Sequence Reservoir Research Articles

EOCENE VOLCANICLASTICS IN THE KARTLI BASIN, GEORGIA: A FRACTURED RESERVOIR SEQUENCE

In the broader Caucasus region, multiple extrusive volcanic units are present within the Jurassic, Cretaceous, Eocene and Miocene sedimentary successions. Partial reworking of volcanic material from various provenance areas into Eocene, Oligocene and Miocene reservoir units is commonly observed in the Eastern Black Sea and in the Rioni, Kartli and Kura Basins of onshore Georgia. Reservoir quality has in general been negatively affected by volcanic rock fragments which may have undergone complex diagenetic alteration. However, despite concerns regarding reservoir quality, oil at the Samgori field, the largest field in Georgia (∼200 MM brl recovered), is hosted in altered Middle Eocene volcaniclastic sandstones interbedded with deep‐water turbidites. Previous studies of core material from numerous wells in this field showed that most of the oil is contained in altered, microfractured, laumontite‐rich tuffs which have fracture and cavernous net porosities averaging 12% and average permeability of 15 mD. The laumontite tuffs comprise only up to 20% of a tuffaceous sandstone section and occur as isolated lenses or pods on a sub‐seismic scale (i.e. 5‐10 m thick), causing highly variable oil productivity from one well to another.The petrographic analysis of samples of Middle Eocene volcaniclastic sandstones from outcrops in the central part of the Kartli Basin around Tbilisi broadly confirms the main conclusions of studies completed some 30 years ago which were based on the analysis of subsurface samples. However, the surface samples analysed show that zeolitization events typically did not improve, but actually reduced, reservoir quality due to extensive zeolite cementation. The poor reservoir properties of the plug samples, which are age‐equivalent to the proven subsurface Middle Eocene reservoir interval, highlight fracturing as a key factor controlling the presence of exceptional producers (up to 9000 b/d) in the Samgori field complex. The study therefore underlines the critical role of fracturing of the Middle Eocene volcaniclastic reservoir sequence in the Kartli Basin.

An improved stratigraphic modified lorenz (ISML) plot as a tool for describing efficiency of the hydraulic flow units (HFUs) in clastic and non-clastic reservoir sequences

An improved stratigraphic modified lorenz (ISML) plot as a tool for describing efficiency of the hydraulic flow units (HFUs) in clastic and non-clastic reservoir sequences

Alterations to sediment nutrient deposition and transport along a six reservoir sequence

Reservoir presence and construction has become commonplace along rivers due to the multitude of ecosystem services they provide. Many services are well recognized, including the effectiveness of sequestering both sediments and sediment-bound nutrients such as silts and phosphorus (P). Reservoirs are also capable of transforming or sequestering significant quantities of nutrients with more complex biogeochemical pathways, like nitrogen (N). Reservoir assessments, independent of inflow-outflow models, have primarily focused on a small number of systems creating a growing need to understand how reservoirs function both individually and as reservoir sequences within large rivers and their watersheds. Models have simulated the overall efficiency and drivers of reservoir nutrient deposition, but few have considered how a sequence of reservoirs alters deposition as an interdependent watershed-sediment-transport-system. In this study, we collected sediment cores from a six-reservoir sequence along a 5th – 6th order stream receiving treated waters from a large metropolitan area in the subtropical southeastern United States. Paleolimnological studies of subtropical reservoirs are underrepresented and are needed to understand the history of reservoir development. Using paleolimnological techniques and a known 30 year flux of riverine nutrient loading from waste water treatment facilities, we compared nutrient deposition to reservoir morphological qualities and primary producer community structure during the past ~50 years. Our findings suggest phosphorus deposition is associated with reservoir order downstream of the primary nutrient source, nitrogen deposition is linked to reservoir water retention time, and N:P is most strongly linked to reservoir surface area and watershed population density. Our results were strongly influenced by a large upstream and metropolitan nutrient source, common in large rivers, but under different conditions of nutrient loading (i.e. nonpoint source), reservoirs may express other nutrient depositional patterns.

