Reservoir Units Research Articles

Implication of well logs for evaluation of a carbonate reservoir: an example, the Sarvak Formation, Zagros Basin, SW Iran

Petrophysical evaluation of well log data of the Mid Cretaceous rocks (Upper part of the Sarvak Formation) were conducted for the Marun oil field. Rock and fluid volumetric indices, such as porosity type and distribution, water saturation, and lithology, were estimated from density, resistivity, neutron porosity, sonic and gamma ray logs. Petrophysical parameters including shale volume (Vsh), total porosity (PHT), effective porosity (PHE), water saturation (Sw), hydrocarbon saturation (Sh) and lithology were calculated. Matrix Identification (MID), M-N, NPHI- RHOB, NPHI- DT cross-plots indicated that the Sarvak Formation is mainly composed of carbonate lithology. Results also indicated that shale volume varies between 0.1% and 23.3%; total and effective porosities are between 0.8% and 47.2% and between 0.1% and 45.1%, respectively. Various primary and secondary porosities do exist in the Sarvak Formation. Majority of the porosities are preferentially developed in the middle part of this oil field. Water saturation is between 2% and 100%. The results reveal that the reservoir characterization of the Sarvak Formation is very variable and fluctuating from poor to good reservoir units. Apparently, Sw increase toward the center of the reservoir and eastward as well. This is probably in part controlled by fractures that are preferentially concentrated in the middle part of the anticline.

Interpretation of Nitrogen Isotope Profiles in Petroleum Systems: A Review

Bulk sedimentary nitrogen isotope profiles are often used as proxies for depositional redox conditions, nitrogen cycling, and nutrient uptake in modern and ancient marine systems. The general preference in terms of analysis is that the sediments measured have undergone minimal thermal alteration, as post-depositional processes might have altered the initial δ15N signal, thus complicating the interpretation of these records. Although not a traditional proxy for petroleum evaluation purposes, recently the use of nitrogen isotopes in petroleum systems has been investigated as potential proxies to reconstruct paleoenvironmental conditions such as redox, and for organic matter evaluation. In this paper we review the use of nitrogen isotope data in petroleum systems, their interpretations, and factors that may complicate their use as proxies. We review the evidence for nitrogen isotopic fractionation during diagenesis, catagenesis, and fluid migration as determined by lab experiments, and how these might impact interpretation of δ15N data in petroleum systems. We also analyze the use and interpretation of δ15N data from petroleum-producing reservoir units, including unconventional reservoirs and lacustrine basins. Lastly, we discuss potential applications for nitrogen isotopes in petroleum systems with regards to their use as both geochemical proxies and as tools to evaluate petroleum reservoirs.

Exhumation filling and paleo-pasteurization of the shallow petroleum system in the North Slope of the Biyang Sag, Nanxiang Basin, China

Deposits of biodegraded heavy oils are commonly encountered within the Eocene reservoir units in the North Slope of the Biyang Sag, Nanxiang Basin, eastern China. Oil physical property data and biomarkers show that these biodegraded oils occur only above burial depth equivalent to about 62 °C. This is much cooler than the cutoff temperature of biodegradation (about 80 °C), which has been interpreted within a complex petroleum evolution history that includes an early oil filling, significant uplift, a second phase of filling, and late-stage biodegradation.We use a new combination of fluid-inclusion analysis and calcite LA-ICP-MS U–Pb dating to obtain a temporal constraint on oil migration in the siliciclastic reservoirs. Two generations of oil inclusions, each showing a distinct fluorescence color (yellow and blue-green), were trapped before and after quartz cementation, respectively, which indicates multi-stage oil charge events. The early oil charge, marked by hydrostatic conditions and low-salinity pore waters, occurred during the late Eocene to early Oligocene burial period, corresponding to peak oil generation by basin modeling. The reservoirs were then refilled at a moderate-overpressure regime by higher maturity oils accompanied by high-salinity waters during the early Miocene exhumation. Reservoir sandstone-hosted, yellowish calcite veins, characteristic of 13C depletion and oil odor, contain primary blue-green fluorescent oil inclusions and bitumens, consistently pointing to precipitation from petroleum-derived fluids. LA-ICP-MS U–Pb dating of these vein calcites yields a U–Pb age of 19.6 ± 1.2 Ma, representing the latest timing of the second oil charge event in the North Slope. The isotope age of the fissure calcites near fault zones coincides well with the indirect age estimate based on fluid-inclusion homogenization temperature and the regional uplift stage. This scenario suggests that the Miocene tectonic compression not only triggered the recharge of oils but also facilitated the initiation or re-activation of faults that acted as conduits for oil migration.Reconstructed burial models show a continuous burial followed by significant uplift and erosion in this region. Since some reservoirs with maximum paleotemperature less than 80 °C were not sterilized during burial, the contained oils suffered from extensive biodegradation, presumably during the middle Miocene to present day. Thus, the shallower shutoff depth of biodegradation in this region was most likely ascribed to the paleo-pasteurization during burial, as opposed to later fresh oil replenishment or influx of shallow aquifers.

