Remote sensing and geophysical studies for groundwater exploration in Osmania University campus, Hyderabad, India: A case study

With the increasing resolution of satellite sensors, it is possible to fruitfully exploit the special advantages of image analysis for a wide range of geological environments. With this view, a LISS-III and PAN merged image of the 1600 acre (approximately 6.5 sq km) Osmania University (OU) campus taken from IRS-ID in the month of May (a fairly representative month in terms of minimum annual drainage/vegetation cover) was acquired. The image was then digitally processed and visually interpreted for potential groundwater resource regions. Since occurrence of groundwater in crystalline rocks, the host rocks for the entire Hyderabad region, is generally associated with secondary porosity, the accent was on determining and establishing lineaments of considerable surface extent. This was then augmented with maps of subsurface features as obtained from geophysical studies for the southern part of 0 U campus and available bore well/open well information. Subsequently, information from the three sources was integrated for a better understanding of the geological situation and the interrelationship of its various constituents to determine possible locations of groundwater resources. The significant findings comprised the identification of three major dykes, two running E-W and the third running NE-SW. A major N-S linear exposure of granitic rocks, as also several criss-crossing fractures in the southern side of the campus, along with the prevailing drainage pattern for the entire campus area were mapped. Based on these findings and supporting geophysical/hydrogeological data, a geological/lithological map of Osmania University campus was prepared and prospective groundwater zones have been identified.

Petrophysical Properties and Digenetic Evolution of Shuaiba Formation in Nasiriyah Oil Field, Southern Iraq

Shuaiba Formation is a carbonate succession deposited within Aptian Sequences. This research deals with the petrophysical and reservoir characterizations characteristics of the interval of interest in five wells of the Nasiriyah oil field. The petrophysical properties were determined by using different types of well logs, such as electric logs (LLS, LLD, MFSL), porosity logs (neutron, density, sonic), as well as gamma ray log. The studied sequence was mostly affected by dolomitization, which changed the lithology of the formation to dolostone and enhanced the secondary porosity that replaced the primary porosity. Depending on gamma ray log response and the shale volume, the formation is classified into three zones. These zones are A, B, and C, each can be split into three rock intervals in respect to the bulk porosity measurements. The resulted porosity intervals are: (I) High to medium effective porosity, (II) High to medium inactive porosity, and (III) Low or non-porosity intervals. In relevance to porosity, resistivity, and water saturation points of view, there are two main reservoir horizon intervals within Shuaiba Formation. Both horizons appear in the middle part of the formation, being located within the wells Ns-1, 2, and 3. These intervals are attributed to high to medium effective porosity, low shale content, and high values of the deep resistivity logs. The second horizon appears clearly in Ns-2 well only.

Structural Reservoir Characterization of Akkas Gas Field, Western Iraq: Implications for Hydrocarbon Recovery

Akkas Field is a structural trap with a sandstone reservoir that contains proven gas condensate. The field is a faulted anticline that consists of the Ordovician Khabour Formation. The objective of this research is to use structural reservoir characterization for hydrocarbon recovery. The stratigraphic sequence of the Silurian and older strata was subjected to an uplift that developed a gentle NW-SE trending anticline. The uplifting and folding events developed micro-fractures represented by tension cracks. These microfractures, whether they are outer arc or release fractures, are parallel to the hinge line of the anticline and perpendicular to the bedding planes. The brittle sandstone layers of the reservoir are interbedded with ductile units of shale. The sandstone layers accommodate the formation of micro fractures that play a major role to increase the secondary porosity. The gas and condensate have been stored mainly through the micro fractures. Two types of drilling have been used for experimental gas production, vertical and horizontal. Horizontal drilling was parallel to both hinge line of the anticline and micro fracture surfaces that was conducted and doubled the gas production of the vertical well multiple times. However, if used the third type of drilling, directional, that is perpendicular to the hinge line and parallel to the beddings of both flanks of the anticline gas production will increase more than the horizontal drilling. The directional drilling will become perpendicular to the fracture surfaces and allow the gas and the condensate to flow into the well from all directions. Additionally, it will reduce the effect of both semi – liquid hydrocarbon condensate and vertical sediment barriers.

