Oil-bearing Zones Research Articles

Analytical prediction of the formation factor for anisotropic mono-sized unconsolidated porous media

The rectangular Representative Unit Cell (RUC) models for mono-sized isotropic unconsolidated porous media have been extended to anisotropic media. Volume averaging was applied to Ohm's law in order to propose analytical expressions for the formation factor for electrical conduction in terms of the pore-scale linear dimensions. The formation factor, crucial for understanding electrical conduction in porous media, has significant applications in subsurface geophysics, petroleum reservoir characterization, and the durability assessment of construction materials. These analytical models provide valuable insights for optimizing the electrical properties of porous structures in various engineering fields, for example in mapping groundwater resources, differentiating oil-bearing zones in reservoirs, and predicting ion migration in concrete. Aspect ratios of the cell and solid dimensions have been introduced, and the formation factor expressed in terms thereof for five different arrays, i.e. a regular, a non-overlapping streamwisely fully staggered, an overlapping streamwisely fully staggered, a non-overlapping transversally fully staggered, and an overlapping transversally fully staggered array. The Laplace equation has furthermore been solved numerically for two-dimensional versions of the different arrays and the formation factor computed for several values of the aspect ratios. The proposed analytical models have been validated against the generated numerical data and compared to experimental and numerical data obtained from the literature. The proposed models have also been adapted to include a percolation threshold porosity in order to improve the model predictions for very low porosity media.

Petrophysical Properties Estimation by Using Well Log and Core Data Interpretation for Tertiary Reservoir in Ajeel Oil Field

Understanding the petrophysical properties of reservoirs is paramount for assessing their characteristics and estimating the potential of oil-bearing formations. This study focuses on the tertiary reservoir in the Ajeel oil field, renowned for its heterogeneous carbonate nature and diverse production formations, including Jeribe, Dhiban, and Euphrates. The formation of the tertiary reservoir is evaluated through a comprehensive analysis of petrophysical properties utilizing well log data from well AJ-25 and core analysis data (routine and special analysis). The study reveals significant insights into the petrophysical properties of the formations. The effective porosity values for the Jeribe, Dhiban, and Euphrates formations are determined as 15.41%, 4.65%, and 9.85%, respectively, with lithology predominantly consisting of dolomite rock interspersed with limestone slices and anhydrite nodules. A high Secondary Porosity Index (SPI) indicates fractures. Archie's Parameters, obtained from a Pickett Plot, yield cement coefficient (m=1.8), saturation exponent (n=1.9), and tortuosity factor (a=1.19). Water saturation levels for the Jeribe, Dhiban, and Euphrates formations are 33%, 86%, and 81%, respectively, with porosity and water saturation cutoff values determined as 10% and 60%, respectively. Net to Gross of Jeribe, Dhiban, and Euphrates formation are 0.706, 0.029, and 0.011, respectively. Jeribe Formation is identified as an oil-bearing zone. In contrast, the Dhiban and Euphrates formations are identified as water-bearing zones. To enhance the accuracy of petrophysical assessments, modern well logging techniques, such as the Formation Micro Scanner log (FMI log), are recommended to investigate fractures and their impact on field performance, as traditional logs may not adequately capture these features. Additionally, our comparative analysis highlights superior petrophysical properties of the Euphrates Formation compared to the Jeribe Formation. Therefore, prioritizing drilling and completion activities in the Euphrates Reservoir within the field, contingent upon its positioning relative to the oil-water contact level, is suggested for optimizing reservoir performance.

Current condition, geological structure and prospects of oil and gas resources in the Aral sea

The article presents the results of the analysis of the current state of study of the Aral Sea region by geological exploration works, and in more detail – of the Aral Sea aquatory. An attempt has been made to correlate new geological data based on the works of Uzbek geologists and materials of seismic surveys of the Kazakh part of the Aral Sea, since the West Aral oil and gas condensate field has been discovered in the Uzbek part of the Aral Sea water area, the productivity of which is associated with the Middle-Upper Jurassic deposits. Taking into account the history of geological development of the territory and formation of oil and gas bearing zones, it is necessary to carry out geological exploration works in the perspective of the unified model of the Aral Sea basin. On the basis of the discussed model of geological structure the prospects of oil and gas potential of separate structural-tectonic zones were predicted, and a series of recommendations were issued.