Paleogeography of the West Siberian Sedimentary Basin in the Late Bajocian–Bathonian

Abstract —The paper presents results of regional paleogeographic reconstructions of the West Siberian sedimentary basin in the Late Bajocian–Bathonian. Regional paleogeographic maps of the Yu4, Yu3 and upper part of the Yu2 reservoir units were constructed and described for the first time ever. The implemented approach provided insights into the evolution of paleolandscapes and highlighted the deposition features of the Upper Tyumen Subformation and Malyshev Formation in the different parts of the West Siberian basin. The compilation of paleogeographic maps was based on the electrofacies analysis performed for individual parts of the Malyshev stratigraphic horizon, with regard to the core description materials, paleontological, sedimentological, geochemical data and other. The paleogeographic control of the reservoir’s formation in the Bathonian regional reservoir is discussed.

Prioritization of Noise Control Solutions in an Oil Refinery Using the Noise Control Priority Index

Background: It is essential to decide on where to allocate available resources and identify priorities in noise control. Objectives: This study was performed to prioritize noise control solutions in various units of an oil refinery using the noise control priority index (NCPI). Methods: This cross-sectional study was conducted in an oil refinery in 2019. The standard of ISO 91612 was applied in the first stage to assess workplaces and determine the values of the noise pressure level (SPL). The activity of stations and the duration of workers’ presence in these stations were determined via interviews with the supervisors and senior personnel of each unit. The NCPI value in various units was determined using three variables, including the number of exposed people, exposure duration, and the weighting factor related to the sound pressure level (SPL). Finally, units were prioritized based on the final NCPI value. Results: Totally, 10 units were assessed based on the ISO9612 standard. The results revealed that 8.09% of the assessed stations were in the safe zone, 62.24% in the warning zone, and 29.66% in the hazard zone. The highest noise emission was related to the NTA unit (98 dB), and the lowest noise emission was observed in the spherical reservoir unit (84 dB). The NTA unit with 12 workers had the highest noise control priority index (1.25) among the units. Conclusions: The NCPI index makes it possible to appropriately prioritize noise control solutions in various industrial units and also implement technical and noise control plans in the oil and gas industries.

Sandstone reservoir zonation of the north-western Bredasdorp Basin South Africa using core data

