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Ofei, Titus Ntow (Norwegian University of Science and Technology) | Lund, Bjørnar (SINTEF) | Saasen, Arild (University of Stavanger) | Sangesland, Sigbjørn (Norwegian University of Science and Technology) | Linga, Harald (SINTEF) | Gyland, Knud Richard (M-I SWACO, Schlumberger Norge AS) | Kawaji, Masahiro (City College of New York)
Incidences with sag of solid weighting agents in drilling fluids can lead to potential drilling impediments including; loss of wellbore control, lost circulation, stuck pipe and high torque. The presence of sag has relatively often been the cause for gas kicks and oil-based drilling fluids are known to be more vulnerable for sag than water-based drilling fluids. Separation of weighting materials in a non-moving fluid column is referred to as static sag while sag in a flowing fluid is normally referred to as dynamic sag. An approach to obtain static and dynamic barite sag measurement protocols is presented to examine the effects of rheological and viscoelastic properties of typical field oil-based drilling fluids on barite sag performance. Static sag results are computed based on modified Stokes settling theory while dynamic sag results are compared for rotational and oscillatory ultra-low to low shear conditions. For static sag measurements, an optical scanning analyzer, which is based on the principle of multiple light scattering was used to characterize the stability and particles settling speed of the drilling fluid samples. A cylindrical glass cell containing 20
Saasen, Arild (University of Stavanger) | Pallin, Jan Egil (JAGTECH AS) | Ånesbug, Geir Olav (JAGTECH AS) | Lindgren, Alf Magne (Schlumberger Oilfield Services) | Aaker, Gudmund (Schlumberger Oilfield Services) | Rødsjø, Mads (AkerBP)
Different logging operations can suffer from presence of metallic particles in the drilling fluids. Directional drilling in Arctic areas can be a challenge because of magnetic contamination in the drilling fluid. This is a challenge especially when drilling east-west relative to the magnetic north direction. Magnetic and paramagnetic particles in the drilling fluid will shield the down hole compasses and introduce additional errors to the surveying than those normally included in the uncertainty ellipsoid. The objective of the project is to remove the magnetic particles being the largest contributor to this error.
On many offshore drilling rigs there is mounted ditch magnets to remove metallic swarf from the drilling fluid. These magnets will normally only remove the coarser swarf. In this project we use a combination of strong magnets and flow directors to significantly improve the performance of the ditch magnets. This combination, together with proper routines for cleaning the ditch magnets significantly helps cleaning the drilling fluid.
By the combined use of flow directors and ditch magnets it was possible to extract more than five times as much magnetic contamination from the drilling fluid. This is verified by comparing the ditch magnet efficiencies from two drilling rigs drilling ERD wells. The logging tool signal strengths of several down hole instruments were unusually good and insignificant down times were observed on the logging tools. The results are anticipated to have aided to the directional drilling performance.
Detailed information on how to clean the drilling fluid properly from magnetic contamination is presented. It is also shown that this cleaning is significantly better than conventional cleaning of magnetic debris from drilling fluids.
In recent years, drilling fluids have become more complex in nature to satisfy diverse requirements in drilling operations. Accurate prediction of the frictional pressure losses while drilling is complex because of a combination of various drilling parameters. In the present study, a computational-fluid-dynamics (CFD) analysis is performed to investigate the hydraulics of solids-free non-Newtonian drilling fluids with an eccentric annulus coupled with a rotating drillstring. The Herschel-Bulkley fluid model is used to describe the non-Newtonian fluid behavior of the drilling fluid. Annular inlet fluid velocities are varied from 0.5 to 1.2 m/s (laminar flow). Simulation results are compared with the experimental data from the in-house flow-loop results. The flow loop has a 10-m-long annulus section with a 100-mm-inner-diameter (ID) wellbore and 50-mm-outer-diameter (OD) fully eccentric drillstring. Pressure-drop results from the flow-loop experiments at various flow velocities with and without drillstring rotation are reported. Experimental results show that the pressure drop increases with the drillstring rotation in an eccentric annulus. Pressure-drop predictions from CFD analysis are in close agreement with the experimental results. Also, it has been observed that drilling fluids with similar viscosity profiles measured according to API RP 13D (2017) can have significantly different hydraulic and cuttings-transport behavior. As observed from experimental results, drilling fluids with similar viscosity profiles and density have different pressure drops. This study will contribute to a better understanding of the hydraulic behavior of drilling fluids.
The estimated frictional pressure loss of fluid flow in a pipe is highly dependent on the rheological properties of the fluid. The applied curve fitting method of the viscosity curve will impact the accuracy of the modelled frictional pressure loss. This study evaluates a new approach for application of the power law model previously presented by Saasen and Ytrehus (2018), using dimensionless shear rates, allowing for simpler comparison between fluid characteristics.
