Reservoir Interval Research Articles

Mitigating Water Production from High Viscosity Oil Wells in Unconsolidated Sandstone Formations

Summary Large reserves of high-viscous oil in Kuwait call for improved oil recovery scenarios. In Kuwaiti unconsolidated sandstone formations, the sandstone intervals represent extensive reservoir intervals of sand separated by laterally extensive nonreservoir intervals that comprise finer-grained argillaceous sands, silts, and muds. The reservoir is shallow with high permeability (above 1,000 md) and under bottom aquifer pressure support. Due to strong viscosity contrast between oil and water, after breakthrough, the water cut rises quickly, resulting in strong loss of production efficiency. Mitigating water production is thus mandatory to improve production conditions. The candidate wells have two to three open intervals in different rock facies with comingle production. The total perforated length is between 38 and 48 ft. Production is through progressing cavity pumps (PCP) at a rate of around 300 B/D, and basic sediment and water is between 71 and 87%. The technology applied utilizes pregelled size-controlled product [small microgels (SMG Microgels)] having relative permeability modification (RPM) properties; that is, inducing a strong drop of relative permeability to water without affecting oil relative permeability. The size is chosen to selectively treat the high-permeability water producing zones while preserving the lower-permeability oil zones. The chemical can also withstand downhole harsh conditions such as salinity of around 170,000 ppm and presence of 2% H2S. The treatment consisted of bullhead injection of 300 bbl of pregelled chemical through-tubing. The first results seem very favorable, since for two wells, the water cut has dropped from 80 to 40% with almost same gross production rate. The incremental oil is more than 100 BOPD. The third well did not show marked change after water system operation (WSO) treatment. The wells are under continuous monitoring to assess long-term performance. Such result, if confirmed, may lead to high possibilities for the improvement of heavy oil reservoir production under aquifer support by mitigating water production with simple chemical bullhead injection.

Conceptual sedimentation model as the basis of geological correlation in a case study of AT6-8 reservoirs of Beregovoye field in West Siberia

For the Beregovoye field (West Siberia, Yamalo-Nenets Autonomous Okrug), a new subsurface geologic model for AT6-8 group of reservoirs in the Lower Cretaceous (Hauterivian-Aptian) interval within Ereyamskaya formation was built following the reprocessing and reinterpretation of 2D and 3D seismic data in 2020, drilling of new wells (new wells, which were drilled after 2016, account for about 10 % of the total well stock that penetrated the AT6-8 reservoirs), updating the structural framework, additional core studies, and revising the well test results. Well log correlation in the AT6-8 interval was based on the reservoirs formation in alluvial and tidal delta plain environments. Multidirectional source areas formed disconnected zones in the net reservoir interval, which controlled the oil and gas content of these reservoirs. Taking into account the results of the geochemical survey, a stage-by-stage approach to hydrocarbon accumulations (light oil and gas condensate) formation was proposed, which led to vertically and laterally varied phase compositions of the discoveries.

Pore pressure prediction using seismic acoustic impedance in an overpressure carbonate reservoir

The drilling engineers favor a quantifiable understanding of the subsurface overpressure zones to avoid drilling hazards. The conventional pore pressure estimation techniques in carbonate reservoirs are prone to uncertainties that affect the calculated pore pressure model resolution and are still far from satisfactory. Basically, in carbonate reservoirs, the effect of chemical process and cementation on porosity is more important than the mechanical compaction, so the conventional pore pressure prediction methods based on the normal compaction trend mostly do not provide acceptable results. Using the conventional methods for carbonate reservoirs can yield large errors, even suggesting a reduction in abnormal pressure in overpressure zones where considerable attention must be paid. Conventional methods need to model density and velocity to calculate the effective and overburden pressures. Converting acoustic impedance to density and velocity is always associated with errors and generally provides low resolution, which adds substantial uncertainties to the pressure prediction. Although pore pressure measurements are usually associated with low resolution, additional error-prone steps can be dropped if used directly. This research outlines the pore pressure estimation of a famous Iranian carbonate reservoir using direct acoustic impedance without inverting it to density and velocity. Finally, this method gives acceptable results in carbonate formations compared to the results of the Repeat Formation Test (RFT) in this region. The results show a zone of overpressure between the two low-pressure intervals of the carbonate reservoir. This result can be of great help in determining reservoir boundaries as well as in planning for drilling trajectory for new wells. Furthermore, the pore pressure estimation results also show pressure reduction in the central part of the seismic section. The proposed approach is a viable alternative to the conventional method and is in line with the geological field report, where the ratio of hydrocarbon potential of total rock on the reservoir sides is higher than its middle part. In this study, we want to emphasize that the calibrated function obtained in our area can be used in similar basins with carbonate reservoirs.

