2018 IADC/SPE Drilling Conference abstracts
Tuesday, March 06 (Station 1: Knowledge Sharing ePosters)
IADC/SPE 189603
The Role of Big Data in Operational Excellence and Real-Time Fleet Performance Management – The Key to Deepwater Thriving in a Low Cost Oil Environment
M.S. Bolen, Chevron Corporation; V. Crkvenjakov, J. Converset, Schlumberger
Objectives/Scope: Apply a unique approach and workflow to transform data into usable knowledge supporting multi-rig deepwater operations to aid the reduction of well cycle time and remain economically competitive during low cost oil environment. Maximize the utilization and concise visualization of surface digital data providing invaluable insight to achieve reliable, efficient and world-class performance excellence. Establish data-driven well construction optimization process to achieve rig operations consistency closer to the technical limit.
Methods, Procedures, Process: Establish effective in-house data analysis center to support faster, data driven, decision-making process. Execute real-time performance surveillance by in-house drilling data specialists that fully support integrated drilling teams and provide invaluable information to facilitate effective operations. Apply methods of critical thinking in the process of data analysis to challenge operational procedures, support adjustments to actual well conditions and technology available while maximizing efficiency. In addition to the basic process of benchmarking that quantifies invisible lost time (ILT) while tripping and drilling, workflow considers enhanced KPIs of other operations from day one to the last day of the well. The key enabler for effective benchmark calibrations for future operations across the fleet, lies in a comprehensive repository catalogue of well construction operations.
Results, Observations, Conclusions: Workflow was established through specific data visualization methods, reporting, performance plans and performance meetings, which had significant impact on achieving consistency in drilling operations and quick reduction of invisible lost time. “Low hanging fruit” such as tripping and drilling connection time were quickly reduced to technical limits of the fleet. Less than 1/3 of well time is spent on tripping and drilling, so step-change was needed in order to achieve effective well cycle time reduction:
- New set of enhanced KPI parameters were developed that covered all operations taking place from first to last day of the drilling and completion operations;
- Performance optimization through simple benchmarking was extended by adding innovation and changes in drilling practices with data driven lean sigma projects;
- KPI real-time viewer on rig site was established for faster correction of inconsistency in operations
Established well construction optimization process, generated sufficient data set:
- To be used in deterministic AFE planning; and
- To support development of real time KPI dashboards on the rig site, which would allow shorter corrective cycle of crew inconsistencies.
The key to positive impact of achieving performance improvement lies in effective collaboration of all levels of integrated drilling teams and utilization of data center.
Novel/Additive Information: Successful transformation of rig surface data into usable knowledge has multiple benefits in deepwater drilling operations: from basics of performance monitoring, benchmarking and reducing ILT, reducing well cycle time, supporting lean sigma projects to more complex usage such as deterministic methods of AFE planning.
IADC/SPE 189622
CFD Hydrodynamic Performance Comparison Between Conventional and VIV-Mitigating Drill Riser Buoyancy Modules
Lai, Trelleborg Offshore
Objectives/Scope: Vortex-induced vibration (VIV) is a significant factor in causing cyclic stress and fatigue damage in drill risers. A new design of drill riser buoyancy is introduced with tri-helical grooves formed into the module which purpose is to mitigate VIV. The focus of this work is to characterize the hydrodynamic performance improvement of this new design over conventional buoyancy designs.
Methods, Procedures, Process: Computational fluid dynamics (CFD) is employed to simulate the buoyancy module hydrodynamic behavior in the 3D space. A range of current magnitudes that are representative of offshore environments is considered using a Reynolds-averaged (k-epsilon) turbulence model. This methodology is based on previously validated domain, mesh and temporal independence studies for a circular cylinder that also showed agreement with published literature. The hydrodynamic performance is characterized in terms of the drag coefficient (Cd), lift coefficient (Cl) and vortex shedding Strouhal number (St).
Results, Observations, Conclusions: The CFD results show comparable Cd between conventional buoyancy and the new design. However, Cl is significantly lower for the new design buoyancy module which is an indicator that the riser crosswise movement is reduced and therefore the dynamic Cd component is reduced as well. Furthermore, the regular vortex shedding experienced by conventional buoyancy does not occur with the new design. The helical grooves form channels that allow flow along different directions away from the free-field flow directions which function to disrupt the downstream regular flow order. This prevents the regular formation of vortex shedding in the wake of the riser which is an indicator to vortex-induced vibration. This is quantitatively proven as the vorticity generated by the new design buoyancy is an order of magnitude lower than the conventional design. The omni-directional nature of the helical grooves ensures this mechanism for breaking regular flow is achievable regardless of the environmental current direction acting on the riser.
Novel/Additive Information: VIV is an increasingly significant problem with deepwater exploration in harsh weather environments. The new buoyancy design provides passive vortex shedding mitigation to top-tensioned risers which would reduce the propensity of VIV occurrence.
IADC/SPE 189705
A New Rotary Steerable System Designed for Vertical and Nudge Applications in North America Pad Development Drilling
Jones, J. Sugiura, Sanvean Technologies; C. Feddema, Turbo Drill Industries/Scout Downhole; M. Charter, Scout Downhole
Objectives/Scope: Pad drilling has become commonplace for North America shale development drilling, which requires tighter well spacing/separation and reduced anti-collision risk. A new digitally-controlled RSS, extensively embedded with electronics, solid-state sensors and electrically controlled mud valve, has been developed specifically for drilling vertical and nudge well profiles from pads in North America.
Methods, Procedures, Process: The new digitally-controlled RSS has been designed using the latest sensor and electronics technology. Differentiating technology includes a slow-rotating steering housing with four mud activated pads to apply side force at the bit. The pad activation is controlled using a novel mud valve driven by a low-power electric motor and gearing system.
The electronics measurement and control system are mounted in the slow-rotating steering housing and includes 3-axis inclinometers, 3-axis magnetometers, 3-axis shock sensors, 3-axis gyros, and temperature sensors. Additionally, compact drilling dynamics sensors are placed at the bit box to gather at-bit data to evaluate bit-rock dynamic interaction.
Results, Observations, Conclusions: The new RSS has several distinct features that make the system cost-effective and fast to service for high-volume land activity. The electronics, sensors, power supply, valve controller and mud valve are all housed in one chassis module. Having the control system as one independent module allows for a simple, reliable and uncomplex design.
Activation of the steering pads and control of force to the steering pads is achieved using a small percentage of mud flow and 500 psi pressure drop below the tool. The limited amount of mud flow passing through the mud valve eliminates internal wash issues and reduces repair costs.
Communication with the tool downhole is achieved using a fast rotary downlink. Downlinks can be sent downhole to 1) activate and deactivate the steering pads 2) change demand toolface (magnetic and gravity), and 3) change steer force for DLS control.
This paper will describe the unique features that allow the system to be reliable and cost-effective for high-volume land drilling activities. The RSS BHAs have been extensively instrumented with multiple downhole dynamics sensors, which reveal a challenging drilling environment unique to vertical drilling and nudge applications and show the performance of the RSS in this environment.
Novel/Additive Information: The ability to drill extended-reach lateral wells efficiently is reliant upon the quality of the wellbore drilled in the upper and intermediate sections of the well. Tortuous wellbore from surface to above the curve can have a serious impact on lateral drilling performance. The new digitally-controlled RSS has been developed to deliver vertical and low-dogleg nudge performance to ensure low torque and drag in the upper and intermediate sections of the wellbore
IADC/SPE 189617
The Impact of Molecular Diffusion of Methane into Wells with Oil Based Mud
Petersen, Intl Research Inst of Stavanger
Objectives/Scope: A model of the diffusion of methane into a wellbore in overbalance with oil-based mud is described. In some situations, this can cause unexpected gas in riser and well control problems. The situation when the OBM contaminated with diffused methane is circulated is simulated. The model has been used to analyze measurements of hydrocarbon obtained during drilling and circulation in an offshore well in the North Sea, showing excellent agreement with the model.
Methods, Procedures, Process: The tools used are:
- a) A 2D finite difference diffusion program that simulates the diffusion process of methane molecules from the formation, through the mud invasion zone and into the base oil in the well bore.
- b) A finite difference dynamic hydraulics model with modules dealing with the interaction of hydrocarbons entering the mud from the formation and the base oil in the mud.
The lighter hydrocarbons in OBM from the well were measured using FID gas chromatographs capable of accurately measure the amount of C1 through C5 continuously. The measurements were analyzed using a PVT simulation program.
Results, Observations, Conclusions: The diffusion was simulated in two positions in the well, the two days waiting for the 13 5/8” liner, 1850 m TVD, and the four days waiting for pipe at full depth, 4500 m TVD. The inputs to the diffusion model were based on measurements obtained while drilling in the two depths. The hydrocarbon measurements from circulations after the two and four days were compared with the amounts provided by the diffusion theory.
The distribution of the light hydrocarbon elements obtained during drilling through the formation and circulation after the delay periods, were compared. After the delay period, the relative amount of methane (compared with ethane, propane, etc.) was substantially greater. This is because methane has greater diffusion coefficient than the “larger” hydrocarbon elements.
The potential problems of having diffused gas in the base oil are shown using a hypothetical well where the OBM has been left overbalanced for days in the one kilometer long horizontal reservoir section. The contaminated OBM is circulated through the riser, and the low level of methane produces a domino-effect as it starts to boil out in the riser.
In-line gas-chromatograph measurements have provided information that shows the diffusion of methane into OBM while overbalanced.
Novel/Additive Information: This model used together with in-line gas-chromatograph measurements will provide additional insight in how light hydrocarbons end up in oil based mud. The dynamic hydraulics model can be used to show the safety limit when leaving the well without circulation.
IADC/SPE 189651
Well Control Simulator: Enhancing Models With Compositional PVT Models and Kinetics
Bjorkevoll, J. Skogestad, J. Froyen, H. Linga, SINTEF Petroleum Research
Objectives/Scope: Details of the interaction between natural gas and oil in drilling fluids currently not taken into account will in extreme cases be significant for the safety of drilling and well control operations. The paper describes such effects, in particular time dependence (kinetics) and compositional PVT with dense phase included. The importance of validation and tuning of PVT calculations, even when using state-of-art tools, is demonstrated by integrating new methods in a well control simulator.
Methods, Procedures, Process: In this work, we consider sub-models for kinetics (time dependence of gas dissolution and boiling) and compositional PVT for the drilling fluid-natural gas mixture, and study different effects and assumptions numerically by integration in a well control simulator. Available laboratory data are used for model development and tuning of existing software. The dense phase may be important to consider in HPHT wells, where the conditions allow for the drilling fluid-gas mixture to exceed the critical point. This influences the gas absorption capability of the drilling fluid, as well as the density.
Results, Observations, Conclusions: The paper illustrates the impact of kinetics and improved PVT calculations through a sensitivity analysis using realistic well and fluid data. Two specific base-oils, a refined mineral oil and a linear paraffin, are used in combination with methane gas. The simulations show how kinetic effects can be important in some cases, both for early interpretation of a kick and for the response seen at surface as gas approaches and enters topside equipment. Furthermore, it demonstrates that dense phase effects can be significant, and that even state-of-art PVT software requires tuning when used with new combinations of oil-base fluids and hydrocarbon gasses. Although the effects discussed are small compared to safety margins for many wells, ignorance may cause drilling teams to run into severe risks without knowing in advance for other wells.
Novel/Additive Information: Combining advanced PVT models capable of representing dense phase behavior and a kinetics model with hydraulic flow modeling represents a leap forward in simulation of well control events. In addition, the importance of tuning adds valuable knowledge. These elements enable earlier detection and safer handling, thus increasing the safety on the rig.
IADC/SPE 189579
Active Mud Line Pumping, Design, Testing and Future Possibilities in Rig Design
Hong, R.F. Van Kuilenburg, Noble Drilling
Objectives/Scope: Noble Drilling together with equipment providers and a major service company initiated a test program to validate the idea of actively pumping mud from the diverter to the mud treatment tanks instead of using gravity flow. By actively pumping the mud from the well to the treatment tanks a large limitation in vessel design can be removed. By using active mud line pumping the mud treatment and storage section can be placed at an optimal location on the unit. Hazardous zones can be placed more effectively. Building the vessel could be done more cost effective. In addition to the above advantages active mud line pumping can be used on existing vessels for early kick detection at increased precision and decreased detection times. Furthermore AMP kick detection has the potential to avoid the use of Coriolis flow sensors, which have a somewhat mixed reputation.
Methods, Procedures, Process: A literature search indicated the viability of the concept. Laboratory tests were done to ensure realistic mud properties were used during the testing. A closed loop test setup was designed and built using two tanks, two pumps, flow sensors and supporting equipment. Various tests were performed using water and mud with different properties and cuttings percentages.
Results, Observations, Conclusions: The results aligned with the results that were expected based on fluid flow theory. The tests showed excellent behavior of the disc pumps. Controllability of the fluid flow was proven even under severe conditions. Several unexpected issues were encountered, which provided very useful information for the future design work.
Novel/Additive Information: This paper will present a technology that could radically change how rigs can be designed. Operational efficiency, safety and construction requirements can now be combined without making concessions. Several different design options will be presented.
IADC/SPE 189698
Percussion Performance Drilling Motor Delivered Extreme Cost Saving In Hard and Abrasive Formation in Ahnet Basin, Algeria.
Bendoudou, National Oilwell Varco; S. Ziani, S. Fetayah, A. Boudebza, SONATRACH; Y. Bouabba, M. Fatah, National Oilwell Varco
Objectives/Scope: The Percussion Performance Drilling Motor was proposed in combination with PDC bits to overcome the drilling challenges of the 12 ¼” vertical section in Ahnet field (southwest of Algeria), consisting of harsh lithology types habitually drilled using several bits run.
Methods, Procedures, Process: Introducing the Percussion drilling motor is the next step for performance optimization in harsh drilling environments. Utilizing the advanced generation of performance elastomers in combination with new energy distribution system, enhances the bit’s rock failing mechanism by combining the torque and rotation speed with a high frequency axial oscillation which lifts the entire BHA with each pulse while maintaining the drill bit always fully embedded into the formation, resulting in an increased penetration rate. This paper will present a cases study that evidence the benefit of using such tool to reduce the drilling cost.