ნინოწმინდის გაზნავთობიანი ბუდობის დამუშავება პროდუქტიულ ფენაზე ჰიდროდინამიკური ზემოქმედების მეთოდებით

Ninotsminda oil-and-gas bearing deposit connected with the fractured-cavernous reservoirs of the Middle Eocene volcanogenic-sedimentary suite is in its final, 4th stage of development (operates since 1979). Its energy potential is determined by water drive and gas drive regimes. The main of the prevailing issues is the rapid pace and the scale of production becoming water-cut. Productive suite, that is mainly built with tuff, is anisotropic due to numerous parameters. Respectively, intervals and sections with high and low-filtration properties are identified in the geological cross-section. In addition, the producer well coverage is not dense enough and undeveloped oil-bearing zones (lenses) remain in the spaces between the wells. All of the above indicates that the field is unevenly developed, and certain oil reserves are remaining there. In the period of 2000-2006 and since 2015 the methods of horizontal well drilling and injection of technical water into the productive layer were applied to increase the oil recovery factor. In the result, production (oil and gas) noticeably increased. Application of the complex hydrodynamic methods in the future will enable us to significantly increase the remaining oil production from the stratigraphically lower, water-cut horizons of the productive suite.

Seismic attributes and quantitative reverse reservoir simulations of shallow-marine eocene sedimentary fairways, extensional rifting Indus onshore petroleum system, southern Pakistan: Implications for hydrocarbon exploration

Quantitative reservoir characterization plays a vital role in exploring carbonate depositional systems. The subsurface vertical and lateral changes in the tectonics and sea level adversely impact the signatures of band-limited seismic data. The seismic amplitudes are very sensitive to these vertical and lateral tilts of the stratigraphy and sedimentology of the subsurface stratigraphic layers. The dynamical tectonic-based fluctuating sea creates vital seismic expressions of high amplitude. These seismic expressions can inversely infer the dense-fractured depositional parasequences, thickness, porosity, and lithological change for the accommodation space and the sedimentary influxes for the development of petroleum fairways. Hence, it becomes very challenging to predict whether the producing zone for hydrocarbons sourced from the wet-gas-bearing zones is a potential zone for hydrocarbon exploration or a light oil-bearing zone (WGZ or LOZ). Therefore, the development of reverse quantitative simulations of parasequences within the extensional regimes is always a very complex research problem during stratigraphic-based fuel exploration of thin-bedded carbonate systems. This research utilizes the spectral-based amplitudes along with the instantaneous waveform-based temperature-porosity stratigraphic simulations (WTPS) on middle-Eocene carbonates (MCARB), Pakistan. 18-Hz amplitudes detect the gas-bearing stratigraphic prospect of 230 km2 on the northern flanks. The 18-Hz-based WTPS has predicted the parasequences within the complete petroleum systems. 24 m thick progradational and laterally continuous and fractured reservoirs are deposited within the wet-gas-bearing zones (WGZ) throughout a rapidly falling sea and succeeding growth at 175 °F and 28% porosity pseudo-wells. Deposition of 15–20 m thick deep-marine transgressive shale has been completed throughout a rising sea level at a temperature of 125 °F and 12% poor porosity. There is a lateral change in the dense-fractured then low-velocity from 2.1 to 1.8 g/cc and 2670 to 1690 ms/s predicted by WTPS from the NE to SW zones of MCARB, which impacts the presence of 1.5 km of the regionally developed pure stratigraphic trap. The WGZ has a vertically resolved thickness of 24 m, which is appreciably above the resolvable magnitude threshold of 23 m. Hence, it implies that the extensive fall of sea level followed by the regional development of the accommodation space for the accumulation of WGZ carbonate stratigraphic units is at its accurate location within the sub-surface reservoir system. This workflow has robust consequences towards exploring petroleum systems, Onshore Pakistan. Hence, this workflow may serve as an exemplary move towards regional analogues aimed at world carbonate in extensional regimes.

