scholarly journals Reservoir and sealing properties of the Newark rift basin formations: Implications for carbon sequestration

2020 ◽  
Vol 39 (1) ◽  
pp. 38-46
Author(s):  
N. V. Zakharova ◽  
D. S. Goldberg ◽  
P. E. Olsen ◽  
D. Collins ◽  
D. V. Kent
Keyword(s):  
Carbon Sequestration ◽  
Atlantic Coast ◽  
High Porosity ◽  
Rift Basins ◽  
Reservoir Properties ◽  
Porous Flow ◽  
Mafic Intrusions ◽  
Porosity And Permeability ◽  
Structural Architecture ◽  
Newark Basin

The Newark Basin is one of the major Mesozoic rift basins along the U.S. Atlantic coast evaluated for carbon dioxide (CO2) storage potential. Its geologic setting offers an opportunity to assess both the traditional reservoir targets, e.g., fluvial sandstones, and less traditional options for CO2 storage, e.g., mafic intrusions and lavas. Select samples from the basal, predominantly fluvial, Stockton Formation are characterized by relatively high porosity (8%–18%) and air permeability (0.1–50 mD), but borehole hydraulic tests suggest negligible transmissivity even in the high-porosity intervals, emphasizing the importance of scale in evaluating reservoir properties of heterogeneous formations. A stratigraphic hole drilled by TriCarb Consortium for Carbon Sequestration in the northern basin also intersected numerous sandstone layers in the predominantly lacustrine Passaic Formation, characterized by core porosity and permeability up to 18% and 2000 mD. However, those layers are shallow (predominantly above 1 km in this part of the basin) and lack prominent caprock layers above. The mudstones in all three of the major sedimentary formations (Stockton, Lockatong, and Passaic) are characterized by a high CO2 sealing capacity — evaluated critical CO2 column heights exceed several kilometers. The igneous options are represented by basalt lavas, with porous flow tops and massive flow interiors, and a crystalline but often densely fractured Palisade Sill. The Newark Basin basalts may be too shallow for sequestration over most of the basin's area, but many other basalt flows exist in similar rift basins. Abundant fractures in sedimentary and igneous rocks are predominantly closed and/or sealed by mineralization, but stress indicators suggest high horizontal compressional stresses and strong potential for reactivation. Overall, the basin potential for CO2 storage appears low, but select formation properties are promising and could be investigated in the Newark Basin or other Mesozoic rift basins with similar fill but a different structural architecture.

scholarly journals Petrophysical Properties of Nahr Umar Formation in Nasiriya Oil Field

2020 ◽  
Vol 21 (3) ◽  
pp. 9-18
Author(s):  
Ahmed Abdulwahhab Suhail ◽  
Mohammed H. Hafiz ◽  
Fadhil S. Kadhim
Keyword(s):  
Gamma Ray ◽  
Water Saturation ◽  
Oil Field ◽  
Well Logs ◽  
High Porosity ◽  
Reservoir Properties ◽  
Petrophysical Parameters ◽  
Resistivity Logs ◽  
Lithology Prediction ◽  
Porosity And Permeability

   Petrophysical characterization is the most important stage in reservoir management. The main purpose of this study is to evaluate reservoir properties and lithological identification of Nahr Umar Formation in Nasiriya oil field. The available well logs are (sonic, density, neutron, gamma-ray, SP, and resistivity logs). The petrophysical parameters such as the volume of clay, porosity, permeability, water saturation, were computed and interpreted using IP4.4 software. The lithology prediction of Nahr Umar formation was carried out by sonic -density cross plot technique. Nahr Umar Formation was divided into five units based on well logs interpretation and petrophysical Analysis: Nu-1 to Nu-5. The formation lithology is mainly composed of sandstone interlaminated with shale according to the interpretation of density, sonic, and gamma-ray logs. Interpretation of formation lithology and petrophysical parameters shows that Nu-1 is characterized by low shale content with high porosity and low water saturation whereas Nu-2 and Nu-4 consist mainly of high laminated shale with low porosity and permeability. Nu-3 is high porosity and water saturation and Nu-5 consists mainly of limestone layer that represents the water zone.