Development Environments and Factors of Subsidence Dolines

This study describes the development environments of subsidence dolines based on literary data (development environments create favorable conditions for the local denudation of superficial deposit and thus, for the development of depressions). Development environments are the inclination of the bearing surface, the secondary porosity of the bedrock, the characteristics of the cover, water influx into the cover, karstwater and groundwater, melting permafrost, and anthropogenic activity. These may become optimal when controlled by various geological, geomorphological, and climatic factors. Development environments may be qualitative (there is doline development in case of its presence) and quantitative (doline development occurs in case of suitable quantitative values). The development environment groups of subsidence dolines are environment groups independent of water level, environment groups dependent on water level, and anthropogenic environment groups. In the case of an environment group independent of water level, surface morphology, cover characteristics, geomorphic evolution, and water supply are determining, while in case of an environment group dependent of water level, subsurface water level and its fluctuations and the characteristics of rainfalls interrupting dry seasons are crucial. Anthropogenic impacts mainly affect doline development through water balance.

Integrated Porosity Classification and Quantification Scheme for Enhanced Carbonate Reservoir Quality: Implications from the Miocene Malaysian Carbonates

The pore system in carbonates is complicated because of the associated biological and chemical activity. Secondary porosity, on the other hand, is the result of chemical reactions that occur during diagenetic processes. A thorough understanding of the carbonate pore system is essential to hydrocarbon prospecting. Porosity classification schemes are currently limited to accurately forecast the petrophysical parameters of different reservoirs with various origins and depositional environments. Although rock classification offers a way to describe lithofacies, it has no impact on the application of the poro-perm correlation. An outstanding example of pore complexity (both in terms of type and origin) may be found in the Central Luconia carbonate system (Malaysia), which has been altered by diagenetic processes. Using transmitted light microscopy, 32 high-resolution pictures were collected of each thin segment for quantitative examination. An FESEM picture and a petrographic study of thin sections were used to quantify the grains, matrix, cement, and macroporosity (pore types). Microporosity was determined by subtracting macroporosity from total porosity using a point-counting technique. Moldic porosity (macroporosity) was shown to be the predominant type of porosity in thin sections, whereas microporosity seems to account for 40 to 50% of the overall porosity. Carbonates from the Miocene have been shown to possess a substantial quantity of microporosity, making hydrocarbon estimate and production much more difficult. It might lead to a higher level of uncertainty in the estimation of hydrocarbon reserves if ignored. Existing porosity classifications cannot be used to better understand the poro-perm correlation because of the wide range of geological characteristics. However, by considering pore types and pore structures, which may be separated into macro- and microporosity, the classification can be enhanced. Microporosity identification and classification investigations have become a key problem in limestone reservoirs across the globe.

Integration of NMR Factor Analysis, Multifunction LWD Measurements, and T2 Modeling Improve Fluid Identification in Complex Carbonate Reservoirs