Machine-Learning Algorithms Optimize Drilling-Center Locations Offshore

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 211772, “Optimizing Future Drilling-Center Locations Using Advanced Analytics and Machine-Learning Algorithms Offshore Abu Dhabi,” by Rail Salimov, Benoit Jaffres, and Jamal Alblooshi, ADNOC, et al. The paper has not been peer reviewed. _ Long-term development planning requires infill drilling. Because of the limited number of slots in the offshore environment, new drilling centers (wellhead towers) are required. Optimized location of drilling centers can play a major role in reducing drilling expenses. Two main challenges related to wellhead-tower placement are discussed in the complete paper: first, where to place future drilling centers based on subsurface coordinates and drilling constraints; and second, how to allocate dozens of subsurface targets to multiple drilling centers. The drilling-center placement optimization algorithm developed by the authors is based on multiple optimization parameters related to well cost. Introduction To finalize well trajectories, and thus best manage well costs, before the drilling phase, the following detailed analyses are required: - Evaluation of horizontal trajectory in terms of landing point and total depth - Optimization of horizontal drain length - Optimization of the horizontal drain length in the best oil-bearing zone - Torque-and-drag evaluation - Anticollision assessment - Selection of optimal completion accessories However, for most giant offshore fields with complex plans, hundreds or even thousands of infill developments are required. Definition of optimal locations and allocations of wells to drilling centers will require multiple iterations of already tedious work. An alternative methodology is described in the complete paper that allows finalization of future facility placement with the use of open-source machine-programming tools and applied mathematics. The presented methodology was deployed successfully on two major offshore fields where current production is connected through wellhead towers. Evolution of the development plan and the ramp-up of production means that additional drilling is planned during the next 10 years. Approximately 100–150 development wells are planned to be drilled from yet-to-be-constructed wellhead towers. One of the main challenges in achieving cost efficiency is effective placement of the new towers to minimize the total drain length of all development wells. The methodology covers the two most important aspects of facility construction that play vital roles in optimization of capital investment in facility expansions of offshore oil and gas fields. These aspects are optimized allocation of future wells to drilling centers and placement of those drilling centers.

Field and Experimental Investigations on the Effect of Reservoir Drill-In Fluids on Penetration Rate and Drilling Cost in Horizontal Wells.

In this study, the reservoir drill-in fluid (RDF) was modified and optimized to improve the rheological properties and reduce the filtration properties of the drilling fluid used for drilling the oil-bearing zone horizontally. In polymer science, degradation generally refers to a complex process, by which a polymeric material exposed to the environment and workload loses its original properties. Degradation is usually an unwanted process. In certain cases, however, controlled polymer degradation is useful. For instance, it can improve the processability of the polymer or can be used in recycling or natural decomposition of waste polymer. Thus, the drilling fluid and parameter data of 30 horizontal wells that were drilled in the south of Iraq were collected using several reservoir drill-in fluids (RDFs), including FLOPRO, salt polymer mud (SPM), non-damaged fluid (NDF), and FLOPRO_PTS-200 (including the polymer thermal stabilizer). The obtained results showed that the polymer temperature stabilizer (PTS-200) enabled reducing the filtration rate by 44.33% and improved the rheological properties by 19.31% as compared with FLOPRO. Additionally, the average cost of NDF and SPM drilling fluids for drilling the horizontal section of the selected wells is around USD 96,000 and USD 91,000, respectively. However, FLOPRO-based drilling fluid showed less cost for drilling the horizontal section, which is USD 45,000.

Seismic Interpretation and Petrophysical Analysis for Evaluation of Ataga Field, Onshore Niger Delta, Nigeria

