Sequence Reservoir Research Articles

Geophysical data processing, rock property inversion, and geomechanical model building in a Midland Basin development project, Midland/Ector counties, Texas

The current state of the art for development of unconventional projects integrates geology, geophysics, and engineering into a comprehensive reservoir description. To that end, we have designed a comprehensive geophysical workflow to define the structure, stratigraphy, and rock mechanics of a stacked reservoir sequence in the west-central Midland Basin. The purpose of this paper is to describe the workflow. Portions of three seismic data sets were merged and processed anisotropically, preserving the full range of azimuths. Well control consisted of 35 compressional sonic logs, eight shear sonic logs, three sonic scanners, two lateral formation microimaging tools, and three cores. Nine newly drilled laterals are on production along with a large number of vertical legacy wells. Prestack inversion produced acoustic impedance, shear impedance, and density with good accuracy, although the compressional-to-shear-velocity ratio (VP/VS) was not stable. This volume was successfully recreated via neural net, which was also used to calculate total porosity and total water saturation volumes. Poisson's ratio, Young's modulus, and brittleness were created using standard equations and the neural net VP/VS volume. Structural attributes consisted of ant track, coherence, semblance, fault probability, and Kmin and Kmax curvature. The final step in this portion of the workflow was to create a high-resolution depth conversion velocity volume. A geocellular grid was built and populated with petrophysical volumes, lithology facies, and structural attributes. Principal stresses were incorporated by first establishing 1D mechanical earth models (MEMs) where appropriate log suites were available. These 1D MEMs were extended to a 3D MEM, although confidence in this volume is not high due to known pore pressure and closure stress reductions as a result of legacy vertical well production. Calibration incorporating new data as it becomes available is an ongoing task. An informative simulation using the MEM is frac models, which define the most optimal landing points for laterals. This MEM and the simulations it can perform have easily demonstrated the value of this integrated workflow.

Controls on the distribution of volcanism and intra-basaltic sediments in the Cambo–Rosebank region, West of Shetland

The NE Atlantic margin is one of the last frontier areas of hydrocarbon exploration within the UK Continental Shelf. In 2004, a major oil and gas discovery (Rosebank) was made within Paleocene–Eocene-age lavas in the Faroe–Shetland Basin. The Rosebank Field consists of intra-basaltic terrestrial to marginal-marine reservoir sequences, separated by basaltic lava flows and volcaniclastics. Despite the identification of a major intra-lava-incised drainage system running parallel to the SW–NE-trending Rosebank Field, the controls on the distribution of both the volcanics and the intra-basaltic sediments were previously unclear, in part due to the difficulties that volcanic sequences pose to seismic acquisition, processing and interpretation. This has led to uncertainty in defining the wider intra-basaltic play. However, the examination of the recently acquired FSB 2011–12 MultiClient GeoStreamer® Survey has facilitated an increased definition of the geological units within and below the volcanic succession, and a reinterpretation of the Late Paleocene–Early Eocene stratigraphy. Through integration of 3D seismic data and well analysis, we present a regional overview of the volcanics and intra-basaltic sediments in the Rosebank region of the Faroe–Shetland Basin. We find that the structural setting of the Rosebank Field, in addition to lava-flow morphology, strongly influences the distribution of the intra-basaltic play fairway within the Paleocene–Eocene-aged Flett Formation. Restriction of fluvial siliciclastic sediments adjacent to the Corona Ridge extends the theorized Rosebank play fairway to the area SW of the Rosebank Field. Our analysis indicates that understanding the underlying basin structure is integral to the success of intra-basaltic plays.

Pluto 4D—Australia's first 4D over a gas field is an outstanding success

The Pluto 4D seismic survey is Australia’s first 4D survey acquired over a gas field and has been an outstanding success despite the prior high technical risk of not being able to detect 4D differences above the background noise. At the time of the Pluto 4D monitor survey, the Pluto field had been on production for three years and nine months and produced approximately 1 Tcf of gas. The first monitor survey was acquired by PGS between November 2015 and February 2016 using dual sources and 12 streamers of 7050 m (geostreamer configuration). Also of note was the use of steerable sources to assist with repeatability, and towing the streamers at 20 m to minimise noise. Data was processed by CGG to pre-stack depth migration (PreSDM), took 12 months to deliver and required significant interaction between Woodside geoscientists and CGG to ensure an excellent 4D product. 4D feasibility studies carried out before acquisition showed that saturation changes (related to water ingress) were expected to show strong 4D responses near the gas water contact (GWC) and would be interpretable if the monitor survey was run after approximately three to four years of production. If the monitor survey was delayed, it showed that the pressure response became too large, swamped the 4D differences and made interpretation difficult or impossible. Strong ‘hardening’ responses on the 4D difference volumes are interpreted as water ingress into the field. Hardening responses are seen in all reservoir sequences in the Triassic from the TR27 to the TR32 units and range from strong (obvious) to weak (possible). Several examples are shown – the strongest response is seen in the large Triassic (TR27.3) valley within an essentially shale prone unit, which shows water ingress into the valley and moving upwards from the GWC towards the producing well. The results/insights from the 4D data have provided excellent control points for the history matching of the Pluto Field.