The Cambrian Basal Sandstone Unit in central Alberta — an investigation of temperature distribution, petrography, and hydraulic and geomechanical properties of a deep saline aquifer

2014 ◽  
Vol 51 (8) ◽  
pp. 783-796 ◽  
Author(s):  
Simon Weides ◽  
Inga Moeck ◽  
Jacek Majorowicz ◽  
Matthias Grobe
Keyword(s):  
Geothermal Gradient ◽  
High Porosity ◽  
Reservoir Properties ◽  
Geothermal Heat ◽  
Hydraulic Stimulation ◽  
Deep Saline Aquifer ◽  
Thin Sections ◽  
Geomechanical Properties ◽  
Western Canada Sedimentary Basin ◽  
Porosity And Permeability

Recent geothermal exploration indicated that the Cambrian Basal Sandstone Unit (BSU) in central Alberta could be a potential target formation for geothermal heat production, due to its depth and extent. Although several studies showed that the BSU in the shallower Western Canada Sedimentary Basin (WCSB) has good reservoir properties, almost no information exists from the deeper WCSB. This study investigated the petrography of the BSU in central Alberta with help of drill cores and thin sections from six wells. Porosity and permeability as important reservoir parameters for geothermal utilization were determined by core testing. The average porosity and permeability of the BSU is 10% and <1 × 10−14 m2, respectively. A zone of high porosity and permeability was identified in a well located in the northern part of the study area. This study presents the first published geomechanical tests of the BSU, which were obtained as input parameters for the simulation of hydraulic stimulation treatments. The BSU has a relatively high unconfined compressive strength (up to 97.7 MPa), high cohesion (up to 69.8 MPa), and a remarkably high friction coefficient (up to 1.22), despite a rather low tensile strength (<5 MPa). An average geothermal gradient of 35.6 °C/km was calculated from about 2000 temperature values. The temperature in the BSU ranges from 65 to 120 °C. Results of this study confirm that the BSU is a potential geothermal target formation, though hydraulic stimulation treatments are required to increase the permeability of the reservoir.

West Africa Lacustrine Pre-Salt Carbonates: How Interaction of Tectonics and Diagenesis Produced Different Reservoir Facies

2016 ◽  
Author(s):  
Paola Ronchi ◽  
Giovanni Gattolin ◽  
Alfredo Frixa ◽  
Chiara Margliulo
Keyword(s):  
Congo Basin ◽  
High Porosity ◽  
Carbonate Platforms ◽  
Pore System ◽  
Reservoir Properties ◽  
Deep Faults ◽  
Facies Associations ◽  
Porosity And Permeability ◽  
Hydrothermal Dolomite ◽  
Reservoir Facies

ABSTRACT During the Early Cretaceous South-Atlantic opening, in large lacustrine basins a series of shallow water carbonate platforms grew along lake margins and paleo-highs. These carbonates are giant reservoirs in the Brasil offshore, while in Angola are productive in Cabinda (Lower Congo Basin) and are being explored in the Kwanza Basin with minor success. These carbonates have peculiar facies associations represented mainly by microbialites and coquinas, and are affected by dolomitization which modified the original pore system in different ways. In presence of deep-seated extensional faults, bounding the paleo-highs, the hydrothermal dolomitization affected the reservoir carbonate improving its quality; in fact the hydrothermal dolomite produced the so-called zebra dolomite which is characterized by high porosity and permeability. On the other hand, when there is a limited influx of hydrothermal fluid, some dolomitization is observed, but it did not produce the zebra facies and the poro-perm system has lower quality. These two examples suggest that the understanding of the distribution of deep faults may help in the prediction of the diagenetic effects and resulting reservoir properties.

scholarly journals THE INFLUENCE OF SEDIMENTATION AND POST-SEDIMENTATION TRANSFORMATIONS ON THE RESERVOIR PROPERTIES OF THE ROCKS

2019 ◽  
pp. 14-19
Author(s):  
V. Khomyn ◽  
M. Maniuk ◽  
O. Maniuk ◽  
A. Popluiko ◽  
N. Khovanets
Keyword(s):  
Oil And Gas ◽  
Scientific Evidence ◽  
Gas Content ◽  
High Porosity ◽  
Reservoir Properties ◽  
Quartz Content ◽  
Positive Correlation ◽  
Median Diameter ◽  
Porosity And Permeability ◽  
Cover Thickness