The majority of geophysical survey in hydrocarbon exploration and production sector is driven by the ability to describe reservoirs. This research is aimed at describing the interpretation and petrophysical analysis of the reservoirs in Ataga field Niger Delta using a combination of seismic and well-log data. The Ataga Field in the Niger Delta was subjected to 3-D seismic interpretation and petrophysical study to perform comprehensive structural interpretation, prospect evaluation, and volumetric calculation. Two reservoir windows “1” and “2” were identified and correlated from four wells ATA 10, ATA 11, ATA 5 and ATA 7. Detailed evaluation was done on well ATA 11 since it is the only well that has sufficient data for both qualitative and quantitative interpretation. Structural interpretation for inline 5731 revealed fifteen faults on the seismic vertical section through ATA 11, most of which are antithetic faults while the rest are synthetic faults. Top and base of each reservoir window was delineated from the well. Result of the petrophysical assessment of reservoir A, B and C for ATA 11 revealed that the porosity values range from (24 -29) % which are indicative of very good to excellent porosity value according to Rider (1996). While the permeability values range from (1887-2582) mD were obtained from the three reservioir A, B and C of ATA 11 which depict very good to excellent reservoir units. Since, .all of the wells were discovered to have hydrocarbon-bearing reservoir formations (sandstones), the integration of structural interpretation and well logs have successfully revealed that the reservoirs are mostly oil-bearing zones.

Reservoir characterization of the upper Turonian – lower Coniacian Khasib formation, South Iraq: Implications from electrofacies analysis and a sequence stratigraphic framework

The Upper Turonian – Lower Coniacian Khasib Formation is a significant hydrocarbon reservoir in southern Iraq. The present study integrates multiple data sets of 33 wireline wells, available core, and thin sections from two important oilfields: Amara and Noor to interpret the lateral and vertical facies changes and petrophysical reservoir variability within a sequence stratigraphic framework. Cluster analysis based on well log data including gamma ray, sonic, neutron, bulk density data were used to classify the Khasib Formation into five carbonate electrofacies and determine the petrophysical properties. These electrofacies consists of compacted marly, argillaceous, chalky, porous, and vuggy limestones which are interpreted to have been deposited in a ramp setting. Sequence stratigraphic analysis shows that the Khasib Formation consists of two third-order sequences with three sequence boundaries refer to global sea-level changes: the Mishrif-Khasib regional unconformity, the intra-Khasib unconformity, and the Khasib-Tanuma formational boundary. Each sequence consists of a transgressive system tract (TST) and a highstand systems tract (HST) which are separated by a maximum flooding surface (MFS). Reservoir correlation and mapping of the Khasib Formation in both the Amara and the Noor oilfields show the best important oil-bearing zones are located dominantly in transgressive system tracts (TSTs).

Petrophysical characterization for Thebes and Mutulla reservoirs in Rabeh East Field, Gulf of Suez Basin, via well logging interpretation

The current work assesses the sandstones of the Mutulla Formation as well as the limestone of the Thebes Formation for being promising new oil reservoirs in Rabeh East field at the southern portion of the Gulf of Suez Basin. This assessment has been achieved through petrophysical evaluation of wireline logs for three wells (RE-8, RE-22 and RE-25). The visual analysis of well logs data revealed that RE-25 Well is the only well demonstrating positive criteria in five zones for being potential oil reservoirs. The favourable zone within Thebes Formation locates between depths 5084 ft and 5100 ft (Zone A). However, the other positive zones in Mutulla Formation occur between depths: 5403.5–5413.5 ft (Zone B), 5425.5–5436 ft (Zone C), 5488–5498 ft (Zone D) and 5558.5–5563.5 ft (Zone E). The quantitative evaluation shows that the Zone A of Thebes Formation is the best oil-bearing zone in RE-25 Well in terms of reservoir quality since it exhibits lowest shale volume (0.07), minimum water saturation (0.23) and lowest bulk volume of water (0.03). These limestone beds include type of secondary porosity beside the existing primary porosity. On the other hand, the sandstones of Mutulla Formation in RE-25 contain four reservoir zones (B, C, D and E) with the total net pay thickness of 35.5 ft. Moreover, the obtained results revealed that it is expected for zones B, C and D to produce oil without water but Zone E will produce oil with water.