Results, Observations, Conclusions: The 12.25” section in the subject field is usually drilled using 6-10 drill bits with the associated excessive NPT and increased drilling costs for the operator. Extreme dull characteristics are also exhibited by all drill bits after every run. The introduction of the Percussion Drilling Motor in this section represents a step-change in performance and drilling efficiency to reduce drilling time. In combination with optimized PDC bits, the Percussion Drilling Motor completed the interval with just 2 bits compared to offsets using 10, 8 and 6 bits respectively. In conclusion, this approach crucially contributed to save 7.72 drilling days to the client compared to the initial plan. Moreover, an increase of 119% was recorded in term of ROP compared to the best offset well and a very good hole quality with only 0.7% excess recorded on the Calliper log.
Novel/Additive Information: The innovation of the Percussion performance drilling motor is a completely new telescopic bearing mandrel design to keep the bit always in contact with the formation while gently oscillating the upper BHA reducing friction, improving weight transfer, and improving bit cutting structure efficiency enhancing its rock-failing properties.
IADC/SPE 189615
Modeling of Cuttings Lag Distribution in Directional Drilling to Evaluate Depth Resolution of Mud Logging
Naganawa, University of Tokyo; M. Suzuki, K. Ikeda, N. Inada, R. Sato, Japan Oil, Gas and Metals National Corporation
Objectives/Scope: Dispersion of cuttings transport velocity limits the depth resolution of mud logging. Modeling of cuttings lag depth distribution caused by the dispersion of cuttings transport velocity in directional drilling is presented. The depth resolution of mud logging in directional and horizontal wells is evaluated based on the cuttings lag depth simulations using the developed model.
Methods, Procedures, Process: The new approach of cuttings lag calculation is based on the previously developed complete physical model of transient cuttings transport behavior in directional drilling (SPE-171740-PA). In addition, the lag distribution is modeled using the log-normal probability density function. The parameters of the distribution function are determined by lag time measurement experiments for various hole inclination angles using a large-scale cuttings transport flow loop apparatus. The implementation of lag depth calculation is achieved by convolving the lag distribution functions determined for each hole section with different inclination angles. The detail mathematical method is described.
Results, Observations, Conclusions: The lag depth distribution model is compared to the conventional lag calculation methods using bottoms-up time or cuttings slip velocity. Lag depth simulation studies are presented for a simple horizontal well case and a more realistic field directional well case. The most significant new finding is that cuttings sampled at the surface can be contaminated by cuttings originated from other unintended depths to the extent being not negligible compared to the typical sampling interval of 30 ft or 10 m. This tendency of smearing in the formations and depths from which the sampled cuttings are originated would be significant if the high inclination or horizontal hole section exceeds a certain length depending on the rate of penetration.
Novel/Additive Information: Novelty of the new method is the ability to quantitatively evaluate the uncertainty in the depth resolution of mud logging that is crucial for improving the lateral quality of reservoir characterization, which can be beneficial such as in shale oil and gas projects.
IADC/SPE 189703
Artificial Islands vs. Wellhead Towers: Search for Optimized Infrastructure for Shallow-Water Developments
J.E. Hess, M. Franco, B. Gille, Halliburton
Objectives/Scope: Artificial island construction is increasingly being adopted by the oil and gas industry. As part of the long-term development plan for a brown field in shallow waters, a drilling study was conducted to evaluate the feasibility of using artificial islands to reduce field development time, costs, and risks. This paper describes how a multidisciplinary project team incorporated artificial islands in combination with wellhead towers to develop an optimized drilling scenario, reaching approximately 200 drilling targets while navigating through 1,600 existing wells in close proximity.
Methods, Procedures, Process: The project team used 3D visualization software to analyze wellhead tower and artificial island(s) surface locations, targets, and surface and subsurface hazards to develop a variety of drilling scenarios. Each scenario was then evaluated based on four criteria: technical feasibility, costs, time, and potential risk. First, technical feasibility was determined by calculating maximum drilling depths based on the tubular mechanical constraints. Next, scenario costs were calculated using well cost modeling software. In addition, drilling time was estimated by creating a project plan for each scenario. Finally, potential risks were identified and ranked in terms of probability and impact in several risk workshops, and mitigation plans were developed. All criteria was considered when determining the optimal drilling scenario.
Results, Observations, Conclusions: Through collaborations with multiple departments, the key objectives of the field development project were identified and made a focal point for critical activities. This enabled multiple simultaneous software simulations through which several unique field development configurations could be performed and calculated with an optimal scenario identified. This enabled the project team to evaluate various development scenarios based on defined well complexity, risk, and well trajectory requirements. Collaborative planning with strong operator participation enabled the project to be completed on time and within budget with key objectives met.
Novel/Additive Information: The project team had to navigate through a maze of approximately 1,600 wells in close proximity to almost 200 drilling targets. Well trajectories were carefully developed to reduce collision and fault intersection risks. Anti-collision analysis was performed on the worst case wells for each scenario, which proved very valuable in identifying an optimal scenario. Then, based on the tortuous nature of the wellbores after performing the anti-collision analysis, casing designs were created using industry standards to determine maximum drilling depths that could be reached without breaching the tubular mechanical integrity, and the wells were categorically defined as high, medium, or low risk wells based on predetermined criteria. A classification cost model was then designed for each well type, including empirical risk event data. Based on this information, analysis was performed to determine both probabilistic and deterministic well costs both with and without risk. As a result, the development cost per well and the field development as a whole could be determined, as well as the risk value per scenario at any point during field development. Additionally, the full project schedule and timeline were developed based on previous outputs to determine which scenario would best meet the facilities timing and production objectives.
IADC/SPE 189618
Reconstruction of Pipe Displacement Based on High-Frequency Triaxial Accelerometer Measurements
Cayeux, Intl Research Inst of Stavanger
Objectives/Scope: Heavy vibrations in the bottom hole assembly (BHA) may cause permanent damage to the bit or other BHA components, like measurement while drilling (MWD) tools or rotary steerable systems (RSS). Tool-joints along the drill-string may get warned out by high levels of whirl along the drill string. Repetitive shocks of drill pipes against the formation may be the origin of wellbore instabilities or cause malfunctions of the communication network of wired drill pipe high-speed telemetry communication systems.
Methods, Procedures, Process: Because of all these potential problems, it is important to better understand how pipes actually move inside a wellbore. High-frequency recordings of triaxial accelerometer measurements at different locations inside the BHA, or along the drill string, open the possibility to reconstruct the actual displacement of drill string tubulars. However, because accelerometer readings are taken in a reference frame that is not in uniform movement compared to a fixed referential, the readings are subject to complex effects of centrifugal, Coriolis and Euler accelerations that make the estimation of the pipe movement rather intricate.
Results, Observations, Conclusions: Without considering these so-called fictitious accelerations, it is easy to misinterpret the actual movement of the accelerometers attached to a pipe. For that reason, a numerical method has been developed to calculate the displacement of the support of the accelerometers. To validate the numerical model, a laboratory setup has been built that allows for a precise control of the movement of an element that supports three triaxial accelerometers. The known displacements of the accelerometer support and the reconstructed displacements have been compared and a methodology has been developed to use the redundant measurements to reduce the uncertainty of the estimated movement resulting from inaccuracies around the exact position and orientation of the accelerometers relatively to its support. The validated model has then been applied to actual high-frequency measurements taken along a drill string to reconstruct the plausible path followed by drill pipes far beyond the BHA while drilling a complex trajectory.
Novel/Additive Information: Lately, several publications have reported results from high frequency triaxial measurements at different locations along the BHA and the drill string, while others have pointed out the risk of misinterpretation associated with the existence of fictitious accelerations. This paper presents a validated numerical method that allows for an accurate reconstruction of the displacement of drill string and BHA elements therefore providing a unified point of view to the problem of estimating drill-pipe displacements based on accelerometer measurements.
IADC/SPE 189575
Investigation of Fracture Reopening Pressure in Wellbore Strengthening
Zhong, S.Z. Miska, M. Yu, M.E. Ozbayoglu, N.E. Takach, University of Tulsa
Objectives/Scope: Lost circulation is one of the most costly drilling issues and a major contributor of non-productive time. Wellbore strengthening has been successfully applied to reduce the associated cost and increased the wellbore stability over the past two decades. It is of critical importance to accurately predict the extra drilling margin after wellbore strengthening. However, previous research assumed fixed boundary conditions and only considered the stress intensity factor in the calculation of fracture reopening pressure (FROP). The change of pressure boundary on the fracture surfaces was ignored, which may overestimate the FROP.
Methods, Procedures, Process: This paper employed a dislocation-based fracture model to determine the FROP in wellbore strengthening. The proposed model is verified with finite element simulation. An excellent match is obtained for the fracture profile and a clear inflection point can be observed between the plug zone and unplugged zone. We present how wellbore pressure can change the pressure boundary in the model. Thus, the FROP calculation can be modified with the consideration of fracture plug width.
Results, Observations, Conclusions: Results show that the fracture plug zone pressure can affect the fracture profile. Furthermore, lower fracture plug zone pressure results in higher FROP. Thus, better wellbore strengthening can be achieved in the depleted sections during drilling. On the other hand, the fracture plug width plays an important role in determining FROP. With fixed fracture plug location, larger fracture plug width can lead to higher FROP. However, there exists a critical fracture plug width for the maximum FROP, which is the value predicted by the previous research. Finally, the implications for field applications are presented.
Novel/Additive Information: The study reveals the importance of fracture plug zone pressure and fracture plug width for FROP in wellbore strengthening. The model is useful for the design of wellbore strengthening materials, which are critical to achieve the best wellbore strengthening effect.
IADC/SPE 189593
Wellbore Stability Solution Incorporating the Weak Bedding Planes Effect with Field Case Study
Mehrabian, Formerly Halliburton; A. Diaz-Perez, C.L. Santana, Halliburton
Objectives/Scope: Wellbore stability in low-permeability shale is strongly influenced by disturbances in the pore fluid pressure, and consequently, effective stress of the rock surrounding the wellbore. In addition, the detrimental effect of existing planes of weakness by enhancing the rock tendency for shear failure is well-documented in the literature. This paper investigates the simultaneous effects of these factors by taking a poroelastic approach to the wellbore stress problem, together with the analysis of rock failure along a weak bedding plane. The paper presents a case study of the highly inclined section of a well in a laminated layer of troublesome shale above the target formation at Sacha field in Ecuador with strike-slip faulting regime.
Methods, Procedures, Process: A closed-form solution to the time-dependent and fully coupled poroelastic formulation of the wellbore stress problem is derived and presented. The mud weight threshold for shear failure of the intact rock is determined by applying Drucker-Prager, Modified-Lade, or Mohr-Coulomb failure criteria to the obtained wellbore stress solution. In addition, a Coulomb failure analysis in a coordinate system aligned with the normal-to-bedding-planes axis is conducted to obtain the mud weight threshold that may trigger the slip of the rock along the bedding planes. In the case study, the rock strength anisotropy is characterized by the published laboratory results of measured variations in the rock compressive strength vs. relative orientation angle between the applied load and bedding planes of the tested samples. The obtained mud weight values are compared to determine the overall collapse margin of the wellbore section.
Results, Observations, Conclusions: Study findings indicate that, even in the case of a fully sealed wellbore wall, the poroelastic effects can trigger substantial disturbances in the pore fluid pressure of the shale around and away from the wellbore wall. Depending on the rock permeability, the resulting variations in the rock effective stress may cause a significant time-dependency in the collapse mud weight of the wellbore. The effect of weak bedding planes on the collapse mud weight is determined by identifying a critical wellbore inclination angle beyond which the tendency of rock to slip along the bedding planes would dominate the shear failure mechanism of the intact rock matrix. The obtained critical inclination in the case study was too low to enable horizontal drilling in the reservoir rock below the troublesome shale section. Consequently, it was advised to continue drilling the well deeper than the planned true vertical depth (TVD) and to reenter the reservoir from the bottom.
Novel/Additive Information: The novelty in this work arises from the fully-analytical approach and the integrated methodology that combines coupled poroelasticity and weak bedding plane solutions to the wellbore stability problem. The approach allows for more accurate evaluation of the safe window of drilling fluid density.
IADC/SPE 189712
Dilatancy and Pressure Dependence of Threaded Connection Performance
R.F. Mitchell, Well Complete; M.A. Goodman, Altus Well Experts
Objectives/Scope: Connector joint strength and leak resistance depend on internal and external pressures. Axial tension or compression opens (dilates) the connector, while the pressures tend to close the connector. This paper presents a “toy” connector model that incorporates actual connector elements, but in a simplified form useful for analysis, so equations of joint strength and leak resistance can be determined as functions of axial load and internal/external pressures.
Methods, Procedures, Process: In a previous paper, one of the authors looked at a failure criterion dependent on hydrostatic pressure as a possible model for connector performance, and evaluated a 7” API round thread connector from a purely theoretical approach to show that the hydrostatic effect allows the connector to withstand differential pressures higher than the published ratings. This paper is a follow-up of that paper to develop more specific information on the mechanics of connectors. The “toy” connector formulated in this paper, while not an exact model of an actual connector, provides guidance for the testing and evaluation of real connectors. The analysis demonstrates that connector dilatancy and contact forces are indeed dependent on the hydrostatic component of the stress.
Results, Observations, Conclusions: If the connector opens too much, the connector will pull out, so hydrostatic pressure tends to make the connector stronger. If a leak is determined by contact forces at the teeth or sealing element, it seems clear that hydrostatic pressures influence the contact forces. Pipe body strength is adequately modeled by the von Mises criterion, which is independent of hydrostatic pressure. Connectors are more complicated mechanically and can dilate due to shear forces across threads created by pin/box axial loads, so a von Mises criterion is less plausible as a model for connector failure. Current connector failure criteria tend to be uniaxial in nature, so they are not even as sophisticated as triaxial pipe body criteria. The most sophisticated connector model plots connector performance as points on a force-pressure plot, connected with straight lines. The simple “toy” model in this paper confirms that dilatancy associated with the hydrostatic component plays a critical role in connector failure (leak or pull-out). Von Mises stress alone cannot model dilatancy and the hydrostatic effect.
Novel/Additive Information: This paper supports the conclusion that the Drucker-Prager failure criterion, which includes hydrostatic dependence and was proposed in a prior paper by one of the authors, is more suitable than von Mises for describing threaded connections. This means that substantial cost savings can be realized from reduced connector testing, efficient extrapolation across connector types and sizes, and optimal placement of connectors to harness the hydrostatic benefit. Experimental validation is the next step.
