Conventional low-permeability sandstone formations with strong shale barriers require hydraulic fracturing (HF), a classical approach to fracture geometry optimization, which is needed to enhance oil production of each well and oil recovery from such fields overall. Unfortunately, in most cases there are insufficient resources to acquire the information to create precise fracture modeling for every suggested well. Rock elastic properties and distribution of in-situ stresses have the greatest influence on fracture geometry. HF modeling without proper understanding of these parameters usually results in loss of the relationship between log or core data and zone properties in the model.
A new, innovative approach provides the ability to extract mechanical rock properties for each well from a standard log dataset. This was achieved by introducing correlation functions based on multiple wells with an advanced log dataset including density and acoustic logs and core analysis to correlate dynamic and static rock properties. Correlation functions were built into a Geomechanical (GM) software module referred to here as the GM Module.
The module can be used with any commercial fracture simulator to automate and link the process to log data during each step of the HF modeling and evaluation workflow. Although a majority of studied wells produce from several separately stimulated layers, an adjustment in the GM Module for one HF treatment allows a continuous model of geomechanical properties and stress distribution to be built along the entire logging interval.
As a first step, the module was integrated into a standard modeling workflow for 60 HF treatments; comparative study of the improved versus conventional approach was performed. Second step will be to introduce the GM Module to a stimulation service company operating in Priobskoe oilfield, one of the world's largest oilfields, which will ensure uniform and reliable control over the fracture optimization process to enhance overall field development and oil recovery.
Analysis of opportunity of multiple fractured horizontal wells application in low-permeability zones of Priobskoye oil field is considered. Geological and engineering issues of area selection for horizontal wells drilling and features of multi-staged fracturing design are discussed. Brief description of completion technology applied is observed. Comparison between fractured horizontal wells and fractured vertical wells performance based on detailed flow simulation is presented.
Well performance monitoring is extremely useful to effectively control hydrocarbon production and make timely decisions when it comes to run various well interventions. The more ample and correct are the data at our disposal, the more efficient will be the management. Traditionally little attention is given to the gas liberated at oil degassing and no measurements are taken; although this kind of data would allow computing a number of rather critical figures, such as gas content in the mixture, bottomhole pressure, etc.
For the moment maximum 20% of all the wells in the Priobskoye field are outfitted with the PHD sensors, and the BHP as well as the pressure at the ESP intake for the most of the wells are computed. This kind of computation requires an ESP separation efficiency function. However, all the available efficiency-function computation equations are based on tests run on recombined liquid/gas mixtures at lab setups, that is, under ideal conditions.
In this paper we put focus on the efforts to evaluate the free gas separation at the ESP intake; estimate the bottomhole pressure based on production data; and assess the gas separation impact on both the pumping unit performance (variation of Q-H characteristics) and the in the tubing and annulus flow parameters.
Measurements of the dynamic level and wellhead annulus pressure that vary with time and allow computation of the fraction of the gas separated were used as input data. As well as the data collected with the PHD sensors, or pressure gauges below the ESP.
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