This study delineates sandstone reservoir flow zones in the north-western Bredasdorp Basin, offshore South Africa, using conventional core porosity and permeability data. The workflow begins by integrating sedimentology reports and logs to identify lithofacies before evaluating petrophysical flow zones. Three lithofacies were classified as lithofacies 1, 2, and 3. Lithofacies 1 is a silty shale and bioturbated sandstone, lithofacies 2 is an interbedded sandstone and shale, with very fine sandstone with well-sorted grains, and is heavily cemented. Conversely, lithofacies 3 is a fine-to medium-grained sandstone with minor shale that is moderately cementation. Lithofacies 3 is ranked as the best reservoir rock, followed by lithofacies 2 and 1.Four independent reservoir zonation methods (permeability anisotropy, Winland r35 pore throat, flow zone indicator (FZI), and stratigraphic modified Lorenz lot (SMLP)) were applied to core samples from three wells (MO4, MO5, and MO6). The core samples predominantly had slight anisotropic permeability (0.5–1.1). The reservoir units were ranked into four flow zone categories as tight, very low, low, and moderate, based on porosity and permeability, and calculated parameters. Owing to the reservoir unit heterogeneity, the classification was based on average values. The moderate zone exhibits the best reservoir quality, which is associated with lithofacies 3. The very-low flow zone extends laterally to all wells. The tight zones showed fluid storage potential but no flow capacity. In general, the lithofacies do not always correspond to petrophysical flow zones. The moderate and low flow zones identified in well MO5 are comparable to previously identified flow zones (MO2, MO3, and MO1) in the Western Bredasdorp Basin.

Construction and application of an adapted rock physics template (ARPT) for characterizing a deep and strongly cemented gas sand in the Nam Con Son Basin, Vietnam

The Hai Thach field is one of the biggest gas and condensate producing fields in Vietnam. Located in the Nam Con Son Basin, offshore southern Vietnam, the field consists of multiple, stacked reservoir units, for which petrophysical characterization is challenging and a site-adapted rock physics template (ARPT) was proposed to solve this task. As reported in many publications, rock physics templates (RPTs) have been successfully applied for the characterization of shallow unconsolidated and weakly cemented reservoirs with cementation of less than 5% like in the North Sea or some other sites. However, the construction of RPT is very site-dependent. In this study, an approach of rock physical modelling, named the adapted stiff sand model (ASSM), was proposed to construct a site-adapted RPT of Vp/Vs versus acoustic impedance (AIP) for characterizing the upper part of Middle Miocene Sand in the Nam Con Son Basin, which is a 3.5-km deep and strongly cemented gas sand with 10% up quartz-overgrowth and clayey cementation. A key point in this approach was the use of a modified Biot-Gassmann's equation and in situ well log data to calculate the dry moduli of reservoir rock frame. As a result, the elastic and petrophysical parameters of this upper MMS sand, named as MMF30, are well evaluated, i.e., AIp from 9000 to 11,000 m/s*g/cc, Vp/Vs from 1.65 to 1.8, porosity from 12 to 16%, and gas saturation from 50% up, which match well with the core data and were used further in a prestack elastic inversion of a seismic inline that could map well the multiple stacked gas zones of the study reservoir. The rock physical modelling approach in this study could help characterize successfully deep and highly-cemented clayey gas sands in the Nam Con Son Basin.

Delineation of reservoir channels by different seismic attributes and geobody extractions for robust volumetric estimation, Saffron Field, offshore Nile Delta, Egypt

The Nile Delta Basin is a major gas province. Commercial gas discoveries there have been proven mainly in Pleistocene to Oligocene sediments, and most discoveries are within sandstone reservoirs. Three-dimensional seismic data acquired over the basin have helped greatly in imaging and visualization of stratigraphy and structure, leading to robust understanding of the subsurface. Channel fairways serve as potential reservoir units; hence, mapping channel surfaces and identifying and defining infill lithology is important. Predicting sand distribution and reservoir presence is one of the key tasks as well as one of the key uncertainties in exploration. Integrating state-of-the-art technologies, such as including 3D seismic reflection surveys, seismic attributes, and geobody extractions, can reduce this uncertainty through recognition and accurate mapping of channel features. In this study, seismic attribute analysis, frequency analysis through spectral decomposition (SD), geobodies, and seismic sections have been used to delineate shallow Plio-Pleistocene El Wastani Formation channel fairways within the Saffron Field, offshore Nile Delta, Egypt. This has led to providing more reliable inputs for calculation of volumetrics. Interpretation of the stacked-channels complex through different seismic attributes helped to discriminate between sand-filled and shale-filled channels and in understanding their geometries. Results include more confident delineation of four distinct low-sinuosity channelized features. Petrophysical evaluation conducted on five wells penetrating Saffron reservoirs included electric logs and modular dynamic test data interpretation. The calculated average reservoir properties were used in different volumetric calculation cases. Different approaches were applied to delineate channel geometries that were later used in performing different volumetric cases. These approaches included defining channels from root-mean-square amplitude extractions, SD color-blended frequencies, and geobodies, all calculated from prestack seismic data. The different volumetric cases performed were compared against the latest field volume estimates proven after several years of production in which an area-versus-depth input showed the closest calculated hydrocarbon volumes to the actual proven field volumes.

