Landmark Graphics Corporation

Halliburton Energy Services, Inc.

Aniket

Robello Samuel

Adolfo Gonzales

Serkan Dursun

Yuan Zhang

Gustavo Adolfo Urdaneta

Manish Kumar Mittal

Nitish Chaudhari

Robert D Gilcrist

Predicting casing wear, riser wear, and friction factors in drilling operations may be achieved with data-driven models that use discrete inversion techniques to updated casing wear models, riser wear models, and/or friction factor models. For example, a method may applying a linear inversion technique or a nonlinear inversion technique to one or more parameters of at least one of a casing wear model, a riser wear model, or a friction factor model using historical data from a previously drilled well as input data to produce at least one of an updated casing wear model, an updated riser wear model, or an updated friction factor model, respectively; and implementing the at least one of the updated casing wear model, the updated riser wear model, or the updated friction factor model when designing and/or performing a drilling operation.

Modeling casing/riser wear and friction factor using discrete inversion techniques

Disclosed embodiments include a method for estimating casing wear including the operations of: obtaining locations of survey points along a borehole, said survey point locations representing a borehole trajectory; casing at least a portion of the borehole with a casing string; deriving locations of adjusted survey points that represent a casing trajectory along said portion of the borehole, the casing trajectory being different from the borehole trajectory; estimating, as a function of position along said casing string, a side force of a drill string against the casing string; computing, as a function of position along the casing string, casing wear based at least in part on the side force; and generating a notification of any positions where casing wear exceeds a threshold.

Adjusting survey points post-casing for improved wear estimation

A casing wear estimation method includes obtaining a set of input parameters associated with extending a partially-cased borehole and applying the set of input parameters to a physics-driven model to obtain an estimated casing wear log. The method also includes employing a data-driven model to produce a predicted casing wear log based at least in part on the estimated casing wear log. The method also includes storing or displaying information based on the predicted casing wear log.

Casing wear prediction using integrated physics-driven and data-driven models

Systems and methods for utilizing hybrid mechanical-laser drilling tools, such as drill bits and hole-openers, are provided. Such drilling tools may include mechanical cutters in addition to laser cutting mechanisms designed to focus laser beams toward a subterranean formation. The mechanical cutters and laser cutting mechanisms may work in combination to advance a wellbore through the subterranean formation. The drilling tools may be controlled to vary the amount of energy output through the mechanical drilling via the cutters and through the laser-assisted drilling via the lasers.

Hybrid mechanical-laser drilling equipment

Damage to a casing string in a wellbore resulting from a wellbore operation can be predicted. For example, a stiff string model can be used to determine a contact point between the casing string and a well tool positionable within the casing string for performing the wellbore operation. The stiff string model can be used to determine a force of the well tool against the casing string at the contact point. The force can be used to determine a volume of damage to the casing string proximate to the contact point. A depth of a groove formed in the casing string proximate to the contact point can be determined based on the volume of damage.

Determining damage to a casing string in a wellbore

An illustrative method for estimating casing wear, including estimating, as a function of position along a casing string, a side force of a tubular string against the casing string, wherein said estimating accounts for a bending stiffness of the tubular string. The method further including determining, based at least in part on the side force, a casing string wear volume as a function of position along the casing string, and presenting the casing string wear volume to a user.

Estimating casing wear using models incorporating bending stiffness

A method including obtaining input attribute values and a target risk attribute value associated with a first borehole segment. The method also includes training a prediction model for the target risk attribute using the input attribute values and the target risk attribute value. The method also includes acquiring subsequent input attribute values. The method also includes using the trained prediction model and the subsequent input attribute values to predict a target risk attribute value for a second borehole segment. The method also includes storing or displaying information based on the predicted target risk attribute value.

Employing a target risk attribute predictor while drilling

One drilling method embodiment includes: obtaining a set of drilling parameters, possibly from a drilling plan; applying the set of drilling parameters to a physics-based model to obtain an estimated log of a downhole parameter such as temperature; and refining the estimated log using a data-driven model with a set of exogenous parameters. Temperature cycling and cumulative fatigue (or other measures of failure probability or remaining tool life) may be derived to predict tool failures, identify root causes of poor drilling performance, and determine corrective actions.