Mudstone Baffles and Barriers in Lower Cretaceous Strata at a Proposed CO2 Storage Hub in Kemper County, Mississippi, United States

The Cretaceous and Tertiary deposits in Mississippi, Alabama, and the adjacent continental shelf constitute a widespread succession of sandstone, mudstone, and carbonate that has proven to be an important target for geologic CO2storage in the onshore Gulf of Mexico basin. Integrated analysis of stratigraphy, sedimentology, and reservoir properties based on cores and geophysical well logs indicates that the Paluxy Formation and Washita- Fredericksburg interval present gigatonne-class storage opportunities. The distribution, geometry, and composition of the area is a direct reflection of the original depositional environments, and understanding these factors is essential for understanding the geologic storage potential of the Paluxy Formation and Washita-Fredericksburg interval at the Kemper County energy facility in Mississippi. Geologic characterization of the Mississippi Embayment at the energy facility focused primarily on characterizing the confinement potential of the storage complex. Integration of core analyses and geophysical well logs has yielded a high-resolution stratigraphic analysis of storage reservoirs, baffles, barriers, and seals. Scanning electron microscopy (SEM) coupled with energy dispersive X-ray spectroscopy (EDS), and quantitative X-ray diffraction (XRD) was used to characterize microfabric, pore types, and mineralogy within mudstone of the east-central Mississippi Embayment at the Kemper County energy facility. Mudstone beds in the Paluxy Formation and Washita-Fredericksburg interval have variable thickness and continuity. High water saturation in the Cretaceous mudstone units influences swelling smectite clay and mudrock permeability based on pulse decay analysis is 1–96 nD. These low permeability values indicate that the mudstone units are effective baffles, barriers, and confining intervals that make significant migration of injected CO2out of the storage complex unlikely. The numerous baffles and barriers within the target reservoir intervals, moreover, favor the retention of multiple CO2in plumes within the abundant stacked sandstone bodies.

Tectonostratigraphic development of the Upper Triassic to Middle Jurassic in the Hoop Area, Barents Sea: Implications for understanding ultra-condensed reservoir units

The most prolific reservoir intervals in the Barents Sea are found in the Upper Triassic to Middle Jurassic Realgrunnen Subgroup, deposited during a major change in the structural evolution of the basin which greatly influenced its development and distribution. The effects are evident in one of the petroleum provinces in the SW Barents Sea, the Hoop Area. Due to the condensed nature of the succession, the tectonostratigraphic evolution has been enigmatic.We use a range of different methods and dataset, including high-resolution P-Cable seismic to determine the tectono-stratigraphic evolution of the succession. Results are important for exploration and production in the Hoop Area and beyond, but also for a broader understanding of how ultra-condensed successions might evolve during long periods of non-deposition and short bursts of deposition.Seven major phases of deposition and non-deposition/erosion are defined. Stage 1 represents fluvio-deltaic deposition in the Fruholmen Formation (Norian), followed by Stage 2 with significant truncation and non-deposition, lasting up to 35 million years. Deposition resumed with the shallow marine to fluvial Nordmela and Stø formations (Pliensbachian to Bajocian), which both encapsule long periods of erosion and non-deposition (stage 3–6). Stage 7 is represented by transgression and shelf deposition in the Fuglen Formation (Bathonian).The change from a high-accommodation setting with continuous and relatively high rate of accumulation in the Triassic, to a low-accommodation setting with episodic deposition and extensive sediment cannibalization in the Jurassic, resulted in cleaner sandstones with better reservoir properties. The low-accommodation setting also enabled coarse-graded detritus from hinterlands in Fennoscandia to prograde into distal part of the basin and more amalgamation of the sands during the Jurassic. Adversely, the low accommodation setting also caused a fragmented pattern of deposition and preservation that needs to be carefully considered in subsurface datasets, often with limited resolution.

