Low Reservoir Quality Research Articles

Reservoir characterization of GABO field in the niger delta basin using facies and petrophysical analyses

This study investigates the GABO field in the onshore Niger Delta Basin using well logs and core samples, with a focus on rock type distribution, reservoir continuity, and petrophysical properties to enhance hydrocarbon exploration accuracy. The research involved detailed analysis of core descriptions and images from GABO-20, along with petrophysical data from wells GABO-4, GABO-12, GABO-13, GABO-20, and GABO-51, aiming to identify rock types, evaluate reservoir quality, and determine the spatial distribution of petrophysical properties. The methodology included rigorous well log quality checks, data correlation between wells, petrophysical property evaluation, and lithofacies description. The analysis revealed thirty-five hydrocarbon-bearing zones, with GABO-20 showing average shale fraction values between 0.111 and 0.335, total porosity ranging from 0.242 to 0.329, and hydrocarbon saturation from 0.667 to 0.923, indicating substantial porosity and hydrocarbon saturation conducive to extraction. Well correlations demonstrated excellent sand-shale continuity within the reservoir intervals. Lithofacies analysis of the GABO-20 core identified eight distinct facies, including shale poles, liquid-rich shales, and sandstone poles, revealing a complex distribution of reservoir qualities with significant variations in potential. Cores 1 and 2 exhibited favourable conditions for hydrocarbon production, while Core 3 showed lower reservoir quality due to increased clay content. The depositional settings of the GABO field, particularly in the lower delta plain and delta front zones, showed well-developed reservoir bodies with moderate potential in the tidal zone and little potential in the shaly prodelta environment. This distribution highlights the complexity of the deltaic system and its implications for reservoir modeling and utilization. Reservoir zones associated with High-Quality Reservoir Facies exhibited strong petrophysical properties, suggesting excellent hydrocarbon production potential. The study underscores the importance of detailed reservoir characterization to optimize recovery strategies, offering valuable insights into the distribution and quality of reservoir sands, reducing subsurface uncertainty, and emphasizing the integration of facies and petrophysical approaches for a better understanding of reservoir characteristics in the GABO field.

Improved reservoir quality assessment by evaluating illite grain coatings, quartz cementation, and compaction – Case study from the Buntsandstein, Upper Rhine Graben, Germany

Reservoir quality (RQ) in the Buntsandstein of the Upper Rhine Graben is in the center of attention as it is a possible target formation for geothermal energy production and hydrocarbon exploration surrounding existing fields. An understanding of properties affecting reservoir quality of the target lithology is still fairly poor and the success of accurately targeting high RQ intervals is limited. This is due to the fact, that the effect of compaction and the interplay between enhanced chemical compaction (i.e. pressure dissolution of quartz grains), illitic contact coatings and quartz cementation in the lithology has been underestimated. The understanding and quantification of controlling factors on reservoir qualities in fluvio-eolian sedimentary rocks, deposited in a (semi-)arid climate has been improved in recent years and this case study highlights the benefits of detailed petrographic analyses in understanding diagenetic and compactional processes in this lithology. This is especially relevant in the observation of grain coating clay minerals, whose effect depends on their specific location, i.e. either at grain contacts between quartz grains (GTG coating) or at the interface between detrital quartz grains and the intergranular volume (GTI coating).Illitic GTI coatings affect syntaxial quartz overgrowth precipitation, as precipitation sites are locally blocked. The negative correlation between the grain coating coverage and quartz cement volumes support these findings across multiple sample sets, and they may locally preserve intergranular porosity. Illitic GTG coatings on the other hand enhance chemical compaction (i.e. pressure dissolution) and will reduce the IGV. The negative correlation between these two properties again underlines the negative effect of this process on reservoir properties. Studied samples from a deep Buntsandstein well in the central URG show low reservoir quality due to either intense quartz cementation (0.7–31.7%) or a high degree of mechanical and chemical compaction (IGV: 2.3–38.0%). Higher illitic GTG and GTI coating coverages play a substantial role in controlling reservoir quality development, as demonstrated by comparing data from other fluvio-eolian lithologies (Triassic Buntsandstein and Permian Rotliegendes) to results of this study. In relation to their respective burial histories, higher illitic GTI coating coverages always correlate with smaller syntaxial quartz cement volumes. Similarly, higher illitic GTG coating coverages always correlate with lower IGV values in the three compared sample series.As both, the precipitation of quartz cements and compaction, are a function of the burial history, i.e. effective stresses and experienced temperatures, understanding the interaction of both these processes may enable the prediction of reservoir properties in undrilled areas.