Tuesday, March 6 (Station 2: Knowledge Sharing ePosters)
IADC/SPE 189706
Adaptive PDC Drill Bit Reduces Stick-Slip and Improves ROP in the Midland Basin
Phillips, D.E. Gavia, A. Noel, M. Savage, T. Stefanik, Baker Hughes, a GE Company
Objectives/Scope: In-bit vibration sensors reveal that stick-slip and lateral vibrations are the primary cause of poor polycrystalline diamond compact (PDC) bit performance in the 12-1/4” section of the Midland basin. Premature dulling leads to low penetration rates and failure to reach the targeted depth. New drill bit technologies have been designed to mitigate stick slip and lateral vibrations. This paper shows the method utilized to reduce drilling vibrations and increase penetration rate and footage to meet the operator’s objectives.
Methods, Procedures, Process: Performance benchmarks were established by conducting a post-run analysis of drilling parameters incorporating in-bit sensing vibration data and through PDC bit dull evaluation from offset runs. This analysis led to new designs incorporating shaped diamond elements (SDE) to mitigate lateral vibrations and ovoid’s with adaptive exposure that mitigate stick-slip without hindering rate of penetration (ROP). After the field runs showed a poor dull on the 6-blade frame and low performance from the 7-blade frame, they were tested in multiple states in a high-pressure downhole simulator to determine which elements have the highest effect on performance. The learning’s from these where applied to a more durable, higher performing design.
Results, Observations, Conclusions: The 6-bladed bit drilled 6636 feet, which is average footage, compared to offsets. However, the vibrations recorded during the 6-bladed bit run were 82% smooth, which is significantly less than the 52% smooth drilling typically seen in this interval. The bit was tripped short of target depth, due to low ROP with a ring-out in the shoulder. To improve durability the team recommended a 7-blade PDC bit, which resulted in low performance through ROP. With this result, the bit was laboratory tested replicating the ROP observed at the end of the field run by selecting an equivalent carbonate rock and adjusting the simulator to the overburden pressure. This provided a baseline that could evaluate the true impact of design changes, on field performance. Comparison of the all the features indicate that edge geometry, blade count, cutter size and backrake angle can increase ROP by making the bit drill more efficient while decreasing overall bit aggressiveness at lower ROP’s. The findings show the primary benefit is improved ROP at high power levels, and reduced bit reactive torque at low power levels, at the time when lateral vibrations typically occur. The adaptive and SDE features will further add to this performance by reducing vibrations. This holistic approach allowed the team to identify the primary performance limiters through field, laboratory and downhole vibration analysis. The suite of full bit simulator tests established several key learnings, to improve performance. These learning when applied to the new design, proved to have good durability, reduced vibration and high performance, meeting the customer’s objectives.
Novel/Additive Information: Design improvements were achieved based on the results of field tests and a series of full bit high-pressure simulator tests. The combination of adaptive PDC drill bit technology and shaped diamond elements was used to reduce downhole vibrations, thereby enabling the operator to improve overall bit performance and durability.
IADC/SPE 189621
A Method to Estimate Working Range of Vibrators
Zhang, R. Samuel, Halliburton
Objectives/Scope: Agitators are used to create oscillation in the string, which can reduce the amount of friction force present on the string. Ordinarily, the placement of agitators is based on past field experience; an improper arrangement of agitators, however, will reduce their efficiency and can cause tool damage. This paper proposes a new method based on stress wave theory to predict the working range of an agitator and help to ensure that agitators are installed at optimal locations in field operations.
Methods, Procedures, Process: Driven by drilling fluid, agitators create a periodical pressure pulse that becomes a periodical stress wave in the drill string. The proposed method uses stress wave theory to calculate the vibration velocity. Beginning at the agitator, the stress wave travels a far distance in the string. The friction on the string, however, diminishes the stress wave energy until the vibration speed reaches zero. The agitator working range is defined as the string section with a non-zero oscillation velocity. Within this range, the friction force on the string is kinetic friction force, as compared to the static friction force without oscillation velocity.
Results, Observations, Conclusions: This model provides a theoretical prediction of agitator work range that can optimize agitator use. The agitator work range is the range within which the stress wave energy is large enough to cause the string to oscillate. The stress wave travelling distance predicted from this model is likely to be a linear relationship to the acceleration generated by the agitator, which is similar to the results obtained in the field. The predicted work range level is very close to the field data, likely 1,000 or 2,000 ft. The paper also discusses the reflection of stress wave in the string, which suggests that using the average vibration speed in calculation is better than the maximum vibration speed in this model.
Novel/Additive Information: This paper presents a new method of predicting the work range for agitators that is based on stress wave theory. It also includes a set of equations that are proposed to calculate the stress wave travelling distance. This model can be used to better determine the most effective placement of the agitators in horizontal wells.
IADC/SPE 189654
Probability of Wellbore Intercept Made Easy
J.M. Codling, Halliburton
Objectives/Scope: Wellbore intercept probability calculations are important not only for avoiding collisions but also for relief well planning and planning for wellbore re-entry in abandonment projects. This study reviews current methods for calculating probability and their sensitivity to input variables. A probability of intercept calculation is presented that is proved, robust, and can be implemented in a spreadsheet using input wellbore positions and survey error dimensions.
Methods, Procedures, Process: Given the lack of availability of empirical collision data, it was necessary to model the wellbore intercept scenario using a Monte Carlo simulation constructed by breaking the two wellbores into short segments. Simulator validity is highly sensitive to the probability distribution of the input survey errors. The input probability distribution of well separations in the high side and lateral directions is determined from survey comparison studies for both systematic and random error sources. The simulator is used to compare the accuracy and reliability of different probability integration types and sensitivity to the input data and distribution of errors.
Results, Observations, Conclusions: It is observed from survey comparisons that the distribution of survey inclination and azimuth errors behave as “heavy tailed” probability distributions, such as Laplacian or Student’s t. This increases the probability of intercept at higher sigma levels than the previously assumed normal distribution. The results of this study show the sensitivity of the probability result to the degree of sophistication of the probability calculation from a simple one-dimensional projection to a three-dimensional integration of probability density. There is a law of diminishing returns with the sensitivity of complex models being lost in the reliability of the input error values and assumptions on probability distributions. One observation is that there is no “pedal curve” effect for high-angle well crossings. The simple point-to-point collision calculations using this vector method do not include the confidence in the relative direction of the two wellbores. Therefore, probability calculations and separation factor calculations that engage the pedal curve distances are overly conservative. A comparison is made to show the change in confidence when a survey quality checking procedure is implemented based on comparison checking against a second survey. The process of survey rejection should remove outlier values and, therefore, help improve confidence in the original survey.
Novel/Additive Information: A reliable prediction of wellbore intercept probability is achieved using a relatively simple method. There is a measurable improvement to the confidence of wellbore position given quality checking against second redundant surveys. The economic value of second surveys is quantified based on the positional objectives of the well. This study shows the importance of the angle of intercept to enhance interception probability for relief wells and the abandonment of re-entry work.
IADC/SPE 189596
A New Approach to Characterize Dynamic Drilling Fluids Invasion Profiles in Application to Near-Wellbore Strengthening Effect
C.P. Ezeakacha, S. Salehi, University of Oklahoma; F. Bi, Grace Instrument Company
Objectives/Scope: Drilling fluids loss and complex invasion profiles in various lithologies are influenced by several operational factors. In this study, rotary speed effect, geothermal impact, type of wellbore strengthening material (WSM), concentration of WSM, overbalance and formation pressure, eccentricity, type of rock and rock permeability, and fracture size were considered. Combining these factors in a preventative approach can minimize drilling fluid invasion, in addition to providing data for quantifying near wellbore strengthening by filter cake evolution.
Methods, Procedures, Process: Experimental and statistical methods were integrated to investigate the individual and interaction effects of these factors, as well as their significance. Factorial Design of Experiments (DoE) was used to generate the experimental matrix. The levels of the selected factors were chosen from a drilling fluid loss database and industry recommendations. The rheological stability of each mud recipe was tested for operating temperature limits. Dynamic drilling fluid invasion experiments were performed using cylindrical-wellbore shaped ceramic filter tubes, various lithology samples, and fracture slots of variable fracture widths. Data acquisition and statistical computation was used to generate fluid loss response to these conditions and their significance.
Results, Observations, Conclusions: The results and analyses from the tests indicate that temperature, rock type and permeability, rotary speed, and WSM concentration are the most influential factors. The cumulative fluid loss profiles generated for each experiment reveal that ceramic filter tubes cannot represent the complex fluid invasion profiles in actual rocks. The invasion rate profiles also reveal that the critical invasion rate changes from one lithology to another, and is highly dependent on the influential factors mentioned. This in part, controls the near wellbore bridging process by internal mud cake build up. It is important to consider formation permeability and porosity side-by-side in designing an optimum drilling fluid system. This approach can potentially aid in drilling fluid optimization for minimizing fluid loss, cost reduction, and selection of best-fit operational conditions.
Novel/Additive Information: The novelty in this approach is that the cylindrical-wellbore shaped Sandstones, Limestones, Chalk, and core slots with varying fracture sizes and orientation will provide qualitative and quantitative data for characterizing near wellbore bridging effects in specific operating conditions. Statistical correlations are also generated for estimating dynamic drilling fluid loss in different lithologies, based on the influential operational factors.
IADC/SPE 189598
Wellbore Instability Prediction Using Adaptive Analytics and Empirical Mode Decomposition
Lin, M. Alali, S. Almasmoom, University of Southern California; R. Samuel, Halliburton
Objectives/Scope: Despite all previous knowledge and experience, many wellbore stability issues can still be encountered when drilling a particular formation. Wellbore stability is a combination of multiple factors that can be interrelated. Although there is no acceptable universal mathematical model that describes the behavior, the use of the large amount of data collected while drilling can provide insight. The combination of adaptive data analysis techniques with artificial intelligence models can be used to predict wellbore stability.
Methods, Procedures, Process: This study uses data from several wells located in the same field and contains 20 input parameters. With so many input parameters, commonly known feature extraction techniques, such as principal component analysis (PCA) and linear discriminant analysis (LDA), were used in an attempt to reduce the dataset dimensionality. Next, nonlinear artificial intelligence models, such as the Bayesian regularization neural network (BRNN) and support vector machine (SVM) models, were implemented. The data were continuously fed to these adaptive data analytics algorithms, which decomposes the incremental data at each depth into its intrinsic mode functions (IMF) using empirical mode decomposition (EMD). The classification accuracy was observed for both models. The input parameters were filtered with EMD, and the classification accuracy was observed and compared. To increase the speed and straightforwardness of this entire process, the energy of the final IMF, referred to as IMF energy, was also continuously computed. This algorithm can be implemented in two ways: incremental depth analysis and incremental depth interval analysis. The depth interval analysis can be used in the preplanning stage of drilling operation to identify the intervals in which the field personnel should use more caution; the incremental depth analysis can be used while drilling.
Results, Observations, Conclusions: The results from the feature extraction techniques (PCA and LDA) showed that the dimensionality of the dataset could not be effectively reduced while retaining valuable information from the original data. Consequently, the nonlinear artificial intelligence models were implemented. The BRNN and SVM models achieved relatively accurate results; however, the use of EMD to filter the input parameters achieved a higher classification accuracy. The study results show that EMD improved classification accuracy by approximately 15% for both the BRNN and SVM models. Increased classification accuracy provides better foresight for drillers during the planning drilling operations, especially in potentially unstable intervals, which leads to significant cost reductions. In either case, the depth and/or depth interval at which the IMF energy becomes negative and/or the trend of the final IMF plot changes the shape indicates the depth and/or interval at which the wellbore instability risk is high and may lead to instability. The results were also verified with the historical data from the field to confirm the predictions of the algorithm presented. The results predicted were synchronous. There have been no false results recorded to date.
Novel/Additive Information: EMD was used to reduce high variation in the data and examine the effect on wellbore stability classification accuracy. It is commonly used in the field of signal processing to eliminate noise and variation in the data.
IADC/SPE 189696
Real-Time Well Construction Process Inference Through Probabilistic Data Fusion
Chambon, S. Venkatakrishnan, M.K. Hamzah, J. Belaskie, Y. Yu, Schlumberger
Objectives/Scope: Well construction process automation systems rely on the tracking of the state of the world (equipment, wellbore, process) with a high degree of confidence for safe and efficient operations. Robust state detection algorithms are paramount as they depend on uncertain models and data from imperfect sensors. The proposed solution outlined here is a practical implementation for well construction state inference, for instance bit interacting with rock and slips status.
Methods, Procedures, Process: Probabilistic mixture models are learned from windowed input sensor data stream, e.g. surface torque and hook load, accounting for noise and suitable priors. These models are then used for online classification of observations related to the underlying state of operations (e.g. on bottom drilling vs off bottom rotating). Multiple classified observables from different types of measurements are subsequently fused into system states using a temporal Bayesian network, giving a robust state detection under uncertainty. The method requires drilling mechanics knowledge in the interpretation of the classification as well as the design of the Bayesian network model.
Results, Observations, Conclusions: The method was applied on real sensor data (hook load, surface torque, stand-pipe pressure), for the inference of elementary states such as slips status (in / out of slips), and bit interaction with rock (no interaction, bit fully engaged with formation, in transition).
The use of windowed input data to continuously learn the mixture model allows the tracking of levels. For instance, hook load is modeled as the mixture of several distributions evolving as the well progresses, correlated to the drill string being in slips, out of slips off bottom, or on bottom rotating.
Observations inferred from the mixture models have various levels of confidence, but the Bayesian network allows their fusion into a robust system state. For instance, different observations are made when going on bottom, whether in rotary or slide drilling mode.
In conclusion, the proposed Bayesian network backed by mixture model is a fast, adaptive and robust solution to detect system state from drilling time series with complex temporally correlated patterns.
Novel/Additive Information: By learning from data and using priors from domain experts, the inference algorithms operate without user tuned thresholds or parameters. The probabilistic Bayesian approach provides a framework for dealing with uncertainty in drilling systems and can be extended in the future with additional observations drawn from new measurements.
IADC/SPE 189620
Dynamic Axially-Stiff String Model for Tripping Operations in Directional Wellbores
Zamanipour, S.Z. Miska, University of Tulsa; P.R. Hariharan, Shell
Objectives/Scope: The soft string model has been widely used for torque and drag calculations. Although several modifications have been developed, the standard model in the oil and gas industry is the static soft string model, in which the string is assumed to be motionless and its stiffness is neglected. Not only the acceleration effect, but also axial stiffness of the string should be included in the soft string model to provide a more realistic and accurate calculation of drillstring loading. In this paper, a dynamic axially-stiff string model is presented for load calculations of drillstring motion in 2D and 3D wellbores. The new model considers both acceleration and axial stiffness.
