Development of an optimised integrated underbalanced drilling strategy for cuttings transport in gas-liquid flow through wellbore annuli.

Although understanding the relationship between gas-liquid two-phase fluid flows and the effects of the major drilling variables is critical to optimising underbalanced drilling (UBD) operations, to date, this has been an area of limited research and knowledge. This study contributes to the limited knowledge base by: 1) determining the key operational drilling parameters which shape the gas-liquid two-phase multiphase flow behaviour characteristics during UBD operations, 2) evaluating the most critical operational issues that have impacted the implementation of global UBD programmes, and 3) investigating the Newtonian and non-Newtonian gas-liquid two-phase flow patterns which affect the wellbore hydraulics and cuttings transport efficiency during UBD operations. Thus, this study developed a rigorous integrated strategy for maximising the efficiency of UBD for the transport of cuttings in gas-liquid two-phase flow through wellbore annuli. An experimental approach was applied to analyse and evaluate the relationship between the gas-liquid two-phase flow patterns and the major operational drilling parameters (gas and liquid flowrates, fluid rheology, inner pipe rotation, pipe inclination angle, pipe eccentricity and solid particle size and density) and to investigate their influence and interaction on the fluid flow dynamics and solids transport mechanisms in horizontal and inclined annuli. Experimental results revealed that drilling fluid flowrate along with fluid flow pattern are the most prominent parameters that strongly influence the cuttings transport efficiency within wellbore annuli. Annuli cleaning requirements for a concentric annulus was found to be lower than that required for an eccentric annulus for both Newtonian and non-Newtonian fluids. Pipe inclination angle was shown to affect hole cleaning, with the degree of its effect being significantly influenced by the drilling fluid properties, prevailing gas-liquid fluid flow pattern and cuttings transport mechanism. Moreover, inner pipe rotation was observed to improve cuttings transport in both horizontal and inclined eccentric annuli to varying extents. Experimental evidence was supplemented with a theoretical approach. Flow pattern dependent multi-layered mathematical models applicable for any level of pipe eccentricity were used for the different cuttings transport mechanisms existing in the different fluid flow patterns (dispersed bubble, bubble, and slug), offering a unique method to evaluate cuttings transport efficiency and wellbore hydraulics performance for UBD operations. A favourable comparison was observed between the experimental data and proposed flow pattern dependent multi-layered mathematical models with an error margin of ±15%. This research has generated new knowledge and created value through mapping the factors influencing particle transport and by evaluating the fluid-particle dynamics (fluid forces, gas-liquid fluid flow patterns and particle transport mechanisms) for flow in wellbore annuli. It has further identified and evaluated the effect of gas-liquid two-phase fluid flow patterns on fluid-particle transport dynamics which results in areas of preferential flows and stagnation zones. It also proposed a systematic solution to the governing equations for the simultaneous flow of gas-liquid two-phase fluids and solid particles in wellbore annuli. Overall, the mapping of the major operational drilling parameters and their influence and interdependencies on wellbore dynamics and cuttings transport efficiency in the context of gas-liquid fluid systems, provides a tool for the prediction of cuttings transport mechanism, determination of the stationary bed height, and calculation of the annuli pressure losses. Therefore, wellbore pressure evaluation and management and hole cleaning requirements for UBD operations can be addressed

Correction to: Swelling performance of sodium polyacrylate and poly(acrylamide‑co‑acrylic acid) potassium salt.

The original version of this Article contained an error of judgement in the inclusion of the names of the polymers and their application. The names of the polymers and their application were included, however, due to potential issues relating to confidentiality, it has since been removed from the text, and tables. This information is available from the authors, and the data availability section has been updated to reflect this. These errors have now been corrected in the PDF and HTML versions of the Article

Experimental investigation of the displacement flow mechanism and oil recovery in primary polymer flood operations.