Impact of depositional and diagenetic features on petrophysical and rock mechanical properties in Arab-D reservoir equivalent upper Jubaila Formation, Saudi Arabia

This paper presents a comprehensive analysis of multiscale geological, petrophysical and rock mechanical data acquired from 35 m of outcrop well core from the Late Jurassic (Kimmeridgian) Upper Jubaila Formation, Saudi Arabia. In this location the sequence is a typical shallow marine heterogeneous carbonate sequence and a direct analogue to a part of the prolific Arab D reservoir sequence in the subsurface towards the east. Four main lithofacies types were identified with a general shoaling upwards trend, varying from nodular bioturbated peloidal mudstone/wackestone facies to sharp-based intraclast-peloidal, skeletal rudstone/floatstone facies. The mineralogy in the upper section of the well cores is predominantly calcite, while the lower section is also comprised of some dolomite and quartz. Stratiform dedolomitization as a telogenetic overprint is only evident in the upper 18 m of the core and controlled by vertical flow of meteoric fluids. The core plug porosity distribution is lower than that of the subsurface equivalent reservoir zones, and is attributed to meteoric cementation. Thalassinoides burrow features in mudstone and wackestone facies in the upper sections of the core control horizontal permeability distribution at the centimeter to meter-scale. Micrite morphology and dedolomitization appear to be key controls on plug permeability, rock strength and sonic velocity. Based on the trends observed in compressive rock strength, p-wave velocity and plug porosity distributions, the cored section was divided into five main rock mechanical layers. Despite reduced porosity, the average compressive rock strength in the outcrop core is lower than that of the Arab-D subsurface equivalent rocks, indicating overall ‘weakening’ of the rock due to telogenetic processes and surface weathering.

Predicting Formation Pore-Pressure from Well-Log Data with Hybrid Machine-Learning Optimization Algorithms

Accurate prediction of pore-pressures in the subsurface is paramount for successful planning and drilling of oil and gas wellbores. It saves cost and time and helps to avoid drilling problems. As it is expensive and time-consuming to measure pore-pressure directly in wellbores, it is useful to be able to predict it from various petrophysical input variables on a supervised learning basis calibrated to a benchmark wellbore. This study developed and compared three-hybrid machine-learning optimization models applied to a diverse suite of 9 petrophysical input variables to predict pore-pressure across a 273-m-thick, predominately carbonate, reservoir sequence in the giant Marun oil field (Iran) using 1972 data records. The analysis identified that the multilayer extreme learning machine model hybridized with a particle swarm optimization (MELM–PSO) applied to seven input variables by feature selection provided the most accurate pore-pressure predictions for the full dataset (RMSE = 11.551 psi (1 psi = 6.8947590868 kPa) for well MN#281). The Savitzky–Golay (SG) filter was applied to pre-process the data, and the properties were filter-ranked using the wrapping method. The MELM–PSO model outperformed the pore-pressure prediction accuracy achieved by commonly used empirical formulas involving sonic or resistivity log data or calculated pore compressibility. To further verify and generalize the applicability of the MELM–PSO model, it was applied to two other Marun oil field wells (MN#297 and MN#378) achieving RMSE prediction accuracy of 10.031 psi and 10.150 psi, respectively. These results confirmed that the trained model can be reliably applied to multiple locations across the Marun oil field for predicting pore-pressure.

Sequential distribution of gas reservoirs in the Hangjinqi area, Ordos Basin, North China: Application of continuous and discontinuous hydrocarbon accumulation mode

The gas accumulation mode can be divided into two types based on the migration and accumulation characteristics: discontinuous accumulation into the reservoir rocks and continuous accumulation within or adjacent to the source rocks. Correspondingly, there are three different gas reservoirs including conventional, unconventional, and those in a transitional state. To demonstrate the differences in the formation mechanisms and distribution features of the two accumulation types, we have scrutinized the continuous accumulation and discontinuous accumulation in the Hangjinqi area of the Ordos Basin in North China. Continuous gas accumulation (basin-centered gas and water-soluble gas, as well as potential coalbed methane and shale gas) and discontinuous accumulation (various conventional gas traps) are, respectively, distributed in the southern and northern regions of the Hangjinqi area, which may change with the source-rock quality, migration force, reservoir capacity, and trapping condition. We identified that the essential factors influencing the formation and current distribution of gas reservoirs are the hydrocarbon generation ability, porosity, and cap rock-trap combinations in the study area. An ideal complete gas reservoir sequence develops coalbed methane, shale gas, basin central gas, water soluble gas, and conventional gas reservoirs from the center to the edge of the basin. Understanding the distribution characteristics of continuous accumulation and discontinuous accumulation allows better prediction of the potential gas reservoir types with the knowledge of discovered reservoirs. We recommend exploring anticline gas reservoirs in areas north of the Boerjianghaizi fault and basin-centered gas reservoirs in areas south of the Boerjianghaizi fault. We also suggest performing further research on shale source rocks because the maturity and the burial depth of the marine-continental organic-rich shale in the Shanxi-Taiyuan Formations are recognized to be favorable for shale gas generation and preservation.

