scholarly journals Natural Fractures in Carbonate Basement Reservoirs of the Jizhong Sub-Basin, Bohai Bay Basin, China: Key Aspects Favoring Oil Production

Energies ◽  
2020 ◽  
Vol 13 (18) ◽  
pp. 4635
Author(s):  
Guoping Liu ◽  
Lianbo Zeng ◽  
Chunyuan Han ◽  
Mehdi Ostadhassan ◽  
Wenya Lyu ◽  
...  
Keyword(s):  
Oil Production ◽  
Bohai Bay ◽  
Well Testing ◽  
Natural Fractures ◽  
Lower Paleozoic ◽  
Thin Sections ◽  
Mechanical Stratigraphy ◽  
Porosity And Permeability ◽  
Basement Reservoirs ◽  
Dip Angle

Analysis of natural fractures is essential for understanding the heterogeneity of basement reservoirs with carbonate rocks since natural fractures significantly control key attributes such as porosity and permeability. Based on the observations and analyses of outcrops, cores, borehole image logs, and thin sections from the Mesoproterozoic to Lower Paleozoic in the Jizhong Sub-Basin, natural fractures are found to be abundant in genetic types (tectonic, pressure-solution, and dissolution) in these reservoirs. Tectonic fractures are dominant in such reservoirs, and lithology, mechanical stratigraphy, and faults are major influencing factors for the development of fractures. Dolostones with higher dolomite content are more likely to have tectonic fractures than limestones with higher calcite content. Most tectonic fractures are developed inside mechanical units and terminate at the unit interface at nearly perpendicular or high angles. Also, where a thinner mechanical unit is observed, tectonic fractures are more frequent with a small height. Furthermore, the dominant direction of tectonic fractures is sub-parallel to the fault direction or oblique at a small angle. In addition, integrating diverse characteristics of opening-mode fractures and well-testing data with oil production shows that, in perforated intervals where dolostone and limestone are interstratified or dolostone is the main lithologic composition, fractures are developed well, and the oil production is higher. Moreover, fractures with a larger dip angle have bigger apertures and contribute more to oil production. Collectively, this investigation provides a future reference for understanding the importance of natural fractures and their impact on oil production in the carbonate basement reservoirs.

Natural fractures in the Triassic tight sandstones of the Dongpu Depression, Bohai Bay Basin, eastern China: The key to production

2020 ◽  
Vol 8 (4) ◽  
pp. SP71-SP80
Author(s):  
Zhaosheng Wang ◽  
Lianbo Zeng ◽  
Zhouliang Luo ◽  
Kewei Zu ◽  
Haigang Lao ◽  
...  
Keyword(s):  
Crude Oil ◽  
Near East ◽  
Oil Production ◽  
Natural Fracture ◽  
Natural Fractures ◽  
Tight Sandstone ◽  
Thin Sections ◽  
Crude Oil Production ◽  
Dongpu Depression ◽  
East West

Natural fractures are identified as high-quality storage space and seepage channels for the Triassic tight sandstone reservoirs in the Dongpu Depression, playing an important role in tight sandstone oil production. We have evaluated natural fracture growth at different scales using outcrops, cores, thin sections, and imaging logs and analyzed the correlation between fractures and crude oil production capacity with production data. Results show that natural fractures primarily are distributed in fine sandstones and siltstones, which mostly are shear fractures of near east–west and northeast–southwest strikes. The natural fractures of near east–west strikes generally are parallel to the present-day maximum horizontal principal stress with the biggest apertures and the highest permeability, which are the main seepage channels, next being the fractures of northeast–southwest strike. The natural fractures of near east–west strikes also are the most important contributors to the crude oil production in the Triassic tight sandstones of the Dongpu Depression. The intensity, permeability, and direction of natural fractures govern the crude oil productivity in the per-unit sandstone thickness.

First-Ever Vessel-Based Large-Scale Propped Fracturing Treatment in a Tight, Deep, Hot Formation in Bohai Bay Yields Multiple Fold Oil Production Increase

2008 ◽  
Author(s):  
Khay Kok Lee ◽  
Binhai Zhang ◽  
Jianming Deng ◽  
Xiaocheng Zhang ◽  
Meng Seng Tan ◽  
...  
Keyword(s):  
Large Scale ◽  
Oil Production ◽  
Bohai Bay ◽  
Production Increase

Mechanical stratigraphy in Mesozoic rocks of the San Juan Basin: Integration of stratigraphic and structural terms and concepts