Особенности формирования и расчета обратных течений в Воткинском водохранилище (1d-постановка)

Issues of the contraflows formation in the Votkinsk Reservoir (the middle one in the sequence of the Kama reservoirs) have been studied. The water discharge regime through the Kama Hydro Power Plant determines the contraflow occurrence. The importance of the contraflow issues is caused by the risk of contaminated waters input to water intakes located upstream in respect of the waste water outlets. One of the major industrial agglomeration, namely the Perm-Krasnokamsk cluster with numerous water intakes and waste water discharge points, is located in the upstream part of the Votkinsk Reservoir with is the downstream reach of the Kama Reservoir. On the basis of assessment of the contraflows scale and the consequences for water users the water/economic and environmental limitations are set for the power plant operation regime including sanitary discharge volumes. The contraflows have been simulated as a result of digital solution of the Saint-Venant equation in 1D-definintion with input of the first type boundary conditions directly in the vicinity of the Votkinsk Power Station dam. We have assessed the reservoir morphometry role in the contraflows formation. Outputs of the comparative experiments performed at different schematic models of the Votkinsk Reservoir have shown that reflection of the level lowering straight wave from the Votkinsk Power Station dam is the determining factor of the contraflows formation rather than peculiarities of the morphometry. When decreasing the period of water discharge to the downstream reach the zone of contraflows formation is displacing towards the Votkins Power Plant dam.

Petroleum systems in Southeast Asian Tertiary basins

Productive Tertiary basins in Southeast Asia have essentially similar geodynamic developments, and share many hydrocarbon habitats and active petroleum systems. In order to facilitate understanding of the essential elements that contribute to the success of petroleum systems I have classified them into a number of groups or ‘associations’ according to their sedimentary facies. This facilitates use of them as valuable analogues. Five such facies associations, containing characteristic and distinct petroleum parameters have been recognised: (i) lacustrine (ii) paralic (iii) open marine shelf (iv) deeper marine and (v) pre-Tertiary. They belong to particular cycles or stages in basin development that provide the context within which the depositional environments and palaeogeography evolve. Lacustrine facies typify the early stages of synrift development in basins closer or more proximal to the Sundaland province in northern and western SE Asia. Open marine facies, on the other hand, typify the early postrift period and basins in palaeogeographically more distal areas, such as eastern Indonesia and The Philippines. Paralic and bathyal facies characterise the later stages of the synrift and postrift cycles and are widespread throughout the proximal and intermediate parts of the area. Pre-Tertiary source facies, which provide charge in parts of eastern Indonesia and Thailand, are mainly terrestrial in nature. These differences have important implications for petroleum occurrence, which can be summarised accordingly: • More proximal basins are dominated by lacustrine to paralic facies in the synrift cycle and have a mainly non-marine sedimentary fill. Petroleum systems with oil charge are dominant. • More distal basins are dominated by rapid postrift subsidence. In the open marine facies carbonate reservoirs are well-developed, while petroleum systems are mainly gas-prone. • Around Borneo thick late postrift passive margin delta sequences with oil- and gas-prone coaly source rocks and clastic reservoirs are developed in delta-top environments. Transported terrigenous organic material is commonly found in related deep marine environments and contributes to a marine source facies. Both give rise to prolific petroleum systems. • Many basins in the Sunda Shelf area lie in an intermediate situation, where a non-marine synrift is followed by a marine postrift cycle. Such basins benefit from lacustrine and paralic source rock and reservoir sequences in both the syn- and the postrift, and are often characterised by multiple petroleum systems. Evaluation of petroleum potential in Southeast Asian Tertiary basins requires a special approach: in most parts of the World, such as the Middle East and Northwest Europe, source rocks are of marine origin, are relatively consistent in type and quality and are located in well-defined formations of regional extent. In SE Asia the terrestrial and lacustrine source rocks are more difficult to locate, are variable in quality and are often distributed in thin beds throughout thick sequences. These differences mean that predictive extrapolations of charge quality and maturity, and therefore of basin prospectivity, are much more difficult in Southeast Asia: This probably explains why discoveries continue to be made after almost 130 years of exploration!