Methods, Procedures, Process: The mathematical model is developed to introduce axial stiffness of the drillstring and acceleration effects into the soft string model by coupling a mass-spring system and the soft string model. Moreover, static friction and drilling fluid drag are also taken into account. The drillstring is considered to be a system of several coupled harmonic oscillators subject to gravity and buoyancy, as well as mechanical and viscous friction forces. The motion of the individual oscillator is governed by external forces and the forces applied by its two neighboring oscillators. The static friction effect is included as a constraint for initiation of motion. A different friction model based on continuous velocity dependency is employed to model and, in the process, account for the discontinuity between static and dynamic friction forces.
Results, Observations, Conclusions: The drill string configuration is considered to consist of drill pipe, drill collar, and directional assembly. The developed model (“new model”) is implemented for tripping-out one stand in three ideal directional wellbores plus one field case wellbore trajectory and the following conclusions are obtained accordingly. Axial force shows a trend of acceleration that is similar to that observed with the previous dynamic soft string model (“previous model”: SPE-173084-MS), and the first peak contains the effect of static friction. Displacement at the end of the string shows that the whole drill string is in motion after few seconds. Hookload for tripping out of a field case wellbore trajectory with the doglegs shows more oscillations in the hookload for similar assumed damping factors. Axial force using the new model is compared to axial force calculated using the previous model for two different cases. In the acceleration part of the motion, the new model shows a peak about 12% higher than the maximum load in the previous model which is due to the static friction force effect. In the constant velocity interval of motion, depending on the amount of damping, the new model can show a result similar to that of the previous model. The Stribeck friction model, which provides continuous velocity dependency, is applied to the calculations and the results are compared to the Coulomb friction model. The Stribeck model provides a smooth transition between static and dynamic conditions. The implemented cases show that Coulomb friction model is sufficient for these types of calculations.
Novel/Additive Information: New dynamic axially-stiff string model provides more realistic prediction of hookload, and consequently more realistic loading of the hoisting equipment and fatigue life of the drill string. Other applications of this model are wellbore planning, drill string design, problem detection, optimization and automation of tripping operations.
IADC/SPE 189628
Robust MMH Drilling Fluid Mitigates Losses, Eliminates Casing Interval On 200+ Wells in the Permian Basin
Offenbacher, N. Erick, M. Christiansen, AES Drilling Fluids; C. Smith, CES Energy Solutions; T. Barnard, R. Farrell, Occidental Oil and Gas Corporation
Objectives/Scope: The objective of the paper is to introduce how a mixed metal hydroxide (MMH) system was able to improve drilling efficiency by comparing data before and after introduction as well as highlighting improvements and lessons learned during the use of the system. The most noteworthy savings is the elimination of a casing string across a troublesome salt interval.
Methods, Procedures, Process: The original problem presented was the need to eliminate washout associated with drilling through salt sections. The MMH system was recommended to prevent turbulence which would aid in incorporating more salt from the formation into the water-based drilling fluid. While the system achieved that objective, several other benefits were derived including improved well integrity and the elimination of a casing section.
Results, Observations, Conclusions: Historically, MMH systems cannot tolerate a variety of contaminants, including high salinity and anionic materials. The recommended MMH system was designed to tolerate this contamination and continue to perform. The MMH system mitigated excess washout and also aided in density control. The original gel system incorporated salt from the formation, resulting in increased density and the risk of losses. To control the density the salt concentration was diluted with water, increasing overall fluid volumes and associated waste. The MMH system also featured greater flexibility with density control as its thixotropic nature limited fluid invasion. Observations suggest that losses occurred at 0.2 to 0.4 lb/gal high density than the gel system. These benefits resulted in the ability to eliminate a casing string across the salt section and the weaker section below. As experience grew using the new system, optimization resulted in further waste reduction and the elimination of earthen pits.
Novel/Additive Information: While MMH has been available for over 30 years, this system offers the necessary debris tolerance to drill in challenging zones. Experience with the system in the Permian basin presents the opportunity to improve drilling efficiency elsewhere.
IADC/SPE 189590
Fuel Economy and Emission Characteristics of a High Horsepower Natural Gas/ Diesel Dual-Fuel Engine in Oil & Gas Operations
A.I. Wijesinghe, C. Lafleur, F. Meng, J. Colvin, R.C. Haut, Houston Advanced Research Center
Objectives/Scope: An evaluation of the fuel economy and emissions characteristics of a compression ignition natural gas/diesel duel-fuel engine is presented to compare and determine the benefits of substituting part of the diesel fuel with natural gas as a fuel source for modern drilling operations.
Methods, Procedures, Process: A series of tests were conducted on an engine fitted with a dual-fuel system and fully equipped with the instrumentation required to better understand the engine’s performance and emissions. The engine was operated at rated speed- 1200 RPM, with eight different load points. Specific generator operating/control parameters were obtained from the engine controller unit (ECU). Flow meters were used to measure the instantaneous natural gas and diesel flow rates. Gaseous emissions and soot, the main component of particulate matter (PM) in exhaust, were measured using a Fourier Transform Infrared (FTIR) Spectroscopy gas analyzer and a micro soot sensor.
Results, Observations, Conclusions: The effects of natural gas/diesel substitution ratios, engine speed, load, brake specific fuel consumption (BSFC), and gaseous emissions of hydrocarbons (HC), carbon monoxide (CO), carbon dioxide (CO2), formaldehyde (CH2O), and nitrogen oxides (NOx) were compared for the dual-fuel and diesel operation modes. Over a wide range of operating conditions, the duel-fuel mode clearly shows the benefits of reduced NOX, CO2, and soot emissions. Significant disadvantages are seen in emissions of non-combusted methane (NCM) and formaldehyde. In the typical operation 6% – 25 % of the NCM was emitted, significantly diminishing fuel economy and increasing greenhouse gas emission. However, under low loads, the results indicate high CO and HC emissions and a higher brake specific fuel consumption when compared to those of the diesel only operation. Dual-fuel engines have the advantage of providing the same power as conventional diesel generators, producing lower amounts of emissions such as NOx and soot, and cost saving through diesel displacement up to 50 %. These results raise both challenges and potentials for natural gas/diesel duel-fuel engine controller design & operation. In conclusion, given the right economic environment, dual-fuel engines can be beneficial to the oil & gas industry.
Novel/Additive Information: Compression ignition diesel engine units are converted to natural gas/diesel dual-fuel operation using a moderate engine modification. However, just how these new dual-fuel generators and emissions control technologies perform in day-to-day oil and gas industry operations is not well documented. The data generated by this work can not only answer questions about natural gas/diesel dual-fuel engine fuel economy and emissions, but can also be used to develop a more accurate emissions inventory for oil and gas operations.
IADC/SPE 189625
Fuel Economy and Emission Characteristics of a High Horsepower Natural Gas/ Diesel Dual-Fuel Engine in Oil & Gas Operations
IADC/SPE 189686
Annular Casing Seal Test Method
W.W. Fleckenstein, R. Baker, A.W. Eustes, Colorado School of Mines
Objectives/Scope: A method and apparatus to test the annular seal of a casing string placed in a wellbore is presented. Results are presented of experimental studies using prototypes under a variety of cemented casing conditions to determine the ability to detect well and poorly cemented casing annular seals.
Methods, Procedures, Process: Prototypes were constructed of 4 1/2” casing, with eighteen ¼” ports radially distributed in two offset rows accessing bores encapsulated in a PDC drillable cement. When the interior of the tool is drilled out, the array of encapsulated bores is exposed, allowing pressure and flow communication between the interior and the annulus of the casing. Prototypes tested in shallow test wellbores confirm the ability of the technology to detect well cemented and poorly cemented casing annular conditions.
Results, Observations, Conclusions: The new annular casing seal test (ACST) successfully measures the annular casing seal in the wellbore using a positive pressure test. Six prototypes were constructed and cemented into test wellbores. Two prototypes had good cement jobs and four prototypes had poorly cemented annuli, which the annular casing seal test is designed to easily distinguish between. A well cemented casing annulus is easily detected, since the test pressure only encounters the annular cemented across the full circumference of casing. A poorly cemented annulus is similarly detected, since pressure escapes the ports into the void in the cemented annulus. An important application of this method allows the annular seal at the casing shoe in surface casing to be inexpensively and quickly tested, providing an affirmative confirmation of the protection of the aquifer that the surface casing is protecting. This is an improvement over the casing shoe test, which is a measure of formation strength, and has demonstrated short comings in detecting poor cement jobs near the casing shoe in a variety of applications. This is also an improvement over cement bond logs, which are more expensive, time consuming, and do not provide a positive test of hydraulic isolation.
Novel/Additive Information: The ACST provides a simple yet robust direct test of the hydraulic isolation of the annulus of a casing string. This provides inexpensive evidence of the seal protecting aquifers.
IADC/SPE 189650
Objectives/Scope: Aluminum drill pipe has already been proven as a viable alternative to steel drill pipe when drilling long horizontal wells thanks to its lighter weight that does not compromise resistance to yield and buckling. At the same time, the development of unconventional wells has seen the deployment of numerous technologies to further improve the performance and increase the lateral section to reduce costs. An operator has recently and successfully tested a new aluminum drill pipe with an axial oscillation tool to push further the limits of the drilling system.
Methods, Procedures, Process: This paper presents the key findings of the case study using a mixed aluminum-steel string combined with an axial oscillation tool. First, the innovative drill pipe design is presented, followed by lessons learned during rig operations regarding pipe handling practices, rig compatibility and pipe inspection. Then, results of the drilling simulations performed during the well planning phase are presented. This modeling led to an optimum drill string design associating the steerable mud motor assembly, aluminum drill pipe, axial oscillation tool and steel drill pipe. The number and placement of aluminum drill pipe along the string was key to reducing friction and improving weight transfer between the bit and the axial oscillation tool.
Results, Observations, Conclusions: Through extensive modeling and field data interpretation, this paper presents the comparison of the overall drilling performance between steel only and aluminum-steel drill pipe strings, and provides metrics in terms of weight transfer and rate of penetration improvement.
Novel/Additive Information: This innovative and promising drill string design opens the doors to set new limits in terms of horizontal departure.
Tuesday, March 6 (Casing and Completions)
IADC/SPE 189637
Optimizing the Deepwater Completion Process: Case History of the Tamar 8 Completion Design, Execution and Initial Performance – Offshore Israel
IADC/SPE 189644
Evaluation of a Casing-in-Casing Refracturing Operation in the Burleson County Eagle Ford Formation
Elbel, N. Modeland, Halliburton; S. Habachy, J. Nabors, R. Brannon, Wildhorse Resources
Objectives/Scope: A case study is presented discussing a refracturing operation wherein a 3.5-in. flush-joint string of casing was cemented inside the original horizontal lateral, 4.5-in. casing. The challenge of successfully cementing this tight annular clearance across existing perforations necessitated a heightened investigation into the necessary cement and rheological properties to achieve sufficient isolation. The overall success of the refracturing operation is evaluated and compared to other refracturing methods without cemented casing string isolation.
Methods, Procedures, Process: The procedure consisted of installing a new production string that tied back to the surface inside an existing horizontal Eagle Ford wellbore. Through proper evaluation of cementing testing and chemistry development, a fit-for-purpose slurry was designed and pumped to maintain circulation, despite tight annular clearance, providing good mechanical properties for proper isolation. Once in place, the well was stimulated using plug-and-perf methodology in a 3.5-in. lateral. Other wells in the Eagle Ford area have been refractured using a bullhead methodology down the original casing that provided no cemented isolation and ineffective fracture stimulation placement; these wells serve as a point of comparison for success evaluation.
Results, Observations, Conclusions: Given the carefully designed cement slurry with the necessary properties for this unique application, a 3.5-in. casing string can be successfully cemented into an existing horizontal wellbore to provide adequate isolation for an effective refracturing stimulation. Circulation and full returns can be maintained, despite the tight annular clearance, and a good cement bond can be achieved; this has been verified by cement bond log. Refracturing a well with this style of isolation using plug-and-perf methodology provides increased production and predictability in comparison to the more commonly performed “bullhead/diversion” refracturing in horizontal wells. Although this process is more costly and complex than the more common “bullhead” refracturing operations, this approach, economically, enhances recovery of an existing asset at a higher rate of return.
Novel/Additive Information: This application of cementing a smaller flush-joint string inside an existing wellbore for refracturing is not currently common within the industry but is gaining more traction and economic results are being delivered. Few operators are presently using this completion technique.
IADC/SPE 189694
Simple Calculation of Compaction-Induced Casing Deformation Adjacent to Reservoir Boundaries
Guo, BP; N.C. Last, BP; M. Blanford, BP
Objectives/Scope: Compaction-induced casing damage, particularly adjacent to reservoir boundaries, has been frequently observed in many fields. As part of mitigation planning for potential casing collapse due to reservoir compaction, expensive numerical models are often employed to quantitatively assess casing strain under simulated reservoir conditions. In order to simplify casing deformation analysis and reduce analysis time, the current study was initiated to quantify the effects of depletion magnitude, rock compressibility, borehole orientation, casing diameter-to-thickness ratio (D/t ratio) and grade on compaction-induced casing deformation using finite element modelling (FEM). The model results allowed an empirical equation to be derived to predict casing strain that is sufficiently accurate for engineering applications.
Methods, Procedures, Process: The objective of the study was achieved by building a series of 3D FEM models to systematically simulate the deformation of casings cemented perfectly within a horizontal reservoir that underwent up to 8.3% compaction due to depletion. To capture the pattern of casing strain variation adjacent to the reservoir boundaries, the simulations were run over a range of borehole deviations (0°, 22.5°, 50°,67.5°and 90°). For each borehole deviation, casing D/t ratios of 8.14, 19.17 and 32.67 and grades of 40 ksi, 90 ksi and 135 ksi were defined to evaluate their impact on casing strain variations.