Study of novel steam assisted gravity drainage multilateral wells with dynamic gridding

SAGD (steam assisted gravity drainage) performance and its stream chamber growth are primarily determined by the vertical permeability of a reservoir. To deal with inter-bedded shale (IBS)-isolated intervals in bitumen reservoirs and improve steam chamber conformance, novel multilateral (MLT) wells with laterals and/or vertical legs in their trajectories are drilled to penetrate IBS. PetroChina Canada LTD. (PCC) has implemented MLT wells as a technology trial to evaluate potential mitigation to the presence of IBS in its MacKay River SAGD Project. Taking into account both accuracy and efficiency, dynamic local grid refinement (DLGR) is incorporated into the description of the mass and heat transfer phenomena in the vicinities of MLT wells. Also, to represent MLT injection and production wells as open hole branches, their lateral properties are adjusted by considering pore-scale mechanisms of fluid flow and heat transfer. With all these novel features established, the impacts of MLT wells on steam chamber growth and oil recovery are evaluated. It is discovered that MLT wells are conducive to increasing both injectivity and productivity due to the improvement of contact and drainage areas. Besides, how MLT wells perform with various steam operation strategies, geological parameters, injection pressure and NCG (non-condensable gas) wind-down scenarios is assessed.

Concurrent 1. Presentation for: A regional chronostratigraphic framework for play-based resource assessments in the Eromanga Basin

Presented on Tuesday 17 May: Session 1 Geoscience Australia is undertaking a series of basin-scale assessments to identify the ‘yet-to-find’ resource potential for hydrocarbons, as well as for groundwater resources and carbon capture and storage (CCS) opportunities in central Australia under the Exploring for the Future (EFTF) Program. A play-based exploration approach is being used to systematically evaluate the key risk elements for each resource type through the analysis of drilling results and spatial data to map ‘sweet spots’ for exploration. These assessments aim to reduce the risks and uncertainties for explorers by providing spatially enabled assessments of energy resources and CCS potential. The work will also improve the understanding of existing groundwater resources which may be impacted by future energy resource developments or provide feedstock for future green hydrogen projects. A key requirement for undertaking such play-based resource assessments is to apply a common regional chronostratigraphic framework across all the resource types that link different geological unit nomenclatures through defining the assessed reservoir and seal intervals and their associated sequence stratigraphic surfaces (sequence boundaries, transgressive surfaces and maximum flooding surfaces). A Mesozoic chronostratigraphic framework has been developed for the Eromanga Basin, which defines nine regional play intervals that host the known hydrocarbon and groundwater resources, or represent potential CCS targets. The Mesozoic play framework is now being applied to undertake play-based low-carbon energy resource assessments in the western Eromanga Basin, with initial work focussing on the interpretation and correlation of the nine play intervals in wells for post-drill analysis. To access the presentation click the link on the right. To read the full paper click here

Cyclostratigraphy and eccentricity tunning of the middle Miocene succession, Gulf of Suez, Egypt: Astronomical age dating and undetected hiatus

The middle Miocene Kareem Formation is a major hydrocarbon reservoir in the Gulf of Suez rift basin. The middle Miocene Kareem Formation is a major hydrocarbon reservoir in the Gulf of Suez rift basin. The age of this formation has remained controversial due to the lack of clear marker species and the presence of barren intervals in evaporite seals or sand reservoirs. Furthermore, until now, the absolute age and duration of a well-known recognized hiatus (T40) in this formation has not been estimated. Here, we establish the precise age and extent of the Kareem Formation based on the integration of foraminifer and calcareous nannofossil biostratigraphy, with the establishment of an astronomically tuned timescale (ATS) based on gamma-ray variations of two wells, Gs197-2 in the October Basin and J58-81 in the July Basin. These two wells represent the most complete cored sequence of the Middle Miocene Kareem Formation, recording six calcareous nannofossil, four planktonic, and one benthic foraminiferal biohorizons, that enable us to define the Langhian-Serravalian boundary. According to our new biostratigraphically-supported ATS, we estimate that the Kareem Formation spans from 13.25 to 15 Ma. The T40 hiatus is identified in both wells at the boundary between the Shagar and Rahmi Members, with an estimated duration of ca. 0.26 Myr and 0.18 Myr for Gs197-2 and J58-81, respectively. A pronounced obliquity imprint is recorded in the upper Langhian to Serravalian of Gs197-2 well, right above the T40 hiatus.