Reservoir characterization, Facies distribution, and sequence stratigraphy of Mishrif Formation in a selected oilfield, South of Iraq

Mishrif Formation is considered the most important between the reservoirs formations in the south of Iraq because of its geographic extent. The facies were predicted in Ratawi oilfield from wireline logs that divided Mishrif Formation into two main reservoirs separated by a barrier member. So the formation is almost cupped with shale intervals in both contacts of Rumaila Formations in the bottom and Khasib Formations in the top. While the reservoir characteristics were calculated using the log set in terms of petrophysical properties. The reservoir characteristics destroy and decrease to the south of Ratawi area because of the abundance the facies of the deep marine environments. Furthermore, it was predicted that Mishrif Formation has good reservoir characteristics to the other directions, especially to the east, contrary to the previous expectations.

Development of a microfluidic collection system to measure electrolyte variations in sweat during exercise.

A wide variety of electrochemical sweat sensors are recently being developed for real-time monitoring of biomarkers. However, from a physiological perspective, little is known about how sweat biomarkers change over time. This paper presents a method to collect and analyze sweat to identify inter and intraindividual variations of electrolytes during exercise. A new microfluidic sweat collection system is developed which consists of a patch covering the collection surface and a sequence of reservoirs. Na+, Cl- and K+ are measured with ion chromatography afterwards. The measurements show that with the new collector, variations in these ion concentrations can be measured reliably over time.

Cretaceous petroleum system modeling of Kairouan Basin in eastern Tunisia

Upper Cretaceous deposits in central eastern Tunisia represent a potential proven source rocks from Cenomanian–Albian Fahdene and Turonian Bahloul Formations and reservoir rocks of Turonian Bireno, Douleb, and Campanian–Maastrichtian Abiod Formations. The latter form the main oil and gas field systems in onshore and offshore central eastern Tunisia. Seismic tectonics and seismic stratigraphy based on 2D seismic analyses calibrated to the petroleum well’s wireline logging led to the identification of source rock and reservoir sequence distribution between high platforms and subsiding basin areas. This structuring has been created by inherited deep-seated transtensive and transpressive flower faults (Kairouan-Sousse, Hdadja, El Jem, Mahdia, etc.) that are intruded by Triassic halokinetic evaporites. Geochemical analyses and modeling of the well and pseudo-well deposits using BasinMod 1D software from a plate river had permitted to differentiate kitchen areas, within the basin areas, that have high maturity level (late oil to gas generation phase) of Fahdene and Bahloul Cretaceous source rocks. The neighboring high flank structures might constitute good traps to accumulate expelled materials. The large-scale fault system and the dense fracture network related to the Kairouan Basin borders represent a preferential pathway for fluids to reach updip flank reservoir units. The geochemistry modeling was performed in order to characterize the maturity, generation, and expulsion timing of hydrocarbons. In addition, this study highlights the great gas shale potential steel remaining in the subsiding basin kitchens.

Effects of diagenesis on natural fractures in tight oil reservoirs: A case study of the Permian Lucaogou Formation in Jimusar Sag, Junggar Basin, NW China