Results, Observations, Conclusions: The FEM models show that casing deformation adjacent to reservoir boundaries is accommodated by radial expansion and axial shortening in vertical wellbores, while the deformation is characterized by bending in deviated wellbores. The maximum strain adjacent to reservoir boundaries varies systematically, but nonlinearly with each variable evaluated. The maximum strain increases with reservoir compaction strain, i.e. increases with rock compressibility and depletion, but decreases with increasing hole deviation. Both casing D/t ratio and grade affect casing strain, but their effects are secondary. In general, the maximum strain is greater for casings with smaller D/t ratios and higher grades at any given borehole deviation and compaction strain.The variation of the maximum casing strain with compaction strain can be described by a power law. Both its constant and exponent are functions of borehole deviation, casing D/t ratio and grade.
Novel/Additive Information: Because of the complexity of borehole-reservoir geometry and casing plastic behavior, there is no analytical solution available to estimate compaction-induced casing strain adjacent to reservoir boundaries. Numerical models may be used to predict the casing strain, but the numerical analysis is time consuming and requires specialist knowledge. The equation proposed from this study is sufficiently accurate compared to numerical models in terms of casing strain prediction, but provides a much simpler and quicker analysis. In addition, the study provides insight on the variation of casing strain with the major controlling factors, leading to a more complete understanding of compaction-induced casing deformation.
Tuesday, March 6 (Deepwater Operations)
IADC/SPE 189674
LMRP Disconnect in Deepwater, Harsh Environment conditions
Dupal, Shell Exploration & Production Co; J. Curtiss, Shell International E & P; R.H. Van Noort, Shell International E&P Co.; C. Mack, Shell International E & P; S. Greer, Stena Drilling
Objectives/Scope: Operations were being conducted in deepwater, harsh environment conditions offshore Nova Scotia. After securing the well, the rig disconnected the lower marine riser package (LMRP) from the lower BOP. After disconnect, dynamic loads caused an uplift of the marine riser, ultimately resulting in a failure of the tensioner ring support and loss of the riser to the seabed. The paper provides a summary of the root causes and contributing factors for the incident.
Methods, Procedures, Process: The Tripod beta method was used to conduct the review of the incident. The scope of the review included the following:
- Measured data (rig heave, tensioner stroke, tensioner pressures)
- Analytical models for vessel & marine riser dynamics, including the riser tensioner antirecoil system
- Rig/moonpool geometry, riser tensioner ring design, and space-out
- Weather forecasting
- Operating procedures
Based on initial findings, further studies and analyses were conducted to better understand the dynamic behavior during the transition phase from initial disconnect to hang-off position
Results, Observations, Conclusions: Forecasted Metocean conditions from a late winter storm indicated the potential to exceed the threshold for rig heave, with the Marine riser connected to the well. In preparation for disconnecting the LMRP, the well was secured with a storm packer and closure of the blind shear rams. Once the rig heave limit was reached, the LMRP was disconnected from the lower BOP stack. Seven minutes after unlatching the LMRP, the riser tensioner profile on the slip joint outer barrel lifted off the riser tensioner load ring and landed back onto the load ring off-center. This uneven loading caused in the load ring to separate, dropping the LMRP and riser to the sea floor.
Analysis showed that one of the most critical phases of disconnecting the LMRP from the BOP occurs immediately after disconnecting and prior to moving the rig a safe distance from well center.
The investigation indicated that the root causes of the event included human factors, such as additional air added to tensioner system and re-set of the riser anti recoil system prior to final hang-off condition. Contributing factors included riser dynamics analysis and lack of specific procedures for addressing the dynamic system conditions during the critical transition phase.
Novel/Additive Information: The paper provides additional information for riser/tensioner configuration and riser dynamics analyses during harsh environment conditions. In particular, additional analyses are presented for the transition phase from disconnect to hang-off position. Initial data is provided for further development of a smart disconnect algorithm, based on machine learning techniques of hind cast data.
IADC/SPE 189623
Knarr Field – Optimization of Wellbore Clean-up Through Dynamic Transient Modeling
Dimude, Shell; B. Wane, Shell Exploration & Production Co; H. Lu, Schlumberger
Objectives/Scope: Optimized well clean-up planning and procedures are crucial for the effective development of offshore subsea wells and their subsequent production stage to host facilities. The objective of the well cleanup is aimed at ensuring a successful removal of the completion fluids and drill-in fluid out of the wellbore to restore connectivity with the reservoir, maximize well productivity while minimizing tensile sand failure, and properly conditioning the sand face completion (in a standalone screen scenario). In order to achieve this goal, the well clean-up time, bean-up procedure, rate and fluid volumes to be produced should be appropriately estimated to properly size the surface testing equipment required for the operation.
Methods, Procedures, Process: Due to the highly dynamic and transient nature of the cleanup process, the use of a dynamic simulator was required in order to effectively capture the physics of the concurrent flow of the various phases present in the system. An extensive modeling and simulation of the unload process has been performed through the use of a dynamic multiphase simulator to assess the transient displacement of the various wellbore fluids according to several unload strategies. Potential clean-up times and volumes were assessed using flowrate ramp-up schedules designed for different completion fluid distribution in the wellbore. Clean-up to FPSO (4km tie-back) and clean-up to rig scenarios were both evaluated. The constrained flowrate cases were considered to represent the constraint on the rig restricted as a result of surface handling capacity issues.
Results, Observations, Conclusions: The well clean-up procedure was developed to minimize clean-up time, avoid formation damage, and minimize volume of formation liquids on flow back during the rig well tests. During the execution, the movement of fluids along the wellbore, surface production rates, the drawdowns and duration of clean-up to predefined targets were monitored and recorded. The acquired field data from the clean-up operation was compared against simulation prediction and validated the reliability of the predictive model.
Novel/Additive Information: This study proves the transient multiphase simulation to be effective in capturing the physics of the multiphase flow process involved in the clean-up operation. It also demonstrates that, when appropriately done, it could be an effective tool for the planning and strategy selection for the well cleanup operation.
IADC/SPE 189687
Overcoming Tight Annulus Cementing Design Challenges: Gulf of Mexico Case Study
M.I. Dooply, Schlumberger; S. Sianipar, Schlumberger Technology Corp.; F. Rodriguez, Schlumberger; D. Poole, Chevron; C.E. Fuenmayor, Chevron Corporation; J. Carrasquilla, I. Rosero Palacios, Schlumberger
Objectives/Scope: Achieving successful cement placement in tieback casings and liners on deepwater wells is very critical. One of the design challenges is to displace compressible drilling fluid in the tight annulus within the mechanical limitations of downhole tubulars. Accounting for the compressible nature of drilling fluids with changing pressure and temperature, combined with fluid contamination level, will provide better understanding of cementing dynamic pressure during placement.
Methods, Procedures, Process: Cementing tight annulus normally requires managing high placement pressures within the tubulars’ mechanical limits. Field measurements from case studies in the Gulf of Mexico were analyzed and compared with simulated cementing dynamic pressure accounting for effect of synthetic-based mud compressibility as it is displaced by viscous spacer and cement slurry. The rheology of the contaminated mixture also provides an input for better interpretation of cementing surface-pressure response. These analyses, including estimating hookload variations while cementing, allow selection of an appropriate fluid placement rate without exceeding the mechanical limits while also achieving effective fluid displacement.
Results, Observations, Conclusions: Comparison analysis of measured and simulated data shows that use of a complete fluid rheology profile at various temperature and pressure provides a more accurate prediction of cementing dynamic pressure in tight annulus cementing with synthetic-based mud. This approach also allows a better estimation of the minimum rate required for efficient mud displacement enabling an optimal design of the cement slurry thickening time when coupled with a representative mud circulation schedule.
Precise annular clearance of tieback strings provides better understanding of fluid positions inside the tieback strings and annulus, which ensures achieving planned top of cement to mitigate annular pressure buildup. This is critical to protect the outer casing against any potential collapse loading in a blowout scenario.
Interpretation of the surface pressure (job signature) on the tieback string cement jobs indicates the predominance of friction pressure with respect to displacement efficiency, in addition to pipe eccentricity effect and evolution of the rheological properties of different mixtures of mud, spacer, and cement slurry. Monitoring dynamic hookload during cementing also ensures the tieback string stays in tension throughout the job. Hookload loss is mostly due to dynamic buoyancy, although hookload is affected by hydrodynamic drag.
Novel/Additive Information: Knowledge of varying compressible drilling fluid rheology, prejob circulation temperature and pressure, and the effect of pipe eccentricity ensures better understanding of tight annulus cementing dynamics beyond the traditional constant-fluid-properties approach. Dynamic hookload is obtained from dynamic buoyancy and hydrodynamic drag calculation. Applications of these novel engineering methods provide safe cement placement and achieve zonal isolation requirements.
Tuesday, March 6 (Directional Drilling and Hole Placement 1)
IADC/SPE 189607
Directional Advisor Driven Rig and Directional Operation Integration
Hildebrand, Schlumberger Limited; H. Schultz, Obsidian Energy; A.M. Torre, Precision Drilling Corporation; L. Olesen, Pason Systems
Objectives/Scope: In the North America Land market, drilling operations are typically conducted by a selection of different service companies. Each is responsible for a different aspect of the well construction process, but they must work together to deliver a successful well for the operator. This operational model can lead to overlaps and gaps across the various providers in terms of responsibilities and tasks. Due to differing skill sets across rig and directional personnel, integrating rig and directional execution has practically translated into drilling contractors establishing a directional company and providing both services. While this provides a single accountability point for both, it does not fundamentally change the operational model. A new approach to integrated operations is now possible with the assistance of directional advisor software coupled with changes in rig driller capability and accountability.
Methods, Procedures, Process: This paper discusses the advantages of integrated operations enabled by advisor software. The rig driller was trained in the physical aspects of the directional drilling process. Directional advisor software provided step-by-step instructions on steering operations based on formally captured objectives provided by the operator. The software continually tracked the results against those objectives and provided feedback to both rig site and office personnel at each step along the way. The directional drillers utilized the directional advisor software to validate the instructions and monitor operations from a remote command center.
Results, Observations, Conclusions: Twenty (20) wells were drilled for an operator in western Canada using a reduced rig site team using this approach. Nine (9) of those wells were drilled with one directional driller and one MWD engineer at the rig site, supported by a real-time operating center and the software. The last three (3) wells were drilled with all directional drilling operations conducted from the remote command center. Each well was drilled faster than the last, and well time was reduced from 4.5 to 3.7 days.
These results validate that the integrated directional model can deliver record performance in an extremely fast-paced drilling environment.
Novel/Additive Information: After the reduced crew program, the operator requested two (2) additional wells be drilled with full directional crews in order to have a direct comparison in performance. The results from this comparison showed that the integrated reduced crew model performance was not below that of the full crew performance.
IADC/SPE 189691
Automated Directional Drilling Software and Remote Operations Centers Drive Rig Fleet Well Delivery Improvement
C.J. Gillan, Nabors Industries; M.R. Isbell, T.Z. Visitew, Hess Corp.
Objectives/Scope: The Automated Remote Drilling project uses a centralized command center and specialized distributed software systems to automate the directional drilling decision making workflow and the implementation of decisions at the rig. The use of automation to standardize decision making process improves the consistency of results and simplifies the existing process. This centralized command center enables colocation of geo-steering and directional drilling. This results in faster decisions and better wellbore quality and placement with fewer problems, such as mechanical and geological sidetracks. De-manning the directional resources at the rig enables operators to use fewer supervisors to control a larger footprint of rigs than previously possible.
Methods, Procedures, Process: In addition to the standard high-speed data links from office to rig, the project is built around an automated directional drilling guidance system configured to optimize directional slide drilling with motors. The integrated software suite communicates directly with the top drive directional control system to ensure slide commands are implemented exactly as calculated. The software suite also captures and assesses the effectiveness of slides automatically, and it uses sophisticated steering logic and targeting systems to support geo-steering adjustments in the production zone. The standardized workflow leads to actionable metrics that improve the directional drilling process. The steering instruction and resulting execution can be compared against software projections over time to improve the system logic, well planning practices, and bottomhole assembly requirements.
Results, Observations, Conclusions: The authors present feedback from directional drillers on the automated system’s decisions and the results of following system directives in the low angle and nudge sections, the curve, and the lateral wellbore. This includes case studies and summaries of the workflow changes implemented at the remote operations center and at the rig. The Bakken case studies provide evidence of the effectiveness of the automated remote drilling project approach and the benefits of this level of collaboration between a forward looking operator and drilling contractor. Drilling logs, specialized drilling accuracy key performance indicators, and other visualizations show the delivery of the planned and actual wellbores. Rig site and office based personnel commentary are included in summaries based on the major roles involved, such as directional driller, MWD specialist, geo-steering technician, rig driller, toolpusher, and drilling superintendent.
Novel/Additive Information: The combination of a directional drilling guidance system, automated implementation, geo-steering support, and a new, integrated workflow offers an innovative approach to an industry-wide challenge to do more with less in the current market without compromising efficiency, safety, or intervention.
IADC/SPE 189677
A 300 Degree Celsius Directional Drilling System
Stefánsson, HS Orka; R. Duerholt, J. Schroder, J.D. Macpherson, C. Hohl, T. Kruspe, T. Eriksen, Baker Hughes, a GE company
Objectives/Scope: Downhole equipment for oil and gas drilling is typically rated to between 150C and 175C. There is currently very little drilling equipment rated for operation at temperatures above 200C. This paper describes the development, testing and field deployment of a drilling system comprised of drill bits, positive displacement motors, and drilling fluids, capable of drilling at operating temperatures up to 300C. It also describes the development and testing of a 300C capable measurement-while-drilling platform.
Methods, Procedures, Process: The development of 300C technologies for geothermal drilling also extends tool capabilities, longevity and reliability at lower oilfield temperatures. New technologies developed in this project include metal-to-metal drill bits and motors, a 300C drilling fluid, and advanced hybrid electronics and downhole cooling systems for a measurement-while-drilling platform. The overall approach was to remove elastomers from the drilling system, and to provide a robust “drilling-ready” downhole cooling system for electronics. The project included laboratory testing, field testing and full field deployment of the drilling system. It was funded in part by the US Department of Energy Geothermal Technologies Office.
Results, Observations, Conclusions: The use of a sub-optimal drilling system due to limited availability of very high temperature technology can result in unnecessarily high overall wellbore construction costs. It can lead to short runs, downhole tool failures and poor drilling rates. The paper presents results from the testing and deployment of the 300C drilling system. It describes successful laboratory testing of individual bottom-hole-assembly (BHA) components, and full-scale BHA integration tests on an in-house research rig. The paper also describes the successful deployment of the 300C drilling system in the exploratory geothermal well IDDP-2 as part of the Iceland Deep Drilling Project. The well was drilled to an MD of 4659m, by far the deepest in Iceland. One of the motors drilled 436m in 296 hours, one of the roller cone bits drilled 463m in 141 hours. Drilling performance data and the results of post-run analysis of bits and motors used in this well are presented, confirming the encouraging results obtained during the laboratory tests. The paper also discusses testing and performance of the 300C rated measurement-while-drilling components – hybrid electronics, power and telemetry, and the performance of the drilling tolerant cooling system.
