Leveraging Acoustic Logging for Identification & Quantification of Induced Fractures

2021 ◽  
Author(s):  
Adnan Bin Asif ◽  
Mustafa Alaliwat ◽  
Jon Hansen ◽  
Mohamed Sheshtawy

Abstract The main objective of the acoustic logging in 15K openhole multistage fracturing completions (OH MSFs) is to identify the fracture initiation points behind pipe and contributing fractures to gas production. The technique will also help to understand the integrity of the OH packers. A well was identified to be a candidate for assessment through such technique. The selected well was one of the early 15K OH MSF completions in the region that was successfully implemented with the goal of hydrocarbon production at sustained commercial rates from a gas formation. The candidate well was drilled horizontally to achieve maximum contact in a tight gas sandstone formation. Similar wells in the region have seen many challenges of formation breakdown due to high formation stresses. The objective of this work is to use the acoustic data to better characterize fracture properties. The deployment of acoustic log technology can provide information of fractures initiation, contribution for the production and the reliability of the isolation packers between the stages. The candidate well was completed with five stages open-hole fracturing completion. As the well is in an open hole environment, a typical PLT survey provides the contribution of individual port in the cumulative production but provides limited or no information of contributing fractures behind the pipe. The technique of acoustic logging helped to determine the fracture initiation points in different stages. If fractures can be characterized more accurately, then flow paths and flow behaviors in the reservoir can be better delineated. The use of acoustic logging has helped to better understand the factors influencing fracture initiation in tight gas sandstone reservoirs; resulting in a better understanding of fractures density and decisions on future openhole length, number of fracturing stages, packers and frac ports placement.

1995 ◽  
Vol 35 (1) ◽  
pp. 692
Author(s):  
D.G. Crosby ◽  
D. Tamhane ◽  
Z. Yang ◽  
A.K. Khurana ◽  
V.A. Kuuskraa

The recovery of natural gas from low permeability sandstones in the US has been made commercially possible due, to a large degree, to advanced technologies. The US currently produces 2 TCF annually from tight gas sandstone reservoirs. Large efforts have been directed towards identifying and developing the more productive basinal areas, or 'sweet spots9 of tight gas reservoirs. The identification of natural fractures prior to drilling, through the use of remote imagery in combination with established methods such as magnetic and gravity mapping, is currently being pioneered. Reduction in well-bore stimulation costs through development and application of advanced hydraulic fracture technology has improved the economics of tight gas production. The use of 3D fracture models in combination with realistic insitu stress profiles, appropriate proppants and effective quality controls have greatly increased well productivities through smaller, more efficient fracture treatments. Treatments have been successfully designed to avoid damage to natural fractures.Large tight gas sandstone resources similarly exist in the Cooper and Perth Basins of Australia and in the Taranaki Basin of New Zealand, although these resources remain largely untapped. To date, less than 50 BCF has been produced from Australian and New Zealand tight sandstones, largely from the Tirrawarra Sandstone and Patchawarra Formation of the Cooper Basin and the Ngatoro/McKee Formations of the Taranaki Basin. These formations compare well however, in terms of depositional environments with prolific US tight gas producing formations. They appear to be well placed to take advantage of the experiences and technologies gained by their US counterparts as well as through site specific adaptation of such technologies and the development of new technologies.


2021 ◽  
pp. 1-47
Author(s):  
Chao Li ◽  
Peng Hu ◽  
Jing Ba ◽  
José M. Carcione ◽  
Tianwen Hu ◽  
...  

Tight-gas sandstone reservoirs of the Ordos Basin of China are characterized by high rock-fragment content, dissimilar pore types and a random distribution of fluids, leading to strong local heterogeneity. We model the seismic properties of these sandstones with the double-double porosity (DDP) theory, which considers water saturation, porosity and the frame characteristics. A generalized seismic wavelet is used to fit the real wavelet and the peak frequency-shift method is combined with the generalized S-transform to estimate attenuation. Then, we establish rock-physics templates (RPTs) based on P-wave attenuation and impedance. We use the log data and related seismic traces to calibrate the RPTs and generate a 3D volume of rock-physics attributes for the quantitative prediction of saturation and porosity. The predicted values are in good agreement with the actual gas production reports, indicating that the method can be effectively applied to heterogeneous tight-gas sandstone reservoirs.


2021 ◽  
pp. 1-14
Author(s):  
Ahmed Farid Ibrahim ◽  
Salaheldin Elkatatny ◽  
Yasmin Abdelraouf ◽  
Mustafa Al Ramadan

Abstract Water saturation (Sw) is a vital factor for the hydrocarbon in-place calculations. Sw is usually calculated using different equations; however, its values have been inconsistent with the experimental results due to often incorrectness of their underlying assumptions. Moreover, the main hindrance remains in these approaches due to their strong reliance on experimental analysis which are expensive and time-consuming. This study introduces the application of different machine learning (ML) methods to predict Sw from the conventional well logs. Function networks (FN), support vector machine (SVM), and random forests (RF) were implemented to calculate the Sw using gamma-ray (GR) log, Neutron porosity (NPHI) log, and resistivity (Rt) log. A dataset of 782 points from two wells (Well-1 and Well-2) in tight gas sandstone formation was used to build and then validate the different ML models. The data set from Well-1 was applied for the ML models training and testing, then the unseen data from well-2 was used to validate the developed models. The results from FN, SVM and RF models showed their capability of accurately predicting the Sw from the conventional well logging data. The correlation coefficient (R) values between actual and estimated Sw from the FN model were found to be 0.85 and 0.83 compared to 0.98, and 0.95 from the RF model in the case of training and testing sets, respectively. SVM model shows an R-value of 0.95 and 0.85 in the different datasets. The average absolute percentage error (AAPE) was less than 8% in the three ML models. The ML models outperform the empirical correlations that have AAPE greater than 19%. This study provides ML applications to accurately forecast the water saturation using the readily available conventional well logs without additional core analysis or well site interventions.