2021 ◽  
Vol 58 (2) ◽  
pp. 159-204
Author(s):  
Bruce Hart ◽  
Scott Cooper
Keyword(s):  
Depositional Environments ◽  
Rock Properties ◽  
San Juan ◽  
Primary Control ◽  
Natural Fractures ◽  
Fracture Characterization ◽  
San Juan Basin ◽  
Mechanical Stratigraphy ◽  
Fracture Development ◽  
Shoreline Progradation

We characterize relationships between stratigraphy and natural fractures in outcrops of Mesozoic strata that rim the San Juan Basin in New Mexico and Colorado. These outcrops expose fluvial and shallow-marine siliciclastic deposits and calcareous mudstones deposited in a distal marine setting. We focus primarily on a regionally extensive fracture set formed during the Eocene to minimize localized tectonic effects on fracture development. Where possible, we supplement our observations with wireline log- or laboratory-derived measurements of rock properties. Our goals are twofold: 1) to illustrate how direct integration of data and concepts from stratigraphy and structural geology can lead to better fracture characterization, and 2) to develop thought processes that will stimulate new exploration and development strategies. Genetic beds form one scale of stratification in the outcrops we describe. For example, sandstone beds can be arranged into coarsening and thickening upward successions that are the depositional record of shoreline progradation. In fluvial settings, cm- to dm-scale sandstone beds can also be part of m-scale single-storey channel complexes that, themselves, can be arranged into amalgamated channel complexes 10s of m thick. In these and other settings, it is important to distinguish between beds and features that can be defined via wireline logs because it is the former (cm- to dm-scale) that are usually the primary control the distribution of natural fractures. The extension fractures we describe are typically bed-bound, with bedding being defined by lithology contrasts and the associated changes in elastic properties. Fracture spacing distributions are typically lognormal with average spacing being less than bed thickness. Although mechanical bedding and depositional bedding are commonly the same, diagenesis can cut across bed boundaries and complicate this relationship, especially where lithologic contrasts are small. Deposits from similar depositional environments which undergo different diagenetic histories can have substantially different mechanical properties and therefore deform differently in response to similar imposed stresses.

Unlocking Idle Production in an Offshore Sandstone Oil Field With Gas Hydrate Issues

2021 ◽  
Author(s):  
Babalola Daramola
Keyword(s):  
Gas Hydrate ◽  
Oil Production ◽  
Oil Field ◽  
Third Party ◽  
Flow Assurance ◽  
Well Testing ◽  
Production Wells ◽  
Oil Flow ◽  
Offshore Oil ◽  
Production Losses

Abstract This publication presents how an oil asset unlocked idle production after numerous production upsets and a gas hydrate blockage. It also uses economics to justify facilities enhancement projects for flow assurance. Field F is an offshore oil field with eight subsea wells tied back to a third party FPSO vessel. Field F was shut down for turnaround maintenance in 2015. After the field was brought back online, one of the production wells (F5) failed to flow. An evaluation of the reservoir, well, and facilities data suggested that there was a gas hydrate blockage in the subsea pipeline between the well head and the FPSO vessel. A subsea intervention vessel was then hired to execute a pipeline clean-out operation, which removed the gas hydrate, and restored F5 well oil production. To minimise oil production losses due to flow assurance issues, the asset team evaluated the viability of installing a test pipeline and a second methanol umbilical as facilities enhancement projects. The pipeline clean-out operation delivered 5400 barrels of oil per day production to the asset. The feasibility study suggested that installing a second methanol umbilical and a test pipeline are economically attractive. It is recommended that the new methanol umbilical is installed to guarantee oil flow from F5 and future infill production wells. The test pipeline can be used to clean up new wells, to induce low pressure wells, and for well testing, well sampling, water salinity evaluation, tracer evaluation, and production optimisation. This paper presents production upset diagnosis and remediation steps actioned in a producing oil field, and aids the justification of methanol umbilical capacity upgrade and test pipeline installations as facilities enhancement projects. It also indicates that gas hydrate blockage can be prevented by providing adequate methanol umbilical capacity for timely dosing of oil production wells.