Implications of the depositional and diagenetic attributes on the reservoir properties of the siliciclastic mangahewa formation, Taranaki Basin, New Zealand: Integrated petrographical and petrophysical studies

The siliciclastic Mangahewa reservoir in the Pohokura Gas Field presents a formidable challenge for gas exploration due to its diverse petrophysical properties. To address this challenge, our study employs a comprehensive approach integrating petrography and petrophysical analyses for core and well logging data. In the present study, we uncover an association of sandstone microfacies, in the key wells like Pohokura South-1, Pohokura-1, and Pohokura-2 wells, which change from fine to medium-grained subfeldsarenites to lithic feldsarenites microfacies. The petrographic investigation pinpoints the critical factors influencing the reservoir quality, including facies types, grain size, pore types, sedimentary structure, detrital clay content, and mineral composition. Both the primary intergranular and secondary dissolution pore spaces are responsible for the influential large intergranular pore volumes causing a superior reservoir quality. Mineral composition, influenced by the source and lithofacies, significantly impacts the reservoir properties. Diagenetic processes further control the reservoir quality, where the abundant silica cement, the illitic clays, and the rare pervasive carbonate cementation render the low reservoir quality. Compaction significantly reduces porosity during diagenesis. High-quality reservoir sandstones are characterized by coarse grain size, minimal detrital clay presence, predominantly quartz composition, limited carbonate and moderate silica cementation, low authigenic illite levels, and minor compaction impact. Based on the petrophysical data, the Mangahewa reservoir is composed of five RRTs (reservoir rock types) with the RRT1 samples having the best reservoir characteristics due to their fair porosity, very good permeability, and macro pore sizes. On the other side, the RRT5 samples are characterized by the lowest reservoir quality (poor porosity and permeability and micropore sizes) due to cementation and compaction. Our study provides valuable insights into the intricate petrophysical properties of the Mangahewa reservoir, enhancing the predictability of the reservoir behavior and optimizing hydrocarbon production in this challenging geological setting.

Mechanisms of Waterflood Inefficiency: Analysis of Geological, Petrophysical and Reservoir History, a Field Case Study of FWU (East Section)

The petroleum reservoir represents a complex heterogeneous system that requires thorough characterization prior to the implementation of any incremental recovery technique. One of the most commonly utilized and successful secondary recovery techniques is waterflooding. However, a lack of sufficient investigation into the inherent behavior and characteristics of the reservoir formation in situ can result in failure or suboptimal performance of waterflood operations. Therefore, a comprehensive understanding of the geological history, static and dynamic reservoir characteristics, and petrophysical data is essential for analyzing the mechanisms and causes of waterflood inefficiency and failure. In this study, waterflood inefficiency was observed in the Morrow B reservoir located in the Farnsworth Unit, situated in the northwestern shelf of the Anadarko Basin, Texas. To assess the potential mechanisms behind the inefficiency of waterflooding in the east half, geological, petrophysical, and reservoir engineering data, along with historical information, were integrated, reviewed, and analyzed. The integration and analysis of these datasets revealed that several factors contributed to the waterflood inefficiency. Firstly, the presence of abundant dispersed authigenic clays within the reservoir, worsened by low reservoir quality and high heterogeneity, led to unfavorable conditions for waterflood operations. The use of freshwater for flooding exacerbated the adverse effects of sensitive and migratory clays, further hampering the effectiveness of the waterflood. In addition to these factors, several reservoir engineering issues played a significant role in the inefficiency of waterflooding. These issues included inadequate perforation strategies due to the absence of detailed hydraulic flow units (HFUs) and rock typing, random placement of injectors, and uncontrolled injected fresh water. These external controlling parameters further contributed to the overall inefficiencies observed during waterflood operations in the east half of the reservoir. A detailed understanding of the mechanistic factors of inefficient waterflood operation will provide adequate insights into the development of the improved recovery technique for the field.