The modelling approach is based on selecting an appropriate characteristic shear rate for the flow, replacing the consistency index. The curvature exponent is subsequently fitted to the shear rate region of interest. The applied test fluid is Poly-Anionic Cellulose (PAC) in aqueous solutions. Apparent viscosity measurements have been performed using a high precision rheometer (Anton Paar MCR 302) keeping the temperature constant at 20˚C.
A method for evaluating the accuracy of estimated frictional pressure loss when using the new model of Saasen and Ytrehus is presented. The uncertainty evaluation of the derived model coefficients is based on the estimated probability distribution of the apparent viscosity measurements and error in the model parameter estimation. This uncertainty is further propagated in the estimated frictional pressure loss for evaluation of total modelling accuracy. The new simplified model is more robust and reduces the need for iterative calculations. It has the advantages of simplifying digitalization of the drilling process, being easier and quicker to curve fit at the rig and making it easier to compare different fluids.
Considering the uncertainties related to the rheological properties of the fluid and the impact on the frictional pressure loss is highly applicable when evaluating non-Newtonian fluid flow in pipes. This increased understanding of the uncertainties related to the modelled frictional pressure is also essential information when automating the drilling process.
Occasionally the drilling fluid pressure exceeds the fracturing pressure and drilling fluid is lost to the formation. Several types of lost circulation materials (LCM) are used to heal such losses. However, in standard testing procedures like American Petroleum Institute Recommended Practice 13-1 or 13-2, only a 100psi or 500psi differential pressure is required in the pressure cell for LCM testing. It is shown that this pressure is by far too small to give any meaningful data for LCM performance.
Lost circulation can occur in all well sections. Especially, will lost circulation represent a potential problem during drilling long sections with varying formation strengths and varying formation pressures. In a typical drilling situation, the minimum static overbalance in the well is more than 100psi in order to control the formation pressures and avoid influx of formation fluids into the wellbore. During drilling this overbalance will increase due to, amongst others, frictional effects. These effects, together with variations in formation pressures sometimes lead to dynamic differential pressures exceeding 2000 or even 3000psi. Testing under conditions exceeding the expected maximum differential pressures are meaningful in order to identify the sealing capabilities of LCM materials under such conditions.
Some tests focus on losses through tapered slots. In such cases particles larger than the slot outlet will sooner or later contribute to stopping the loss. In a real situation the fracture would be in position to open further. Hence, such tests are not optimal. Other tests are based on slot openings as the minimum size. In such cases the fluids will need to bridge off the opening to work. Based on bridging formation ideas, a development of new LCMs was conducted. These LCMs were able to handle downhole pressure differences.
Slotted disks were installed into a high-pressure cell. The slots were 18.00 mm long and 400, 700, 1600, 2000 and 2500μm wide which were made into disks with a diameter of 24.13 mm. Drilling fluid was pumped through the cell and an LCM filter cake was formed across the disk slot. The pressure required to break this filter cake was obtained (unless it exceeds 5000 psi) and recorded. The fluid filtration losses through the apparatus was strongly dependent on the LCM concentration. A set of LCM tests was performed, and examples are given where the LCM actually would withstand a differential pressure 5000 psi across the slotted disks without failing.
In recent years, nanomaterials have attracted researcher's attention especially in the field of oil and gas. Nanomaterials based research results showed an improved performance in the areas of cement, drilling fluid and enhanced oil recovery. In this study, the effects of Boron Nitride (BN) microparticles on mechanical friction, fluid loss and viscosity were investigated. Boron Nitride (BN) microparticles were dispersed in a solution of Carboxymethylcellulose (CMC) and Fe2O3 nanoparticles were dispersed in Xanthan gum (XG) solution in water. Both fluids were treated with KCl and bentonite to create laboratory drilling fluid systems, which were studied at 22 °C.
The results show that the addition of 0.0095 wt. % BN and Fe2O3 reduced the mechanical friction coefficients of the laboratory drilling fluids by 37 %, and 43 %, respectively. Fe2O3 nanoparticles reduced the API static filtrate loss by 14.3 %, but the addition of BN didn't show any impact on filter loss. The particles have also shown an impact on the drilling fluid's viscosity parameters. The essence of this study is to understand the effect of nanoparticles on the drilling fluid performance and to get the better idea of how nanoparticles can contribute to improve the drilling fluid properties.
Brown, Christian F. (ALTISS Technologies LLC) | Podnos, Evgeny G. (ALTISS Technologies LLC) | Saasen, Arild (University of Stavanger) | Dziekonski, Mitchell (ALTISS Technologies AS) | Furati, Mostafa Al (ALTISS Technologies AS)
Drill string vibrations are a significant concern during drilling operations, and are a common cause of downhole tool failures and decreases in drilling efficiency. Drill string vibrations are typically categorized in three ways: axial (the drill string is vibrating along the axis of drilling), lateral (the drill string is vibrating perpendicular to the axis of drilling), and torsional (the rotational speed of the drill string is varying along the axis of rotation).