Structure-guided gravity inversion for layered density modeling with an application in the Chezhen Depression, Bohai Bay Basin

Geophysics ◽  
2021 ◽  
pp. 1-54
Author(s):  
Jie Liu ◽  
Jianzhong Zhang
Keyword(s):  
Spline Interpolation ◽  
A Priori ◽  
Structural Similarity ◽  
Gravity Inversion ◽  
Inversion Method ◽  
Bohai Bay ◽  
Bohai Bay Basin ◽  
Lower Paleozoic ◽  
Gas Targets ◽  
Density Modeling

Gravity inversion, as a static potential field inversion, has inherent ambiguity with low vertical resolution. In order to reduce the nonuniqueness of inversion, it is necessary to impose the apriori constraints derived by other geophysical inversion, drilling or geological modeling. Based on the a priori normalized gradients derived from seismic imaging or reference models, a structure-guided gravity inversion method with a few known point constraints is developed for mapping density with multiple layers. The cubic B-spline interpolation is used to parameterize the forward modeling calculation of the gravity response to smooth density fields. A recently proposed summative gradient is used to maximize the structural similarity between the a priori and inverted models. We first demonstrate the methodology, followed by a synthetic fault model example to confirm its validity. Monte Carlo tests and uncertainty tests further illustrate the stability and practicality of the method. This method is easy to implement, and consequently produces an interpretable density model with geological consistency. Finally, we apply this method to the density modeling of the Chezhen Depression in the Bohai Bay Basin. Our work determines the distribution of deep Lower Paleozoic carbonate rocks and Archean buried hills with high-density characteristics. Our results are consistent with the existing formation mechanism of the “upper source-lower reservoir” type oil-gas targets.

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.

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.

Reservoir Quality of the Miocene Formation Gas Deposits, Onshore Abu Dhabi

2021 ◽  
Author(s):  
Catherine Breislin ◽  
Laura Galluccio ◽  
Kate Al Tameemi ◽  
Riaz Khan ◽  
Atef Abdelaal
Keyword(s):  
Depositional Environment ◽  
Middle Miocene ◽  
Quality Analysis ◽  
Reservoir Quality ◽  
Carbonate Facies ◽  
Pore System ◽  
Thin Sections ◽  
Reservoir Architecture ◽  
Porosity And Permeability ◽  
Permeability Anisotropy

Abstract Understanding reservoir architecture is key to comprehend the distribution of reservoir quality when evaluating a field's prospectivity. Renewed interest in the tight, gas-rich Middle Miocene anhydrite intervals (Anh-1, Anh-2, Anh-3, Anh-4 and Anh-6) by ADNOC has given new impetus to improving its reservoir characterisation. In this context, this study provides valuable new insights in geological knowledge at the field scale within a formation with limited existing studies. From a sedimentological point of view, the anhydrite layers of the Miocene Formation, Anh-1, Anh-2, Anh-3, Anh-4 and Anh-6 (which comprise three stacked sequences: Bur1, Bur2 and Bur3; Hardenbol et al., 1998), have comparable depositional organisation throughout the study area. Bur1 and Bur2 are characterised by an upward transition from intertidal-dominated deposits to low-energy inner ramp-dominated sedimentation displaying reasonably consistent thickness across the area. Bur3 deposits imply an initial upward deepening from an argillaceous intertidal-dominated to an argillaceous subtidal-dominated setting, followed by an upward shallowing into intertidal and supratidal sabkha-dominated environments. This Bur3 cycle thickens towards the south-east due to a possible deepening, resulting in the subtle increase in thickness of the subtidal and intertidal deposits occurring around the maximum-flooding surface. The interbedded relationship between the thin limestone and anhydrite layers within the intertidal and proximal inner ramp deposits impart strong permeability anisotropy, with the anhydrite acting as significant baffles to vertical fluid flow. A qualitative reservoir quality analysis, combining core sedimentology data from 10 wells, 331 CCA data points, 58 thin-sections and 10 SEM samples has identified that reservoir layers Anh-4 and Anh-6 contain the best porosity and permeability values, with the carbonate facies of the argillaceous-prone intertidal and distal inner ramp deposits hosting the best reservoir potential. Within these facies, the pore systems within the carbonate facies are impacted by varying degrees of dolomitisation and dissolution which enhance the pore system, and cementation (anhydrite and calcite), which degrade the pore system. The combination of these diagenetic phases results in the wide spread of porosity and permeability data observed. The integration of both the sedimentological features and diagenetic overprint of the Middle Miocene anhydrite intervals shows the fundamental role played by the depositional environment in its reservoir architecture. This study has revealed the carbonate-dominated depositional environment groups within the anhydrite stratigraphic layers likely host both the best storage capacity and flow potential. Within these carbonate-dominated layers, the thicker, homogenous carbonate deposits would be more conducive to vertical and lateral flow than thinner interbedded carbonates and anhydrites, which may present as baffles or barriers to vertical flow and create significant permeability anisotropy.

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