Novel/Additive Information: This is the industry’s first 300C capable drilling system, comprising metal-to-metal motors, drill bits, and drilling fluid, and accompanying MWD system. These new technologies provide opportunities for drilling oil and gas wells in previously undrillable ultra-high temperature environments.
Tuesday, March 6 (Well Control/Kick Detection)
IADC/SPE 189655
Dynamic Kill Method Using Staged Fluid Densities Can Improve the Killability of Relief Wells for Challenging Blowouts
IADC/SPE 189610
Predicting Hydrocarbon Burn Efficiency of Ignited Blowout for Oil Spill Source Control
M.D. Dunn, Hilcorp Alaska LLC; S. Fitzgerald, Intuitive Machines, LLC.; J.B. Garner, Boots & Coots L.P.
Objectives/Scope: The yet to be developed Liberty field was discovered in the 1980s, and then confirmed with the Liberty No. 1 well in 1997 by BP. The reservoir lies within OCS leases in 20’ of water, in Foggy Island Bay, about 20 miles southeast of Prudhoe Bay. The reservoir is estimated to produce between 80 and 140 MMBO of high quality crude. Hilcorp Alaska, LLC purchased 50% ownership and assumed operatorship in 2014, and submitted the DPP to BOEM in 2015. Since then, BOEM as the lead agency, has been conducting a NEPA review which is expected to deliver the Final EIS in mid-2018.
Concurrent with the NEPA review, Hilcorp submitted the Oil Spill Response Plan (OSRP) to BSEE in March 2017. A unique feature of this development in OCS waters is that wells will be drilled from an artificial gravel island using a land-based rig. One of the key elements of the OSRP is the utilization of well ignition as an early step in a well capping operation, and to minimize the volume of oil that hits the ocean or ice. As prescribed in regulations, the operator must demonstrate it has a plan and resources to remediate a spill of the worst case discharge (WCD) rate. Because the Kekiktuk formation at Liberty has very high (>1 darcy) permeability, the WCD rate of a blowout from the reservoir and up 9-5/8” casing is approximately 90,000 bopd and 90 MMscfpd.
Methods, Procedures, Process: To prove the WCD rate would remain ignited, and to calculate how much liquid would not combust, Hilcorp hired two companies to research the robustness of combustion models, and develop model(s) that would determine if the blowout would remain ignited, and calculate the liquid carryover that would have to be recovered with spill response equipment. The companies created several models that resolved these issues, which calculate:
- Burn efficiency, defined as the ratio of oil combusted to total oil exiting wellbore
- Blowout flame radiant heat flux
- Mass flux and heat content of unburned residual
- Spatial distribution of unburned residual
Results, Observations, Conclusions: The work was based on four broad areas: research of governing physics, evaluation of academic and laboratory scale measurements, evaluation of blowout database, and numerical modeling utilizing both computational fluid dynamics and first principles engineering modeling. The numerical model validated the presence of complex supersonic shock structures and calibration data for the development of the engineering burn efficiency methodology. Research results were integrated with extensive field-based blowout experience and validated numerical modeling results. Parametric analysis of key driving variables provide measures of burn efficiency margin and robustness required for approval of the spill response plan.
Novel/Additive Information: This paper presents the methodology and engineering-based solution that integrates oil blowout fire experience with aerospace engineering expertise to accurately predict burn efficiency of very high rate blowouts. This methodology allows the operator to justify the use of well ignition as a step in well capping and as a means of source control, on a development from an artificial gravel island in the Beaufort Sea, of Arctic OCS waters.
IADC/SPE 189665
Digitized Uncertainty Handling of Pore Pressure and Mud-weight Window Ahead of Bit; Example North Sea
A.E. Lothe, P.R. Cerasi, K. Bjorkevoll, SINTEF Petroleum Research; S. Haavardstein, ConocoPhillips
Objectives/Scope: A digitized workflow from pre-drill pore pressure modeling with Monte-Carlo uncertainty approach, till update of pressure prognosis while drilling from e.g. sonic and/or resistivity data is described. The new approach will reduce the uncertainty in the mud-weight window ahead of bit, and the paper presents testing of the new workflow on a North Sea dataset.
Methods, Procedures, Process: For the 3D pressure modeling, a basin modeling software approach is used, where the pressure compartments in the study area are defined by faults, interpreted from seismic. Key input parameters like minimum horizontal stress, permeability across faults and shales acting as cap-rock are varied. The output is the pressure profile along the planned well path, with uncertainties. While drilling, log-data will be used to update the pressure prognosis ahead of bit. The updated pressure prognosis will further be used to update the mud-weight window. The digitized pressure and mud-weight update, will reduce uncertainty ahead of bit.
Results, Observations, Conclusions: The work was carried out on a North Sea dataset with replay of historical data from a drilling operation. The results show that we can narrow the uncertainty for both pressure and mud-weight window prediction ahead of bit, with real-time digital update. The new workflow, using a 3D pre-drill pressure simulations Monte-Carlo approach, shows that the estimate for minimum horizontal stress, fault permeability properties and cap-rock properties are important input parameters to the model setup. Update of the model while drilling, by pressure data (e.g. sonic and/or resistivity log data), influence and narrow the uncertainty in pore pressure prognosis and thereby in the mud-weight window predictions along the well path. The uncertainty in the mud-weight prediction is highly dependent on the uncertainty in the pore pressure, but also on update of rock strength, and the minimum horizontal stresses. The conclusion is that such digital updated prognosis can help the drilling crew in the decision-making in a drilling campaign.
Novel/Additive Information: The novelty of the digital workflow is that both the uncertainty in pore pressure, as well as in mud-weight window will be addressed and handled. This is a step towards a new automated handling of pressure and mud weight in drilling operations.
IADC/SPE 189606
Gas Kicks in Non-Aqueous Drilling Fluids: A Well Control Challenge
Ma, A. Karimi Vajargah, D. Chen, E. van Oort, The University of Texas At Austin; R. May, J. MacPherson, G. Becker, GE-Baker Hughes; D. Curry, Retired
Objectives/Scope: Non-aqueous drilling fluids (such as synthetic-based mud) are frequently used to drill one or more sections of an oil/gas well to reduce drilling problems such as shale sloughing, wellbore stability and stuck pipe. However, solubility of formation gas in the non-aqueous drilling fluids makes the well control process and early gas detection very challenging. This is particularly of great concern in deep offshore wells in which large amount of gas can be dissolved in this type of drilling fluids under high pressure and temperature and remains in solution during most of the process. Sudden release of gas at shallow depth can compromise wellbore/riser integrity, noticing that in deep offshore wells in many cases the blow out preventer is installed at the seafloor. Therefore, an advanced planning tool to simulate the transient multi-phase phenomenon, which occurs during gas kick incident in non-aqueous drilling fluid, is of high demand.
Methods, Procedures, Process: This paper presents a novel and comprehensive hydraulic software package and its underlying models to simulate a gas kick in non-aqueous fluids. A transient drift-flux approach based on conservation of mass and momentum was applied in association with appropriate closure relationships and sophisticated friction and choke models. Advanced numerical schemes applied previously have been modified to handle the mass transfer between the liquid (mud) and gas phase. In addition, PVT sub-models are included to investigate and predict the effect of gas solubility in various types of drilling fluids. A user-friendly graphical user interface eases building the simulation cases.
Results, Observations, Conclusions: The presented model is validated with experimental data in which a gas kick was induced in a test well. An excellent agreement was observed between the experimental and simulation results from the test well, justifying the application of this tool to real-world drilling scenarios. Then, through a simulation scenario, this tool is used to simulate a gas kick in a (3D) deviated offshore well. Several crucial parameters during well construction such as equivalent circulating density, pit gain, gas break out location and void fraction, annular pressure profile, kick tolerance, choke opening, flow out, gas rising velocity, and pump pressure are predicted. Effect of oil/water ratio in the drilling fluid and also type of base oil on the simulation results is also investigated. This tool can handle several other complexities which occur during a well control incident as handling multiple influxes from one or several formations, dynamic well control (suitable to managed pressure drilling), automated choke control, sudden pump start-up/shut-down, non-Newtonian drilling fluids, arbitrary wellbore path, lost circulation etc.
Novel/Additive Information: Applying advanced numerical schemes associated with relevant PVT models and several types of boundary condition makes this tool comprehensive, unique, robust, and efficient for well control analysis of variety of complex drilling scenarios, particularly deepwater wells. As such, it has the potential to enhance well control operations and well design, thereby enhancing rig safety and reducing non-productive time and cost associated with well control-related events.
IADC/SPE 189701
A Cyber-Physical Approach to Early Kick Detection
Andia, R.R. Israel, BP
Objectives/Scope: This paper describes a novel approach to early kick detection via the use of a cyber-physical model, which combines first principle physics based modeling with Bayesian mathematics for detecting subtle changes in noisy and uncertain measurements. An application was built to test this approach in real-time during well construction operations. Although a kick was not experienced during the real-time trials, the results from historical datasets demonstrate that this approach can alert earlier than conventional methods.
Methods, Procedures, Process: A cyber-physical approach is utilized to improve the speed and consistency at which a kick can be identified during drilling operations, thus automating this process. This methodology combines first principle physics based modeling with Bayesian mathematics for detecting subtle changes in noisy and uncertain measurements. For early kick detection purposes, the physics model is that of a lumped parameter model that describes the fluid flow in a well and the noisy and uncertain measurements are the data streams from rig sensors available during well construction operations, which are used to fit/correct results of the model to well measurements via an extended Kalman filter approach.
Results, Observations, Conclusions: A tool was built that is able to consume real-time and archived data, solve the lumped parameter model and Kalman filter implementation, and output the computed results for real-time viewing purposes. Historical datasets were used to demonstrate that the tool is able to detect kicks earlier than with conventional methods and provides an acceptably low false alarm rate. A real-time test was conducted within a real-time monitoring center to evaluate the performance of the tool as an effective early kick detection technology via a set of key performance indicators and test the developed operational protocols and training materials with personnel of a real-time monitoring center. The metrics put in place evaluated the tool in three categories: software robustness, data quality and early kick detection technical performance. A test plan was developed with test procedures and a workflow for utilizing the information given by the tool in the context of a real-time monitoring center. No kicks occurred during the construction of the well. However, certain operational events that resemble a kick demonstrated that the tool is able to identify them and trigger an alarm. The overall results of the real-time test were favorable and potential enhancements to the tool were identified.
Novel/Additive Information: The application of Bayesian mathematics and machine learning to well construction operations will continue to increase as value is found in its estimating capabilities. This project illustrates one approach to early kick detection that is unique to date in terms of combining a deterministic well hydraulics model with real-time measurements via an extended Kalman filter approach. In this way, it is an improvement over data driven approaches applied to well construction operations where the physics of the operations is not taken into account.
IADC/SPE 189661
A Novel Practical Approach to Borehole Breathing Investigation in Naturally Fractured Formations
Baldino, S.Z. Miska, M.E. Ozbayoglu, University of Tulsa
Objectives/Scope: Occurrence of reversible mud losses and gains while drilling in naturally fracture formations is of primary concern. Borehole breathing can greatly complicate the already difficult practice of fingerprinting the changes in the return flow profile, hence undermining the reliability of kick detection. Issues can also derive from misdiagnosing a kick and attempting to kill a ballooning well. The objective of this work is to correctly address the phenomenon and increase insights of its physical characterization.
Methods, Procedures, Process: The fluid progressively flows in and out of the fractures as a consequence of three mechanisms: (1) bulk volume deformation, (2) fluid compressibility, and (3) fracture aperture variation. To represent this complex scenario, a model involving a continuously distributed fracture network is developed. A time dependent, 1-dimensional dual-poroelastic approach is coupled with a variable fracture aperture and a passive porous phase. Finite fracture length is considered and no limitation on the number of fractures is posed. The latter permits us to analyze long open-hole sections intersecting several fissures, which is a more realistic approach than the available single fracture models.
Results, Observations, Conclusions: The proposed model is able to quantify the pressure distribution in the fractures and the pores, together with the flow rate entering or exiting the fractures. When the fissured space is reduced to zero, the developed system reduces to the one obtained for single porosity. Moreover, when incompressible bulk volume is considered, the solution reduces to that of classical reservoir engineering. A sensitivity analysis is performed on the physical properties of the formation and the drilling fluid. The latter provides a deeper insight on the factors that significantly influence breathing phenomena (i.e. drilling fluid weight, rheology and formation mechanical parameters). Furthermore, the typical pump-off profile associated with breathing events was reproduced by estimating the frictional pressure losses caused by the fluid entering the wellbore. Model results have been compared against a field case of a deep-water well, proving to be quite successful in predicting real Pressure While Drilling (PWD) response. In addition, the shut in drill pipe pressure, recorded from a real kick, has been compared to the one caused from a simulated breathing case. Although the two SIDPPs show great similarities, the correct modeling of breathing can significantly help the identification of the major differences between kick and breathing.
Novel/Additive Information: The proposed model, which solves a forward problem, can also be adapted to a so-called inverse problem. Consequently, formation in-situ parameters can be estimated using recorded values of PWD or measured lost and gained drilling fluid volumes. Appraisals on fracture volume and/or fracture permeability can be, then, obtained from this geomechanical well testing protocol. Moreover, the in-depth characterization of borehole breathing can be used to effectively design unconventional drilling techniques such as Managed Pressure Drilling.
Tuesday, March 6 (Cementing and Zonal Isolation)
IADC/SPE 189682
Application of an Innovative Spacer System Designed for Optimal Performance in HTHP Wells
Doan, Baker Hughes Inc; A.C. Holley, Baker Hughes; M.G. Kellum, Baker Hughes Inc; S. Dighe, Baker Hughes, Inc.; C. Arceneaux, K. Conrad, Chevron Corporation
Objectives/Scope: Extreme well conditions, especially higher temperatures, are becoming more commonplace. This in turn requires improvements to our wellbore fluids. This study focuses on the development of a new spacer system designed especially for those exhibiting extremely high temperatures.
