Application of extended elastic impedance in seismic geomechanics

Geophysics ◽  
2019 ◽  
Vol 84 (3) ◽  
pp. R429-R446 ◽  
Author(s):  
Javad Sharifi ◽  
Naser Hafezi Moghaddas ◽  
Gholam Reza Lashkaripour ◽  
Abdolrahim Javaherian ◽  
Marzieh Mirzakhanian

We have evaluated an innovative application of extended elastic impedance (EEI) to integrate seismic and geomechanics for geomechanical interpretation of hydrocarbon reservoirs. EEI analysis is used to extract geomechanical parameters. To verify and assess the capabilities of EEI analysis for extracting geomechanical parameters, we selected a jointed, oil-bearing, shale carbonate reservoir in the southwest of Iran, and we used petrophysical data and core analysis to estimate static and dynamic moduli of the reservoir rock. We calculated the corresponding EEI curve to different intercept-gradient coordinate rotation angles (the chi angle, [Formula: see text]), and we selected the angles of the maximum correlation for the corresponding geomechanical parameters. Then, combining the intercept and gradient, we generated 3D reflectivity patterns of EEI at different angles. To obtain a cube of geomechanical parameters, we performed model-based inversion on the EEI reflectivity pattern. A comparison between the modeling results and well data indicated that the geomechanical parameters estimated by our method were well-correlated to the observed data. Accordingly, we extracted the geomechanical and rock-physical parameters from the EEI cube. We further found that EEI analysis was capable of giving a 3D mechanical earth model of the reservoir with the appropriate accuracy. Finally, we verified the proposed methodology on a blind well and compared the results with those of the simultaneous inversion, indicating comparable levels of accuracy. Therefore, application of this method in seismic geomechanics can bring about significant progress in the future.

2010 ◽  
Vol 50 (1) ◽  
pp. 535 ◽  
Author(s):  
Vamegh Rasouli ◽  
Zachariah Pallikathekathil ◽  
Elike Mawuli

A geomechanics study carried out in the Blacktip field, offshore Australia led to optimum wellbore deviation and azimuth to minimise drilling-associated instability problems near a major fault in the field. Elastic and strength properties of the formations and magnitude of principal stresses in the field were estimated from a mechanical earth model (MEM) based on offset well data. The direction of the minimum horizontal stresses was predicted from formation microresistivity image (FMI) logs available in offset wells. The MEM results were calibrated using results from laboratory experiments, well tests and drilling incidents from drilling reports. The MEM showed that formations at the lower section of the well are very competent and have high uniaxial strength; however, most of the failures in the form of breakouts observed from calliper and image logs were in this interval. Therefore, obtaining a good match between the model and observed failures required a large stress anisotropy to be considered for the lower section of the wellbore. Further investigations demonstrated that this is because the wellbore trajectory at deeper depth gets closer to the major fault plane, and this large stress anisotropy is due to the stress redistribution near the fault. The data from offset well was mapped into the planned trajectory, and the selection of the optimum trajectory and a stable mud weight window for the appropriate section led to successful drilling of the deviated well.


2019 ◽  
Vol 38 (4) ◽  
pp. 254-261
Author(s):  
Deepa ◽  
J. Nagaraju ◽  
Binod Chetia ◽  
Rajeev Tandon ◽  
P. K. Chaudhuary ◽  
...  

Basement exploration in India has seen increased interest after the recent discovery of a field in the Cauvery Basin in southeastern India, with an average individual well production of 700 b/d from a fractured basement reservoir. The field is presently under development, with several development well locations identified for drilling. Optimized development of a fractured basement reservoir requires identification of areas with a permeable fracture network. To meet this objective, we adopted a comprehensive integrated workflow involving the use of common reflection angle migrated seismic data, fracture modeling, a 1D mechanical earth model (MEM), identification of critically stressed fractures in 3D space, fracture permeability/connectivity analysis, and sweet spot identification. The workflow yielded a robust discrete fracture network model based on 3D directional fracture intensity, a 1D MEM that gave regional stress gradients (pore pressure, overburden, Shmin, and SHmax), and rock strength and elastic properties. In addition, we generated a critically stressed 3D fracture model and performed sequential stratal surface restoration for predictive strain modeling that was calibrated at wells. Our fracture permeability and connectivity analysis showed that existing hydrocarbon-producing wells are located within areas that have a fracture cluster/swarm with associated good fracture connectivity. A 3D basement facies model constructed by integrating well data and a poststack inversion impedance volume showed that major flow zones occur in weathered basement associated with low impedance. This model, in combination with fracture intensity data, provides good indication of the location of basement sweet spots in the Cauvery Basin. The understanding gained on the controls of occurrence of basement fractures explains why some wells in the field are producers and others are dry. This led to greater confidence in optimizing the locations of previously proposed new development wells.


2003 ◽  
Author(s):  
P. M. Doyen ◽  
A. Malinverno ◽  
R. Prioul ◽  
P. Hooyman ◽  
S. Noeth ◽  
...  

2021 ◽  
Vol 8 ◽  
pp. 55-79
Author(s):  
E. Bakhshi ◽  
A. Shahrabadi ◽  
N. Golsanami ◽  
Sh. Seyedsajadi ◽  
X. Liu ◽  
...  