Geostatistical Inversion of Spectrally Broadened Seismic Data for Re-Evaluation of Oil Reservoir Continuity in Inas Field, Offshore Malay Basin

The application of geostatistics in seismic inversion techniques has been proven somewhat reliable in the delineation of reservoir properties and has recently attracted the attention of many geoscientists. However, there are cases where its prediction returned negative results after drilling. In this research, we re-evaluated a reservoir in Inas Field, whose geostatistical inversion result wrongly predicted sand continuity, resulting in the spudding of a dry hole. When a geostatistical seismic inversion is successfully applied, it provides an increase in seismic resolution and aids the prediction of sand continuity. Although this method relies more on the statistical data from a well because of the limitation of the seismic data in resolving thin geologic features, the spatial variation of reservoir parameters still depends on seismic data, which often have poor resolution quality. Therefore, to investigate the impact of bandlimited data on the geostatistical inversion, we harmonically extended the seismic bandwidth by applying a sparse-layer spectral inversion algorithm to the data. This algorithm increased the seismic data bandwidth from 80 Hz to 180 Hz, and its tuning thickness reduced from 32 m to 10 m at the reservoir interval. The resultant broadband (180 Hz), as well as the original seismic (narrowband of 80 Hz) data, were both used as input to build two separate geostatistical prediction models, respectively. Twenty (20) realizations of these models were generated, ranked into P10, P50, and P90, and the best case was selected for interpretation. These realizations were used to characterize the reservoir lithofacies distribution. When compared, the result of the broadband inversion, facies and sand distribution model showed that the reservoir facies changed towards the location of the dry well. The broadband geostatistical inversion efficiently improved the reservoir characterization process by not only producing an accurate estimation of the lateral extent of the reservoir heterogeneities but also generating outcomes that help us understand why other geostatistical inversion analyses of the target reservoir were misleading. Contrary to the popular assumption, it was discovered that the tuning effects of bandlimited data could affect the result of a geostatistical inversion and result in wrong facies predictions.

Optimization of the PLT complex for the problems of the inflow profile estimate in low-rate gas wells on the example of the Berezovskaya suite

Currently, more and more attention is being paid to hard-to-recover reserves characterized by low flow rates. And one of the problematic issues in the process of studying them is the correct determination of the inflow profile by conducting production logging tool (PLT). In this regard, there is a need to increase the information content of the PLT in the conditions of gas reservoirs with a low flow rate, where the Berezovskaya suite is an actual research area. In this paper, a new PLT scheme is proposed, based on the actual PLT scheme, which will allow more reliable determination of operating intervals in low-rate gas-saturated reservoirs.

Two-dimensional numerical simulation of spontaneous potential logging data with account to clay content of a reservoir by finite element method

Spontaneous polarization potential (SP) logging remains one of the most widely used geophysical methods of borehole investigation. However, for a long time its interpretation was based on empirical dependences and analytical solutions in simplified formulations. At present the development of the method is associated with the development of new approaches to numerical modeling and quantitative interpretation of SP logging data. Application of numerical algorithms makes it possible to considerably increase information content and resolution of SP method. Nevertheless, most of the currently proposed approaches rely on a simplified description of SP signal formation, which may lead to errors in data interpretation for complex reservoir intervals. In this work, we propose an algorithm for numerical simulation of SP logging data as applied to the study of clayed fluid-saturated reservoirs. The physical and mathematical model of SP signal formation in terms of coupled fluxes for the case of electrochemical SP source is considered. The software realization of the algorithm includes a two-dimensional numerical simulation of SP signals based on the application of the finite element method in the axially symmetric model of the geological medium. The character of SP signals for reservoirs of different thickness at four values of the reservoir water saturation coefficient is studied, as well as the dependence of the shape and amplitude of the SP anomaly in a water- and oil-saturated clayed reservoir on the content and type of clay mineral. The obtained results, aimed at the development of the SP method, improve the quality of SP diagrams interpretation for the study of clayed reservoirs.