Methods, Procedures, Process: A critical characteristic of this spacer is that the surface rheology must not be overly excessive as to maintain a pumpable fluid; however, the downhole rheology must not diminish due to thermal thinning or degradation of the gelling agent so the spacer remains stable. To ensure the spacer suitably meets these requirements, both ambient and elevated temperature rheologies are analyzed and reported. The stability of the spacer related to settling of solid particulates is examined by conducting dynamic settling tests at 300 °F and above.
Results, Observations, Conclusions: In this study, spacer compositions and densities were adjusted to examine effects on rheology and stability of the solids within the system at elevated temperatures. Results show that conventional spacer systems are not adequate at elevated temperatures especially above 300 °F. The newly developed spacer system shows much improved results from dynamic settling tests even up to 400 °F. Also, the surface rheology of the new spacer system is not significantly different from that of the conventional system. Studies were also conducted on just the viscosifying agents of a conventional spacer and that used in the new system to try to determine a correlation between yield point, plastic viscosity, and spacer stability at elevated temperatures.
Novel/Additive Information: This innovative spacer system is proven within this paper to add significant value to extreme cementing operations. In addition, by comparing the results between these two testing methods, the dynamic settling test should be considered as an alternate procedure for testing the stability of spacers under high temperature conditions.
IADC/SPE 189587
Flexible, Self-Healing Cement Eliminated Sustained Casing Pressure in Denver Julesburg Basin Unconventional Wells
M.M. Langley, M.A. Cleveland, J.T. Eulberg, M. Hudson, Schlumberger
Objectives/Scope: The oil and gas industry has operated in Denver Julesburg (DJ) basin for many decades. Currently in the basin, increasing population density and wellbore complexity have resulted in a heightened visibility of long term well integrity. Failure can lead to future liabilities, loss of public trust, and a revoked right to operate. Operators must demonstrate commitment to well integrity to continue operating in the basin, yet many still report sustained casing pressure (SCP) on a significant portion of wells. Because SCP corresponds to the open communication of fluids to surface, it is a direct metric of well integrity failure. Regulations require operators to report and remediate instances of SCP on all wells. On average, clients experience one well with SCP for every six drilled.
Methods, Procedures, Process: As a primary well barrier element, the cement sheath is vital to well integrity improvement. Enhanced placement techniques of conventional cements failed to prevent SCP, confirming that failure is derived from post-placement dynamic conditions. The solution must account for pressure and temperature stresses, preventing and mitigating mechanical failures throughout the well life cycle. A flexible and self-healing cement design provides a twofold response that is ideal for wells in areas, such as the DJ basin, with SCP risk.
Results, Observations, Conclusions: Flexible and self-healing cement has been successfully designed and implemented on approximately 150 wells in the DJ basin with no reported SCP to date. Elimination of SCP provides confidence in long term well integrity, which is essential to continued operation in the basin.
Novel/Additive Information: Flexible and self-healing cement gains its optimized mechanical properties and self-healing mechanisms through the inclusion of an elastic and a thermoplastic particle to the cement matrix. Mechanical properties are optimized based on the results of a mathematical stress model. Although Portland-based cement systems can be optimized to sustain higher levels of dynamic stresses, it is impossible to avoid a mechanical failure entirely. Therefore, a self-healing function is a critical secondary feature. The self-healing mechanism is designed to activate upon contact with an invading hydrocarbon, and can be formulated for any type of hydrocarbon, from high gravity oil to dry gas.
IADC/SPE 189685
The Application of Wellbore Strengthening to Achieve Zonal Isolation
Majidi, A.T. Dondale, N.C. Braley, R. Flores, BP America Inc
Objectives/Scope: Lost circulation while running casing, pre-cement job mud circulation, and/or cement placement can increase well cost, create challenges in achieving zonal isolation objectives and in some cases impact well integrity. Well design requirements may increase the risk of fracture initiation and propagation during tripping, circulating, and cementing operations as a result of surge pressures, and the placement of more viscous and denser fluids in narrow flow geometries.
Methods, Procedures, Process: To address this lost circulation challenge, the focus of this article is on prevention. Wellbore strengthening is utilized to strengthen weak and permeable zones to a target maximum equivalent circulating density (ECD) values induced during tripping, circulating, and cementing. Engineered lost circulation material (LCM) pills of specified particle concentration and size distribution are placed in the open hole and pressurized in a controlled fashion. As a result, a higher fracture gradient (FG) of the weak sands exposed in open hole is achieved, allowing those formations to withstand higher ECDs without inducing losses during subsequent tripping, circulating, and cementing operations.
Results, Observations, Conclusions: This paper summarizes the field application of wellbore strengthening in deep-water Gulf of Mexico. The design, execution, and post-well analysis of dozens of wellbore strengthening applications in various formations, from shallow and soft overburden sands, to deep producing reservoir sands with depletions greater than 4,000 psi, are discussed.
Novel/Additive Information: The track record of successful wellbore strengthening treatments performed demonstrates the potential for achieving good quality cement jobs and adequate zonal isolation in narrow pore pressure fracture gradient environments.
IADC/SPE 189635
Minimizing the Risk of Casing Failures Across Plastic Salts with Tailored Cements and Software Analysis: Case Histories from the Williston Basin, North Dakota
J.F. Pereira, S. Jandhyala, Halliburton
Objectives/Scope: A significant challenge associated with cementing across salt zones in the Williston basin is mitigating risks of casing collapse or deformation. An operator (Operator A) in this area reported that five of their old wells experienced casing failures/deformation caused by salt creep. Post-job analysis showed that these older wells employed conventional cement designs. Based on the lessons learned from successful cement jobs for other operators in the same region and knowledge about salt creep loads, tailored fluid systems were proposed with optimized job design and placement procedures for Operator A’s upcoming wells. The current work demonstrates the benefits of the proposed modifications by comparing the logs and outcomes of old and new wells. Through post-job analysis, this study highlights the importance of using cementing simulation and modelling software to design a dependable barrier.
Methods, Procedures, Process: The casing inspection logs and cement bond logs across salts from old wells indicated that deformation occurred within a few weeks of cementing. Use of a tailored cement system with enhanced mechanical properties along with specialized spacer systems and effective centralization showed improvement in bond logs, no casing deformation, and better casing-cement bonding in the new wells for Operator A. Prejob simulations were performed using in-house cementing software to verify the cement job and ensure cement was effectively placed in the annulus.
Results, Observations, Conclusions: Cement sheath integrity modeling software was used to perform post-job analysis, which simulated the actual exerted loads from plastic salt formations and subsequent drilling, completion, and production operations. This software uses a semi-empirical creep law that describes the creep process of a wide variety of salts. The cement system with enhanced mechanical properties showed sufficient endurance to provide a dependable barrier to the salt creep loads experienced in Williston basin wells. Although the use of salt versus salt-free slurries is debated for salt zone cementing, this paper shows that salt-free cements with enhanced mechanical properties can be used successfully when there is no risk of cement gelation during placement. North Dakota salts principally contain halite (NaCl), which does not pose a risk of gelation.
Novel/Additive Information: The case histories and field studies discussed establish cement systems and practices that can help minimize the risk of casing deformation and improve the cement bond across salt zones in the Williston basin in North Dakota. This tailoring tool, with its unique ability to exert salt creep loads, helps minimize the risk of cement sheath failure through tailored barrier designs. This information should help the petroleum industry address long-term well integrity problems associated with cementing across plastic salts.
IADC/SPE 189580
Perf & Wash Cement Placement Technique as a Cost-effective Solution for Permanent Abandonment of a Well with Multiple Permeable Zones: A Case Study from North Sea, UK
Joneja, S. Nafikova, J. Reid, A. Rublevskyi, J. Salazar, Schlumberger
Objectives/Scope: With low oil prices continuing to challenge the economics of mature offshore assets, many North Sea oil and gas fields have reached the end of their production lives and need to be permanently abandoned. Cost-cutting and time saving initiatives for abandonments have never been more important for operators, and innovative technique are being implemented to achieve more efficient results. A major North Sea operator had an objective to abandon a well that had poor cement bonding behind the casing across the intended isolation interval. The challenge was to provide lateral isolation in the most efficient way possible.
Methods, Procedures, Process: Traditionally, the casing across the abandonment zone lacked proper cement coverage behind it, operators would be required to either perform multiple cement squeezes or undertake lengthy milling operations in order to place cement in the intended interval. Squeezes are risky in that bonded cement placement is not guaranteed behind the casing, and milling can add weeks to abandonment operations. Instead, a “perf and wash” tool was utilized to effectively place cement inside and outside the casing across the required interval. This tool was used to perforate the un-cemented casing, wash the annular space, and then mechanically place the cement across the wellbore in a single run. Advanced cement software simulations were used to optimize fluid interfaces, and new lab testing procedures were devised to ensure job success. Due to the unconventional flow paths and geometry, rigorous fluid compatibility and contamination testing was done to determine that drilling fluid, cement, and spacer designs were appropriate for job success.
Results, Observations, Conclusions: Two “perf and wash” operations were executed successfully during this well abandonment. Firm cement was tagged & pressure tested confirming success of the fist operation. To reassure sufficient isolation provided across shallow perforated interval, cement inside casing was drilled out and cement evaluation log was run. The results of the log indicated good circumferential coverage obtained across more than 76% of the perforated interval, which was in line with regulatory abandonment guidelines and the operator’s objectives. Once the bond log results were confirmed, cement plug was set across the shallow interval by conventional methods and verified by tagging and pressure testing. By using this method of placing cement behind the casing, the operator saved up to 20 days of rig time corresponding to $14,860,000.
Novel/Additive Information: This paper outlines a case history demonstrating the successful application of advanced perf and wash and cementing technology in a challenging abandonment. The design strategy, execution, evaluation, and results are discussed in detail and will be relevant to future operations.
IADC/SPE 189646
Mud-Cement Displacement in Eccentric Annuli: Analytical Solution, Instability Analysis, and Computational Fluid Dynamics Simulations
H.K. Foroushan, M.E. Ozbayoglu, University of Tulsa; P. Gomes, BP Exploration Operating Co; S.Z. Miska, M. Yu, University of Tulsa
Objectives/Scope: A successful cement placement essentially guarantees zonal isolation and environmental safety. Effective design of cement placement and mud removal impact all the stages of the wellbore life from drilling ahead to production. Accurate predictions of fluid displacement in the wellbore are vital to design fluid properties and plan the cementing job. In this work, an analytical model is developed to simulate the displacement of fluids in eccentric annuli.
Methods, Procedures, Process: This paper presents a novel method for the solution of cement/mud displacement and evaluation of inter-fluid contamination during displacement, for eccentric annuli. This new approach starts by addressing the problem of single fluid flow in eccentric annuli by solving analytically the governing transport equations for a flow inside an unwrapped annulus. The solution is, then, extended to a system of two fluids in a vertical annulus by adjusting the boundary conditions for displacement. The model is completed by adding the time-dependent calculation of interface between the two fluids, enabling the accurate determination of the amount of mixing and displacement efficiency.
Results, Observations, Conclusions: The analytical method proposed is used to simulate single and multi-fluid flows and study the effect of fluid properties of cement, spacer, and drilling mud at different flow rates on displacement efficiency, for both concentric and eccentric, vertical annuli. 3-dimensional Computational Fluid Dynamics (CFD) simulations were also performed and the results were compared to the analytical solution. Moreover, instability of the interface in all the cases was studied and the analysis offers an understanding of the role of fluid properties and proposes applicable optimized design to enhance the displacements. The amount of mixing and contamination that occurs during the displacement was calculated for both methods. The analytical solution and CFD produce results within a 13% difference, which validates the analytical model. Evidence was gathered to support that the improper design of fluid properties and flow rate along with a highly eccentric annulus can lead to substantial cement contamination. This may lead to overdesigning the amount of fluids to be pumped to provide a complete mud removal and an efficient cement placement. On the other hand, learnings and models developed allow optimizing fluid properties that may lead to best outcomes even for highly eccentric annulus.
Novel/Additive Information: The undeniable importance of a complete cement placement is addressed by means of an analytical solution of the displacement, which provides a realistic prediction of the amount of inter-fluid mixing and cement contamination. This approach coupled with the interface instability analysis, which offers improvement techniques for the displacement, provide beneficial enhancements for practical industrial applications.
Tuesday, March 6 (Directional Drilling and Hole Placement II)
IADC/SPE 189613
Twist Compensation Reduces Trajectory Tortuosity and Improves ROP
Kyllingstad, NOV
Objectives/Scope: Conventional directional drilling with a mud motor and a bent sub is obtained by toggling between rotation and sliding modes. Major drawbacks of this method, when compared with more expensive rotary steerable systems, are excessive well bore tortuosity and poor overall ROP. This paper shows that these disadvantages can be substantially reduced through a smart control technique called twist compensation.
Methods, Procedures, Process: When the bit torque changes during the sliding mode, the string responds by a proportional but slow change in the reactive twist. The equilibrium twist can be estimated from the change in standpipe pressure and used in a feed-forward loop called twist compensation. It adjusts the angular top drive position and minimizes torque induced changes of the tool face. By allowing bit load optimization while controlling the tool face, it is possible to achieve high penetration rates also during sliding mode. Moreover, the effective curvature can also be controlled by varying the tool face in various smart ways.
Results, Observations, Conclusions: The new methods have been tested with an advanced computer model able to simulate axial and torsional drill string motions for a wide range of applications. The model includes string elasticity and a vector based well bore friction that couples axial and torsional string motion. The simulations strongly indicate that both twist compensation and various new smart ways to control the top drive will work in the field, even in deep deviated wells with a typical bit torque produces a total string twist of many turns. The simulations show that twist compensation works best when the downhole directional data has a high rate, but the method is applicable also when combined with a low rate telemetry system.
Novel/Additive Information: The study strongly justifies that both trajectory smoothness and penetration rates can be substantially improved when using conventional directional drilling assemblies. A key in this improvement is twist compensation, a new and smart technique for angular position control of the top drive.
IADC/SPE 189702
Probabilistic Real-Time Trajectory Control Considering Uncertainties of Drilling Parameters and Rock Properties
Liu, R. Samuel, Halliburton
Objectives/Scope: This work provides a probabilistic approach to proactively adjust drilling parameters (which may be uncertain) in real time to ensure that the actual drilling path overlaps the ideal drilling path to the maximum extent.