Evaluation of Petrophysical Properties Using Well Logs of Yamama Formation in Abu Amood Oil Field, Southern Iraq

The petrophysical analysis is very important to understand the factors controlling the reservoir quality and production wells. In the current study, the petrophysical evaluation was accomplished to hydrocarbon assessment based on well log data of four wells of Early Cretaceous carbonate reservoir Yamama Formation in Abu-Amood oil field in the southern part of Iraq. The available well logs such as sonic, density, neutron, gamma ray, SP, and resistivity logs for wells AAm-1, AAm-2, AAm-3, and AAm-5 were used to delineate the reservoir characteristics of the Yamama Formation. Lithologic and mineralogic studies were performed using porosity logs combination cross plots such as density vs. neutron cross plot and M-N mineralogy plot. These cross plots show that the Yamama Formation consists mainly of limestone and the essential mineral components are dominantly calcite with small amounts of dolomite. The petrophysical characteristics such as porosity, water and hydrocarbon saturation and bulk water volume were determined and interpreted using Techlog software to carried out and building the full computer processed interpretation for reservoir properties. Based on the petrophysical properties of studied wells, the Yamama Formation is divided into six units; (YB-1, YB-2, YB-3, YC-1, YC-2 and YC-3) separated by dense non porous units (Barrier beds). The units (YB-1, YB-2, YC-2 and YC-3) represent the most important reservoir units and oil-bearing zones because these reservoir units are characterized by good petrophysical properties due to high porosity and low to moderate water saturation. The other units are not reservoirs and not oil-bearing units due to low porosity and high-water saturation.

CO2-responsive agent for restraining gas channeling during CO2 flooding in low permeability reservoirs

Hydraulic fracturing and CO2 flooding are extensively used in low-permeability reservoirs to enhance oil recovery (EOR). However, due to the serious heterogeneity of the formation, CO2 is prone to break through the oil-bearing zone prematurely, which leads to the decrease of the swept volume. Conventional blocking agents have some defects such as difficult injection, poor stability and weak sealing strength. Therefore, it is critical to developing a new type of channeling blocking agent for low-permeability fractured reservoirs. In this study, ten kinds of chemicals with tertiary amino groups are filtered for the most effective CO2-responsive agent, which turns out to be N, N-Dimethyl erucamide tertiary amine (DMETA). Subsequently, rheological properties, response performance, and microstructure of the optimum agent are researched systematically through rheological experiments, CO2-response processes and Cryo-TEM. The results show that the viscosity of the DMETA solution can increase to nearly 605,700 mPa·s by self-assembly into wormlike micelles (WLMs). And it can be reversibly circulated between low viscosity and high viscosity by alternately introducing and removing CO2, which endows it with the ability to healing its viscoelasticity under an environment full of CO2. A new method based on optical microrheology is proposed to study the viscoelastic properties of WLMs under no external force. The experiments prove that the network structure is not stable after formation, but remains in a continuous process of separation and reconstruction as “a living polymer.” Furthermore, the plugging performance and EOR capacity are evaluated using fractured tight cores. The experiments demonstrate that the optimum agent can effectively restrain gas channeling and enhance recovery factor by 21.7%. We expect our work can provide insights for the synthesis of CO2-responsive WLMs and guidance for retarding gas channeling during CO2 flooding in low permeability reservoirs.

To the issue of oil and gas potential in the decompression zones of the Dnieper-Donets depression

Formulation of the problem. Currently, interest in the foundation as a gas and oil field facility has increased significantly. The low efficiency of oil and gas exploration in the basement rocks is usually explained by the absence of a generally accepted hypothesis about the genesis of oil and gas and as a result of migration and accumulation of hydrocarbons. One of the main factors of accumulation is the presence of decompression zones of the foundation, as potential hydrocarbon traps. The article is devoted to the problem of identifying oil and gas bearing zones of foundation decompression. Analysis of recent research and publications. A number of scientific articles on the composition, age, structure and oil and gas potential of the foundation are analyzed. The first step in identifying decompression zones is to conduct gravimetric and magnetic surveys and apply various techniques to interpret the resulting mathematical model of the wave field pattern in order to localize the sources of its anomalies. Identification of previously unresolved parts of a common problem. In order to save money when conducting prospecting and exploration for oil and gas, the foundation proposes an improvement in the methodology for separating gas-bearing “vaulted” parts of decompression zones. Formation of the purpose of the article. The aim of the work is to establish a seismic pattern of anomalies in the geophysical fields of the base decompression zones. The object of research is the zone of decompression of the foundation on the northern side of the Dnieper-Donets depression. The subject of the study is a seismic drawing of the anomaly of the geophysical field of the gas-bearing zone of decompression of the foundation of the Rozsoshinsk structure. Report of the main material. The article analyzes a few materials to identify areas of base decompaction in various oil and gas regions. It was found that for localization of decompression zones, the Berezkin “singular points” method and the correlation method of separation of geophysical anomalies are most effective. The essence of these methods is a kind of filtering of field anomalies, where against the background of the "structural" factor, one can distinguish the "non-structural factor", i.e. decompression zone. This zone in wave fields (∆g and ∆Т) is fixed by a seismic pattern, where minima are usually fixed over hydrocarbon accumulations in relation to contouring maxima. Based on the results of the application of these methods, the structure-testing ground of the gas-bearing decompression zone is established. As an illustrative example of the successful localization of ∆g and ∆Т, data are presented on modeling the foundation softening zone in one of the oil and gas regions of the northern side of the Dnieper-Donets depression.