Substantiation of reservoirs in the Bazhenov Formation in the Malobalykskaya and neighboring areas (KhMAO, Western Siberia)

The article presents the results of a comprehensive interpretation of new results of laboratory studies of the core material of the Bazhenov formation and well logging data for three wells. A set of criteria for identifying reservoir intervals is substantiated, which includes the results of determining the chemical and mineral-component composition of rocks, the pyrolytic characteristics of the organic matter contained in them, as well as the petrophysical properties of these deposits. It has been established that the reservoirs can be silicites occurring in the middle part of the Bazhenov formation section - they have a high open porosity and the presence of mobile oil, confirmed by the inflow in one of the wells. It is shown that at a distance of 15-20 km this siliceous interval may not have reservoir properties, which is probably due to a different filling of the void space of these rocks. Carbonate and phosphorite rocks, which are also reservoirs in some fields in this region, do not contain mobile oil in the studied sections. It is substantiated that well logging data can only be used to identify possible productive intervals, the study of which by laboratory methods will make it possible to establish and forecast the presence or absence of reservoirs in them.

A regional chronostratigraphic framework for play-based resource assessments in the Eromanga Basin

Geoscience Australia is undertaking a series of basin-scale assessments to identify the ‘yet-to-find’ resource potential for hydrocarbons, as well as for groundwater resources and carbon capture and storage (CCS) opportunities in central Australia under the Exploring for the Future (EFTF) Program. A play-based exploration approach is being used to systematically evaluate the key risk elements for each resource type through the analysis of drilling results and spatial data to map ‘sweet spots’ for exploration. These assessments aim to reduce the risks and uncertainties for explorers by providing spatially enabled assessments of energy resources and CCS potential. The work will also improve the understanding of existing groundwater resources which may be impacted by future energy resource developments or provide feedstock for future green hydrogen projects. A key requirement for undertaking such play-based resource assessments is to apply a common regional chronostratigraphic framework across all the resource types that link different geological unit nomenclatures through defining the assessed reservoir and seal intervals and their associated sequence stratigraphic surfaces (sequence boundaries, transgressive surfaces and maximum flooding surfaces). A Mesozoic chronostratigraphic framework has been developed for the Eromanga Basin, which defines nine regional play intervals that host the known hydrocarbon and groundwater resources, or represent potential CCS targets. The Mesozoic play framework is now being applied to undertake play-based low-carbon energy resource assessments in the western Eromanga Basin, with initial work focussing on the interpretation and correlation of the nine play intervals in wells for post-drill analysis.

3D-static reservoir and basin modeling of a lacustrine fan-deltaic system in the Gulf of Suez, Egypt

Lacustrine-fan deltas feature high reservoir-quality lithounits that are critical targets to hydrocarbon exploration and development. However, depicting their intricate sedimentary architectural elements is still challenging due to complex stacking-patterns and limited examples. In this study, both 3D-static geocellular reservoir modeling and 1D-basin modeling approaches were combined as an established effective workflow that is capable of efficiently delineating reservoir-heterogeneities and confirming hydrocarbon-charging. This integration was for the purpose of unlocking the ultimate petroleum potential of fluvio-lacustrine units, Nubia Formation, in the southwest of the Gulf of Suez rift (West Esh-ElMallaha Concession, Egypt). Pixel-based stochastic-simulation was applied, constrained by an established depositional-model developed after adequate integrated-facies analysis, upon geocellularly modeling rock and fluid properties of Nubia reservoir intervals; utilizing several key-information scales (seismic-profiles, well-logs). The results reveal a lowstand-transgressive systems tract encompassing fluvio-lacustrine depositional-systems subdivided into eight facies-associations, of which fluvial-channels and deltaic mouth bars represent significant reservoir-quality facies. Given efficient reservoir-quality, mouth sand-bars deserve special consideration, and testing, while running further oilfield development-endeavours and investigating similar-settings.

Optimization of Reservoir Flood Control Operation Based on Multialgorithm Deep Learning