Rock Typing and Characterization of the Late Cretaceous Abu Roash "G" Reservoirs at East Alam El-Shawish Field, Western Desert, Egypt

Rock typing and petrophysical characterization play a vital role in constructing reservoir models for petroleum exploration and development. This study focuses on evaluating the petrophysical characteristics of the Late Cretaceous Abu Roash "G" Reservoirs at the East Alam El Shawish field in Egypt's Western Desert. The study involved five vertical wells and employed various techniques and analyses to investigate the reservoir. Lithology determination utilizing well logs and core analysis helps identify the lithology types and corresponding porosity of the Abu Roash "G" reservoirs. Sandstone and limestone lithologies with varying porosity ranges were identified, along with the influence of shale on neutron porosity values. Facies analysis of the Abu Roash "G" Member identified seven lithofacies types, categorized into shallow marine and deeper marine depositional environments. The petrophysical analysis involves evaluating gamma-ray logs, porosity, permeability, flow zone indicator (FZI), and reservoir quality index (RQI) values for each lithofacies type. This analysis classifies the core samples into seven reservoir rock types (RRT1 to RRT7) based on petrophysical attributes, providing a clear classification of the Abu Roash "G" reservoir interval. RRT1, RRT2, and RRT3 exhibit the highest reservoir quality, while RRT4 and RRT5 indicate moderate reservoir quality. RRT6 and RRT7 exhibit low reservoir quality due to unfavorable petrophysical behavior. The findings of this study provide valuable insights into the Abu Roash "G" reservoir, including its lithofacies, reservoir properties, and depositional environments. This knowledge is crucial for reservoir characterization and optimizing oil production strategies in the region.

Effects of inorganic CO2 intrusion on diagenesis and reservoir quality of lacustrine conglomerate sandstones: Implications for geological carbon sequestration

Mantle-sourced fluids are common in rift basins and often migrate into the reservoir along deep faults. They have a significant role in hydrocarbon evolution and reservoir quality modifications. In this study, we selected Chagan Sag in China as an example and applied reactive transport modeling to explore the influence of mantle-derived CO2 on diagenesis and reservoir quality evolution in the Lower Cretaceous Bayingebi conglomerate reservoirs. The geochemical modeling constrained by natural CO2 reservoirs provides beneficial information on the underground physical processes and chemical reactions during CO2 injection. This is also an efficient means of validating geological carbon sequestration models. Petrographic, geochemical, and modeling data reveal that CO2 intrusion could reduce the reservoir porosity and permeability via significant CO2-water-mineral interactions. Ankerite and illite are the dominant diagenetic minerals responsible for reservoir quality reduction. Among the different lithologies, the higher reservoir quality conglomerate is mainly caused by its high initial porosity and small quantities of clay minerals, with relatively weak carbonate cementation. The lower reservoir quality finer-grained conglomeratic siltstone is caused by intensive albitization, carbonation, and illitization. In the long-term CO2-water-rock interaction process, CO2 can be sequestered through the precipitation of secondary carbonate minerals such as ankerite and dolomite.

Petrophysical characterization of the heterogeneous shale-rich oil reservoirs: a case study of the Cenomanian Clastics, Abu Sennan Concession, North Western Desert of Egypt

Shale-rich reservoirs present a long-standing challenge for reservoir geologists because the clay minerals often induce a large-scale heterogeneity in the reservoir pore system. This work aims to understand the impact of clay distribution and mineralogy which would enhance the predictability of the best reservoir facies. We integrate seismic, well-log datasets to investigate the petrophysical characteristics of the clay-rich Cenomanian Clastics in the GPY oil field, north Western Desert of Egypt. These Clastics comprise the sandstone intervals which are the most prolific hydrocarbon reservoirs. Seismic data were used to interpret the main structural patterns as well as the different seismic facies. The well log data were utilized to interpret the lithologic variations and the type of clays in the reservoir as well as the different petrophysical parameters. Based on variations in their lithological and petrophysical characteristics, the Bahariya sandstones were sub-divided into three different rock units: Bahariya-3 (B-3), Bahariya-2 (B-2), and Bahariya-1 (B-1), separated by thick laminated clay intervals. AR/G Member is dominated by clays with relatively lower reservoir quality. Spectral gamma ray log values reveal that smectite is the dominant clay mineral in all the studied intervals. Laminated clays are dominant in B-1 and B-2 units, whereas, B-3 unit and Abu Roash G Member are enriched in structural clays. The quartzose sand content decreases from B-3 to AR/G and clay content increases from B-3 to AR/G. Therefore, the best reservoir facies and fluid flow conduits with best pore system characteristics are hosted in B-3 and the smectite clay streaks act as a good seal for hydrocarbons in the quartzose sandstone pay zone.