Well logs reconstruction by DCT based IPRM and genetic algorithm

Hydrocarbon production from a particular layer requires careful identification of the stratigraphic boundaries and choosing the right perforation against the face of oil-bearing intervals.Excessive perforations may cause unwanted water production from adjacent layers. Nowadays, clustering of well log data through various methods such as self-organized maps (SOM) helps to find hydrocarbon intervals from other layers. SOM is a type of artificial neural network, which uses the non-monitored learning of the multi-dimensional logging observations to create a 2D clustering map. However, the noisy response data greatly reduces accuracy of the methods by increasing correlation of different data groups. Although spectral such as discrete wavelet transform (DWT) can reduce correlation and reconstruct the logs that no longer fluctuate as before, they have two major limitations. First, responses smooth the edge-shape behaviors in the log curve while preserving them is essential for recognizing the stratification changes. The second limitation is the generation of spurious oscillations in the reconstructed signals at the vicinity of the edges, known as the Gibbs phenomena. At the present study to overcome these problems, we use, for the first time, the inverse polynomial reconstruction method (IPRM) based on discrete cosine transform (DCT) to attenuate the random noise by projecting the data first on the orthogonal bases derived from Gegenbauer polynomials and then on cosine space. The de-noising level depends on the minimum description length (MDL) criterion that minimizes the distance of all the corresponding coefficients between the original and reconstructed signals during 100 iterations. However, in the proposed method, we use a genetic algorithm to decide quickly and optimally the coefficients of DCT and Gegenbauer required in real data reconstruction related to one of the oil fields in southwestern Iran. The results show that this preprocessing procedure compared to DCT and DWT, increases the success rate of the SOM method for oil-bearing zone detection based on evidence such as core drilling and perforation data. At the same time, the computational time is much shorter than the usual IPRM. The optimal perforation subsequent to this study may cut unwanted water production from adjacent layers. Such water with radioactive nature, in addition to causing environmental problems, greatly increases the cost of extraction operations due to the need to install surface-separating equipment.

Geophysical appraisal and oil potential for Rudeis Formation at West Hurghada area, southern Gulf of Suez: detection of stratigraphic trap

This study suggests a suitable stratigraphic trap in West Hurghada area at the southwest Gulf of Suez Basin based on the interpretation of seismic and well logging data. This stratigraphic trap formed by lateral and vertical facies change from porous limestone to massive marl within Rudeis Formation. The examination of the available mud logs revealed that Rabeh East-22 Well displays positive criteria opposite a thick limestone interval between depths 4550 and 4630 ft (zone 1) to be considered a potential oil-bearing zone. This thick limestone bed did not appear in the other examined wells (Nageh-1, Rabeh East-8, and Rabeh East-25) which are so close to Rabeh East-22 Well confirming the lateral facies change. The expected stratigraphic trap on seismic data extends for about 1.5 km in north-south direction and for 0.75 km in east-west direction throughout the study area. The quantitative petrophysical analysis for this thick limestone interval (zone 1) in Rabeh East-22 Well indicated that the interval between 4569 and 4595 ft (26-ft thick) represents the most promising interval within zone 1. This promising interval reflects good reservoir characteristics with average hydrocarbon saturation of 53%, average shale volume of 21%, average total porosity of 20%, average effective porosity of 15%, and average bulk volume of water of 0.07.