Carbonate environments are complex by nature and the characterization, based on their petrophysical properties, has always been challenging due to the pore heterogeneity. In this paper, we present the integration of factor analysis applied to while-drilling Nuclear Magnetic Resonance (NMR) data, full-suite data from a multifunction logging-while-drilling (LWD) tool, and modeling of the NMR T2 transverse relaxation time to improve the fluid typing interpretation in complex carbonate reservoirs. The interpretation results are essential for perforation and completion decisions in a high-angle development well. The carbonate reservoirs in this case study are within the Kujung formation in the East Java Basin. Kujung I is a massive carbonate reservoir with abundant secondary porosity, while Kujung II and III consist of interbedded thin carbonate reservoirs and shale layers. High uncertainty in identifying the fluid type existed in the Kujung II and III formations due to the presence of multiple fluids in the reservoir, the effect of low water salinity, as well as pore heterogeneity and diagenesis. Due to the high-angle well profile, LWD tool conveyance became the primary method for data acquisition. NMR while drilling and multifunction LWD tools were run on the same drilling bottomhole assembly (BHA) to provide complete formation evaluation and fluid identification. The NMR factor analysis technique was used to decompose the T2 distribution into its porofluid constituents. Thorough T2 peaks modeling was performed to interpret the fluid signatures from the factor analysis results. Borehole images, caliper, triple-combo, density-magnetic resonance gas corrected porosity (DMRP), as well as time-lapse data were evaluated to identify the presence of secondary porosity and narrow down the T2 fluid signatures interpretation. Each of the porofluid signatures were identified and validated in the Kujung I formation with its proven gas and thick water zone. These signatures were then used as references to interpret the fluid types in the Kujung II and III formations. Gas was identified by a low-amplitude peak in the shorter T2 range between 400 ms to 1 s. Oil or synthetic oil-based mud (SOBM) filtrate was indicated by a high-amplitude peak in the longer T2 range (>1.5 s). The water signatures are very much dependent on the underlying pore sizes. Larger pore sizes will generate longer T2 values, which could fall into the same T2 range as hydrocarbon. For that reason, it is important to combine the NMR porofluid signatures interpretation with other LWD data to restrict the fluid type possibilities. This integrated methodology has successfully improved the fluid type interpretation in the Kujung II and III thin carbonate reservoir targets and was confirmed by the actual production results from the same well. This case study presents excellent integration of LWD NMR with other LWD data to reduce fluid type uncertainties in complex carbonate reservoirs, which were unresolved by conventional interpretation methods. Based on this success, a similar integrated NMR factor analysis method can be applied to future development wells in the same field.

Carbonate Reservoir Characterization with High-Resolution Logging-While-Drilling Dual-Images in Oil-Based Mud

Fracture evaluation and vuggy feature understanding are of prime importance in carbonate reservoirs. Commonly the related features are extracted from high resolution borehole images in water-based mud environments. To reduce the formation damage from drilling fluids, many wells are drilled with oil-based muds (OBM) in carbonate reservoirs. There are no appropriate measurements to resolve the reservoir characterization in OBM with the existing technologies in horizontal wells—especially in real-time—to make decisions at an early stage. In this paper, we would like to introduce a workflow for geological characterization using a new dual-images logging while drilling tool in oil-based mud. This new tool provides high resolution resistivity and ultrasonic images at the same time. Structural features, such as bedding boundaries, faults, fractures can be identified efficiently from resistivity images; while detailed sedimentary features, for example, cross beddings, vugs, stylolite are easily characterized using ultrasonic images. Benefiting from the dual images, an innovative workflow was proposed to estimate the vug feature more accurately; and the fractures can be identified from images and classified based on tool measurement principles. One case study from the Middle East demonstrated the benefits of this new measurement. A near well structure model was constructed from bed boundaries picked from borehole images. The fractures were picked and classified confidently using the dual images. Additionally, fracture density statistics are available along the well trajectory. The vug features were extracted efficiently, which indicates the secondary porosity development information. Rock typing is achieved by combining fracture and vug analysis to provide zonation for completion and production stimulation. The dual-images provide the capability for geological characterization in carbonate reservoir in an oil-based mud environment. The image-based rock typing helps segment the drain-hole for completion and production stimulation. The reservoir mapping with rock typing provides detailed information for in-filling well design.

Petrophysical Properties Estimation of Euphrates Reservoir in Qayyarah Oil Field Using Core and Well Log Data

The Early Miocene Euphrates Formation is characterized by its oil importance in the Qayyarah oil field and its neighboring fields. This study relied on the core and log data analyses of two wells in the Qayyarah oil field. According to the cross-plot’s information, the Euphrates Formation is mainly composed of dolomite with varying proportions of limestone and shale. Various measurements to calculate the porosity, permeability, and water saturation on the core samples were made at different depths in the two studied wells Qy-54 and Qy-55. A relationship between water saturation and capillary pressure has been plotted for some core samples to predict sites of normal compaction in the formation. The line regression for this relationship was considered as a function of the ratio of large voids to the total volume of voids in the sample. The coefficient of determination parameter was used in estimating the amount of homogeneity in the sizes of the voids, as it was observed to increase significantly at the sites of shale. After dividing the formation into several zones, the well log data were analyzed to predict the locations of oil presence in both wells. The significance of the negative secondary porosity in detecting the hydrocarbon sites in the Euphrates Formation was deduced by its correspondence with the large increase in the true resistivity values in both wells. More than 90% of the formation parts represent reservoir rocks in both wells, but only about 75% of them are oil reservoirs in the well Qy-54 and nearly 50% of them are oil reservoirs in the well Qy-55.