Compared with conventional reservoirs, tight reservoirs experience more intense diagenesis; thus, their properties are extremely poor. Nevertheless, natural fractures with high‐strength can appear in these reservoirs and could play an essential role in the accumulation and production of tight oil. In this study, we focused on the effects of different diagenetic processes in the formation and transformation of natural fractures to determine the effects of natural fractures on tight reservoirs. Various observation techniques and analysis methods were applied (i.e., observations of cores, cast thin sections, scanning electron microscopy; field emission scanning electron microscopy; and X‐ray diffraction analysis). We clarified characteristics of the fractures and distribution patterns based on core descriptions and microscopic observations and explained the diagenetic stage and evolution sequence of reservoirs. Past studies regarding carbon and oxygen isotope analysis and basin simulation were considered. This study also reviewed the fracture formation time, source of fracture fillings, and oil charging time. We obtained insight into the coupling relationship of fracture states, diagenetic sequences, hydrocarbon charging, and, in particular, the controlling effect of diagenesis on natural fractures. The results revealed that formation, preservation, and destruction of natural fractures in tight reservoirs were closely related to diagenesis. Compaction and cementation in the reservoirs decreased the porosity and altered the petrophysical properties of the reservoir. They also provided favorable conditions for the development of tectonic fractures, while dissolution did not. The influences of dissolution and cementation on natural fractures depended on the duration for which these processes were active. Compaction and cementation formed related types of diagenetic fractures, while dissolution increased the effectiveness of natural fractures. The purpose of this study was to evaluate the influence of diagenesis on the formation, controlling effects, and effectiveness of natural fractures, as well as the effects of natural fractures on tight reservoirs through geological history. This study is expected to provide guidance for future exploration and development of tight oil and gas with similar geological origins.

Sedimentary and structural setting of the Aptian reservoir deposits in the Kasserine area, west-central Tunisia

The Aptian hydrocarbon-producing reservoirs, in the onshore Semmama and Douleb oil fields of west-central Tunisia are characterized by a heterogeneous flow with continuous decline. Petroleum exploration in this area requires detailed knowledge of the structural development of the basin and its relationship to the reservoir sequence and the source rock distribution. The structural configuration of west-central Tunisia is characterized by NE-SW, NW-SE and N-S deep-seated faults, which outline tectonic structures and it is influenced by Triassic salt intrusions. During the Aptian period, the basin was extensive and shallow at the center, though moderately deep to the North. The northeast-southwest dominated synsedimentary extensional tectonics induced high and subsiding zones and thus controlled sedimentary deposition. The Aptian reservoir is characterized by the lateral variation of sedimentary facies. The first zone, dominated by dolomitic lithofacies has been proven as a petroleum reservoir. The second zone corresponds to carbonate reef and para-reef facies. The third zone, trending north-south is characterized by shallow marine sedimentation, punctuated by episodes of detrital influx. The early Aptian is outlined by the emergence of Kairouan Island that took place in central Tunisia. This study facilitated mapping of the areas exhibiting hydrocarbon reservoir potential which resulted from the conjunction of extensional tectonics and salt ascension.

Digital Drill Core Models: Structure-from-Motion as a Tool for the Characterisation, Orientation, and Digital Archiving of Drill Core Samples

Structure-from-motion (SfM) photogrammetry enables the cost-effective digital characterisation of seismic- to sub-decimetre-scale geoscientific samples. The technique is commonly used for the characterisation of outcrops, fracture mapping, and increasingly so for the quantification of deformation during geotechnical stress tests. We here apply SfM photogrammetry using off-the-shelf components and software, to generate 25 digital drill core models of drill cores. The selected samples originate from the Longyearbyen CO2 Lab project’s borehole DH4, covering the lowermost cap rock and uppermost reservoir sequences proposed for CO2 sequestration onshore Svalbard. We have come up with a procedure that enables the determination of bulk volumes and densities with precisions and accuracies similar to those of such conventional methods as the immersion in fluid method. We use 3D printed replicas to qualitatively assure the volumes, and show that, with a mean deviation (based on eight samples) of 0.059% compared to proven geotechnical methods, the photogrammetric output is found to be equivalent. We furthermore splice together broken and fragmented core pieces to reconstruct larger core intervals. We unwrap these to generate and characterise 2D orthographic projections of the core edge using analytical workflows developed for the structure-sedimentological characterisation of virtual outcrop models. Drill core orthoprojections can be treated as directly correlatable to optical borehole-wall imagery data, enabling a direct and cost-effective elucidation of in situ drill core orientation and depth, as long as any form of borehole imagery is available. Digital drill core models are thus complementary to existing physical and photographic sample archives, and we foresee that the presented workflow can be adopted for the digitisation and digital storage of other types of geological samples, including degradable and dangerous ice and sediment cores and samples.