Evaluation of Nubia sandstone reservoir as inferred from well logging data interpretation for Rabeh East-25 well, Southwest Gulf of suez, Egypt

The present study interprets well log responses obtained from the Nubia sandstone in the Rabeh East-25 Well, Southwest Gulf of Suez in Egypt. The reservoir characterization of the Nubia sandstone reservoir demonstrates that it has excellent potential for hydrocarbon production. Based on the qualitative interpretation of available well log data, the examined well through the Nubia sandstone succession has been subdivided into four zones. The hydrocarbon-bearing zones include zone II, a shaly reservoir occurs between depths of 5610 and 5631 ft, and zone IV, characterized by a clean sandstone reservoir is located between depths of 5656 and 5685 ft. When both zones are combined, the net pay thickness of the Nubia sandstone reservoir in the studied well reaches 60 ft. The petrophysical parameters of the oil-bearing zones were calculated to determine their reservoir properties, including their fluid saturation, shale volume, porosity, bulk volume of water and permeability values. The shaly sandstones in zone II have low water saturation (17–47%), low shale volume (0–50%), high total porosity (18–23%) and high effective porosity (8–23%) values. However, the clean sandstones in zone IV display lower water saturation (8–38%), high total porosity (17–22%) and high effective porosity (14–22%) values. Both zones exhibit high permeability values (usually above 50 MD), and their values of the Movable Oil Index are lower than 0.7reflecting the movability of the preserved oil. The constructed Buckles plots for the two zones indicate that the points which follow 0.04 and 0.05 BVW hyperbolas in zone II and points track 0.02, 0.03 and 0.035 BVW hyperbolas in zone IV will produce oil without water. The relative permeability to oil is usually less than 1.0, and the relative permeability to water is less than 0.01. Additionally, the water contents accompanying production are relatively low, i.e., they vary between 0 and 20%, thus reflecting the good reservoir quality of both zones.

Regional patterns in the geochemistry of oil-field water, southern San Joaquin Valley, California, USA

Chemical and isotopic data for water co-extracted with hydrocarbons in oil and gas fields are commonly used to examine the source of the formation water and possible impacts on groundwater in areas of oil and gas development. Understanding the geochemical variability of oil-field water could help to evaluate its origin and delineate possible contamination of shallow aquifers in cases where oil-field water is released to the environment. Here we report geochemical and multiple isotope (H, C, O, Sr, Ra) data from 22 oil wells, three sources of produced water that are disposed of in injection wells, and two surface disposal ponds in four oil fields in the southern San Joaquin Valley, California (Fruitvale, Lost Hills, North and South Belridge). Correlations between Cl and δ18O, as well as other ions, and gradual increases in salinity with depth, indicate dilution of one or more saline end-members by meteoric water. The saline end-members, represented by deep samples (610 m–2621 m) in three oil-bearing zones, are characterized by NaCl composition, near-seawater Cl concentrations (median 20,000 mg/L), enriched δ18OH2O (median 3.4‰), high ammonium (up to 460 mg-N/L), and relatively high radium activity (226Ra+228Ra = 12.3 Bq/L). The deepest sample has low Na/Cl (0.74), high Ca/Mg (5.0), and low 87Sr/86Sr (0.7063), whereas the shallower samples have higher Na/Cl (0.86–1.2), Ca/Mg near 1, and higher 87Sr/86Sr (∼0.7083). The data are consistent with an original seawater source being modified by various depth and lithology dependent diagenetic processes. Dilution by meteoric water occurs naturally on the east side of the valley, and in association with water-injection activities on the west side. Meteoric-water flushing, particularly on the east side, results in lower solute concentrations (minimum total dissolved solids 2730 mg/L) and total radium (minimum 0.27 Bq/L) in oil-field water, and promotes biodegradation of dissolved organic carbon and hydrocarbon gases like propane. Acetate concentrations and δ13C of dissolved inorganic carbon indicate biogenic methane production occurs in some shallow oil zones. Natural and human processes produce substantial variability in the geochemistry of oil-field water that should be considered when evaluating mixing between oil-field waters and groundwater. The variability could result in uncertainty as to detecting the potential source and impact of oil-field water on groundwater.