With the rapid development of China's social economy, it is the most important task for the water conservancy industry to make use of the existing water conservancy engineering measures to carry out the research on river basin flood control dispatching. Large-scale joint operation of river basins usually needs to consider meteorological and hydrological conditions, historical flood data, multireservoir engineering conditions, and multiple flood control targets, which is a complex decision-making problem. Therefore, electing the optimal operation model of reservoir flood control optimization is very important. In this paper, Luanhe River Basin is taken as the research area, and three kinds of constraints, namely, water balance constraint, reservoir flood control capacity constraint, and water release decision constraint, are set to construct the flood control optimization model. Taking the minimum square of the sum of reservoir discharge and interval flood discharge as the objective function, genetic algorithm (GA), particle swarm optimization (PSO), Spider swarm optimization (SSO), and grey wolf optimization (GWO) are introduced into flood control optimal operation to seek the minimum value of objective function, and the results are compared and analyzed. Through the analysis of optimization results, the optimization ability and convergence effect of grey wolf optimization algorithm are better than those of genetic algorithm and particle algorithm, and the results are more stable than those of spider swarm algorithm. It has a good model structure and can make full use of the results of three wolf groups for optimization. Through the analysis of scheduling results, the results of genetic algorithm and particle swarm optimization algorithm are similar, while those of spider swarm optimization algorithm and grey wolf optimization algorithm are similar and slightly better than those of the first two. Moreover, the search range of grey wolf optimization algorithm for solving long sequence problems is wider and the calculation time is shorter. Therefore, the grey wolf optimization algorithm can be applied to solve the flood control operation optimization model of Panjiakou Reservoir Group.

Acoustic Impedance Inversions for Offshore CO2 Storage: South Georgia Embayment, United States

This study builds and expands on previous CO2 storage resource assessment studies of the southeastern offshore Atlantic margin by providing a detailed evaluation on how rock porosities and permeabilities are distributed across the Upper Cretaceous strata restricted to the South Georgia Embayment (SGE). Using legacy industry two-dimensional seismic reflection and well data, this assessment is the first application of multiple seismic inversion techniques in this area. This workflow provides a reliable and repeatable model-based inversion which gives an improved image to discriminate lithology and predict porosity. The workflow is applicable to future CO2 storage resource assessment studies elsewhere. The inversion results indicate that distinct porosity and permeability regimes are present and distributed in the Upper Cretaceous strata within the SGE. The impedance and porosity relationships show well-founded and reliable correlation. These relationships reveal low impedance coincident to the high porosity intervals which are proposed as potential reservoir intervals for CO2 storage. In addition, the result shows that the Upper Cretaceous strata have two main potential reservoirs in the lower part. These are overlain by a thick impermeable interval, mostly shale, which has high impedance, low porosity, and low permeability and extends within the SGE. This result is in agreement with a previous study that also proposed two significant storage reservoirs for CO2 in the Upper Cretaceous strata. Since porosity distribution is estimated using multiple methods, it follows the trends of seismic signature and structures of the Upper Cretaceous strata. The extracted values of porosity, ranging from 15 to 36%, and permeability, ranging from 1 to 100 mD, are close to the measured values from the well core data at the Upper Cretaceous strata interval.

Microfacies Analysis and Diagenetic Assessment of the Late Oligocene- Early Miocene Succession in Khabaz Oilfield, Northern Iraq

The Jeribe and Azkand formations, which were deposited during Late Oligocene-Early Miocene are a major reservoir interval in the Khabaz oilfield where it is, for the most part, a carbonate reservoir. The study area is located in the north of Iraq within the Foothill Zone. Through the thin-section examination for Azkand/Anah carbonates in the Khabaz oil field (Kz-3, Kz-4, Kz-10, and Kz-43), the petrographic and microfacies have been studied, which show six major carbonate microfacies, each of them is representing a distinctive deposition environment, and these are: restricted and semi-restricted for the Jeribe Formation, and semi-restricted, back reef, reef, fore reef, shallow open marine and slope for Azkand and Anah formations. There are several types of diagenetic processes; some of these processes enhance the porosity and the other reduces it. Porosity reduction by: Cementation (Isopachous, meniscus, syntaxial calcite, Drusy calcite, botryoidal, blocky calcite), Recrystallization; Compaction and late stage of dolomitization. This appeared near the upper and lower contact of the Jeribe Formation and in the lower part of the Azkand Formation. While the porosity enhancement which represented by depositional process (primary porosity) and dissolution (secondary porosity), in addition to the early and middle stage of dolomitization. This appeared in the middle part of the Jeribe Formation and the upper part of Azkand.