The more comprehensive information on the reservoir properties will help to better plan drilling and design production. Herein, diagenetic processes and geomechanical properties are notable parameters that determine reservoir quality. Recognizing the geomechanical properties of the reservoir as well as building a mechanical earth model play a strong role in the hydrocarbon reservoir life cycle and are key factors in analyzing wellbore instability, drilling operation optimization, and hydraulic fracturing designing operation. Therefore, the present study focuses on selecting the candidate zone for hydraulic fracturing through a novel approach that simultaneously considers the diagenetic, petrophysical, and geomechanical properties. The diagenetic processes were analyzed to determine the porosity types in the reservoir. After that, based on the laboratory test results for estimating reservoir petrophysical parameters, the zones with suitable reservoir properties were selected. Moreover, based on the reservoir geomechanical parameters and the constructed mechanical earth model, the best zones were selected for hydraulic fracturing operation in one of the Iranian fractured carbonate reservoirs. Finally, a new empirical equation for estimating pore pressure in nine zones of the studied well was developed. This equation provides a more precise estimation of stress profiles and thus leads to more accurate decision-making for candidate zone selection. Based on the results, vuggy porosity was the best porosity type, and zones C2, E2 and G2, having suitable values of porosity, permeability, and water saturation, showed good reservoir properties. Therefore, zone E2 and G2 were chosen as the candidate for hydraulic fracturing simulation based on their E (Young’s modulus) and ν (Poisson’s ratio) values. Based on the mechanical earth model and changes in the acoustic data versus depth, a new equation is introduced for calculating the pore pressure in the studied reservoir. According to the new equation, the dominant stress regime in the whole well, especially in the candidate zones, is SigHmax>SigV>Sighmin, while according to the pore pressure equation presented in the literature, the dominant stress regime in the studied well turns out to be SigHmax>Sighmin>SigV.  


Author(s):  
A. A. Kushlaf ◽  
A. E. El Mezweghy

This paper is to study the structural framework, stratigraphy, and the petro-physical characteristics of Facha reservoir of Gir Formation in Aswad oil field, which is located in Block NC74B at the Zella Trough, south-west of Sirt basin, Libya. The data used have been got from well-logging records of nine exploratory wells distributed in Aswad oil field. These data have been analyzed and interpreted through using analytical cross-plots in order to calculate the petro-physical parameters. The results revealed that the lithological facies consists mainly of dolomite. Moreover, they revealed that the lateral distribution of the petro-physical parameters of Facha reservoir indicates that average porosity is 10-23%, average water saturation is 52- 93%, and net pay is of 62.44 ft. This shows that Facha member is a good reservoir rock. The variations in values between wells have been affected by the trend of faults; this indicates that the area is structurally controlled.


2021 ◽  
Vol 73 (01) ◽  
pp. 20-22
Author(s):  
Trent Jacobs

In the midst of an industry downturn last year, the Abu Dhabi National Oil Company (ADNOC) reached a new oil production ceiling of 4 million B/D. The UAE’s largest producer has no intentions of slowing down. By decade’s end, ADNOC expects to have raised its maximum daily output by another million barrels. To cross that milestone, the company has set its sights on mastering the tight, thin, and unconventional formations that dot the UAE’s subsurface landscape. One of the places where such developments are hoped to unfold soon is known as Field Q. Found in southeastern Abu Dhabi, Field Q sits above a tight carbonate reservoir that holds an estimated 600 million bbl of oil. But with a permeability ranging from 1 to 3 millidarcy and poor vertical communication, the reservoir and its barrels have proven difficult to cultivate economically - until recently. ADNOC has published new details of its first onshore pilot of a “fishbone stimulation” that involved using more than a hundred hollow needles to pierce as far as 40 ft into the reservoir rock. The additional drainage netted by the fishbone needles boosted production threefold in the test well, as compared with its traditionally completed neighbors on the same pad. ADNOC ran the pilot in the summer of 2019 and by the end of the year saw enough production data to launch a wider 10-well pilot that remains underway. Based on a longer-term data set from these wells, the company will decide whether to leap into a fieldwide deployment of the niche completions technology. In the meantime, the petrotechnical team in charge of the test projects have issued roundly positive reviews of the fishbone technique in two recently presented technical papers (SPE 202636; SPE 203086) from the Abu Dhabi International Petroleum Exhibition & Conference (ADIPEC). “There is a chance that the fishbone-stimulated wells can avoid the drilling of multiple wells targeting different sublayers in the same zone,” said Rama Rao Rachapudi, listing one of several of the technology’s advantages over other approaches that were considered. The senior petroleum engineer with ADNOC, who is one of several authors of the papers that cover both the drilling and completions aspects of the pilot, shared during ADIPEC that his onshore team found motivation to test the technology after bringing in a batch of dis-mal appraisal wells. The fishbone system, also known as multilateral jetting stimulation technology, has been a specialized application ever since it was introduced just over a decade ago. Underscoring the potential impact of the current round of pilots on the technology’s adoption rate, ADNOC noted there were only around 30 worldwide fishbone deployments prior to this project. Most of those have been in the Middle East’s naturally fractured and layered carbonate formations - just like those of Field Q.


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