Diagenetic sequence and genetic mechanism of Silurian tight sandstone reservoirs in the eastern Tarim Basin, Northwest China

The Silurian stratigraphic sequence has recently become one of the most important exploration targets in the Tarim Basin, with a considerable amount of profitable hydrocarbon pools discovered in the central Tarim Basin. Previous exploration activities indicate that the Silurian stratigraphic sequence in the eastern Tarim Basin has great hydrocarbon exploration potential. The Silurian reservoirs comprise a set of tight marine sandstones, whose diagenetic sequence and genetic mechanism are still poorly understood. The complex relationship of hydrocarbon generation, the timing of the peak expulsion of the source rocks and the evolution of the reservoirs remains unclear. An integrated description and analysis have been carried out on core samples from eleven wells selected from the eastern Tarim Basin. A range of petrographic and geochemical analyses were conducted. By using an integrated approach with thin-section petrography, scanning electron microscopy (SEM), cathodoluminescence (CL), carbon and oxygen isotope geochemistry, formation water analysis, X-ray diffractometry (XRD), electron probe microanalysis and fluid inclusion microthermometry, the genesis and occurrence of individual diagenetic events were documented to reconstruct the diagenetic sequence and diagenetic model for the Silurian sandstone. Additionally, the tight nature of the Silurian reservoirs can mainly be attributed to the compaction processes and cementation. In particular, the destructiveness of the compactional processes to the original porosity is far greater than that from the cementation. Furthermore, fluid inclusion analyses also indicate that the Silurian sandstone has experienced three phases of hydrocarbon charge. The first two phases occurred during the eodiagenesis stage (from the Late Silurian to the Early Devonian and from the Late Carboniferous to the end of the Late Permian), when the Silurian sandstone was not tight and had a porosity of greater than 20%. The third phase occurred during the stage B of mesodiagenesis (since the Late Cretaceous), when the Silurian sandstone was fully tight.

Formation evaluation using conventional and special core analyses: Belayim Formation as a case study, Gulf of Suez, Egypt

The present study aims to throw the light on the importance of the conventional and special core analyses in the integration with the petrographical studies for the formation evaluation of the reservoir rocks. The petrographical studies include the microfacies analysis and studying the diagenetic factors that predominated during the diagenetic history of the Belayim rock sequence in the study area. Two zones of Belayim Formation in the onshore Belayim oil field (the upper level (zone IIA) represents Hammam Faraun member and the lower one (zone IV) represents Sidri member) were studied. The measured routine core analyses data includes porosity (helium and summation fluids), density (grain and bulk), permeability (horizontal and vertical) and fluid saturations (oil and water). In addition, the formation resistivity factor, irreducible water saturation, Archie’s parameters (a, m and n), liquid permeability, relative permeability, wettability, the pore throat distribution, as well as the porosity and permeability measured under high pressure were measured as a special core analyses procedure. From the integration of the aforementioned petrographical and petrophysical studies, the Belayim Formation can be discriminated into three petrophysical facies (Facies-1, Facies-2 and Facies-3) described petrographically as (1) Facies-1 (argillaceous subfeldspathic arenite microfacies), (2) Facies-2 (siliceous quartz arenite microfacies) and (3) Facies-3 (dolomitic sublithic arenite microfacies). The petrophysical Facies-2 (siliceous microfacies) is characterized by the best reservoir properties (rank III, very good average porosity, very good permeability, fair to very good reservoir quality index (RQI) and relatively poor to good flow zone indicator (FZI), neutral to moderately oil wet and more than 75% macropores and mesopores). On the other side, samples of the petrophysical Facies-1 (argillaceous microfacies) have the lowest reservoir potential (rank VI, poor average porosity, poor to fair permeability, poor to impervious RQI and relatively poor to fair FZI and more than 50% micropores and nanopores). Therefore, it is recommended to use the conventional and special core analyses data in the integration with the petrographical studies as a good procedure for the formation evaluation and discrimination of the reservoir sequence into different flow units.

