Modeling proppant flow in fractures using LIGGGHTS, a scalable granular simulator

textProppant flowback in fractures under confining pressures is not well understood and difficult to reproduce in a laboratory setting. Improper management of proppant flowback leads to flow restrictions near the well bore, poor fracture conductivity and costly production equipment damage. A simple, scalable model is developed using a discrete element method (DEM) particle simulator, to simulate representative cubic volumes consisting of fracture openings, fracture walls and the confining formation. The effects of fracture width, confining stress, fluid flow velocity and proppant cohesion are studied for a variety of conditions. Fracture width is found to be dependent on confining stress and fluid flow velocity while proppant production is also dependent on cohesion. Three regimes are observed, with complete fracture evacuation occurring at high flow rates and low confining stresses, fully packed fractures occurring at high confining stresses and open but mostly evacuated fractures occurring in-between. From these observations, a recommended flowback rate can be estimated for a given set of conditions. A slow and controlled well flowback is recommended to improve proppant pack stability. The rate ramp-up time is dependent on the leak-off coefficient.Petroleum and Geosystems Engineerin

The effect of well path, tortuosity and drillstring design on the transmission of axial and torsional vibrations from the bit and mitigation control strategies

As well designs become increasingly complicated, a complete understanding of drillstring vibrations is key to maximize drilling efficiency, to reduce drillstring dysfunction and to minimize drillstring, tool, and borehole damage. Torque and drag models exist that seek to quantify the effects of borehole inclination and tortuosity on static friction along the drillstring; however, the effects on dynamic friction remains poorly understood. This dissertation begins with a review of the past fifty years of work on drillstring dynamics models, an overview of the proposed control strategies and a summary deployed vibration mitigation applications within the drilling industry. Derivations from first principles of a series of computationally efficient axial and torsional drillstring models in both the frequency and time domains are then presented and verified with field data. The transfer matrix approach is used to predict the severity of axial vibrations along the drillstring and is verified using a series of case studies using field data. Harmonic axial vibrations within drillstrings are either induced intentionally, in the case of axial oscillation tools midway along the drillstring, or unintentional, in the case of bit bounce. Two case studies of bit bounce are first evaluated to ensure model validity for a harmonic excitation at a the bit and the model is found to accurately predict bit bounce based on surface rotation rates. Induced axial oscillations, generated by axial oscillation tools, are then investigated to quantify friction reduction and drilling efficiency improvements. Optimal placement is found to depend on wellbore geometry, but is usually restricted to periodic regions of the drillstring. These optimizations are then verified using field trials and suggest that improved placement can result in 20% or more reduction in friction along the drillstring. Two applications of torsional drillstring vibrations are then investigated -- stick slip mitigation and drillstring imaging. The time domain form of the torsional drillstring model is used first to evaluate the effectiveness of three types of top drive controllers -- stiff controllers, tuned PI controllers and impedance matching controllers -- in mitigating stick slip oscillations. Then, the transfer matrix method is applied to evaluate the effect of wellbore geometry on drillstring mobility to conclude that higher order modes of stick slip may become dominant in non-vertical wellbores. The feasibility of drillstring imaging using torsional signals from surface is then investigated to identify inputs and methods that show promise in three setups of varying complexity -- a hanging beam, a laboratory drillstring model and a drilling rig. Two techniques show promise -- white noise injection and model fitting of a step response -- in identifying larger features, including drillstring length and BHA location. However, low sampling frequencies and low bandwidth inputs reduce the ability to image small features such as friction points along the wellpath.Petroleum and Geosystems Engineerin

Look ahead of the bit while drilling: potential impacts and challenges in the McMurray Formation