Determining static reservoir connectivity using noble gases

Determining the connectivity of fluids in hydrocarbon reservoirs is a key challenge during the appraisal stage. Such information is critical for assessing the economic viability and planning reservoir development. Although several tools exist to determine static connectivity and the fluid column organisation post-hydrocarbon emplacement, it is extremely difficult to determine the extent of the connectivity between fluids of different phases. Conventional connectivity studies on the Tormore field, West of Shetland Basin, UK have resolved the vertical connectivity of one well (T2) but have been unable to resolve further vertical or lateral connectivity. Here, we outline a new tool for assessing hydrocarbon connectivity by completing the first intra-field connectivity study of the noble gas composition (He, Ne, Ar, Kr and Xe) of fluids from individual reservoir units, allowing the resolution of both the vertical and lateral connectivity within the Tormore field. To achieve this, we obtain fluid samples from archived PVT vessels rather than from the wellhead or platform separators, allowing sampling of the individual reservoir units encountered during drilling. Our findings corroborate previous connectivity studies undertaken on the oil well, T2, confirming that the reservoir unit of T2-A is isolated from the lower reservoir units. We apply the same method to the gas well, T3, finding that unit T3-A is isolated from the lower reservoir units. In addition, we identify a previously unknown connection between the gas and oil phase that is separated by a poorly constrained fault. These findings confirm the effectiveness of using noble gas fingerprints to assess the connectivity of fluids in different phases, providing a new tool for understanding connectivity in hydrocarbon and non-hydrocarbon settings (e.g. Carbon, Capture and Storage).

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

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

Identification of the best correlations of permeability anisotropy for Mishrif reservoir in West Qurna/1 oil Field, Southern Iraq

At present, reservoir whether isotropy or anisotropy is taking more attention, particularly the difference in (porosity, permeability, and capillary pressure) associated with pore space. These differences are due to the original sediments and thus diagenetic changes. It has been found that common models are insufficient to predict reservoir performance and field management program design. Recovery factor (RF) is the main factor affecting the optimization process for any reservoir that is very sensitive to reservoir heterogeneity and hence an accurate vertical and horizontal permeability (Kv and Kh) distribution is required. A case study is represented in this paper aimed at vertical permeability estimation from horizontal permeability and porosity for Mishrif reservoir in west Qurna/1 oil field southern Iraq. This study has been accomplished by testing five models, harmonic averaging, Kozeny-Carman equation, Zahaf and Tiab, Iheanacho et al., and Fazelalav to determine vertical permeability and comparing the results with core data values. It is found that the models were used showed an accuracy variation between the units of Mishrif reservoir based on Mishrif full diameter cores from 20 wells. Four new correlations are obtained for mA, CRII, mB1, and mB2 units for Mishrif Reservoir in West Qurna/1 oil field. The correlation shows that the permeability is depending on porosity in the mA unit due to the homogeneity and the Mb1 unit has a higher anisotropy than the other units.