Characterizing the Middle–Upper Miocene Reservoir Intervals of a Producing Field in the Niger Delta Basin: An Application of Facies, Sequence Stratigraphic and Petrophysical Analyses

Well log and core data were used to carry out detailed facies, sequence stratigraphic, and petrophysical analyses of the “Iota field” in the onshore Niger Delta Basin. The aim was to recognize facies distribution, environments of deposition, stratigraphic framework, reservoir continuity, and property distribution for better understanding of reservoir characteristics across the field. Sedimentological evidence reveals the occurrence of fifteen lithofacies, which were further classified into eight facies associations. The facies associations depict deposition in the offshore, offshore transition, lower shoreface, upper shoreface, estuarine channel, tidal channel, and fluvial channel environments. Sequence stratigraphic analysis reveals the occurrence of three maximum flooding surfaces and three sequence boundaries, which reflect series of transgressive and regressive episodes during the Serravallian–Tortonian age. Two depositional sequences comprising lowstand system tract, transgressive system tract, and highstand system tract packages were recognized. The sand and shale of the fluvial, tidal, estuarine, shoreface and offshore deposits, constitute the reservoir and seal/source rock packages. Correlation indicates that the reservoir packages have good lateral continuity, except where channel incision has occurred. Petrophysical analysis shows that the reservoir units have fair-to-good porosity and good- to-excellent net-to-gross qualities. Dominance of oil-bearing zones were detected at shallow to deeper interval at the northern section of the study area, with few gas-bearing intervals occurring at the intermediate intervals of the southern section. Overall, integrated analytical approach has provided more insight into the facies and reservoir quality distribution, thus reducing subsurface reservoir uncertainties.

Modeling formation resistivity changes due to invasion and deformation during initial leak-off test build-up

Leak-off tests (LOTs) are performed to determine the strength of a newly drilled formation below a cased interval and to characterize the upper bound of mud weight that can be safely used while drilling the next section, without risk of formation breakdown and lost circulation. In an LOT, drilling mud is pumped into the wellbore, causing the wellbore pressure to increase and exceed the formation pore pressure. During the initial LOT build up, excess pressure in the wellbore causes the surrounding rock to deform and mud filtrate to invade into the formation via porous flow. In this paper, change in formation resistivity around a wellbore during initial LOT build-up has been investigated. Invasion is modeled assuming two-phase radial Darcy flow and deformation using a 3D finite element model. Invasion may result in an exchange of conductive ions between water-based drilling mud and formation water both by diffusion in the direction favored by the concentration gradient of the ions and by convective transport. This process is incorporated into the model by solving the radial convection-diffusion equation for the aqueous phase using a finite difference method. Archie's law is used to determine the formation resistivity. Findings show that the direct effect of deformation on porosity, therefore on formation resistivity during an LOT, is negligibly small even when the formation rock is highly compressible with compressibility in the order of 10−3 psi−1. While salinity solely controls formation resistivity during an LOT conducted in a fully water-saturated interval, water saturation change and salinity change compete to produce a compound effect on formation resistivity of an oil-bearing zone where water saturation varies dynamically due to displacement of formation fluids. Unlike compressibility, the effect of permeability on formation resistivity response is found to be evident and readily observable. While analyzing the formation resistivity responses at various depths of investigation (DOIs), it is found that the effect of DOI on resistivity response can be useful in studying invasion and assessing formation damage during an LOT. In addition to this, through comparing time-lapse resistivity logs at multiple DOIs during an LOT with numerically synthesized resistivity responses, the model promises a novel approach towards determining the permeability of a freshly drilled and unaltered interval.

Поиск и изучение зон нефтенакопления, контролируемых рифами, на основе применения комплекса региональных критериев

Поиск и изучение зон нефтенакопления, контролируемых рифами, на основе применения комплекса региональных критериев