Integration of geoscience data to delineate quality of the Asmari reservoir, Iranian part of the Persian Gulf basin

The Hendijan Field is an asymmetric structure located in the northwestern Persian Gulf and consists of several oil and gas-bearing intervals. Oligocene to Miocene successions in the field host large volumes of hydrocarbons. The Asmari Formation comprises the mixed siliciclastic and carbonate members formed in a shallow marine carbonate ramp depositional environment. The siliciclastic part displays the best reservoir quality within the Asmari Formation. Through petrophysical, sedimentological, and geophysical analysis, this study divides the Asmari Formation into six, third-order depositional sequences. By doing so, it clarifies the relationships between depositional sequences and reservoir characteristics, particularly porosity and water saturation. Detailed petrographical analysis, core description, well log analysis, and seismic interpretation distinguish eight microfacies, two petrofacies, and six third-order sequences within the Asmari Formation. 3D reservoir-property models are developed that incorporate elements of the sequence stratigraphical framework. Within the six identified sequences, high reservoir quality zones are associated with AS-4 and AS-5, which comprise mostly grain-supported lithologies associated with shoal facies. The supratidal, intertidal, and lagoonal facies of AS-2, which are often associated with the occurrence of anhydrite and mud-supported fabrics, reflect lower reservoir quality. Hydraulic flow units (HFU) are delineated to assist in characterizing reservoir heterogeneity and porosity/permeability prediction. Five HFU were identified by applying the flow-zone-indicator method to evaluate reservoir quality. Both the transgressive system tract (TST) of AS-2 and early TST plus late highstand system tract (HST) of AS-6 contain elements of HFU-A. The most productive units of AS-4 and AS-5 belong to HFU-E.

3D facies and reservoir property prediction of deepwater turbidite sands; case study of an offshore Niger delta field

The distribution of lithofacies and key reservoir properties such as porosity, net to gross and water saturation is essential to describing reservoir heterogeneity predicted within a clastic deep water reservoir unit in the study area. A systematic analysis of core and gamma-ray wireline logs was used to identify the reservoir unit in this study. The identified reservoir unit was mapped on 3D seismic data, and four lithological and fluid sensitive seismic attributes extracted for the reservoir were fed as inputs into an unsupervised artificial neural network (UANN) analysis to define the depositional pattern of the reservoir unit. Afterwards, a 3D sand facies trend model was built using the facies depositional pattern map and upscaled properties from well data. The generated 3D sand probability model from trend modelling was subsequently used to constrain geostatistical facies modelling of the reservoir unit. The systematic stratal analysis from core, well data and the integration of seismic attributes using UANN reveal the reservoir unit as a system of turbidite lobe sands and turbidite channel levees sands. The 3D Geostatistical facies distribution reveals spatial and vertical facies heterogeneity. It indicates high sand amalgamations and static hydraulic connectivity of turbidite lobe sands in the distal part of the study area. Further geostatistical distribution of reservoir properties conditioned to facies indicated good to excellent reservoir quality within the turbidite lobe sands, moderate to low reservoir quality within turbidite channel sands and poor reservoir quality at the turbidite channel margins and the deep-water shale facies. The 3D facies and reservoir property models built in this study would ensure optimisation of the reservoir unit, enable better estimation of hydrocarbon volumes and serve as input data for flow simulation.

Lithofacies classification integrating conventional approaches and machine learning technique

This study introduces an integrated approach for lithofacies classification utilizing core samples, wireline logs, and a machine learning technique. It is specialized for the Eagle Ford shale and the Austin Chalk where operators often face difficulties to define geological heterogeneity due to relatively consistent and low reservoir quality compared to conventional reservoirs. A set of cored slabs, thin sections, scanning electron microscope (SEM) images were utilized for lithofacies classification. Four lithofacies were defined with depositional texture, fabric, mineralogy, pore type, diagenesis, and biological features: (1) Organic-matter-rich mudstone, (2) Organic-matter-lean calcareous marl, (3) Heterogeneous argillaceous wackestone and marl, (4) Massive marly chalk. These four lithofacies are not easily classifiable through conventional wireline log cross-plotting. A convolutional neural network (CNN) model was trained to classify the lithofacies using five wireline logs (Gamma ray, bulk density, neutron porosity, deep resistivity, and compressional sonic logs) which are commonly accessible at field sites. In order to validate and test the CNN model, k-fold cross-validation and blind well test were conducted. This data-driven approach is expected to provide technical insights to operators seeking practical approaches to identifying prospective drilling locations and optimal completion strategies based on in-depth reservoir characterization.