Origin of sulfate-rich fluids in the Early Triassic Montney Formation, Western Canadian Sedimentary Basin

Abstract This study investigates diagenetic and geochemical processes that control regional distribution and formation of sulfate minerals (i.e., anhydrite and barite) in the Early Triassic Montney Formation in the Western Canadian Sedimentary Basin. The generation of H2S in hydrocarbon reservoirs is often associated with the dissolution of sulfate minerals, as a major source of sulfate required for sulfate-reducing reactions. The formation of pervasive late diagenetic anhydrite and barite in the high H2S zone of the Montney Formation is therefore contrary to the normal paragenetic sequence of sour gas reservoirs. Petrographic observations revealed early and late anhydrite and barite cement. The early fine-crystalline anhydrite cement is dominant in northeastern British Columbia (low H2S zone), while the late-stage coarse-crystalline cement and fracture/vug-filling anhydrite are dominant in Alberta (high H2S zone). The bulk isotopic values (δ34S: +2.9 to +24.7‰ V-CDT, δ18O: −11.2 to +15.7‰ V-SMOW) suggest that sulfate-rich fluids originated mainly from modified Triassic connate water was the origin of early anhydrite. In contrast, the SIMS isotopic values of late anhydrite (δ34S: +18.5 to +37‰ V-CDT, δ18O: +12 to +22‰ V-SMOW) and barite cement (δ34S: +23.3 to +39‰ V-CDT, δ18O: +13.2 to +18.7‰ V-SMOW) as well as fracture/vug-filling anhydrite (δ34S: +23.5 to +24.7‰ V-CDT, δ18O: +13.3 to +14.7‰ V-SMOW) from Alberta represents a mixed isotopic signature of Triassic connate water and contribution of dissolved sulfate-rich fluids derived from dissolution of Devonian evaporites. The 87Sr/86Sr isotope ratios of the fracture/vug-filling anhydrite (0.7092–0.7102) are highly radiogenic suggesting extensive water/rock interactions between sulfate-rich fluids and siliciclastic and basement rocks. The similar isotopic composition of the late anhydrite/barite and fracture/vug-filling anhydrite in western Alberta with Devonian evaporites isotopic signature, and the highly radiogenic 87Sr/86Sr ratio further supports sulfate-bearing fluids were mainly originated from underlying Devonian evaporites and migrated upwards through deep-seated faults/fractures to the Montney Formation.

The Maria Field, Block 16/29a, UK North Sea

Abstract The Maria oilfield is located on a fault-bounded terrace in Block 16/29a of the UK sector of the North Sea, at the intersection of the South Viking Graben and the eastern Witch Ground Graben. The field was discovered in December 1993 by the 16/29a-11Y well and was confirmed by two further appraisal wells. The reservoir consists of shoreface sandstones of the Jurassic Fulmar Formation. The Jurassic sandstones, ranging from 100 to 180 ft in thickness, have variable reservoir properties, with porosities ranging from 10 to 18% and permeabilities from 1 to 300 mD. Hydrocarbons are trapped in a truncated rotated fault block, striking NW–SE. The reservoir sequence is sealed by Kimmeridge Clay Formation and Heather Formation claystones. Geochemical analysis suggests that Middle Jurassic Pentland Formation and Upper Jurassic Kimmeridge Clay Formation mudstones have been the source of the Maria hydrocarbons. Estimated recoverable reserves are 10.6 MMbbl and 67 bcf (21.8 MMboe). Two further production wells were drilled in 2018 to access unexploited areas.

Fault seal behaviour in Permian Rotliegend reservoir sequences: case studies from the Dutch Southern North Sea

