A. Al-Ajmi

Parameters of Drag Reducing Polymers and Drag Reduction Performance in Single-Phase Water Flow:

This study presents experimental investigation about the effect of polymer parameters on the performance of the drag reducing polymers in single-phase water flowing in a horizontal pipe of 30.6 mm ID. Master solutions (1000 ppm) of ten high-molecular weight polymers were injected at different flow rates to achieve polymer concentrations in the range of 2–40 ppm in the test section. The drag reduction increased with polymer concentration up to 10 ppm, above which it reached a plateau value. While the drag reduction at the plateau value increases with polymer molecular weight, the maximum drag reduction was not affected by the increase in polymer charge density up to 13%. For instance, the maximum drag reduction for anionic polymers with molecular weight 6–8 million Da. and charge density between 5 and 13% was around 60%, which decreased to around 38% for the polymer with charge density of 25%. Ionic polymers provided more drag reduction than nonionic ones. The overall conclusion is that drag reduction depends on polymer ability to form intermolecular associations and/or its flexibility, which can be enhanced by increasing molecular weight, decreasing charge density, and selecting smaller side groups in the main polymer backbone.

Probabilistic Approach in Wellbore Stability Analysis during Drilling

In oil industry, wellbore instability is the most costly problem that a well drilling operation may encounter. One reason for wellbore failure can be related to ignoring rock mechanics effects. A solution to overcome this problem is to adopt in situ stresses in conjunction with a failure criterion to end up with a deterministic model that calculates collapse pressure. However, the uncertainty in input parameters can make this model misleading and useless. In this paper, a new probabilistic wellbore stability model is presented to predict the critical drilling fluid pressure before the onset of a wellbore collapse. The model runs Monte Carlo simulation to capture the effects of uncertainty in in situ stresses, drilling trajectories, and rock properties. The developed model was applied to different in situ stress regimes: normal faulting, strike slip, and reverse faulting. Sensitivity analysis was applied to all carried out simulations and found that well trajectories have the biggest impact factor in wellbore instability followed by rock properties. The developed model improves risk management of wellbore stability. It helps petroleum engineers and field planners to make right decisions during drilling and fields’ development.

How to economically evaluate a drilling fluid plant? A systematic approach

As the results of government initiative to increase production, large number of wells are planned to be drilled in the next few years. As a consequence of this, huge volumes of drilling fluid are dumped or disposed into land. To maximise savings of drilling fluid, this study aimed to investigate if it is economically viable to set up a drilling fluid plant. This study provides consistent and systematic methodology for evaluating a drilling fluid plant economically. Factors such as well activities, number of fields, location of fields, drilling fluid type and amount of volume dumped act as important elements in determining the feasibility of setting up a drilling fluid plant. Optimum drilling fluid plant locations were determined using analytical method. A practical example is used and detailed economic analysis revealed that it is economically viable to set a drilling fluid plant for the example selected with NPV of

Effect of Water-Soluble Drag-Reducing Polymer on Flow Patterns and Pressure Gradients of Oil/Water Flow in Horizontal and Upward-Inclined Pipes

5 million. The findings show that specific attention is needed for average drilling fluid volume dumped; drilling fluid type and operating costs as they impact economics of the drilling fluid plant the most. [Received: September 03, 2008; Accepted: April 08, 2009]

Experimental Study of the Effects of IFT and Hysteresis on Resistivity and Capillary Pressure of Carbonate Rocks

Experimental investigations of flow patterns and pressure gradients of oil/water flow with and without drag-reducing polymer (DRP) were carried out in horizontal and upward-inclined acrylic pipe of ...

Relation between the Mogi and the Coulomb failure criteria

Characterizing the electrical resistance of the formation rock is of great importance in, for example, interpreting the well log data, calculating the porosity, and water saturation for the formation rocks. The relation between the resistivity factor and porosity and also between the resistivity index and water saturation (Archie equation) in the formation rock uses the parameters, such as the cementation factor and saturation exponent. However, the direct application of Archie equation to carbonate rocks that are very heterogeneous and mostly oil-wet needs further investigation. In this experimental work, the effects of overburden pressure, temperature, and interfacial tension on the capillary pressure and resistivity characteristics during the imbibition and drainage processes are studied. The results showed a decrease of the saturation exponent when the rock changes from the oil-wet to the water-wet, during the primary drainage (e.g., from 5.6 to 2.29), imbibition (e.g., from 3.98 to 1.93), and the secondary drainage (e.g., from 4 to 2.04). As a result, this study improves understanding of the reservoir rock behavior especially when the enhanced oil recovery processes are studied.