Sedimentology and reservoir characteristics of delta plain reservoirs: An example from Messinian Abu Madi Formation, Nile Delta

Delta plain sandstones represent one of the major deltaic hydrocarbon reservoir compartments. The present research provides integrated sedimentological, petrophysical, and petrographical analyses of delta plain reservoirs using an example from the gas-bearing Messinian Abu Madi in the central part of the Nile Delta. The Abu Madi reservoir is interpreted as a tidally-influenced, fluvial-dominated delta plain, and it is subdivided into four sedimentological architectural elements: distributary channel, crevasse channel (straight and meandering), crevasse splays, and interdistributary bay fill. Although the distributary channel has the best reservoir quality (HFU 4 and HFU 5), it is characterized by a high degree of heterogeneity due to the complex interaction between fluvial discharge and tidal currents; straight crevasse channels (HFU 3 and HFU 4) are similar to the distributary channel but have relatively fine grain size and small sand body volume. The meandering crevasse channels are of low reservoir quality (HFUs 1 and 2) due to the formation of point bar muddy inclined heterolithics. According to the results, the delta plain reservoirs are microscopically dominated by quartzose, and litho- and feldspathic quartzose microfacies. The common mud-matrix and poorly sorted fabric due to rapid deposition as well as reworking by tidal/wave currents, that represent the main depositional controls on reservoir quality. Meanwhile, dissolution, anhydrite, quartz, and calcite as well as authigenic kaolinite and chlorite clays are the main diagenetic control factors on reservoir quality.

Implementation of lithofacies and microfacies types on reservoir quality and heterogeneity of the Late Cretaceous Upper Bahariya Member in the Shurouk Field, Shoushan Basin, North Western Desert, Egypt

The Late Cretaceous Upper Bahariya Member is one of the most prolific reservoir sequences in the North Western Desert of Egypt. In this paper, we describe core samples of the Upper Bahariya Member, including core photos, conventional core analysis, petrographical description, scanning electron microscope images, and XRD analysis. Samples for this study are from the reservoir sequence in four wells selected from the Shurouk Field in the Shoushan Basin to delineate the impact of the constraint mineral composition on the reservoir quality. The objective of this study is to get an accurate reservoir characterization of this reservoir by applying the rock typing technique to the studied sequence where four Lithofacies Associations (LFA1, LFA2, LFA3, and LFA4) and four corresponding Reservoir Rock Types (RRT1, RRT2, RRT3, and RRT4) were assigned. These are defined as 1) very fine massive sandstone (LFA1, RRT1), 2) laminated, cross-bedded and bioturbated sandstone (LFA2, RRT2), 3) laminated, highly argillaceous and ferruginated sandstone and siltstone (LFA3, RRT3), and 4) laminated and ferruginated siltstone and well cemented bioturbated limestone (LFA4, RRT4). Petrographically, these lithofacies were categorized into five microfacies; 1) glauconitic quartz arenite, 2) subfeldspathic arenite, 3) glauconitic sublithic arenite, 4) ferruginated subfeldspathic wackes, and 5) sandy fossiliferous packstone microfacies. Conventional core samples include bulk and grain densities (ρb and ρg, respectively), helium porosity (∅He), and horizontal and vertical permeabilities (kH and kV, respectively). The application of the Dykstra-Parsons technique to the available permeability data indicates that the studied sequence is extremely heterogeneous (heterogeneity factor (V) = 0.90). Based on the available samples, the normalized porosity index (∅z), reservoir quality index (RQI), flow zone indicator (FZI), and the discrete rock type values (DRT) were estimated to determine the reservoir quality. The RRT1 samples are characterized by the best reservoir properties (av. ∅He = 14.7%, av. kH 42.0 = md, av. RQI = 0.47 µm, av. FZI = 2.87 µm, and av. DRT = 13), whereas the lowest reservoir quality is assigned to the RRT4 samples (av. ∅He = 18.8%, av. kH 0.30 = md, av. FZI = 0.15 µm, av. RQI = 0.04 µm, and av. DRT = 7). The low reservoir quality of the RRT4 is primarily attributed to the predominance of lower quality features (compaction effect, cementation, and presence of glauconite and authigenic minerals). Following the Improved Stratigraphic Modified Lorenz (ISML plot), the Upper Bahariya reservoir is subdivided into five Hydraulic Flow Units (HFUs) such as the HFU-2, and the HFU-4 that are considered superconductive flow units that alternate with three poorly hydraulic conductive HFUs (HFU-1, HFU-3, and HFU-5). The present integrated sedimentological and petrophysical workflow is considered a significant study of the Shoushan basin which can improve exploration activities as well as production optimization. In addition, dividing the studied clastic sequence into five microfacies association and four reservoir rock types can be extended to other equivalent subsurface Late Cretaceous clastic sedimentary rocks in the vicinity and other basins.