Abstract Permian Rotliegend reservoir rocks are generally characterized by high net/gross (N/G) ratios, and faults in such sand-dominated lithologies are typically not considered likely to seal. Nevertheless, many examples of membrane sealing are present in Rotliegend gas fields in the Southern Permian Basin. This manuscript reviews examples of membrane sealing in the Dutch Rotliegend; it presents an extensive dataset of petrophysical properties of Rotliegend fault rocks and analyses two case studies using commonly used workflows. Fault (membrane) seal studies have been carried out on two Rotliegend fields to test the level of confidence and uncertainty of prediction of ‘across fault pressure differences’ (AFPD) based on existing SGR-based algorithms. From the field studies it is concluded that observable small AFPDs are present and that these are likely pre-production AFPDs due to exploration-time scale trapping and retention of hydrocarbons. Two shale gouge ratio (SGR)-based empirical algorithms have been used here to estimate AFPDs in lower N/G reservoir intervals with the aim of predicting membrane seal behaviour, and these results are compared to field data. It is concluded the selected SGR-based tools predict AFPD for Upper Rotliegend lower N/G reservoir rocks with reasonable results. Nonetheless, the core sample datasets show a much wider range of permeability and capillary entry pressure than predicted by the selected SGR transforms. This highlights the potential to modify existing workflows for application to faults in high N/G lithologies. Data sharing and collaboration between industry and academics is encouraged, so that in the long run workflows can be developed specifically for faults in high N/G lithologies.

The role of Late Cretaceous wrench tectonics in hydrocarbon endowment in El-Gindi Basin, northern Western Desert, Egypt

Abstract Detailed subsurface mapping and structural analysis of El-Gindi basin indicate the hydrocarbon potentiality of the Cretaceous reservoirs. El-Gindi basin is a Late Cretaceous-Eocene basin located at El-Fayium district, northeastern Western Desert of Egypt. The overwhelming impact of the Late Cretaceous wrench tectonics was evident during the inversion of the Jurassic-Early Cretaceous rift-related basins along the North Western Desert of Egypt and subsequent deposition of a thick succession of Eocene sediments (~6000 ft Apollonia Formation) within El-Gindi Basin. These tectonic events were developing the oil maturity and trapping through the Late Cretaceous reservoir sequences, Upper Bahariya Formation (Cenomanian) and the Abu Roash “G” Member (Turonian). The Gindi Fault, however, is a NW-trending basement feature breaching El-Gindi basin and bounding several deeper half grabens in the western half of El-Fayium district. It has been reactivated during the Cretaceous, Eocene and probably Oligocene-Early Miocene times, where extended northwestward to the Qarun Field at the footslopes of the Kattaniya inverted basin forming several oil traps along its strike. The Late Cretaceous dextral wrenching developed a regional system of ENE-oriented structural ridges such as Kattaniya and Silah (bounded El-Gindi basin to the north and south, respectively), associated with a series of NE-to ENE- oriented right-lateral strike-slip faults enclosing some structural closures in between. The development of such ridges causing regional subsidence and subsequent deposition of the Apollonia Formation creating several structural hydrocarbon traps. In addition, the structural closures formed between the ends of right-lateral strike-slip faults at Silah High became potential sites for hydrocarbon accumulation. The thermal maturity model of El-Gindi basin suggests a phase of hydrocarbon expulsion occurred during or immediately after deposition of the Apollonia Formation, where the Lower and Upper Cretaceous sediments passing the oil window. According to the analysis of well cores, E-logs and seismic data, shallow marine to deltaic environments have been assigned for the Cenomanian-Turonian reservoir sediments. Moreover, the deposition within channels, point-bars and estuarine environments for the hydrocarbon bearing sandstone reservoirs within El-Gindi Basin was identified.

Cluster Analysis of Petrophysical and Geological Parameters for Separating the Electrofacies of a Gas Carbonate Reservoir Sequence

Assessing reservoir properties and knowing the relationship between different reservoir parameters can significantly help to plan for production from a reservoir. In this study, which was carried out on the gas reservoir of the Triassic Dahram Group at the South Pars Gas Field, in southern Iran, petrophysical parameters such as porosity, shale volume, saturation of water and hydrocarbon, as well as amount of different minerals in the reservoir sequence, were first calculated using the probabilistic evaluation method. In the second step, for the separation of the sequential electrofacies, the multi-resolution chart-based clustering method was used resulting in recognition of five electrofacies with different reservoir geological properties. The results obtained from the first and second steps showed that the no. 5 electrofacies (EF-5), which has clean lime lithology and has the lowest water saturation, good porosity and high gas volume, was considered as the best reservoir facies in the studied sequence. Therefore, by separation of electrofacies, a suitable relationship can be found between different geological facies and petrophysical parameters of the reservoir.

