Improved formation density measurement using controllable D-D neutron source and its lithological correction for porosity prediction

Controllable D-D neutron sources have a long service life,low cost,and non-radioactivity.There are favorable prospects for its application in geophysical well logging,since traditional chemical radioactive sources used for well logging pose potential threats to the safety of the human body and environment.This paper presents an improved method to measure formation density that employs a D-D neutron source.In addition,the lithological effect on the measured density was removed to better estimate the formation porosity.First,we investigated the spatial distribution of capture gamma rays through Monte Carlo simulations as well as the relationship between the ratio of capture gamma ray counts and formation density to establish theoretical support for the design of density logging tools and their corresponding data processing methods.Second,we obtained the far to near detector counts of captured gamma rays for an optimized tool structure and then established its correlation with the density and porosity of three typical formations with pure quartz,calcite,and dolomite minerals.Third,we determined the values for correcting the densities of sandstone and dolomite with the same porosity using limestone data as the reference and established the equations for calculating the correction values,which lays a solid foundation for accurately calculating formation porosity.We observed that the capture gamma ray counts first increased then decreased and varied in different formations;this was especially observed in high-porosity formations.Under the same lithologic conditions(rock matrix),as the porosity increases,the peak value of gamma ray counts moves toward the neutron source.At different detector-source distances,the ratio of the capture gamma ray counts was well correlated with the formation density.An equation of the formation density conversion was established based on the ratio of capture gamma ray counts at the detector-source distances of 30 cm and 65 cm,and the calculated values were consistent with the true values.After correction,the formation density was highly consistent with the true value of the limestone density,and the mean absolute error was 0.013 g/cm3.The calculated porosity values were very close to the true values,and the mean relative error was 2.33%,highlighting the accuracy of the proposed method.These findings provide a new method for developing D-D neutron source logging tools and their well-log data processing methods.

Porosity Prediction from Well Logs Using Back Propagation Neural Network Optimized by Genetic Algorithm in One Heterogeneous Oil Reservoirs of Ordos Basin, China

A reliable and effective model for reservoir physical property prediction is a key to reservoir characterization and management.At present,using well logging data to estimate reservoir physical parameters is an important means for reservoir evaluation.Based on the characteristics of large quantity and complexity of estimating process,we have attempted to design a nonlinear back propagation neural network model optimized by genetic algorithm(BPNNGA)for reservoir porosity prediction.This model is with the advantages of self-learning and self-adaption of back propagation neural network(BPNN),structural parameters optimizing and global searching optimal solution of genetic algorithm(GA).The model is applied to the Chang 8 oil group tight sandstone of Yanchang Formation in southwestern Ordos Basin.According to the correlations between well logging data and measured core porosity data,5 well logging curves(gamma ray,deep induction,density,acoustic,and compensated neutron)are selected as the input neurons while the measured core porosity is selected as the output neurons.The number of hidden layer neurons is defined as 20 by the method of multiple calibrating optimizations.Modeling results demonstrate that the average relative error of the model output is 10.77%,indicating the excellent predicting effect of the model.The predicting results of the model are compared with the predicting results of conventional multivariate stepwise regression algorithm,and BPNN model.The average relative errors of the above models are 12.83%,12.9%,and 13.47%,respectively.Results show that the predicting results of the BPNNGA model are more accurate than that of the other two,and BPNNGA is a more applicable method to estimate the reservoir porosity parameters in the study area.