Integrating comprehensive two-dimensional gas chromatography and downhole fluid analysis to validate a spill-fill sequence of reservoirs with variations of biodegradation, water washing and thermal maturity

Optimization of production depends heavily on crude oil composition and its variation within and across multiple reservoirs. In particular, asphaltene content has enormous impact on crude oil viscosity and the economic value of reservoir fluids. Thus, it is important to understand the primary controls on crude oil composition and asphaltene distributions in reservoirs. This paper examines a complex oilfield in the North Sea that contains seven separate reservoirs. The crude oil is believed to have spilled from deeper into shallower reservoirs during reservoir charging. In-situ asphaltene content is measured by downhole fluid analysis (DFA) and is generally consistent with a spill-fill sequence in reservoir charging. Detailed compositional analysis of crude oil samples by comprehensive two-dimensional gas chromatography (GC×GC) was used to determine the extent of water washing, biodegradation and thermal maturity among the reservoirs. Increased biodegradation and water washing in the shallower reservoirs is consistent with a spill-fill sequence. Aromatic and alkylated aromatic compounds decrease according to a combination of water solubility and susceptibility to biodegradation in the shallower reservoirs. Four thermal maturity biomarker ratios show that the shallower reservoirs contain less mature oil, consistent with a spill-fill sequence. The combination of DFA for bulk compositional analysis and GC×GC for detailed compositional analysis combined with geochemical interpretation is an effective tool to unravel complex oilfield scenarios.

Seismic tectono-stratigraphy of fluvio-deltaic to deep marine Miocene silicoclastic hydrocarbon reservoir systems in the Gulf of Hammamet, northeastern Tunisia

Most of hydrocarbon accumulations within the Gulf of Hammamet foreland basins in eastern Tunisia are reservoired within the Upper Miocene Birsa and Saouaf sandstones. It is the case of Birsa, Tazarka, Oudna, Baraka, Maamoura, Cosmos and Yasmine fields. These sandstones constitute oil and gas fields located on folded and faulted horst anticline highs and described as varying from shoreface to shallow marine and typically exhibit excellent reservoir quality of 30 to 35% porosity and good permeability from 500 to 1100 md. In addition, the fracturing of faults enhanced their reservoir quality potential. However, due to the lack of seismic stratigraphic studies to highlight depositional environment reservoir characterization and distribution, petroleum exploration faces structural and stratigraphic trap types and remains on targeting only high fold closures with limited reserve volumes of hydrocarbons. As an example of the Birsa concession case, syn-sedimentary tectonic structuring and geodynamic evolution during Middle to Upper Miocene Birsa reservoir sequences have guided the distribution of depositional environment of sandstone channel systems around horst and grabens by E-W, NE-SW and N-S strike slip flower faults controlling the subsidence distribution combined with the eustatic sea level variations. Seismic sequence stratigraphy study of Miocene Birsa reservoir horizons, based on the analysis and interpretations of E-W and N-S 3D selected regional lines that were compared and correlated to outcrops and calibrated by well data, permitted to highlight the basin configuration and sequence deposit nature and distribution. Sedimentary infilling of the basin from Langhian Ain Ghrab carbonate to Serravallian Tortonian Birsa and Saouaf sandstone and shale formations is organized in four third-order seismic sequences, limited by regional erosional toplap, onlap and downlap unconformity surfaces and by remarkable chronostratigraphic horizons of forced and normal erosive lowstand and highstand system tracts separated by transgressive and maximum flooding surfaces. Reconstructed sedimentary paleo-environment distribution vary from deltaic fluvial proximal deposits in the northern part of the high central Birsa horst to a delta front and prodelta coastal and shelf shore face and shore line channelized deposits in the surrounding borders of grabens. Distal deposits seem to be distributed from upper to lower slope fans and probably to the basin floor on the flanks of the subsiding grabens. Synthetic predictive paleogeographic depositional reservoir fairway map distribution of Lower, Middle and Upper Birsa sandstone reservoirs highlights four main domains of channelized superposed and shifted reservoirs to explore.