Geophysics ◽  
2010 ◽  
Vol 75 (1) ◽  
pp. B1-B10 ◽  
Author(s):  
Vladimir Grechka ◽  
Prajnajyoti Mazumdar ◽  
Serge A. Shapiro

The main objective of hydraulic well stimulation is creating fractures in a tight rock that enhance its natural permeability and make hydrocarbon production economic. Because the geometry of fractures and the permeability of treated formation influence the subsequent production, their assessment is important for the development of tight-gas fields. The fracture shapes and orientations are inferred conventionally from microseismic data acquired in the process of well stimulation, but the same data also can be used to estimate the formation permeability. We have compared two techniques for permeability estimation that utilize different aspects of information contained in the observed microseismicity. We applied those techniques to data recorded in the course of the hydraulic fracturing of four wells drilled in the Pinedale Field, Wyoming, U.S.A. Then we used the obtained permeabilities to predict the gas rates from 20 treatment stages at which the number of identified microseismic events was sufficient to perform our analysis. The predictions of both techniques correlate with production and allow us to establish the characteristics of rocks and hydraulic fractures that make good producers at Pinedale.


2019 ◽  
Vol 11 (10) ◽  
pp. 2838 ◽  
Author(s):  
Amjed M. Hassan ◽  
Mohamed A. Mahmoud ◽  
Abdulaziz A. Al-Majed ◽  
Dhafer Al-Shehri ◽  
Ayman R. Al-Nakhli ◽  
...  

Unconventional reservoirs have shown tremendous potential for energy supply for long-term applications. However, great challenges are associated with hydrocarbon production from these reservoirs. Recently, injection of thermochemical fluids has been introduced as a new environmentally friendly and cost-effective chemical for improving hydrocarbon production. This research aims to improve gas production from gas condensate reservoirs using environmentally friendly chemicals. Further, the impact of thermochemical treatment on changing the pore size distribution is studied. Several experiments were conducted, including chemical injection, routine core analysis, and nuclear magnetic resonance (NMR) measurements. The impact of thermochemical treatment in sustaining gas production from a tight gas reservoir was quantified. This study demonstrates that thermochemical treatment can create different types of fractures (single or multistaged fractures) based on the injection method. Thermochemical treatment can increase absolute permeability up to 500%, reduce capillary pressure by 57%, remove the accumulated liquids, and improve gas relative permeability by a factor of 1.2. The findings of this study can help to design a better thermochemical treatment for improving gas recovery. This study showed that thermochemical treatment is an effective method for sustaining gas production from tight gas reservoirs.


2011 ◽  
Vol 14 (03) ◽  
pp. 357-376 ◽  
Author(s):  
Nisael Solano ◽  
Liliana Zambrano ◽  
Roberto Aguilera

Summary 271 wells producing exclusively from the Nikanassin and equivalent formations in a very large area of more than 15,000 km2 in the Western Canada Sedimentary basin (WCSB), Alberta and British Columbia, Canada, have been evaluated with a view to determine the distribution of cumulative gas production and the possibilities of intensive infill drilling. The Upper Jurassic to Lower Cretaceous Nikanassin formation is generally characterized as a tight gas formation with low values of permeability (typically a fraction of millidarcy) and low porosities (usually less than 6%). It is likely that natural microfractures and slot pores dominate the productivity of the formation. The study area was divided into six smaller narrow areas (A through F) approximately parallel to the northwest/southeast-trending thrust belt of the Canadian Rocky Mountains. Area A is located to the west of the deformation edge, Area B is on the deformation edge, and Areas C through F are located to the east. Area C is the deepest and closest to the thrust belt, whereas Area F is the shallowest and farthest from the thrust belt. Cumulative production characteristics within each area were evaluated with a variability distribution model (VDM) developed recently for naturally fractured reservoirs. The evaluation of each one of the six areas (271 wells) resulted in coefficients of determination, R2 greater than 0.99 in all cases. The results indicate that the gas cumulative production distribution per well is more homogeneous along the deformation edge (Area B), in which 80% of the wells contribute approximately 50% of the cumulative production. The highest heterogeneity was found in Area F (the shallowest), with 80% of the wells contributing only 25% of the cumulative gas production. Areas A, C, D, and E have more or less the same distribution with 80% of the wells contributing between 35 and 45% of the cumulative gas production. In preliminary terms, there is an association between the cumulative-production distribution and lateral variations of borehole breakouts in the Nikanassin formation on a transect perpendicular to the deformation belt of the WCSB. Analysis of the distributions leads to the conclusion that the Nikanassin is a very heterogeneous formation and that there is significant potential for massive drilling to efficiently drain the formation. The possibilities of horizontal wells and multistage hydraulic-fracturing jobs are being investigated at this time.


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