Application of improved data-driven diagnostics workflow based on coupled hydro-mechanical model for stimulation candidate selection in a complex carbonate reservoir

The focus of the present paper is on utilizing a comprehensive diagnostics workflow that combines coupled hydro-mechanical modeling with production data-driven diagnostics for optimization of stimulation candidate selection process. Reservoir fluids production and production-induced depletion affect reservoir mechanical environment due to reduced pore pressure and increased effective stress and the consequent porosity and permeability reduction, depending on rock sensitivity to stress changes. The coupled formation damage index (CFDI) is implemented in the traditional stimulation candidate selection workflow to capture the effect of production-induced stress changes on the near-wellbore permeability over time. The top potential stimulation candidates are recognized based on heterogeneity index, static formation damage index, and the CFDI parameter. CFDI is a dynamic parameter for stimulation candidate selection through estimating time-dependent permeability changes induced by stress state and fluid pressure. Probabilistic type curves and decline curve analysis of candidate wells versus reservoir unit are also applied to complement the stimulation and production enhancement candidate selection.

CO2 storage capacity estimation under geological uncertainty using 3-D geological modeling of unconventional reservoir rocks in Shahejie Formation, block Nv32, China

Underground CO2 storage is a promising technology for mitigating climate change. In this vein, the subsurface condition was inherited a lot of uncertainties that prevent the success of the CO2 storage project. Therefore, this study aims to build the 3D model under geological uncertainties for enhancing CO2 storage capacity in the Shahejie Formation (Es1), Nv32 block, China. The well logs, seismic data, and geological data were used for the construction of 3-D petrophysical models. The target study area model focused on four units (Es1 × 1, Es1 × 2, Es1 × 3, and Es1 × 4) in the Shahejie Formation. Well logs were utilized to predict petrophysical properties; the lithofacies indicated that the Shahejie Formation units are sandstone, shale, and limestone. Also, the petrophysical interpretation demonstrated that the Es1 reservoir exhibited high percentage porosity, permeability, and medium to high net-to-gross ratios. The static model showed that there are lateral heterogeneities in the reservoir properties and lithofacies; optimal reservoir rocks exist in Es1 × 4, Es1 × 3, and Es1 × 2 units. Moreover, the pore volume of the Es1 unit was estimated from petrophysical property models, ranging between 0.554369 and 10.03771 × 106 sm3, with a total volumetric value of 20.0819 × 106 sm3 for the four reservoir units. Then, the 100–400 realizations were generated for the pore volume uncertainties assessment. In consequence, 200 realizations were determined as an optimal solution for capturing geological uncertainties. The estimation of CO2 storage capacity in the Es1 formation ranged from 15.6 to 207.9 × 109 t. This result suggests the potential of CO2 geological storage in the Shahejie Formation, China.

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.

Facies analysis and sequence-stratigraphic control on reservoir architecture: Example from mixed carbonate/siliciclastic sediments of Raha Formation, Gulf of Suez, Egypt

Mixed carbonate-siliciclastic systems are complex, and their development can sometimes be difficult to understand, given the various responses to each sub-environment to specific forcing, such as variation in sediment supply, climatic conditions, or available accommodation. This work integrates a detailed facies, associated with a depositional environment reconstruction, all of which is placed in a sequence stratigraphy framework in order identify the different controls on the reservoir architecture of the Upper Cretaceous (Cenomanian) Raha Formation, Gulf of Suez. The study utilized outcrop data from Gabal Ekma and Gabal Nezzazat, as well as subsurface data from five wells drilled through the October oil field.Our findings revealed that the Raha Formation succession is subdivided into eleven facies associations (FA) deposited as one depositional sequence. The Abu Had Member of the Raha formation consists of mixed siliciclastic/carbonate packages, arranged in a retrogradational stacking pattern, which were deposited during a period of pulsative shoreline regression. As a result of the transgression, the siliciclastic input in the system increased, potentially due to increased precipitation and weathering in the hinterland of the study area. The upper part of the Raha Formation belongs to the Mellaha Sand Member, which is mostly composed of bioturbated quartz arenite with bioturbation, and is the main reservoir in the October Field. It was deposited during a period of shoreline progradation as testified by its progradational stacking pattern.The reservoirs of the Raha Formation can be divided into five distinctive types (G, C, Q, P, and M), based on the factors controlling the permeability (Diagenetic criteria and compositional framework). The outcrops-subsurface correlations indicated that these reservoirs in the Mellaha Sand Member are laterally extensive, and thicken from 25 m in the SE to 91 m northwestwards. It is predicted that these reservoir intervals thicken toward the unexplored areas northern of October Field. Pore-filling cement and detrital matrix decreased the permeability and the reservoir quality to minimum while, the grain coating prevented the collapse of the reservoir quality. Pore-filling cement and detrital matrix decreased the permeability values, consequently lowering the reservoir quality to minimum, whereas the grain coating prevented the collapse of the reservoir quality, retaining the highest permeability values in the overall pore system. The aforementioned study provides significant insight into the understanding of depositional facies and sequence-stratigraphic control on reservoir architecture. Additionally, it provides insights for further exploration activities in these mixed carbonate/siliciclastic intervals along the Gulf of Suez and adjacent basin, and the improved understanding of these reservoirs units could also be applied to future Carbon Capture and Storage projects.