Quantifying remaining oil saturation using time-lapse seismic amplitude changes at fluid contacts

Our study shows that time-lapse changes in the amplitude of the seismic reflection at an oil–water contact (OWC) and/or produced OWC can be used to estimate directly the displacement efficiency of water displacing oil, E D , without the need of a rock and fluid physics model. From this value, it is possible to determine the remaining oil saturation if required. A preliminary application is performed using several published literature examples, which are reinterpreted to assess the average E D and ensure that the theory is consistent with expectations. Next, a North Sea field model with a known E D is used to create fluid-flow predictions and the corresponding synthetic time-lapse seismic data. Application to these data again confirms the basic principles of the method and defines the accuracy when applied to 4D seismic data. Finally, an observed 4D seismic dataset from a producing field in the North Sea is analysed. The results suggest a displacement efficiency of between 21 and 65% with an accuracy of 3% due to data non-repeatability (with a NRMS of between 11 and 13%). Given an average irreducible water saturation of 0.32, this calculates the remaining oil saturations at between 24 and 53% for this field. A prerequisite for use of the proposed OWC approach is that a discrete contact be interpreted on either the 3D or 4D seismic datasets. Therefore, successful application of this technique requires moderate- to high-quality seismic data and a fairly thick reservoir sequence without significant structural complexity.

Isotopic analysis of sulfur cycling and gypsum vein formation in a natural CO2 reservoir

In order to assess the long-term security of geologic carbon storage, it is crucial to study the geochemical behavior of sulfur in reservoirs that store CO2. Fossil fuel combustion may produce mixtures of carbon dioxide and sulfur gases, and the geochemical effects of sulfur–CO2 cosequestration are poorly understood. This study examines sulfur mineralization from a core drilled in a stacked sequence of natural CO2 reservoirs near the town of Green River, Utah. These reservoirs include the Entrada and Navajo Sandstone, which are separated by the Carmel Formation caprock and transected by a system of CO2-degassing normal faults, through which saline CO2-charged brines discharge. Our objective in this study is to evaluate the mechanisms and timing of secondary mineral formation, particularly gypsum formation, in the CO2 reservoirs and intervening caprock. The Carmel Formation contains beds of gypsum within a fault zone. Secondary veins of gypsum exist throughout the Entrada Sandstone and Carmel Formation. We report sulfur and oxygen isotope data (δ34SSO4 and δ18OSO4, respectively) measured in gypsum and δ34S measured in pyrite, and the oxygen and hydrogen isotope composition (δ18O and δD, respectively) of gypsum hydration water. The multiple isotope approach allows us to trace the sources of sulfur in the reservoirs and, when combined with structural and petrological evidence, the progress of fluid-rock reactions and relative timing of vein mineralization.The secondary gypsum veins in the Carmel Formation derive from mixing of fluids with two isotopically distinct sulfate sources: sulfate from the gypsum beds within the Carmel Formation and sulfate-rich brines that originate from evaporites in the underlying Carboniferous Paradox Formation. The gypsum veins in the Entrada Sandstone have a relatively wide range of δ18OSO4, both isotopically more enriched in 18O and more depleted in 18O than the primary gypsum sources. We suggest that some aqueous sulfate in the Entrada Sandstone may cycle through multiple valence states as it undergoes reduction and reoxidation, resulting in the replacement of its oxygen atoms and allowing the occasional formation of gypsum with anomalous low δ18OSO4. Our data from gypsum hydration water indicates that groups of gypsum veins formed at two different times. Gypsum veins in the Entrada Sandstone and some veins in the Carmel Formation likely formed during Quaternary CO2-charged brine discharge events, while other veins located close to the gypsum beds in the Carmel Formation formed earlier, likely during cycles of dehydration and rehydration associated with the Laramide-age (40Mya) faulting. We conclude that calcium-sulfate mineral formation in brine-filled fractures may play an important role in inhibiting fluid migration in geologic reservoirs that contain CO2.

An Integrated Work Flow for a Comprehensive Evaluation of Thin, Silty Hydrocarbon-Reservoir Sequences

Summary A robust work flow is established to identify low-resistivity pay (LRP) in thinly laminated sands with silty and/or shaly layers. The work flow integrates data from gas-while-drilling, conventional logging, and nuclear-magnetic-resonance (NMR) logging for picking intervals for further examination with a wireline formation tester (WFT). A mini-drill-stem test (DST) is performed by means of a WFT equipped with either a single probe (SP) or a dual packer (DP) to determine the fluid type and productivity of each individual level. Two field examples are presented to compare well performance predicted by the microscale mini-DSTs with macroscale production tests. In both cases, the traditional DST is eliminated from the drilling/completion program. The final verification consists of comparing contributions of individual levels derived from the mini-DSTs with production logs. In the first case, mini-DSTs are able to provide the fluid type and individual-level transmissibility (kh/μ) for eight out of 13 distinct levels. A cost-effective approach of running mini-DSTs by means of a WFT equipped with a single probe is demonstrated to investigate multiple levels in the thin-hydrocarbon reservoir sequence. Guidelines are provided as to when a WFT with a DP is to be deployed to perform a mini-DST in a laminated formation. In the second case, the same work flow was applied to derive the fluid type and transmissibility for two wells consisting of more than 30 distinct levels in the same field. After integrating mini-DST results from the two wells 750 m apart, a framework is constructed to establish both vertical and lateral heterogeneities of thinly laminated reservoirs. The integration helps visualize the multiple-layer reservoir. Our examples confirm that mini-DSTs effectively define individual-layer producibilities in multiple-layered reservoirs. The benefits are illustrated through case histories that demonstrate our ability to manage expectations of well performance in thin hydrocarbon-reservoir sequences.

