facies deposited in low energy systems. In contrast, high quality HFUs (i.e. D and E) are related to the medium to coarse and very coarse grained facies, showing different petrophysical properties, although they have generally low permeability and they are considered as tight sands. Thus, three sand types, depending on the severity of diagenetic effects, known as type 1 or very tight sands, type 2 or tight sands and type 3 or sub-tight sands were differentiated. In comparison, sandstones in type 3 with higher porosity and permeability have the best reservoir quality, whereas low reservoir quality sandstones in type 1 have been strongly affected by diagenetic effects (quartz and clay cementation). The results indicate a good agreement between core derived rock types and log facies. Using the methodology described in this study, it is possible to track reservoir flow units from well log responses.

Understanding the provenance and reservoir quality of the Sele Formation sandstones of the UK Central Graben utilizing detrital garnet suites

Abstract Detrital garnet suites have been demonstrated to be reliable indicators of the mineralogical and lithological characteristics of sediment source areas. This study applies garnet analysis to the Paleocene to Eocene Sele Formation deep-water sandstone units of the central North Sea. These stratigraphic units are economically important as they represent one of the main hydrocarbon reservoir intervals in this mature basin. The routing of turbidity currents into the Central Graben has been demonstrated to be related to axial fans (ultimately sourced from Lewisian and Moine basement rocks and Triassic sandstones to the NW) and lateral fans (ultimately sourced from the Dalradian basement rocks to the west). Garnet analysis suggests the majority of samples can be attributed to the axial fan system and that the lateral system contributed little to sandstone deposition east of the Gannet Fields. This contradicts previous seismic mapping work, which suggested that the lateral fan system dominated sedimentation as far east as the Merganser Field. This reinterpretation is potentially important for our understanding of sediment routing and its impact on the distribution of reservoir quality, particularly as this is believed to relate directly to proximity to the shelf.

Fluvial architecture and connectivity of the Williams Fork Formation: use of outcrop analogues for stratigraphic characterization and reservoir modelling

Abstract This study addresses the stratigraphic architecture and connectivity of fluvial sandstones of the Williams Fork Formation through outcrop analysis, and static and dynamic modelling of equivalent reservoirs in the Piceance Basin, Colorado. The Williams Fork Formation is a succession of fluvial channel sandstones, crevasse splays, floodplain mudstones and paludal coals that were deposited by meandering- and braided-river systems within coastal- and alluvial-plain settings. Three-dimensional (3D) static and dynamic reservoir models that are constrained to both outcrop-derived and subsurface data show how static connectivity is sensitive to sandstone-body type and width, and varies with net to gross ratio. Connectivity analyses of 3D outcrop-based architectural-element models show how relatively wide sandstone bodies enhance connectivity. At Mamm Creek Field, connectivity of sandstones that are pay within the middle Williams Fork Formation is 12–18% higher than for the lower Williams Fork Formation. For highly constrained 3D object-based models of architectural elements, connectivity is only 4% higher when crevasse splays are included as reservoir-quality sandstones. Dynamic simulation results also suggest that the best history match is possible by considering only point bars and channel bars (reservoir-quality sandstones) as pay. Additional research is necessary to determine the impact of crevasse splays on reservoir connectivity.