Hamed Hamoud Al-Sharji

Segregated pathways mechanism for oil and water flow through an oil-based gelant

Abstract Excessive water production during oil and gas recovery is often controlled by the injection of polymer-based gels into the near well-bore formation. Certain polymers and gels, when placed within a porous rock, are known to reduce the water permeability much more than oil permeability (often known as disproportionate permeability reduction, DPR). Different mechanisms have been postulated to explain the relative permeability change, one of the most widely accepted of which is the mechanism of segregated pathways. The key element of this mechanism is that a water-based gelant will follow the water pathways, producing a gel in these pathways, thereby reducing the water permeability. Likewise, an oil-based gelant should follow the oil pathways and preferentially reduce the oil permeability. A series of two-phase flow experiments were performed in transparent micromodels under both water-wet and oil-wet conditions to test this hypothesis. An oil-based gelant, a solution of tetramethyl orthosilicate (TMOS) in oil that preferentially reduces water permeability, was used. This is in contrast to the relative permeability effects reported for most oil-based gelants. The tetramethyl orthosilicate oil-based gelant follows the oil pathways, but only reacts with the water, to produce a silicate gel. The gel therefore dramatically reduces the water permeability in the water-occupied regions, and also induces the formation of new water paths between the oil and the gel. The results from studies in water-wet and oil-wet media confirm that the flow of oil-based gelant through the oil paths, and its subsequent reaction with water, produced a significant reduction of water flow but less change in the oil flow. Visual and quantitative evidence that segregated paths cause a preferential reduction in water permeability, and a disproportionate permeability reduction, are presented.

Investigation of Inducing Vibration to Reduce Friction of Coiled Tubing in Deep Drilling Operations

This work examines the buckling behavior of constrained horizontal tubular in a cylinder subjected to axial compression force. Such configurations are of interest to coiled tubing (CT) and conventional hydrocarbon drilling. When compression force is applied beyond a critical value the coiled tubing (CT) will buckle forming sinusoidal wave and with increasing the load the CT ultimately goes into a helical configuration. The friction is introduced due to the contact between the CT and the borehole wall. Increasing the CT friction eventually leads to lock-up length beyond which the drilling cannot proceed further. Vibration is a well-known technique to reduce friction between contacting bodies in many engineering systems. An in-house experimental setup is developed to imitate the wellbore being drilled with the presence of drilling fluids and vibrating facility that has the capability to vibrate the CT axially. The setup is employed to examine the effects of amplitude and frequency of vibration on the axial force transfer and weight on bit (WOB) at normal and high temperature environments. Results show that both amplitude and frequency have significant effects in reducing the friction and they alter the buckling behavior on both normal and high temperature.Copyright

Investigation of frictional effects on buckling behavior of drill string

The in-house developed experimental setup that imitates the wellbore being drilled in presence of surrounding drilling fluid is utilized to investigate the buckling phenomena of drill string. The paper also presents experimental investigations on the effect of changing the friction coefficient on the buckling lock-up situations of drill string. Results reveal that axial transferred loads decrease with the increase of friction coefficient. The results, highlights the significance of changing the drilling fluid rheology, mainly the friction factor, to reduce the friction between the wellbore and the tubing, and thus improve axial force transfer which is mainly responsible for initiation of buckling and limited reach of drilling operation. Drilling fluid with lower friction factor significantly reduces the friction between the tubing and the wellbore. The tube takes the same shape with the change of COF at the same load.Copyright

Experimental Evaluations for the Effects of Amplitude and Frequency of Vibration on the Friction of Coiled Tubing in Hydrocarbon Drilling Operations

In a hydrocarbon drilling operations, when an axial load is applied beyond a critical value the coiled tubing (CT) will buckle forming sinusoidal wave and with increasing the axial load the CT ultimately goes into a helical configuration. The higher number of contacts between the CT and the wellbore the more friction is introduced. Increasing the CT friction, due to increasing the area of contact with the wellbore, eventually leads to lock-up length beyond which the drilling cannot proceed further. Vibration is understood to be a well-known technique to reduce friction between contacting bodies in many engineering systems. An in-house experimental setup is developed to imitate the wellbore being drilled with the presence of vibrating facility that has the capability to vibrate the CT axially. The setup is employed to examine the effects of amplitude and frequency of vibration on the friction force, between the CT and the wellbore, and on the axial load transfer or the weight on bit (WOB) of the CT. Response surface methodology is used to produce a prediction model to determine the effects of various amplitudes and frequencies the WOB of the CT. The investigations have shown that both amplitude and frequency of vibration have positive effects on reducing friction force and increasing WOB. The actual and predicted optimal designs are also presented in this work.Copyright

Production Logging Low Flow Rate Wells with High Water Cut

Production logging low flow rate wells is difficult because mechanical spinners have a small dynamic range in slow moving fluids. Low flow rates in horizontal wells means the fluid holdups in the stratified flow are very sensitive to the wellbore inclination, and the high water cut means a small proportion of the flowing liquid will be oil. At what point do these compounding affects limit the ability of current technology to measure low oil flows?