Hydrocarbon potential, structural setting and depositional environments of Hammam Faraun Member of the Belayim Formation, Southern Gulf of Suez, Egypt

The Middle Miocene Belayim Formation is one of the most prolific formations in the Southern Gulf of Suez. It consists of four members; two members are evaporitic (Baba and Feiran) and the other two members are prospective, mostly clastics (Hammam Faraun and Sidri). The hydrocarbon potential and depositional environment of Hammam Faraun Member, the target of the present study, have been studied in 11 wells distributed in the southern province of the Gulf of Suez. The traditional well log data, as well as the Spectral Gamma-Ray logs ‘SGR’ and dipmeter data were used to evaluate the petrophysical properties and distribution of the Hammam Faraun Member in the Southern Gulf of Suez. It varies greatly in thickness with the greatest thicknesses in GS 365 (372 ft) and GS 373 (430 ft) fields in the central parts and the thinnest at the basin margins of the studied area at GH376 (65 ft) and Ras El Bahar (67.5 ft) fields. It is composed of clastic rocks, mainly shales and sometimes reef carbonates. The very good petrophysical properties of the studied sequence indicate a good reservoir in some fields with good to very good porosity (13.5 ≤ ∅ ≤ 25.0%). The shale volume of this reservoir sequence is less than 33% and the water saturation is less than 42.3%, while the net-pay thickness is up to 58 ft.The SGR and Pe logs indicate that, the studied rocks were deposited mostly in lagoonal to shallow marine environments, with illite and montmorillonite as dominant clay minerals.The dipmeter data obtained in some wells indicate slightly tilted beds, mostly less than 20° with an overall dip direction towards the SW, which represents the regional dip in the Southern Gulf of Suez. Based on dipmeter data, two major angular unconformities can be detected; one at the top of the sequence, separating it from the overlying South Gharib evaporates, and another one at the base of the sequence, separating it from the underlying Feiran Member.

Oligo-Miocene reservoir sequence characterization and structuring in the Sisseb El Alem–Kalaa Kebira regions (Northeastern Tunisia)

The Sisseb El Alem-Enfidha basin is located in the northeastern Tunisia, It is borded by Nadhour – Saouaf syncline to the north, Kairouan plain to the south, the Mediterranean Sea to the east and Tunisian Atlassic “dorsale” to the west. Oligocene and Miocene deltaic deposits present the main potential deep aquifers in this basin with high porosity (25%–30%).The interpretation of twenty seismic reflection profiles, calibrated by wire line logging data of twelve oil wells, hydraulic wells and geologic field sections highlighted the impact of tectonics on the structuring geometry of Oligo-Miocene sandstones reservoirs and their distribution in raised structures and subsurface depressions. Miocene seismostratigraphy analysis from Ain Ghrab Formation (Langhian) to the Segui Formation (Quaternary) showed five third-order seismic sequence deposits and nine extended lenticular sandy bodies reservoirs limited by toplap and downlap surfaces unconformities, Oligocene deposits presented also five third- order seismic sequences with five extended lenticular sandy bodies reservoirs. The Depth and the thickness maps of these sequence reservoir packages exhibited the structuring of this basin in sub-basins characterized by important lateral and vertical geometric and thichness variations. Petroleum wells wire line logging correlation with clay volume calculation showed an heterogeneous multilayer reservoirs of Oligocene and Miocene formed by the arrangement of fourteen sandstone bodies being able to be good reservoirs, separated by impermeable clay packages and affected by faults. Reservoirs levels correspond mainly to the lower system tract (LST) of sequences. Intensive fracturing by deep seated faults bounding the different sub-basins play a great role for water surface recharge and inter-layer circulations between affected reservoirs. The total pore volume of the Oligo-Miocene reservoir sandy bodies in the study area, is estimated to about 4 × 1012 m3 and equivalent to 4 × 109 m3 of deep water reserves.