Reservoir zonation in the framework of sequence stratigraphy: A case study from Sarvak Formation, Abadan Plain, SW Iran

Located in the northeast of the Arabian Plate, Zagros Basin hosts some of the most significant hydrocarbon reservoirs in Iran, including the Sarvak Formation. It has been dated back to the Middle Cretaceous and exhibits a dominantly carbonate lithology. In this study, petrographic and petrophysical data of the Sarvak Formation were analyzed. The results of the petrographic study showed that the formation was deposited in a homoclinal carbonate-ramp depositional environment and exposed to diagenetic processes in three depositional environments: marine, meteoric, and deeply buried environments. The stratigraphic modified Lorenz plot (SMLP) method was used to distinguish between the reservoir and non-reservoir zones. By integrating the petrographic and petrophysical findings, stratigraphic relationships among the identified zones were assessed. Accordingly, three third-order sedimentary sequences were identified on the Middle Cenomanian-to-Middle Turonian section within the studied formation. Two disconformities were detected in the Upper Sarvak, namely Cenomanian-Turonian disconformity (CTD) and Middle Turonian disconformity (MTD). The highest-quality reservoir zones were related to the CTD. The porosity resulted from the karstification, meteoric diagenesis, and significant dissolution beneath the CTD was found to have greatly increased the reservoir quality. Later on, however, the sediments were overmatured under the impact of the MTD, which is known to take a long time to occur, with their porosity largely decreased, ending up with a much lower reservoir quality. In general, the sedimentary facies were found to be the most important factors controlling the distribution of the reservoir zones across the Sarvak Formation, followed by the diagenetic processes. The findings provided an insight into the factors controlling the reservoir quality in the Sarvak Formation within the study area and the Arabian Plate.

Research and application of large-scale fracturing imitating horizontal well technology in vertical well

Hailaer Basin is rich in geological reserves, but the proportion of undeveloped reserves is high, accounting for 30% of the proved reserves. In order to improve the production degree of reserves and single well production, and realize the purpose of high and stable production of the oilfield. Taking the ultra-low permeability reservoir of oilfield B in Hailaer Basin as an example, this paper puts forward the large-scale fracturing of vertical wells and water injection development technology of imitating horizontal wells. By forming directional ultra long fracturing fractures in the oil layer, this technology can effectively increase the reservoir conductivity, increase the oil well drainage area and water well control area, reduce the well pattern density and improve the production of single well. The research shows that the undeveloped reserves in Hailaer oilfield have the characteristics of low thickness, low permeability and low reservoir quality index. There are 55 large-scale mold fracturing wells in Hailaer oilfield, with an initial oil increase of 2.2 times. The sand amount of large-scale fracturing is 2.5 times that of ordinary fracturing, and the fluid amount and sand intensity are 4.5 times that of conventional fracturing. The vertical well large-scale fracturing imitating horizontal well technology is adopted in Oilfield B. The designed vertical well fracturing fracture is 600m long and 120m wide, and the production effect is good after fracturing. The research results are of great significance to the high and stable production of undeveloped reserves block in Hailaer oilfield and other similar oilfields.

Geologically based integrated approach for zonation of a Late Jurassic–Early Cretaceous carbonate reservoir; a case from Persian Gulf