Predicting temperature-cycling-induced downhole tool failure

The disclosed embodiments include a method, apparatus, and computer program product for determining a suitable casing design for a well. For example, one disclosed embodiment includes a system that includes at least one processor and at least one memory coupled to the at least one processor and storing instructions that when executed by the at least one processor performs operations for receiving historical data associated with previously drilled wells; in response to a determination that the historical data associated with previously drilled well is relevant to the well, generating a first set of casing designs using a probabilistic approach and generating a second set of casing designs using a combination approach that combines the probabilistic approach with a deterministic approach; and selecting a suitable casing design from a resulting set of casing designs.

Method and analysis for holistic casing design for planning and real-time

Casing wear estimation. At least some of the illustrative embodiments are methods including: calculating a value indicative of static casing wear of the drilling operation, the static casing wear caused by interaction of a drill string against an inside diameter of a casing; calculating a value indicative of impact casing wear of the drilling operation, the impact casing wear caused by interaction of the drill string against the inside diameter of a casing; and combining the value indicative of static casing wear and the value indicative of impact casing wear to determine the value indicative of aggregate casing wear.

Casing wear estimation

Drilling system and methods may employ a weight-on-bit optimization for an existing drilling mode and, upon transitioning to a different drilling mode, determine an initial weight-on-bit within a range derived from: a sinusoidal buckling ratio, a helical buckling ratio, and the weight-on-bit value for the prior drilling mode. The sinusoidal buckling ratio is the ratio of a minimum weight-on-bit to induce sinusoidal buckling in a sliding mode to a minimum weight-on-bit to induce sinusoidal buckling in a rotating mode, and the helical buckling ratio is the ratio of a minimum weight-on-bit to induce helical buckling in the sliding mode to a minimum weight-on-bit to induce helical buckling in the rotating mode. The ratios are a function of the length of the drill string and hence vary with the position of the drill bit along the borehole.

Ratio-based mode switching for optimizing weight-on-bit

Estimating casing wear during a reciprocation portion of a drilling operation may take into account the forces that cause casing wear during the up and down strokes independently. For example, during a drilling operation, a method may include reciprocating the drill string through the wellbore for a plurality of up strokes and a plurality of down strokes according to reciprocation parameters; calculating an up stroke normal force and a down stroke normal force for the casing or a section thereof; calculating up and down stroke casing wears based on the up and down stroke normal forces, respectively, using a reciprocation casing wear model; calculating a reciprocation casing wear based on the up and down stroke casing wears; and calculating a total casing wear for the casing or the section thereof based on the reciprocation casing wear using a total casing wear model.

Estimating casing wear due to drill string reciprocation

Estimating casing wear for individual portions or lengths of a casing may take into account that individual drill string sections cause different amounts of casing wear based on the physical and material properties of each drill string section. In some instances, a method performed during a drilling operation may involve tracking a location of the plurality of drill string sections along the wellbore; corresponding a casing section with the drill string wear factors of the drill string sections radially proximate to the casing section the drilling intervals of the drilling operations; and calculating a drilling casing wear for the casing section based on the drill string wear factors corresponding to the casing section.

Estimating casing wear during drilling using multiple wear factors along the drill string

The subject matter of this specification is directed to a method that includes providing an outer tubular member having a bore with an inner surface, applying a lubricant layer to at least a portion of the inner surface of the outer tubular member, and positioning the outer tubular member in at least a portion of the wellbore. During the drilling process, mechanical wear between the outer and inner members can be measured by an indicator to determine if the measured indicator exceeds a predetermined threshold level.

Friction and wear reduction of downhole tubulars using graphene

Systems and methods for well integrity management in all phases of development using a coupled engineering analysis to calculate a safety factor, based on actual and/or average values of various well integrity parameters from continuous real-time monitoring, which is compared to a respective threshold limit.

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Houston, TX, United States of America

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