The Method of Establishing Analogy Reservoir for Low Permeability Sandstone Reservoir

Analogy reservoir is accurate or not, related to the reliability of the SEC reserves evaluation. According to the characteristics of Jilin Oilfield low permeability sandstone reservoir, in accordance with SEC new rules and the principle of analogy reservoir establishment, we establish analogy reservoir of low permeability sandstone reservoir by taking the steps of selecting analogy reservoir, calculating geological reserves, evaluating recoverable reserves, and defining analogy recovery. With this method, we set up analogy reservoir sequence of low permeability sandstone reservoir and the sequence provides a reliable basis for SEC reserves evaluation. Key words: SEC rules; Geological reserves; Recoverable reserves; Analogy reservoir; Recovery efficiency

Vertical anomaly clusters: Evidence for vertical gas migration across multilayered sealing sequences

We present the results of a seismic interpretational study of amplitude anomalies in the East Falkland basin using an extensive grid of approximately 8000 line kilometers (4971 line miles) of high-resolution two-dimensional seismic reflection data. We mapped 474 discrete amplitude anomalies developed within a dominantly hemipelagic and highly reflective megasequence of the Cretaceous to early Cenozoic that is distributed in a northeast–southwest swath across the basin. The amplitude anomalies range from a kilometer to over 25 km (15.5 mi) in lateral extent, have sharp lateral amplitude cutoffs, sometimes at faulted margins, and are invariably associated with reflections with negative acoustic impedance contrasts. They exhibit class III amplitude versus offset (AVO) responses, frequency shadows, and push-down effects, from which the amplitude anomalies are interpreted as related to free gas. All the amplitude anomalies are characterized by vertical clustering, and based on this strong spatial association we refer to these mappable groups of amplitude anomalies as vertical anomaly clusters (VACs). We suggest that VACs form by strongly focused vertical hydrocarbon migration in a heterogeneous stacked sequence of poor-quality reservoirs interbedded with layers with lower permeability, and where the necessary bottom-to-top cross-stratal flow exploits a well-developed fault and fracture network. Similar vertical associations of gas-related amplitude anomalies could be expected in many other basins, so VACs may be a useful direct hydrocarbon indicator with specific genetic significance for hydrocarbon migration mechanisms.

Hydrocarbon migration and accumulation in the Upper Cretaceous Qingshankou Formation, Changling Sag, southern Songliao Basin: Insights from integrated analyses of fluid inclusion, oil source correlation and basin modelling

The Upper Cretaceous Qingshankou Formation acts as both the source and reservoir sequence in the Changling Sag, situated in the southern end of the Songliao Basin, northeast China. An integrated approach involving determination of hydrocarbon charging history, oil source correlation and hydrocarbon generation dynamic modeling was used to investigate hydrocarbon migration processes and further predict the favorable targets of hydrocarbon accumulations in the Qingshankou Formation. The hydrocarbon generation and charge history was investigated using fluid inclusion analysis, in combination with stratigraphic burial and thermal modeling. The source rocks began to generate hydrocarbons at around 82Ma and the hydrocarbon charge event occurred from approximately 78Ma to the end of Cretaceous (65.5Ma) when a large tectonic uplift took place. Correlation of stable carbon isotopes of oils and extracts of source rocks indicates that oil was generated mainly from the first member of Qingshankou Formation (K2qn1), suggesting that hydrocarbon may have migrated vertically. Three dimensional (3D) petroleum system modeling was used to evaluate the processes of secondary hydrocarbon migration in the Qingshankou Formation since the latest Cretaceous. During the Late Cretaceous, hydrocarbon, mainly originated from the Qianan depression, migrated laterally to adjacent structural highs. Subsequent tectonic inversion, defined as the late Yanshan Orogeny, significantly changed hydrocarbon migration patterns, probably causing redistribution of primary hydrocarbon reservoirs. In the Tertiary, the Heidimiao depression was buried much deeper than the Qianan depression and became the main source kitchen. Hydrocarbon migration was primarily controlled by fluid potential and generally migrated from relatively high potential areas to low potential areas. Structural highs and lithologic transitions are potential traps for current oil and gas exploration. Finally, several preferred hydrocarbon accumulation sites have been identified by this work, like Western Slope, Southern uplift, and Eastern Slope, helping reduce the risk on targeting hydrocarbon potential reservoirs in Changling Sag.