The topicality of the research is proved by the scientific evidence of the peculiarities of the sedimentation and post-sedimentation transformations of the rocks in relation to their possible oil and gas content. The productive sediments of the deposits of the interior of the Precarpathian Depression were thoroughly and lithologically researched. The objective implied the study and recognition of the reservoir properties within primary (sedimentation) and secondary (post-sedimentation) factors. The primary ones are as follows: granulity (grains median diameter), sorting, and rock maturity. Consequently, a positive correlation between the grains median diameter and rock porosity has been determined; the very coefficient equals 0.56. Evidently, unlike the well-sorted sandstones, the badly graded ones are marked by poor porosity and permeability. The positive correlation between porosity and clastic quartz content is revealed: should the latter increase, the former will go up as well. Apparently, more mature sandstones are characterized by dramatically high porosity; this factor positively affects the reservoir properties of the rocks. After studying the secondary transformations of the sandy rocks, we have determined that the diagenesis stage is defined by the change of mineral composition. This alteration is mainly caused by organic material decomposition and the appearance of reducing environment. Considering the cover thickness, we have graded the transformations of the fragments of the sandy-aleuritic rocks of the depression. The pattern of the catagenetic changes at various depths has been introduced. In the end, we have inferred that the increasing depth starts influencing the three types of the structures, i.e. incorporating, reclaiming and microstilolite rather gradually. In addition, the declining importance of the conformal structures has been identified. The stress pattern of the catagenetically transformed solid rocks promotes the microfracture within the late catagenesis zones; this factor predetermines the development of decompression zones at the depths exceeding 4 km characterised by good reservoir properties.

The Research and Application of Cementing Isolation Technology in High Porosity and Permeability of Developed Clastic Rock Reservoir in Tarim Basin

2021 ◽  
Author(s):  
Hongtao Liu ◽  
Zhengqing Ai ◽  
Jingcheng Zhang ◽  
Zhongtao Yuan ◽  
Jianguo Zeng ◽  
...  
Keyword(s):  
Drilling Fluid ◽  
Water Layer ◽  
High Porosity ◽  
Self Healing ◽  
Cement Slurry ◽  
Clastic Rock ◽  
Pump Rate ◽  
Porosity And Permeability ◽  
Zonal Isolation ◽  
High Pump

Abstract The average porosity and permeability in the developed clastic rock reservoir in Tarim oilfield in China is 22.16% and 689.85×10-3 μm2. The isolation layer thickness between water layer and oil layer is less than 2 meters. The pressure of oil layer is 0.99 g/cm3, and the pressure of bottom water layer is 1.22 g/cm3, the pressure difference between them is as bigger as 12 to 23 MPa. It is difficult to achieve the layer isolation between the water layer and oil layer. To solve the zonal isolation difficulty and reduce permeable loss risk in clastic reservoir with high porosity and permeability, matrix anti-invasion additive, self-innovate plugging ability material of slurry, self-healing slurry, open-hole packer outside the casing, design and control technology of cement slurry performance, optimizing casing centralizer location technology and displacement with high pump rate has been developed and successfully applied. The results show that: First, the additive with physical and chemical crosslinking structure matrix anti-invasion is developed. The additive has the characteristics of anti-dilution, low thixotropy, low water loss and short transition, and can seal the water layer quickly. Second, the plugging material in the slurry has a better plugging performance and could reduce the permeability of artificial core by 70-80% in the testing evaluation. Third, the self-healing cement slurry system can quickly seal the fracture and prevent the fluid from flowing, and can ensuring the long-term effective sealing of the reservoir. Fourth, By strict control of the thickening time (operation time) and consistency (20-25 Bc), the cement slurry can realize zonal isolation quickly, which has achieved the purpose of quickly sealing off the water layer and reduced the risk of permeable loss. And the casing centralizers are used to ensure that the standoff ratio of oil and water layer is above 67%. The displacement with high pump rate (2 m3/min, to ensure the annular return velocity more than 1.2 m/s) can efficiently clean the wellbore by diluting the drilling fluid and washing the mud cake, and can improve the displacement efficiency. The cementing technology has been successfully applied in 100 wells in Tarim Oilfield. The qualification rate and high quality rate is 87.9% and 69% in 2019, and achieve zone isolation. No water has been produced after the oil testing and the water content has decreased to 7% after production. With the cementing technology, we have improved zonal isolation, increased the crude oil production and increased the benefit of oil.

scholarly journals Numerical Simulation of Two-Phase Flows in Heterogeneous Porous Media

2020 ◽  
Vol 21 (2) ◽  
pp. 339
Author(s):  
I. Carneiro ◽  
M. Borges ◽  
S. Malta
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Flow Behavior ◽  
Water Injection ◽  
Heterogeneous Porous Media ◽  
Flow In Porous Media ◽  
High Porosity ◽  
Two Phase ◽  
Recovery Method ◽  
Porosity And Permeability