Importance of Velocity Deviation Technique and Negative Secondary Porosity in Detection of Hydrocarbon Zones in Khasib Formation, East Baghdad Oil Field

The velocity deviation technique is one of the important techniques in hydrocarbon investigations, through which it is possible to identify the types and the content of rock pores. The current study aimed to demonstrate the benefit of this technique in discovering the oil sites of the Khasib formation in the East Baghdad oil field, as well as the possibility of separating the oil and gas zones by combining the velocity deviation technique with the anomalous primary porosity information that leads to negative secondary porosity. In this study, log data of three wells distributed in the study area (EB-04, EB-16, and EB-34) were used. From these data, the velocity was estimated by the sonic log, the porosity was estimated by the neutron and the density log, while the velocity deviation was determined by subtracting the velocity calculated from the density log from the sonic log velocity. The result showed that there is significant agreement between the secondary porosity values that turned positive after the oil effect was removed and the confirmed oil zones derived from the core information. Also, there was a clear correlation between velocity deviation values above -500 m/s and the permeability zone of formation, which may reflect the importance of this technique in the identification of the permeability zone. Both techniques (Velocity Deviation and log porosity analysis) can be correlated to predict the locations of gas, large-scale fractures, and unconsolidated beds in sites of high negative secondary porosity and low-velocity deviation (under -500 m/s).

The geology of Pegasus Basin based on outcrop correlatives in southern Wairarapa and northeastern Marlborough, New Zealand

<p>Acquisition of high quality 2D seismic data by the New Zealand Government in 2009-10 (the PEG09 Survey) sparked new interest in Pegasus Basin, an offshore frontier basin situated east of central New Zealand. Although no wells have been drilled in Pegasus Basin, strata exposed onshore in southern Wairarapa and northeastern Marlborough provide useful analogues for the sedimentary fill of the basin. Using field observations in combination with petrographic analysis and seismic interpretation, this study provides a more complete understanding of the geology of Pegasus Basin. 13 outcrop localities are described from the surrounding southern Wairarapa and northern Marlborough regions, which are inferred to have been deposited in a range of depositional environments including fluvial, terrestrial and shallow marine deposits, through to inner – mid shelf, and deep marine channel-levee and submarine fans, with fine-grained sedimentation at bathyal depths. These outcrops provide representative and well-exposed examples of facies and lithologies typical of the depositional environments that are likely to exist in Pegasus Basin. Petrographic analysis of six Cretaceous and six Neogene sandstones from Marlborough and Wairarapa regions has revealed that they are compositionally classified as litharenites and feldspathic litharenites, derived from the Torlesse Supergroup. Primary porosity is best preserved in Neogene sandstones, whilst Cretaceous sandstones only tend to preserve secondary porosity, in the form of fractures or dissolution of framework grains. Carbonate cementation, compaction and authigenic clay formation are the biggest contributing factors that degrade reservoir quality. Seismic interpretation of the PEG09 survey has revealed that Pegasus Basin contains a sedimentary succession over 10,000 m thick, that mantles Early Cretaceous syn-tectonic strata in various states of deformation attained during mid-Cretaceous subduction at the eastern Gondwana margin. Key horizons mapped extensively over the basin highlight seismic reflection packages, which are linked to described outcrop localities onshore, based on reflection characteristics and geometries. The Miocene succession contains up to 4,000 m of sediments that are likely to include promising reservoir lithologies akin to the Great Marlborough Conglomerate of Marlborough, or the Whakataki Formation of Wairarapa.</p>