Drilling and sampling a natural CO2 reservoir: Implications for fluid flow and CO2-fluid–rock reactions during CO2 migration through the overburden

This paper presents the initial results of a scientific drilling project to recover core and pressurized fluid samples from a natural CO2 reservoir, near the town of Green River, Utah. The drilling targeted a stacked sequence of CO2-charged Jurassic sandstone reservoirs and caprocks, situated adjacent to a CO2-degassing normal fault. This site has actively leaked CO2 from deep supercritical CO2 reservoirs at depth >2km within the basin for over 400,000years. The project objectives were to gather samples to examine reactive fluid flow in the reservoirs, caprocks and faults, during migration of CO2 through the geological overburden from the deep supercritical CO2 reservoirs. Downhole fluid sampling and fluid element and isotope geochemistry show that the shallow reservoirs are being actively fed by inflow of CO2-saturated brines through the faults. Comparisons of shallow and deep fluid geochemistry suggest that: (i) CO2 and CO2-charged brines co-migrated from the deep reservoirs, (ii) the CO2-saturated brines migrating from depth interact with significant volumes of meteoric groundwater in aquifers in the shallower Permian and Jurassic sandstones, diluting the brine composition, and (iii) that a significant fraction of the CO2 migrating from depth is dissolved in these brine–meteoric water mixtures, with >99% of the CO2 in fluids sampled from the shallow reservoirs being derived during fluid migration, after the fluids left their source reservoir. The 87Sr/86Sr ratio of the brine flowing through the faults is significantly elevated due to the addition of Sr from silicate mineral dissolution during fluid migration.The association of bleached sandstones in the core with CO2-rich fluids supports interpretations from elsewhere that CO2-charged brines with CH4 or H2S reductants can dissolve hematite present within the sediment. Analysis of fluid geochemistry and sandstone petrology suggests that the CO2-rich fluids dissolve carbonate, hematite and gypsum in the reservoirs, as they flow away from the faults.Element and isotope geochemistry of fluid samples from the drillhole and Crystal Geyser constrain mixing models which show that, within the Navajo Sandstone, the reservoir fluids are undergoing complex mixing of: (i) CO2-saturated brine inflowing from the fault, (ii) CO2-undersaturated meteoric groundwater flowing through the reservoir and (iii) reacted CO2-charged brines flow through fracture zones in the overlying Carmel Formation caprock, into the formations above. Such multi-scale mixing processes may significantly improve the efficiency with which groundwaters dissolve the migrating CO2.

Reservoir sequences of the Anabar-Khatanga saddle: Formation conditions and reservoir properties

The reservoir properties of prospective petroleum complexes of the Anabar-Khatanga saddle are characterized on the basis of summarized published data and laboratory studies of drill cores carried out by the authors. The reservoir properties, lithological composition, and textural-structural features are described for every prospective reservoir interval and the formation conditions of sedimentation are characterized. Conclusions are drawn about factors that control the changes of reservoir properties.

Definitive Petrophysical Evaluation of Thin Hydrocarbon Reservoir Sequences

SummaryThe petrophysical evaluation of thinly-bedded sand/shale sequences is strongly dependent on the way in which layered and dispersed shales are taken into account. There are two underpinning issues: the recognition of thin bed geometries and the estimation of shale content from lithology logs. The first of these is managed through a scenario approach, whereby different downhole scenarios are set out according to specified ranges of bed thickness. Each range has its own interpretation protocol. The second issue relates to the inherent overestimation of clay-mineral volume fraction by shale indicators and its impact on the petrophysical evaluation of thinly-bedded sand porosity. This shortcoming is managed by applying a validated scaling factor to log-derived estimates of shale volume fraction so that these become workable estimates of clay-mineral fraction for the porosity evaluation of sand layers. Both these problems become more acute for thinner beds. These two key issues are addressed conjunctively through interpretive workflows, each of which relates to a discrete range of bed thickness and uses fit-for-purpose petrophysical data sets. In particular, the multicomponent induction log is adopted as a pivotal technology for the evaluation of sand resistivity within thinly-bedded sand/shale sequences. The objective is to achieve a sound petrophysical interpretation for each downhole situation. Therefore, groundtruthing through core data is advocated where this allows the shale problem to be managed better. The outcome is a systematic approach to thin-bed evaluation, based on prescribed data inputs that optimize project effectiveness. The benefits are illustrated through case histories that demonstrate a securable upside in projected hydrocarbon volumes.