Polymer flooding is a mature chemical enhanced oil recovery method employed in oilfields at pilot testing and field scales. Although results from these applications empirically demonstrate the higher displacement efficiency of polymer flooding over waterflooding operations, the fact remains that not all the oil will be recovered. Thus, continued research attention is needed to further understand the displacement flow mechanism of the immiscible process and the rock–fluid interaction propagated by the multiphase flow during polymer flooding operations. In this study, displacement sequence experiments were conducted to investigate the viscosifying effect of polymer solutions on oil recovery in sandpack systems. The history matching technique was employed to estimate relative permeability, fractional flow and saturation profile through the implementation of a Corey-type function. Experimental results showed that in the case of the motor oil being the displaced fluid, the XG 2500 ppm polymer achieved a 47.0% increase in oil recovery compared with the waterflood case, while the XG 1000 ppm polymer achieved a 38.6% increase in oil recovery compared with the waterflood case. Testing with the motor oil being the displaced fluid, the viscosity ratio was 136 for the waterflood case, 18 for the polymer flood case with XG 1000 ppm polymer and 9 for the polymer flood case with XG 2500 ppm polymer. Findings also revealed that for the waterflood cases, the porous media exhibited oil-wet characteristics, while the polymer flood cases demonstrated water-wet characteristics. This paper provides theoretical support for the application of polymer to improve oil recovery by providing insights into the mechanism behind oil displacement

Swelling performance of sodium polyacrylate and poly(acrylamide-co-acrylic acid) potassium salt.

The application of superabsorbent polymer hydrogels in the oil and gas industry for reservoir and well management is gaining more traction. In this study, the swelling performance and adsorption kinetics of two commercial superabsorbent polymer hydrogels - poly(acrylamide-co-acrylic acid) potassium salt and sodium polyacrylate - were evaluated, based upon their stimuli response to pH and salinity at varying temperature and reaction time periods. Characterisation and evaluation of the materials were performed using analytical techniques - optical microscopy, scanning electron microscopy, thermal gravimetric analysis and the gravimetric method. Experimental results show that reaction conditions strongly influence the swelling performance of the superabsorbent polymer hydrogels considered in this study. Generally, increasing pH and salinity concentration led to a significant decline in the swelling performance of both superabsorbent polymer hydrogels. An optimal temperature range between 50°C and 75°C was considered appropriate, based on swell tests performed between 25°C to 100°C over 2-, 4- and 6-hour time periods. These findings serve as a guideline for field engineers in the use of superabsorbent polymer hydrogels for a wide range of oilfield applications. The study results provide evidence that the two superabsorbent polymer hydrogels can be used for petroleum fraction-saline water emulsions separation, reservoir zonal isolation, water shutoff and cement plugging applications

The combined effect of fluid rheology, inner pipe rotation and eccentricity on the flow of Newtonian and non-Newtonian fluid through the annuli.

The accurate prediction of the fluid dynamics and hydraulics of the axial or helical flow of non-Newtonian drilling fluids in the annuli is essential for the determination and effective management of wellbore pressure during drilling operations. Previous studies have shown that the pressure losses and fluid velocity distributions in the annuli are highly influenced by the rheological properties of the fluid, inner pipe rotary speed and eccentricity. However, many studies in literature have developed or applied theoretical models that were either only valid for Newtonian annuli flows or have not considered the combined effect of the fluid rheological parameters with the inner pipe rotary speed and eccentricity when calculating the frictional annuli pressure losses for non-Newtonian shear thinning fluids. Furthermore, there have been inconsistencies in the description of the effect of inner pipe rotation on the pressure losses experienced for both Newtonian and non-Newtonian flows in concentric and eccentric annuli. In this study, an analytical and numerical approach were carried out to investigate and evaluate the hydrodynamic behaviour of the axial and helical isothermal flow of Newtonian and non-Newtonian fluids through the annuli. Techniques of computational fluid dynamics for fully developed steady-state fluid flow were applied to obtain detailed information of the flow field in the annuli. New analytical and numerical models were developed to obtain the fluid velocity and viscosity field distribution and determine the frictional pressure gradient for laminar and turbulent flows in the concentric and eccentric annuli with and without inner pipe rotation and were compared and validated favourably with models previously presented in literature. Results showed that for a fully developed flow of non-Newtonian shear thinning fluids, if the fluid flowrate is kept constant, an increase in inner pipe rotation leads to a decrease in the axial frictional pressure gradient when the pipe is rotating on its axis. For annuli flows of non-Newtonian fluids, the effect of inner pipe rotation on the axial pressure gradient is dependent on the fluid flowrate and at high fluid flowrates, the influence of the inner pipe rotation on the fluid hydraulics decreases. In general, for shear thinning non-Newtonian fluids, pipe rotation can improve the fluid flow in the region of lower flow in the eccentric annuli. Unlike the flow of Newtonian fluids through the annuli, the friction geometry parameter and thus the friction factor is highly influenced by the rheological parameters of the fluid, the fluid flowrate, inner pipe rotary speed and eccentricity

