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.
Reverse circulation cement placement is the technique when cement slurries are pumped down the annulus and up the casing, as opposed to conventional primary cementing where fluids are pumped down the casing. Reverse circulation can reduce bottom hole pressures compared to conventional cementing, making it particularly attractive for cementing zones where margins to the fracture pressure are small. Since the fluids are not mechanically separated in the annulus, density and viscosity hierarchies need to be carefully designed to minimize mixing and slurry contamination. We investigate the effect of variations in density and viscosity on the displacement efficiency by means of computational fluid dynamics to improve the design of a successful reverse circulation cementing operation.
The simulations are performed using an open-source computational fluid dynamics software, enabling a parameter study of the effect of flow rate, inclination, standoff and fluid parameters such as density and viscosity on the displacement process. We compare the reversed circulation displacement efficiency and the hydraulic pressure in the annulus to corresponding conventional primary cementing operations.
The displacement flows involve complex non-Newtonian viscosities in eccentric annuli, and the flow is typically fully three-dimensional. The efficiency and quality of the fluid-fluid displacement is governed by the hierarchy of fluid properties between the displaced and displacing fluids for both conventional and reverse circulation cementing. Furthermore, it is shown how flow rate and geometric constraints such as inclination and standoff affect the efficiency.
Previous work has focused primarily on hydraulic pressure and downhole temperature calculation. We investigate the effect of fluid hierarchies on cement contamination during reverse circulation cementing. The combination of fluid hierarchies and flow rate need to be carefully designed to avoid cement contamination while maintaining low bottom hole pressures during reverse circulation.
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.
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 (
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.
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.
AbstractA 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.
Pattarini, Giorgio (University of Stavanger) | Strømø, Kjartan Moe (Sunnhordaland Mekaniske Verksted AS) | Saasen, Arild (University of Stavanger) | Amundsen, Per Amund (University of Stavanger) | Pallin, Jan Egil (Sapeg AS Norway) | Hodne, Helge (University of Stavanger)
AbstractDrilling fluids contain magnetic contaminations that negatively affect Measurement While Drilling directional tools and causes damage to the equipment in contact with the fluid. The effect is relevant while drilling long deviated wells. Ditch magnets are routinely installed in the fluid system to remove magnetic particles while drilling, with the purpose of protecting the Shale Shaker screens from large metallic debris, serve as monitoring tool to detect troubles in the drilling operations and clean the fluid from magnetic particles.In this paper we describe field data for the operation and efficiency of the ditch magnets. An extensive set of samples of drilling fluid and of ditch magnets debris have been taken during offshore operations and have been brought onshore for detailed investigations. The material extracted has been assessed as constituted mainly by steel swarfs and steel fines.The magnetic materials still present in the used drilling fluid have been extracted and quantified by a novel method that provide higher extraction rates and better accuracy than the methods currently employed in the industry, allowing to assess the actual content of magnetic contaminant. The magnetic susceptibility of the fluid has been measured and compared with values predicted for a known concentration of magnetic contaminants, allowing for the evaluation of the bias induced by them on the magnetometers of the MWD tools employed.The capability of ditch magnets to remove the magnetic contaminants from fluid is quantified and compared with other available methods, like gravity separation, with special focus on the removal of magnetic particles in the range of few microns. Operational details and current issues in the deployment of ditch magnets are reviewed, and the most viable directions for improvement are briefly discussed.
Linga, Harald (SINTEF Petroleum Research/DrillWell) | Bjørkevoll, Knut Steinar (SINTEF Petroleum Research/DrillWell) | Skogestad, Jan Ole (SINTEF Petroleum Research/DrillWell) | Saasen, Arild (Aker BP)
The paper addresses the gas loading characteristics of the drilling fluid and its influence of the gas influx rate during the flow check operation. In particular, the resulting fluid expansion in the wellbore annulus and the capability to detect gas kick at HPHT process conditions will be discussed for selected drilling fluids.
For the evaluation of the applicability of flow check operations for the detection of gas influx, the time response to the drilling fluid expansion during natural gas influx is addressed in terms of drilling fluid gas loading properties, influx severity and influx area.
The physical gas loading rate of natural gas into the drilling fluid is described as a first order kinetic mass transfer process including the gas loading capability for the multicomponent system of drilling fluid and natural gas, in addition to the gas influx characteristics at the wellbore–formation boundary.
When operating the fluid system of natural gas–drilling fluid in the liquid phase region, a continuous gas influx will at some point give more distinct expansion of the fluid mixture in the wellbore. This occurs for the maximum gas loading of the drilling fluid. Such distinct change in sensitivity in the volume expansion response is not encountered when operating the system of drilling fluid–natural gas in dense phase. For selected cases relevant for HPHT drilling, the volume expansion response during flow check operation is compared for drilling fluid with gas loading characteristics either representing single liquid phase or dense phase gas loading. With the methodology described it is readily shown that the interpretation and design of the flow check operation should be carefully selected when approaching dense phase conditions or if the gas loading capability of the drilling fluid is considerable. This is particularly important for oil-based drilling fluids featuring high gas loading capability.
During a gas influx scenario in drilling and well operations, early detection is important in order to prevent harmful consequences to rig, personnel and environment. However, the influx of natural gas may be masked if the gas loading capability of the drilling fluid is considerable. This work aims to provide a methodology for predicting the gas loading capability of oil-based drilling fluids, such that precautions for early gas influx detection can be made also for HPHT-drilling with oil-based drilling fluids.
In principle, the bubble-point curve; i.e. the transition from single liquid phase to two-phase, of the mixture of drilling fluid and natural gas determines the maximum loading capability of gas in the drilling fluid at the actual pressure and temperature. In overbalance situations the gas loading capability is decisive for the volumetric response and severity of gas influx. Thus, the gas loading capability needs to be accurately described for hydraulic models used for well control. This paper describes a methodology for gas loading capability prediction based on the bubble-point curve as determined from thermodynamical equations-of-state calculations. Different thermodynamical models have been evaluated and compared with experimental data for OBDF–methane systems. In particular, the features and requirements for the models are discussed.
Strategies for tuning the models to experimental results are necessary regardless of the choice of equations. Both models and experimental data on gas loading capability versus pressure follow the linear Henry's law in the subcritical region, and deviate severely from this as the pressure is increased towards the dense phase region of the drilling fluid – natural gas mixture. The determination of the dense phase region is of particular interest, as for this region there exists no limit in terms of gas loading in the drilling fluid. The proposed methodology forms the basis of a promising tool for gas loading capability calculations that, if utilized in drilling simulation software, may improve understanding and help detecting gas kicks early, thus lowering the associated risks, in particular for HPHT-drilling.