Quantitative Interpretation of Petrophysical Parameters for Reservoir Characterization in an Onshore Field of Niger Delta Basin

Reservoir characterization of a field was performed using petrophysical parameters for the evaluation of subsurface geological features and hydrocarbon potential of an onshore field in Niger Delta Basin. Four reservoir intervals were identified within the field wells based on their position within the stratigraphic column, and the reservoir correlation, which was aided using the principle of uniform horizontality, based on the simple rule that sediments are deposited horizontally and basic understanding of sequence stratigraphy. The study revealed that, the four reservoirs were predominantly sand units intercalated with shale within the reservoir units. The petrophysical evaluation revealed the Net to Gross (NTG) values ranges from 79% to 87% within the reservoir units, while the effective porosity ranges from 17% to 21%, the permeability ranges between 1307mD to 1678mD across the reservoir units, while the water saturation ranges from the lowest of 35% (reservoir C) to 78% in reservoir D. The approach validates the lithology discrimination of the elastic properties from the well logs and its effectiveness in optimizing and proper understanding of the subsurface, thus identifying and unmasking hidden features within the reservoir (probable bypass) in the field. The study has revealed that petrophysical parameters can be used quantitatively to characterize a field in terms of its lithology and fluid contents of the reservoir.

Predicting horizontal well flow rates under the geological conditions of Western Siberia fields

Research relevance. The determination of the expected well flow rate is a key problem in designing the development of oil fields with horizontal wells. In industrial practice, actual and real flow rates of horizontal wells usually differ significantly. Research objective. The algorithms for horizontal well potential flow rates determination have been studied extensively. However, the issues of choosing a methodology for determining the flow rate in relation to particular geological conditions remain unresolved. It is necessary to compare the actual and design rates of horizontal wells and identify the most representative methods for flow rates determination for the geological conditions of Western Siberia fields. Methods of research. A single horizontal well draining a semi-infinite reservoir is considered in the absence of hydrodynamically isolated and poorly drained zones within the radius of the well external boundary. The Giger, Joshi, Janar, and Renard–Dupuy methods were used to determine the expected flow rates of horizontal wells only under the following conditions: a homogeneous reservoir and a near-rectilinear horizontal section of the well in the reservoir interval. As an example, the calculation of the expected flow rate of a horizontal well with the following initial data is given: the horizontal section length is 700 m, the net oil thickness is 7.8 m; the permeability coefficient is 127 · 10–15 m2 , oil viscosity is 1.24 MPa ∙ s, the drawdown is 3 MPa, the external boundary radius is 1000 m, and the volume factor is 1.08. Results. Quite significant discrepancies between the actual and design data are recorded for wells with arbitrary numbers 4, 7, 8, 10, 15, 18 and 20. All the methods used for calculations provided comparable results. For all other wells, the calculation results have a high convergence with field data. Conclusions. The Giger, Joshi, Janar, and Renard–Dupuy methods may be recommended for horizontal wells expected flow rates determination only under the following conditions: a homogeneous reservoir and a near-rectilinear horizontal section of the well in the reservoir interval.

Depositional trends and reservoir geometries of the Early Cretaceous Lower Goru Formation in Lower Indus Basin, Pakistan: evidence from sequence stratigraphy

Lower Goru sand intervals of Early Cretaceous age are proven reservoirs in the Lower Indus Platform area. The delineation of reservoir geometries is of utmost importance while searching for stratigraphic and combination traps in clastic reservoirs. The data of ten wells and two 2D seismic lines from the northern part of the Lower Indus Basin are incorporated in this study. These reservoir intervals of the Lower Goru Formation are correlated in a third-order sequence stratigraphic framework to understand the depositional architecture and reservoir geometries. The Lower Goru Formation was deposited in westerly prograding river-dominated deltas developed by river system drained through the Indian Shield from east and south-east during Cretaceous time. Due to auto-cyclic switching of river distributaries, different lobes might have formed which if identified can point out the possible locations and configurations of stratigraphic and combination traps in this highly prospective area of Lower Indus Basin. The Lower Goru Formation (Barremian to Cenomanian) consists of one full second-order sequence of 20 Ma duration, having all the three fundamental system tracts in which eleven sequences of the third order, i.e. LG-1 to LG-11, were interpreted. Proven reservoir intervals of the Lower Goru Formation are concentrated in various third-order lowstand system tracts. The net sand and porosity maps of lowstand system tracts, gross depositional map and depositional cross section of the Lower Goru Formation point out the potential sites of good sandstone reservoirs and hint at the possible sand-body geometries.