International audienceThe oil and gas industry, operating and service companies, and academia are actively looking for ways to see ahead of the drillbit while drilling to reduce the risks and costs of the operation and improve the well-placement process. Optimal drilling in the challenging and highly heterogeneous reservoirs, where geological interpretations overlook the high-frequency variations in the rock properties, requires reliable subsurface information from around and ahead of the drillbit. To provide this, we have developed a seismic-while-drilling imaging algorithm based on signal processing, drillstring modeling, and pre-stack wave-equation migration. To extend the visibility ahead-of-the-bit, we use the drillbit as a seismic source and image the changes in acoustic properties of rocks both around and ahead of the drillbit. The common practice is to build a reverse vertical seismic profile (R-VSP) gathers. Here, we use a blind deconvolution algorithm to estimate the drillbit source signature from the data directly. Alternatively, we can estimate such a signature through drillstring modeling and top-drive measurements (i.e., force and velocity). The drillstring dynamics is modeled by using Riemann's invariants and a backstepping approach. Next, we input the estimated source signature to the pre-stack wave-equation depth imaging workflow. Our simulations show that providing drillbit source signature to the pre-stack wave equation depth migration consistently delivers reliable subsurface images around and ahead of the drillbit. The output of our workflow is a high-resolution subsurface image that provides vital information in oil sands reservoirs for placement of steam assisted gravity drainage (SAGD) well pairs. Compared to conventional practices, the proposed methodology images around and ahead of the drillbit enabling interactive decision making and optimal well-placement. The key feature of the presented methodology is that instead of cross-correlating the seismic-while-drilling data with the pilot trace and building R-VSP gathers, we use the estimated drillbit source signature and deliver high-resolution pre-stack depth migrated images. Through numerical modeling, we tested the potential impacts, validity, and challenges of the proposed methodology in drilling horizontal wells in SAGD settings with an emphasis on the McMurray Formation. We further compared the results with the conventional drilling practice. In contrast to existing tools that have limited depth of penetration, interpreting seismic-while-drilling data in real-tim

Methods relating to tool face orientation

Systems and methods for controlling an orientation of a tool face for a drilling rig. Multiple methods are provided that use estimated tool face orientation along with measured parameters to determine inputs to the drilling rig such that, after activation, the tool face has a desired orientation

Stick-slip and Torsional Friction Factors in Inclined Wellbores

Stick slip is usually considered a phenomenon of bit-rock interaction, but is also often observed in the field with the bit off bottom. In this paper we present a distributed model of a drill string with an along-string Coulomb stiction to investigate the effect of borehole inclination and borehole friction on the incidence of stick-slip. This model is validated with high frequency surface and downhole data and then used to estimate static and dynamic friction. A derivation of the torsional drill string model is shown and includes the along-string Coulomb stiction of the borehole acting on the string and the ‘velocity weakening’ between static and dynamic friction. The relative effects of these two frictions is investigated and the resulting drillstring behavior is presented. To isolate the effect of the along-string friction from the bit-rock interaction, field data from rotational start-ups after a connection (with bit off bottom) is considered. This high frequency surface and downhole data is then used to validate the surface and downhole behavior predicted by the model. The model is shown to have a good match with the surface and downhole behavior of two deviated wellbores for depths ranging from 1500 to 3000 meters. In particular, the model replicates the amplitude and period of the oscillations, in both the topside torque and the downhole RPM, as caused by the along-string stick slip. It is further shown that by using the surface behavior of the drill-string during rotational startup, an estimate of the static and dynamic friction factors along the wellbore can be obtained, even during stick-slip oscillations, if axial tension in the drillstring is considered. This presents a possible method to estimate friction factors in the field when off-bottom stick slip is encountered, and points in the direction of avoiding stick slip through the design of an appropriate torsional start-up procedure without the need of an explicit friction test