Effect of two-phase gas-liquid flow patterns on cuttings transport efficiency.

Effective cuttings transport and accurate drilling hydraulics prediction remain issues of concern during drilling operations of horizontal, extended reach and multilateral wells. While several studies have adopted a two- or three-layered modelling approach to evaluate cuttings transport efficiency, they have neglected the effect of the gas-liquid fluid flow pattern within the annulus on cuttings transport. An experimental and theoretical study was carried out to evaluate the interplay between the two-phase gas-liquid flow patterns and the major drilling parameters and investigate its influence on the cuttings and fluid flow dynamics in a horizontal and inclined drilling wellbore. Several mathematical flow pattern dependent multi-layered models valid for any level of wellbore eccentricity were developed for the different cuttings transport mechanisms in the bubble, dispersed bubble, stratified and slug gas-liquid flow patterns, thereby providing a method to evaluate cuttings transport efficiency and perform wellbore hydraulics calculations for underbalanced drilling operations. Experimental results show that both fluid flow pattern and the drilling fluid flowrate are the most influential controllable parameters that affect the cuttings transport efficiency. Moreover, the hole cleaning requirements for an eccentric annulus is higher than that required for the concentric annulus of both single-phase and two-phase Newtonian or non-Newtonian fluids. Inclination angle was also found to influence hole cleaning and the degree of its effect is highly dependent on the fluid properties, the cutting transport mechanism and prevailing gas-liquid flow pattern. In the horizontal and inclined eccentric annuli, drillpipe rotation can improve cuttings transport for both single-phase and two-phase flows, but generally the effect of the drillpipe rotation on two-phase flow for cutting transport is much less than that of the single-phase flow. Overall, a good match was found between the mathematical flow pattern dependent multi-layered models and the experimental data. The findings of this study serve as a guide in the prediction of the wellbore dynamics for underbalanced drilling operations and provides a tool that can be applied for wellbore pressure management and the evaluation of hole cleaning based upon the specified flow conditions

Experimental investigation of the effect of temperature on two-phase oil-water relative permeability

Relative permeability is affected by several flow parameters, mainly the operating temperature and fluid viscosity. Fluid viscosities change with temperature, which correspondingly affects the relative permeability. Temperature is believed to have a considerable effect on oil–water relative permeability, thus a vital input parameter in petroleum reservoir production modelling. The actual effect of temperature on oil-water relative permeability curves has been a subject of debate within the scientific community. The literature shows contradictory experimental and numerical results concerning the effect of temperature on oil-water relative permeability. This work investigates the effect of temperature on oil-water relative permeability using well-sorted unconsolidated silica sandpacks, by adopting the unsteady-state relative permeability method, and by applying numerical history matching technique. The series of experiments were conducted at different temperatures of 40, 60, and 80 °C under three levels of injection flow rate (0.0083, 0.0125, 0.0167 cm3/s) for two different oil samples. The findings show that oil-water relative permeability is a function of temperature, water injection flow rate and oil viscosity. Generally, the profile of oil and water relative permeability curve changes with varying temperature, oil viscosity and water injection flow rate at the same operating condition