Pore Structure and Seal Capacity of Ilaro Formation Shales in the Eastern Dahomey Basin: Implications from Mercury Injection Capillary Pressure and Spontaneous Imbibition Analyses

A petrophysical evaluation of caprock pore characteristics and seal capacity is critical for geologic storage of CO2. In this study, integration of X-ray diffraction, mercury injection capillary pressure (MICP), and spontaneous imbibition analyses is used to evaluate the pore characteristics and seal capacity of shale samples from the Ilaro formation, which could serve as a seal for CO2 injected into the reservoir units of the eastern Dahomey basin. X-ray diffraction reveals the samples as clay-rich and early diagenetic, while spontaneous imbibition reveals pore connectivity heterogeneity. MICP analysis shows the samples as being characterized by a low breakthrough pressure and reveals the mesopore dominance with majority of pore volumes dominated by 5 to 10 nm-sized pore throats. Furthermore, high CO2 column heights are obtained from conversion of MICP data (at 20% saturation) for mesopore-dominated samples containing ankerite and kaolinite. The study reveals that should injected CO2 migrate upward from the reservoir units of the onshore eastern Dahomey basin, portions of the Ilaro formation may function as a good seal due to the mesopore mineralogical composition influence on the CO2–brine–rock interaction. This result should therefore serve as an important insight for future caprock sealing studies conducted on the onshore eastern Dahomey basin.

Wrench faulting and trap breaching: A case study of the Kizler North Field, Lyon County, Kansas, USA

The Kizler North Field in northwest Lyon County, Kansas, is a producing field with structures associated with both uplift of the Ancestral Rockies (Pennsylvanian to early Permian) and reactivation of structures along the Proterozoic midcontinent rift system (MRS), which contributed to the current complex and poorly understood play mechanisms. The Lower Paleozoic dolomitic Simpson Group, Viola Limestone, and “Hunton Group” are the reservoir units within the field. These units have significant vuggy porosity, which is excellent for field potential; however, in places, the reservoir is inhibited by high water saturation. The seismic data show that two late-stage wrench fault events reactivated existing faults. The observed wrench faults exhibit secondary P, R’, and R Riedel shears, which likely resulted from Central Kansas uplift-MRS wrenching. The latest stage event breached reservoir caprock units during post-Mississippian to pre-Desmoinesian time and allowed for hydrocarbon migration out of the reservoirs. Future exploration models of the Kizler North and analog fields should be based on four play concepts: 1) four-way closure with wrench-fault-related traps, 2) structural highs in the Simpson Group and Viola Limestone, 3) thick “Hunton Group,” and 4) presence of a wrench fault adjacent to the well location that generates subtle closure but not directly beneath it, which causes migration out of reservoirs. In settings where complex structural styles are overprinted, particular attention should be paid to the timing of events that may cause breaches of seals in some structures but not others. Mapping the precise location and vertical throw of the reactivated wrench faults using high-resolution seismic data can help reduce the drilling risk in analog systems.