In this work,we present three-dimensional numerical simulations of water-oil flow in porous media in order to analyze the influence of the heterogeneities in the porosity and permeability fields and, mainly, their relationships upon the phenomenon known in the literature as viscous fingering. For this, typical scenarios of heterogeneous reservoirs submitted to water injection (secondary recovery method) are considered. The results show that the porosity heterogeneities have a markable influence in the flow behavior when the permeability is closely related with porosity, for example, by the Kozeny-Carman (KC) relation.This kind of positive relation leads to a larger oil recovery, as the areas of high permeability(higher flow velocities) are associated with areas of high porosity (higher volume of pores), causing a delay in the breakthrough time. On the other hand, when both fields (porosity and permeability) are heterogeneous but independent of each other the influence of the porosity heterogeneities is smaller and may be negligible.

scholarly journals An Integrated Microfacies and Well Logs-Based Reservoir Characterization of Yamama Formation, Southern Iraq

2021 ◽  
pp. 3570-3586
Author(s):  
Mohanad M. Al-Ghuribawi ◽  
Rasha F. Faisal
Keyword(s):  
Reservoir Characterization ◽  
Water Saturation ◽  
Effective Porosity ◽  
Well Logs ◽  
Petrophysical Properties ◽  
Reservoir Properties ◽  
Thin Sections ◽  
Porosity And Permeability ◽  
South Of Iraq ◽  
Southern Iraq

     The Yamama Formation includes important carbonates reservoir that belongs to the Lower Cretaceous sequence in Southern Iraq. This study covers two oil fields (Sindbad and Siba) that are distributed Southeastern Basrah Governorate, South of Iraq. Yamama reservoir units were determined based on the study of cores, well logs, and petrographic examination of thin sections that required a detailed integration of geological data and petrophysical properties. These parameters were integrated in order to divide the Yamama Formation into six reservoir units (YA0, YA1, YA2, YB1, YB2 and YC), located between five cap rock units. The best facies association and petrophysical properties were found in the shoal environment, where the most common porosity types were the primary (interparticle) and secondary (moldic and vugs) . The main diagenetic process that occurred in YA0, YA2, and YB1 is cementation, which led to the filling of pore spaces by cement and subsequently decreased the reservoir quality (porosity and permeability). Based on the results of the final digital  computer interpretation and processing (CPI) performed by using the Techlog software, the units YA1 and YB2 have the best reservoir properties. The unit YB2 is characterized by a good effective porosity average, low water saturation, good permeability, and large thickness that distinguish it from other reservoir units.

Geostatistics assisted by machine learning for reservoir property modeling: A case study in presalt carbonates of Buzios Field, Brazil

2021 ◽  
Vol 40 (12) ◽  
pp. 876-885
Author(s):  
Danilo Jotta Ariza Ferreira ◽  
Gabriella Martins Baptista de Oliveira ◽  
Thais Mallet Castro ◽  
Raquel Macedo Dias ◽  
Wagner Moreira Lupinacci
Keyword(s):  
Effective Porosity ◽  
Reservoir Properties ◽  
Predictive Capacity ◽  
Seismic Attribute ◽  
Blind Test ◽  
The North ◽  
Basal Section ◽  
Petrophysical Modeling ◽  
Embedded Model ◽  
Porosity And Permeability

An embedded model estimator (EMBER) petrophysical modeling algorithm has been applied to obtain effective porosity and permeability within the presalt carbonate reservoirs of the Barra Velha Formation in Buzios Field, Santos Basin. This advanced methodology was used due to the heterogeneity and complexity of the reservoirs, which makes modeling by conventional geostatistical methodologies difficult. For effective porosity modeling, we chose one facies model, one stratigraphic seismic attribute (acoustic impedance), and one structural seismic attribute (local flatness) as secondary variables. Permeability was modeled by using the best effective porosity simulation result as a secondary variable. Our results demonstrate that average effective porosity and permeability were 0.10 v/v and 440 md, respectively, indicating good reservoir quality throughout the studied area. A vertical trend of high effective porosities and permeabilities for the basal and uppermost reservoir sections was identified in our results, as well as a trend with lower values for these reservoir properties for the intermediate reservoir section. The lower section of the formation presented more continuity, and we infer it to be the best reservoir interval. We observed two horizontal trends for these reservoir properties at the formation top: one of higher values aligned to the north–south direction at the structural highs and another of lower reservoir properties related to isolated structural lows within structural highs. Correlation between modeled results and the blind test ANP-1 well upscaled properties was high, and upscaled well-log property distributions were preserved in the EMBER simulations, proving the predictive capacity of the algorithm. Finally, conditional distributions analysis indicated that the basal section of the Barra Velha Formation presents higher uncertainty for the estimation of effective porosity. Even though this interval is considered to have the best reservoir characteristics, decision making should be done with caution for this section.

Sign in / Sign up

Export Citation Format

Share Document