Phylogenetic approach to recover integration dates of latent HIV sequences within-host

Given that HIV evolution and latent reservoir establishment occur continually within-host, and that latently infected cells can persist long-term, the HIV reservoir should comprise a genetically heterogeneous archive recapitulating within-host HIV evolution. However, this has yet to be conclusively demonstrated, in part due to the challenges of reconstructing within-host reservoir establishment dynamics over long timescales. We developed a phylogenetic framework to reconstruct the integration dates of individual latent HIV lineages. The framework first involves inference and rooting of a maximum-likelihood phylogeny relating plasma HIV RNA sequences serially sampled before the initiation of suppressive antiretroviral therapy, along with putative latent sequences sampled thereafter. A linear model relating root-to-tip distances of plasma HIV RNA sequences to their sampling dates is used to convert root-to-tip distances of putative latent lineages to their establishment (integration) dates. Reconstruction of the ages of putative latent sequences sampled from chronically HIV-infected individuals up to 10 y following initiation of suppressive therapy revealed a genetically heterogeneous reservoir that recapitulated HIV's within-host evolutionary history. Reservoir sequences were interspersed throughout multiple within-host lineages, with the oldest dating to >20 y before sampling; historic genetic bottleneck events were also recorded therein. Notably, plasma HIV RNA sequences isolated from a viremia blip in an individual receiving otherwise suppressive therapy were highly genetically diverse and spanned a 20-y age range, suggestive of spontaneous in vivo HIV reactivation from a large latently infected cell pool. Our framework for reservoir dating provides a potentially powerful addition to the HIV persistence research toolkit.

Quantifying aperture, spacing and fracture intensity in a carbonate reservoir analogue: Crato Formation, NE Brazil

Abstract The characterization of fracture networks in carbonate reservoirs represents a primary approach to understand the processes of fluid flow. The study of outcrop analogues has been used to enhance the understanding of the relative contribution of fracture networks to reservoir permeability. The outcrop data can overcome scale limitations and/or lack of consistency of subsurface datasets (e.g. seismic, well logs, and cores). This paper presents the fracture characterization of the Aptian-Albian lacustrine laminites of Crato Formation (Araripe Basin, NE Brazil), which have been investigated as an analogue to some of the observed carbonate facies present in the pre-salt reservoir sequence of the Brazilian marginal basins. In order to provide fracture attributes for Discrete Fracture Network (DFN) modelling we investigate spacing and aperture distribution, length and intensity of fractures based on the use of traditional scanline (macro and microscale) method. The main fractures identified in the Crato Formation are shear and extensional fractures and with stylolites also present. In this study, we focused on vertical veins, which strike in two principal directions, NNW-SSE (Set 1), NE-SW (Set 2), and are filled or partially filled by calcite or gypsum. The relationship between length and aperture of vertical veins is linear. Apertures and spacings of fractures in both sets 1 and 2 follow power law and lognormal cumulative frequency distribution functions, respectively. Fractures of Set 2 are more likely to be clustered than are fractures of Set 1, which have a wider kinematic aperture. This structural database can be used to populate computational models that consider the widespread fracture system in the fluid flow simulation of carbonate reservoirs.

Correction to: Building 3D Lithofacies and Depositional Models Using Sequential Indicator Simulation (SISIM) Method: A Case History in Western Niger Delta

Sequential indicator simulation algorithm is one of the popular stochastic simulation algorithms for reservoir geomodelling. It has been used to model delineated lithofacies and depofacies units within the OPO field, western Niger Delta. This simulation algorithm was chosen because of its ability to honour the well logs as local conditioning data using the global histogram, areal and vertical geological trends of the data, as well as the patterns of correlation. Three lithofacies were identified and modelled, namely sand, shaly sand and shale units. Vertical succession of the depositional facies within the field reveals five major facies which are basal shelf shale facies, heterolithic (sand–shale) facies, lower shoreface sand facies, upper shoreface sand facies and shoreface channel systems. The general environment of deposition is interpreted to be shoreline–shelf systems where the shoreface channel units, upper shoreface sand, lower shaly sand and heterolithic units constitute the parallic reservoir sequences, while the shale units within the shoreface and coastal environments act as potential source rocks and caprocks for hydrocarbon accumulation.