Stick-slip and Torsional Friction Factors in Inclined Wellbores

Stick slip is usually considered a phenomenon of bit-rock interaction, but is also often observed in the field with the bit off bottom. In this paper we present a distributed model of a drill string with an along-string Coulomb stiction to investigate the effect of borehole inclination and borehole friction on the incidence of stick-slip. This model is validated with high frequency surface and downhole data and then used to estimate static and dynamic friction. A derivation of the torsional drill string model is shown and includes the along-string Coulomb stiction of the borehole acting on the string and the ‘velocity weakening’ between static and dynamic friction. The relative effects of these two frictions is investigated and the resulting drillstring behavior is presented. To isolate the effect of the along-string friction from the bit-rock interaction, field data from rotational start-ups after a connection (with bit off bottom) is considered. This high frequency surface and downhole data is then used to validate the surface and downhole behavior predicted by the model. The model is shown to have a good match with the surface and downhole behavior of two deviated wellbores for depths ranging from 1500 to 3000 meters. In particular, the model replicates the amplitude and period of the oscillations, in both the topside torque and the downhole RPM, as caused by the along-string stick slip. It is further shown that by using the surface behavior of the drill-string during rotational startup, an estimate of the static and dynamic friction factors along the wellbore can be obtained, even during stick-slip oscillations, if axial tension in the drillstring is considered. This presents a possible method to estimate friction factors in the field when off-bottom stick slip is encountered, and points in the direction of avoiding stick slip through the design of an appropriate torsional start-up procedure without the need of an explicit friction test

Comparing advanced control strategies to eliminate stick-slip oscillations in drillstrings

International audienceIn this paper, we present three methods to achieve reliable drillbit angular velocity control for deep drilling operations. We consider a multi-sectional drilling system with the bit off-bottom, which represents the system at the start-up of a drilling operation, e.g., after a connection. The three control procedures are all based on a distributed model for the drilling system. The proposed model has been field validated and considers Coulomb friction between the drillstring and the borehole. The first algorithm we propose combines the industry standard ZTorque controller with a feedforward component. The second procedure is based on a multiplicity-induced-dominancy (MID) design that corresponds to a pole-placement for the downhole state. Finally, the last class of controllers relies on a recursive interconnected dynamics framework. All the controllers are combined with a disturbance rejection procedure whose design is based on a switching-mode approach. These three algorithms are illustrated in simulations with field scenarios on several test-cases. Their complexities, effectiveness and limitations regarding industrial implementation criteria are discussed

Look ahead of the bit while drilling: potential impacts and challenges of acoustic seismic-while-drilling in the McMurray Formation

International audienceThe oil and gas industry, operating and service companies, and academia are actively searching for ways to look ahead of the drill bit while drilling to reduce the risks and costs of the operation and improve the well-placement process. Optimal drilling in challenging and highly heterogeneous reservoirs, where geological data cannot adequately constrain high-frequency variations in rock properties, requires reliable subsurface information from around and ahead of the drill bit. To provide this, we have developed a seismic-while-drilling (SWD) imaging algorithm using signal processing, drillstring modeling, and prestack wave-equation migration.To extend the visibility ahead of the bit, we use the drill bit as a seismic source and image the changes in acoustic properties of rocks both around and ahead of the drill bit. The common practice is to build reverse vertical seismic profile (R-VSP) gathers. Here, we use a blind deconvolution algorithm to estimate the drill-bit source signature from the data directly. Alternatively, we can estimate such a signature through drillstring modeling and surface measurements (i.e., hookload and hook speed). The drillstring dynamics are modeled and analyzed using Riemann’s invariants and a backstepping approach in a field-verified model. Next, we enter the estimated source signature into the prestack wave-equation depth-imaging workflow. Our simulations show that providing the drill-bit source signature to the prestack wave-equation depth migration consistently delivers reliable subsurface images around and ahead of the drill bit.The output of our workflow is a high-resolution subsurface image, which is then applied to provide vital information in oil-sands reservoirs for placement of steam-assisted-gravity-drainage (SAGD) well pairs. Compared with conventional practices, the proposed methodology images around and ahead of the drill bit enable interactive decision making and optimal well placement. The key feature of the presented methodology is that instead of cross correlating the SWD data with the pilot trace and building R-VSP gathers, we use the estimated drill-bit source signature and deliver high-resolution prestack depth-migrated images.Through numerical modeling, we tested the potential impacts, validity, and challenges of the proposed methodology in drilling horizontal wells in SAGD settings with an emphasis on the McMurray Formation. We further compared the results with the conventional drilling practice. In contrast to existing tools that have limited depth of penetration, interpreting SWD data in real time confidently maps key target features ahead of the drill bit. This imaging workflow provides sufficient time to precisely control the borehole trajectory and stay within the desired reservoir zone. Accordingly, it mitigates the risk of intersecting mudstone-filled channels and lean zones