Sedimentology, petrography, hydraulic flow units, and reservoir quality of the bayhead delta reservoirs: Late Messinian Qawasim formation, Nile Delta, Egypt

Bayhead sandstone reservoirs are challenging due to their complexities and limited examples. This paper focused on the characteristics of the bayhead sandstone reservoirs and their heterogeneities based on an integrated sedimentological, petrographical, and petrophysical aspects that controls the exploration and development for these reservoirs. This study uses an example from Manzala Gas Field (Eastern Nile Delta). In this study, the sedimentological and petrographical analyses are employed to understand the internal textures and architecture as well as meso- and microscopic heterogeneities of the bayhead delta reservoirs. This is integrated with the petrophysical characteristics and neural network techniques to characterize hydraulic flow units of bayhead delta reservoir using core, borehole image, and log data. The bayhead delta (bay fill) reservoir consists of five main sedimentary sub-environments include main distributary channel, proximal and distal crevasse splays, and crevasse channels, as well as bayhead delta lobes. The distributary channel represents the highest reservoir quality (units 3 and 4), followed by crevasse channel (unit 3 and 2); bayhead delta front lobes (units 2 and 1), and the lowest quality crevasse splays (unit 1). On microscale, the bayhead delta reservoir is characterized by wide spectrum of lithofacies from quartz arenite to feldspathic wacke. The depositional setting is important controlling factor on the reservoir quality that altered by the diagenetic processes. They include the anhydrite, quartz, carbonate, and chlorite, and kaolinite cements as well as dissolution of quartz, feldspar, bioclast, and carbonate grains. This study enhances the understanding of the of the bayhead distributive system heterogeneities and prediction of bay fill facies reservoirs to improve the exploration and development of that targets.

Petrophysical Characteristics and Reservoir Modeling of Mishirf Formation at Noor Oil Field, South of Iraq

Petrophysical properties of the Mishrif reservoir at Noor oil field have been done. Based on the interpretation of the open hole data from wells (No-1, 2, 3, 4, and 5) .Which have been calculated total porosity, effective and secondary porosity, water and hydrocarbon saturation (moveable and residual hydrocarbon) in invaded and uninvaded zones. Depends on the calculated of petrophysical properties, Mishrif Formation can be divided into eight reservoir units (RU-1 to 8), separated by eight caped rock units (barrier) (Bar-1 to Bar8). Three-dimensional reservoir model of oil saturation was constructed using the Petrel Software, (2009). Distribution of these petrophysical properties for each reservoir unit within the studied field has been done. The results showed that the best reservoir units are the second, fourth and first reservoir unit. It’s worth mentioned here that the heterogeneity of the thicknesses of these units and its individual direction. In addition, observed that the oil saturation increases towards the north of the field at the well (No-5) and the center of the field at the well (No-4).

Analytical and Numerical Analysis for Estimation Hydrocarbon in Place for Fauqi Oil Field

The Fauqi oil field is located about 50Km north-east Amara town in Iraq. This field has two producing reservoir units, the Asmari and the deeper Mishrif. Fauqi field is an anticline crossing the Iraqi-Iranian border and approximately 15 km long and 6 km wide.
 The Fauqi anticline is most probably segmented by several faults due to its location on Zagrous mountains area. Since, it is not possible to get full knowledge on the extent, orientation and segmentation of the field.
 Production data used for the Material Balance analyses is comprised of a record, by well, of monthly cumulative oil production for the period 01 May 1979 – 01November 2007. The field was shut in due to the Iran-Iraq war between September 1980 and August 1998 and due to Gulf war between March to December 2003.
 Twelve major modules, with different degrees of analytical sophistication have been used to prove oil initially in place (STOIIP) for Fauqi oil field throughout analyzing single well production history of FQ-8A. The accuracy for the obtained results has been investigated which show an acceptable degree of reliability.
 Performing the twelve of different analytical and numerical calculation for the production history of Fauqi oil well Fq-8A, may assist to reduce the uncertainties in the reservoir calculation of the STOIIP especially in Asmari reservoir which show a considerable degree of uncertainty between the analytical (multiple column model) and the (full tank model) and also with the numerical calculation.