If applied correctly, the use of low elastic modulus and low density materials in a complex system will dampen vibrations. This hypothesis is confirmed through the use of multiple software simulations including an ABAQUS Finite Element Analysis (FEA) model and an MSC Adams multi-body dynamics model.
The simulations pointed to the conclusion that including sections of aluminum drill pipe into the drill string will dampen drill string vibrations (
It is common practice to use steel casing when constructing and completing oil wells. However, well integrity issues caused by corrosion require well intervention operations which increase the non-productive time. This has led to investigations by researchers and engineers to improve the corrosion resistance of steel by modifying alloying elements. Some other researchers have suggested the use of aluminum alloy casing because of its resistance to corrosive H2S environments, and its lightweight characteristics. However, utilization of aluminum strings has not been reported in North Sea field applications. Although the durability of aluminum in corrosive environments is of interest, there are some other areas to be studied more in detail. These subjects include but are not limited to, mechanical properties of aluminum alloy, galvanic corrosion between the aluminum tubing and steel coupling, pipe wear, and interaction between cement and aluminum casing. Also the potential use of titanium casing elements can be of interest for selected applications.
The primary goals of oil well cementing are achieving proper zonal isolation and anchoring the casing in the well. To evaluate these objectives, cement samples and casing alloys were tested in the lab prior to field operations. This lab testing includes measuring the hydraulic and shear bond strength between the cement and casing after the cement cures.
In this study, shear bond strength and hydraulic bond strength between Portland cement and six different types of pipe were measured. The pipe samples tested were a titanium alloy and different aluminum alloys with coatings, and a steel pipe used as a reference. Three different Portland cements were used: two types of API Class G oil well cement and one rapid hardening cement. The obtained results showed that of these pipe systems, three showed a higher shear bond strength: titanium pipe, coated aluminum pipe, and steel pipe. Subsequently, these three pipes were used for measurements of hydraulic bond strength.
Controlled annual mud level (CAML) is a managed-pressure drilling technology used to drill deep and ultradeep offshore wells that often encounter narrow and challenging operating windows. This technique uses a submersible pump to change the liquid level in the riser to control the bottomhole pressure (BHP) during drilling operations. The flexibility in changing the liquid level in the riser allows the use of higher-density drilling fluids, as well as higher pump rates.
In this paper, a sensitivity analysis is carried out to study the possibility of synergizing the CAML drilling technique and drilling-fluid performance to optimize the casing-design program. Drilling-fluid density, fluid rheological properties, sagging potential, lost circulation, and hole cleaning are the main investigated variables. The results show that, if sag-prevention properties and fluid rheological parameters are controlled, changing the liquid level in the riser and using higher-density drilling fluids will enable drilling deep, challenging offshore wells. In addition, the number of casing strings can be reduced with the proposed synergistic approach. A case study is performed in this paper for an offshore well in the Black Sea to validate this approach. The validation reveals that, if the synergistic approach is applied, the number of casing strings is reduced by approximately 26% in comparison to a conventional casing design. The paper also proposes a best-practice guideline of how to synergize the CAML drilling technique and drilling-fluid performance to optimize the casing-design program.
A reservoir-conditions coreflood study was undertaken to assist with design of drilling and completion fluids for a Norwegian field. Multiple fluids were tested, and the lowest permeability alterations did not correlate with the lowest drilling fluid filtrate loss volumes. This paper will examine the factors which contributed to alterations in the core samples.
A series of corefloods were carried out using core from 2 formations and different drilling fluids. Separate tests were carried out using drilling fluid alone and the full operational sequence. Filtrate loss and permeability measurements combined with interpretative analyses to understand what happened in the near-wellbore. Micro-CT "change maps" gave 3D visualisations of the thickness of operational fluid cakes and extent of retention/clean-up – valuable insights into factors that influence hydrocarbon recovery.
All drilling fluids tested had "normal" filtrate loss volumes, with one having notably higher losses with a particular formation. Normally this would be considered a bridging issue and "fixed", but those tests showed comparable or slightly lower alterations in permeability. Analysis showed that, despite deeper constituent infiltration, they were not contributing significant extra damage or retention; the nature of the drilling fluid attachment and cake seemed to be more relevant here than depth of invasion. Other examples will illustrate that the impact of drilling fluid infiltration and retention can range widely, and that there are more key factors than simply filtrate loss volume.
Results showed that focusing on the metric of filtrate loss alone may increase risk during drilling fluid selection. Understanding the relationship between filtrate loss, permeability/inflow alteration, retention/clean-up after production is important in selecting fluids as well as giving a better understanding of where improvements can be made. 3D visualisations of the alterations caused by drilling fluid allow conclusions to be drawn when previously there would be speculation.