Halliburton Energy Services, Inc.

Vitor Lopes Pereira

Dale E Jamison

Aidan James Porter

Robert Lynn Williams

Joshua Samuel Gollapalli

John Paul Bir Singh

Sandeep D Kulkarni

Donald Lee Whitfill

Krishna Babu Yerubandi

Lawrence Joseph Herskowitz

Alexandra Clare Morrison

A method for detecting the occurrence of an event at a well comprising: recording a first set of measurements collected from the well; processing the recorded measurements to provide a first set of data; calculating a first score based on the first set of processed data; recording a second set of measurements collected from the well; processing the second set of recorded measurements to provide a second set of data; calculating a second score based on the second set of processed data; wherein the first set of processed data and the second set of processed data is the number median of absolute difference from normal; combining the first score and the second score using a weighted average; and comparing the combined scores to a predetermined rule based on a specified time frame; and allowing an operator to adjust parameters of the well operation based on the score comparison.

Method to detect real-time drilling events

Predicting the efficiency of downhole mechanical removal of one or more accreted materials from one or more wellbore walls may prevent the unnecessary consumption of resources in a wellbore fluids displacement operation. A method and system for removing accreted materials in a wellbore is provided, wherein the efficiency of mechanical removal of accreted materials may be characterized based, at least in part, on a comparison between one or more actual shear stresses exerted by a wellbore servicing fluid at one or more depths of the wellbore and one or more required shear stresses to remove the accreted materials from the depth. The one or more required shear stresses may be determined using one or more of one or more known properties of the one or more accreted materials, one or more rheology models, one or more hydraulic parameters, one or more wellbore hydraulic models, and one or more downhole conditions. To account for one or more effects of eccentricity in the wellbore, the one or more actual shear stresses exerted by wellbore servicing fluid may be determined by partitioning one or more three dimensional flow profiles into divided annular segments for individual analysis. To improve operational decision making, operators or automated processes may modify the wellbore fluids displacement operation based, at least in part, on the comparison. The comparison between the one or more actual shear stresses and the one or more required shear stresses may be used to generate a parameter that characterizes the cleaning efficiency of the wellbore fluids displacement operation.

Predicting downhole mechanical cleaning efficiency in wellbore walls during wellbore fluids displacements

The equivalent circulating density ('ECD') in a wellbore may be managed during a wellbore operation using ECD models that take into account the rheology of the wellbore fluid and the rotational speed of tubulars in the wellbore. For example, a method may include rotating a rotating tubular in a stationary conduit while flowing a fluid through an annulus between the rotating tubular and the stationary conduit; calculating an equivalent circulating density ('ECD') of the fluid where a calculated viscosity of the fluid is based on an ECD model ?_eff=f(? ?_eff)*h(Re), wherein ?_eff is the viscosity of the fluid, ? ?_eff is an effective shear rate of the fluid, and Re is a Reynold's number for the fluid for the rotational speed of the rotating tubular; and changing an operational parameter of the wellbore operation to maintain or change the ECD of the fluid.

Managing equivalent circulating density during a wellbore operation

Effective prediction of downhole mixing and channeling at an interface between two or more wellbore fluids may prevent the unnecessary consumption of resources at a well site and enhance the performance of wellbore operations, including drilling operations, completion operations, and reservoir management. A model for a length and a volume of the interface between two wellbore fluids may be used to characterize the amount of mixing and channeling. The model may use known properties of the wellbore fluids before mixing and channeling occurs. The model may account for eccentricity in an annulus of the wellbore by partitioning a three dimensional flow profile in the wellbore into a plurality of segments for separate analysis. Outputs from the model may be used to determine one or more locations of the interface at one or more intervals of time as the wellbore fluids circulate through the wellbore. One or more compositions may be determined and recorded for one or more wellbore fluids at one or more depths of the wellbore during one or more intervals of time. To improve operational decision making at a well site, operators or automated processes may modify a wellbore operation based, at least in part, on the one or more compositions and the one dimensional model for mixing and channeling.

Predicting downhole fluid mixing and channeling in wellbores

Methods and systems for modeling the efficiency of fluid transfer between a wellbore and containers during a displacement operation. In one embodiment, the methods and systems may include providing a fluid transfer model based on constraints determined from data obtained from a wellbore servicing system, wherein the fluid transfer model comprises expected properties of the wellbore servicing system at one or more intervals during a fluid displacement operation, selecting containers for transferring a wellbore servicing fluid to a wellbore based on the expected properties, selecting containers for transferring a return fluid from the wellbore based on the expected properties, determining actual properties of the wellbore servicing system from data obtained from the wellbore servicing system, comparing the expected properties and the actual properties, and if the expected properties are different from the actual properties, modifying at least one of the expected properties of the wellbore servicing system.

Optimizing fluid transfer design and execution during wellbore displacement operations

A method of sealing a lost circulation zone (LCZ) during a drilling operation by: positioning a bottom hole assembly (BHA) at an initial position proximate a LCZ in a wellbore, wherein the BHA includes a drill bit fluidly connected with a surface of the wellbore via a drill string; and pumping first and second reactant pills and a spacer into the LCZ via the drill string and the drill bit, wherein the first reactant pill includes one or more first reactants, wherein the second reactant pill includes one or more second reactants, wherein the first reactant pill is pumped into the LCZ prior to the second reactant pill due to introducing of the spacer into the drill string between the first and second reactant pills, and wherein, after a reaction time, reactants comprising the one or more first and second reactants react within and provide a seal of the LCZ.

Method to manage tandem single string reactive LCM pill applications

A system usable in a wellbore can include a processing device and a memory device in which instructions executable by the processing device are stored for causing the processing device to: generate multiple predicted values of a first parameter associated with a well environment or a wellbore operation; determine a first trend indicated by the multiple predicted values; receive, from a sensor, multiple measured values of a second parameter associated with the well environment or the wellbore operation; determine a second trend indicated by the multiple measured values; determine a difference between the first trend and the second trend or a rate of change of the difference; and in response to the difference exceeding a threshold or the rate of change exceeding another threshold, determine a source of the difference including at least one of an erroneous user input, an equipment failure, a wellbore event, or a model error.

Determining sources of erroneous downhole predictions

A system for use in a wellbore can include a computing device that includes a processing device and a memory device that stores instructions executable by the processing device. The instructions can cause the processing device to generate a predicted value of a parameter associated with a well environment or with a wellbore operation. The instructions can also cause the processing device to receive sensor data that includes a measured value of the parameter; compare the predicted value to the measured value to determine a difference; and generate an interface for display that includes a data point associated with the difference plotted on a probability-mass distribution graph. The system can also include a sensor in electrical communication with the computing device and positionable proximate to the wellbore for generating the measured value of the parameter and transmitting the measured value of the parameter to the computing device.

Predicting wellbore operation parameters

A system for use in a wellbore can include a computing device including a processing device and a memory device that stores instructions executable by the processing device. The instructions can cause the processing device to generate a predicted value of a parameter associated with a well environment or a wellbore operation. The instructions can also cause the processing device to determine a tuning factor for adjusting the predicted value based on historical data. The instructions can also cause the processing device to apply the tuning factor to the predicted value to generate a tuned predicted value. The instructions can further cause the processing device to generate an interface for display that includes a data point associated with the tuned predicted value plotted on a graph.

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The Woodlands, TX, United States of America

Vitor Lopes Pereira