AbstractIn this study, our attempt is to integrate sedimentological and petrophysical data for reservoir evaluation in the sequence stratigraphic framework. Petrographic analysis of the Late Jurassic–Early Cretaceous Fahliyan Formation reservoirs of two oilfields in the northwest of the Persian Gulf led to recognition of twelve microfacies. They can be classified into four facies associations, including open marine, shoal, lagoon and tidal flat, which are deposited in a homoclinal ramp carbonate. Sequence stratigraphy of the studied successions led to the recognition of three third-order depositional sequences based on vertical changes in microfacies and gamma ray analysis. Except for the upper boundary of the third sequence, the other sequence boundaries are type I (SBT.1). Dissolution is the most important diagenetic feature that affected the lower depositional sequence which is caused by the development of subaerial exposure after the deposition of the Fahliyan Formation, whereas cementation is the main diagenetic feature affecting the second- and third depositional sequences, causing their lower reservoir quality. In order to identify the flow units, the flow zone index methods, porosity throat radius (R35) and modified Lorenz based on stratigraphy were applied. The key wells studied in this area have shown good correlation throughout the studied oilfields which may potentially be used for hydrocarbon exploration and field development in the Late Jurassic–Early Cretaceous deposits of the Persian Gulf. This study integrates geological and petrophysical data (rock typing) toward sequence stratigraphic framework.

Carrier-bed plays in the Denver and Powder River Basins

Carrier-bed plays are a new type of unconventional oil play that are currently being developed in North America. The reservoirs are generally low quality because of any of the following: thin beds (heterolithic strata), diagenesis, or burrowing (heterogeneous, mixing of sandstones or carbonates and mudstones). The carrier beds are pervasively hydrocarbon saturated and can occur over an areally extensive (greater than than 50 square miles, greater than 129 square kilometers) area. These low-quality reservoirs generally do not meet traditional petrophysical cutoffs and because of the clay content can create low resistivity, low contrast pays. The reservoirs may be composed of clastics or carbonates or a mixture of both. A sub-category of a carrier-bed play is a halo play. Halo plays are the low permeability flanking edges of a conventional oil accumulation (i.e., waste zone or the fringe). The low reservoir quality is generally stratigraphic in origin (facies change from high quality to low quality reservoirs). Carrier-bed and halo plays are being developed with horizontal drilling and multistage hydraulic fracturing. Traditional vertical drilling yields marginal to uneconomic wells but are a clue to the existence of a carrier-bed play. This paper reviews Upper Cretaceous carrier bed plays in the Denver (Codell SandstoneMember of the Carlile Shale) and Powder River (Turner Sandy Member of the Carlile Shale) basins.

3D Geological Model Creates Potential for Increased Production in Libyan Field

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201417, “Reservoir Characterization and Geostatistical Model of the Cretaceous and Cambrian-Ordovician Reservoir Intervals, Meghil Field, Sirte Basin, Libya,” by Mohamed Masoud, Sirte Oil Company; W. Scott Meddaugh, SPE, Midwestern State University; and Masud Eljaroshi Masud, Sirte Oil Company, prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. The study outlined in the complete paper focuses on developing models of the Upper Cretaceous Waha carbonate and Bahi sandstone reservoirs and the Cambrian-Ordovician Gargaf sandstone reservoir in the Meghil field, Sirte Basin, Libya. The objective of this study is to develop a representative geostatistically based 3D model that preserves geological elements and eliminates uncertainty of reservoir properties and volumetric estimates. This study demonstrates the potential for significant additional hydrocarbon production from the Meghil field and the effect of heterogeneity on well placement and spacing. Introduction The reservoir of interest consists of three stratigraphic layers of different ages: the Waha and Bahi Formations and the Gargaf Group intersecting the Meghil field. The Waha reservoir is a porous limestone that forms a single reservoir with underlying Upper Cretaceous Bahi sandstone and Cambro-Ordovician Gargaf Group quartzitic sandstone. The Waha provides excel-lent reservoir characteristics. The Bahi has fair to good reservoir characteristics, while the Gargaf Group has very poor reservoir quality. The Waha and Bahi contain significant amounts of hydrocarbons. The Bahi is composed of erratically distributed detritus from the eroded Gargaf Group. The characteristic of the Gargaf sediments is quartzitic sandstones indurate to a quartzite with low reservoir quality.

Depositional and diagenetic controls on reservoir quality of the uppermost Jurassic–Lower Cretaceous sequences in the Persian Gulf; a focus on J–K boundary

This study presents reservoir characterization of the uppermost Jurassic–Lower Cretaceous successions of the Manifa and Yamama formations in four wells in the Persian Gulf. Detailed sedimentological, petrophysical and geochemical analyses are integrated to evaluate the controlling factors on reservoir quality of these sequences. Microfacies analysis has resulted in the recognition of 10 facies types deposited in lagoon, algal mounds, shoal, and open marine settings. Micritization, dissolution, various types of cementation, dolomitization, and compaction are notable diagenetic alterations indicating marine/hypersaline, meteoric and shallow to deep burial realms. Stable carbon and oxygen isotopic compositions indicate a meteoric diagenetic alteration at the topmost part of Manifa unit, beneath the Jurassic–Cretaceous (J–K) disconformity. Sequence stratigraphic analysis led to the identification of four transgressive–regressive (T–R) sequences in the Yamama Fm. and a regressive hemi-sequence in the Manifa unit. Reservoir quality study resulted in the recognition of eight hydraulic flow units and four types of reservoir facies with specific and predictable sequence stratigraphic framework. Dissolved grain-dominated shoal facies at the upper part of regressive systems tracts and algal reef/mound facies in transgressive systems tracts provide the best reservoir units of the studied sequences. Microporous mud-dominated facies of open marine settings are dominant reservoir facies in the upper Yamama unit, with moderate to low reservoir quality.

Impact of petrographic characteristics on reservoir quality of tight sandstone reservoirs in coal‐bearing strata: A case study in Lower Permian Shihezi Formation in northern Ordos Basin, China

The lower Shihezi Formation in the Sulige gas field is the main gas exploitation target in the Ordos Basin and is crucial in finding high‐quality reservoirs for further exploration. Using X‐ray diffraction, cathodoluminescence (CL), and scanning electron microscope (SEM) techniques, the eighth member of lower Shihezi Formation (He8) sandstones are characterized as fine‐ to coarse‐grained quartzarenite and litharenite with good sorting, which are controlled by different sources and depositional faces. Four types of sandstones are recognized according to varied petrographic characteristics, among which fine‐grained sandstones (type I) has the poorest reservoir quality and coarse‐grained sandstones with chlorite coating (type II) are the best reservoirs. The complicated diagenetic process mainly includes intense compaction, two‐stage dissolution, quartz and calcite cementation, which is closely associated with the thermal evolution of coals. The increased ductile fragments account for low reservoir quality in type I sandstones. Due to the absence of feldspar, the influence of other detrital components on the reservoir quality has increased. Sandstones with abundant volcanic fragments (type II) usually formed grain‐coating chlorite, which inhibit tight compaction and quartz cementations. Quartz overgrowth originated from feldspar dissolution as well as pressure dissolution of detrital quartz are frequently observed in medium‐ to coarse‐grained quartzarenite (type III). The high‐quality reservoir exits when the ductile grains content is about 4%, according to the negative relationship between quartz cement and ductile content. Although there are a lot of dissolution pores in medium‐ to coarse‐grained litharenite (type IV), the reservoir quality did not improve much due to the diagenetic minerals filling in the secondary pores.

Application of sequential indicator simulation, sequential Gaussian simulation and flow zone indicator in reservoir-E modelling; Hatch Field Niger Delta Basin, Nigeria

The study was carried out with the aim of predicting uncertainty using Sequential Indicator Simulation (SISIM) for lithofacies modelling, sequential Gaussian simulation (SGSIM) for reservoir property modelling and inferring the depositional environment using Flow Zone Indicator (FZI). Five well logs, core analysis data and 3D seismic data were used for the study. Reservoir sand named “Reservoir-E” was correlated across the five wells in the field, and its surface was mapped on the seismic sections from the 3D cube. Petrophysical evaluations revealed average, net to gross, porosity, permeability, the volume of shale, water saturation, hydrocarbon saturation (SH), Reservoir Quality Index (RQI) and FZI as 0.70, 0.29, 2342 mD, 0.158, 0.50, 0.50, 2.44 and 5.62 μm, respectively. Structural interpretations on seismic sections revealed five major faults which trend NE-SW, NW-SE and W-E. A 3D grid with dimension 204 × 120 × 5 = 122,400 was constructed to accommodate our model. Validation of lithofacies models shows a correlation coefficient of 89.43–92.98% for well data and model. The property model shows variability in effective porosity and permeability 0.24 to 0.38 and 560 to 5600 mD. The low amount of SH in well HT-2 and HT-3ST1 is attributed to the presence of baffles with low reservoir quality index with 1.81 and 1.67 for RQI and 5.05 and 5.27 for FZI as compared to well HT-1, HT-4ST1 and HT-5 with RQI of 3.61, 2.71 and 2.41 and FZI of 6.25, 5.85 and 5.66. The environment of deposition is interpreted to be mouth bar-upper shoreface. High porosity and permeability values are linked with high FZI and RQI which are targets for exploitation.