Methods, Procedures, Process: The ideal well path is initially defined by a probabilistic earth model of the formation for maximum production potential, then adjusted to improve well path smoothness for passage of tubular strings. Drilling parameters and earth model data can be updated in real time during drilling operations. Considering the uncertainties of petrophysical properties and drilling parameters, the overlap probability between actual and ideal (or target) well paths can be quantified, and drilling parameters can be optimized for maximum overlapping and drilling efficiency. At a specific depth, the actual well path location can be expressed as two normal distributions of at-bit inclination and azimuth: N(μinc, σinc) and N(μAz, σAz). Similarly, well path deviation can be expressed as N(μΔL, σΔL), where ΔL is the length of deviation vector. Finally, the probability of overlapping the target well path is computed for current and to-be-drilled locations. An iterative method is used to predict and correct, if necessary, the actual well trajectory.
Results, Observations, Conclusions: The case study includes a horizontal well in a typical shale oil and gas field. Based on the log data, the formation properties (Young’s modulus, porosity, and total organic carbon) were calculated using the real-time earth model. At the current drill-bit location, those properties were described statistically as normal distributions, rather than single values, as were the drilling parameters, including weight on bit (WOB), revolutions per minute (RPM), and flow rate.
Statistical methods, such as Monte Carlo, were applied to quantify the uncertainty of the predicted actual well path. All position-related data were described as distributions. The mean value and standard deviation were computed in real-time. A single probability of overlap between actual and target well paths was also computed, which is used as the feedback for drilling parameter adjustment. This closed-loop feedback process enables proactive control of the actual well path.
The drilling path simulation indicates that the trajectory resulting from using this new control method exhibits better reservoir access and maintains dogleg severity at an acceptable level.
Novel/Additive Information: The probabilistic approach is adopted to proactively control the wellbore trajectory for maximum access to reservoir sweet spots, provide better wellbore quality, and ensure better drilling efficiency.
IADC/SPE 189612
Anti-Collision Best Practices Developed for Horizontal Drilling Across Pre-existing Horizontal Wellbores.
E.E. Britton, R. Grande, Liberty Resources
Objectives/Scope: This paper focuses on anti-collision best practices developed and implemented by Liberty Resources for horizontal drilling across pre-existing horizontal wellbores within the same horizon in the Williston Basin. These multidisciplinary collaborative workflows have allowed Liberty Resources to successfully drill multiple complex horizontal wellbores traversing as close as 10 feet wellbore-to-wellbore to exiting laterals. As the horizontal infill development of unconventional reservoirs progresses, complex wellbore trajectories with heightened collision concerns will be required. To achieve this requires advancing the industry’s anti-collision standard practices with new and more precise anti-collision methods, detailed planning, and near prefect execution. In the Williston Basin alone there are over 13,000 vertical wells, 15,000 horizontal wells, and over 1,000 re-entry and directional wells drilled to date, with the first horizontal wells introduced to the basin over 30 years ago. Historically the horizontal wells were drilled using a vast array of well designs and orientations due to the limitations of technology, industry practices and standards, and the insufficient understanding of the reservoir. Advancements in drilling and completions technologies and a better understanding of the reservoir now allow leases to be reassessed for infill potential. This increased infill development has led to increasingly complex wellbore trajectories with collision concerns not only for existing vertical wellbores but now also for existing horizontal wellbores within the same or proximal horizons.
Methods, Procedures, Process: The anti-collision best practices include directional and geologic planning considerations, operational tolerances and requirements including zonal determination, communication protocols, and risk management practices. Creating a broad framework that allows for flexibility to adjust for distinct operational constraints.
Results, Observations, Conclusions: These workflows and tolerances have been implemented in three horizontal wellbores traversing seven same-formation horizontal wellbores. The anti-collision methods were successfully applied in both the Middle Bakken and Three Forks formations, each with their own varied and unique geologic characteristics, demonstrating applicability for a wide range of reservoirs. The ability to execute complex wellbores opens new opportunities to access additional resources in previously considered “fully developed” acreage.
Novel/Additive Information: The best practices presented in this paper have allowed the routine drilling of horizontal laterals as close as 10 feet to existing laterals. This technology can be applied to a variety of reservoirs opening new opportunities to access additional resources previously considered unrecoverable due to existing wellbores.
IADC/SPE 189697
Real-Time Downhole Data Resolves Lithology Related Drilling Behavior
Viens, T. Clark, Nabors Drilling Solutions; J.D. Lightfoot, C. Mercado, Occidental Oil and Gas Corporation
Objectives/Scope: Geology can have a significant impact on the BHA’s tendency to change direction. Concrete examples of the phenomenon however are elusive and therefore are not well understood. Understanding and identifying in real time the geological factors that influence the BHA to change or hold direction adds tremendous value in terms reducing sliding time and targeting zones for optimal ROP.
Methods, Procedures, Process: Employing downhole measurements of azimuthal gamma imaging, continuous inclination, and bending moment, a direct measure of the rock related directional phenomenon have been captured and quantified. Utilizing drilling and geological data from horizontal wells in the Permian Basin, examples of lithology related directional tendencies from the Spraberry and Wolfcamp have been captured.
Results, Observations, Conclusions: Theories about downhole directional tendencies are commonly speculated, but with little merit due to the lack of hard data to reveal the mechanisms behind the phenomenon. Understanding and identifying in real time the geological factors that influence the BHA to change or hold direction adds tremendous value in terms reducing sliding time and targeting zones for optimal ROP. The data demonstrates that angle of approach to bedding planes and formation hardness contrast are the leading factors Techniques presented enable drillers to understand and benefit from lithology related directional behaviors resulting in improved ROP, reduced tortuosity, and more precise wellbore placement. While it is well known that changes to surface drilling parameters of WOB and RPM can impact direction, the broad application of this technique is limited to rocks that are homogeneous in composition and with thick bedding planes. Additionally, these techniques have traditionally relied on personnel with significant local knowledge of these relationships. The availability of downhole data enables this process to become more systematic.
Novel/Additive Information: This is the first time that the phenomenon listed above has been captured by all of the measurements listed above in an LWD system on US land.
IADC/SPE 189668
How To Manage Geomagnetic Field Disturbances In The Northern Auroral Zone To Improve Accuracy Of Magnetic Mwd Directional Surveys
Edvardsen, Baker Hughes, a GE company; E. Nyrnes, Statoil ASA; M. Gullikstad Johnsen, UiT, the Arctic University of Norway; T. Lynne Hansen, NA; I. Aarnes, Baker Hughes, a GE company
Objectives/Scope: The auroal zone is a region surrounding the geomagnetic north and south pole and where the largest disturbances of Earth’s magnetic field are experienced on the northern hemisphere. In this area the accuracy of magnetic MWD directional surveys is largely affected by large and frequent changes in the direction and intensity of Earth’s magnetic field. Surveying wells in the auroral zone is therefore challenging. The objective of this research study is to estimate the statistical properties of geomagnetic disturbances in the auroal zone and develop models for how magnetic field disturbances vary as function of distance and direction. Further, methods and procedures to reduce azimuth uncertainty using data from distant monitoring stations will be presented.
Methods, Procedures, Process: Real geomagnetic data from several land-based magnetic observatories and variometer stations within the auroral zone have been analyzed. The datasets contain measurements of declination, total field intensity and dip angle for periods with both high and low geomagnetic activity. Station-pairs with distances from 150km to 800km are considered. The objective has been to determine both the distance and direction dependent statistical dependency (correlation) of disturbances. By using data from magnetometer stations located in the auroral zone, there has been possible to develop models and correction procedures valid solely for this area.
Results, Observations, Conclusions: The results of the analysis of data from magnetometer stations in Alaska, Canada and Greenland has been applied to improve the understanding of the statistical properties of geomagnetic disturbances in the auroral zone. This is useful when drilling wells at distant offshore locations with limited access nearby monitoring stations. An example is the Barents Sea. Results so far show that during geomagnetic quiet periods the correlation coefficients between data from monitoring stations at distances up to 800km can be as high as 0.9, which means that magnetic field disturbances can be interpolated with sufficient accuracy within this range. Declination is well correlated in the geomagnetic north/south direction, while total field and dip angle tend to be most correlated in the east/west direction. However, during periods that are more active the correlation can be weak for all three parameters even for distances less than 200km. Experience made by the authors show that uncritical use of data from monitoring stations to correct downhole magnetic MWD measurements in the auroral zone can lead to increased azimuth uncertainty. Methods and procedures to correct real time MWD data in a correct and safe manner at high latitudes will be presented.
Novel/Additive Information: The information presented in this paper is novel as the analyzed magnetometer data explicitly is from the auroral zone, hence the presented models and suggested magnetic MWD correction procedures are valid for this area. Models and correction procedures to be applied specifically for auroral zone has not been described by earlier publications.
IADC/SPE 189639
HPHT Wells Spudded Utilizing a Rotary Steerable System Below a 26″x 36” Hole Opener to Improve Tophole Drilling Performance
K.B. Hyland, Maersk Oil; M. Laing, Schlumberger; G. Mathieson, Maersk Oil; D. O’Neill, F. Boyce, A.J. Keen, A. Tarn, R. Milne, Schlumberger
Objectives/Scope: Presentation of the directional control results, learning’s and improvements observed while batch drilling the 36” hole section on the Culzean HPHT project. The changes made to the 36” BHA over seven wells is compared, focusing on the improvement in verticality after the addition of the 17-1/2” Rotary Steerable Assembly (RSS) to the BHA.
Methods, Procedures, Process: The Culzean project 36” batch drill consisted of 7 wells, drilled through the jacket with 3.5m centre to centre well spacing. The Allowable Deviation from Plan was 3.5 ft and a maximum inclination of 0.5 deg was allowed to maintain separation, this was also critical as all seven wells were planned to be vertical to 2,500 ft to mitigate shallow casing wear. The 36” section was planned to be drilled with a 17-1/2” bit and 26”x36” Staged Hole Opener. On the first three wells significant reaming was required to maintain the required verticality. The hole opener was changed on Wells 4-7 and the 17-1/2″ RSS used to maintain verticality and a significant decrease in drilling time due to less reaming. This paper will compare the data from these seven wells.
Results, Observations, Conclusions: The tophole formation drilled at the Culzean platform location turned out to be harder and more abrasive than the appraisal locations, this lead to heavy abrasive wear on the standard hole opener. This wear was suspected to have caused the deviation and extensive back-reaming required to maintain verticality. The 36”x26” hole opener was then changed for a heavy duty version with the RSS between the bit and the motor to assist with verticality, only minor wear was observed but the deviation observed was still present. The nozzling of the bit and hole opener prevented the RSS from generating the force required to steer effectively. On well four five and six, a restrictor was run in the RSS to allow for increased pad force to be generated and the inclination observed dropped significantly from a maximum 0.58 deg on wells 1-4 after significant reaming to a maximum of 0.36 deg on wells 5-7 with minimal reaming required. Due to the reduction in reaming the drilling time was reduced by 37%.
Novel/Additive Information: Only 2 other uses of a Rotary Steerable System below a hole opener in Tophole drilling could be found, with this being the first for a platform operation and also the first with real time communication to the RSS to monitor Inc and Azi. The performance improvements observed will allow for more efficient operations in the future.
Wednesday, March 7 (Performance Drilling)
IADC/SPE 189583
Drilling Analysis Using Big Data Has Been Misused and Abused
E.E. Maidla, proNova; W.R. Maidla, TDE Petr Data Solutions; J.M. Rigg, TDE Petroleum Data Solutions; M. Crumrine, P.W. Zoellner, proNova-TDE Petroleum Data Solutions
Objectives/Scope: We, the authors, see many people today incorrectly utilizing big data to produce cross plots of drilling parameters to come up with correlations that can identify operational “sweep spots.”
Methods, Procedures, Process: This paper will show examples and address the need to add several steps to big data before any meaningful correlation results are obtained, mainly understanding: 1) the sensors involved and their limitations; 2) the errors in the placement of these sensors (e.g. hook load sensor on the deadline); 3) the frequency of the data and how this impacts the analysis (some companies provide 10-second data); 4) the quality of the data itself; 5) the appropriate filtering of data to ensure apples-to-apples comparisons; 6) The rig state must be known.
Results, Observations, Conclusions: The Results show that only after following a well-defined process of rigorously analyzing the data frequency, QC, physical principals and mapping the operational practices, is any meaningful analysis possible and much of the big data collected to date might be of bad quality for analysis. One of the examples will show that plotting WOB vs Motor Delta P to try and find the drilling “sweep spot” is incorrect if sliding and rotating events are not filtered out – even after this filtering it is still incorrect if there is major buckling in the hole, e.g., curve vs. end of the lateral – even after filtering for this it is incorrect if surface pipe oscillation isn’t considered when sliding in the curve and lateral, and so on.
Novel/Additive Information: Big data is only a tool that should be coupled with all our drilling knowledge to be of any meaningful help to engineers, managers, field personnel and alike. The intent of this paper is not to enter discussions of downhole vs surface data but rather point out ways to use either source alone or in combination coupled to QC processes and physical principals to apply the appropriate classification and filtering before making drilling analysis.
IADC/SPE 189602
Real-time Bit Wear Monitoring And Prediction Using Surface Mechanics Data Analytics: A Step Toward Digitization Through Agile Development
Liu, J. Kibbey, Y. Bai, X. Wu, Shell International Exploration and Production
Objectives/Scope: Severe bit damage is a known issue in west Texas land drilling due to abrasive sand formation and inter-bedded hard stringers. Operational performance and rig cost are often impacted by penalty fee of bit DBR (damage beyond repairable), low ROP with worn bit, and inefficient decision-making on tripping. A real time data analytics application is developed aiming to provide actionable information to operation to facilitate decision-making process.
Methods, Procedures, Process: A historical dataset of surface mechanics data and bit records is collected from 40 bit runs (roughly 20 wells) drilled in 2016 and early 2017. A hybrid data analytics procedure consisting of conventional physical modeling of drilling mechanics and supervised learning using machine learning technique is conducted to separate bit failure pattern from normal formation transition. A metric based algorithm is constructed for real-time monitoring bit performance and making prediction on bit cutter wear conditions.
Results, Observations, Conclusions: A web-based real-time software is developed and field trialed on three wells with satisfactory results. Deployments in DART (remote center) and field office are going on for three rigs in west Texas. Positive feedback is generated from operation and engineers. Based on this methodology and software infrastructure, other drilling advisory features like motor life monitoring and smart-tripping evaluation are under development.
Novel/Additive Information: This application combines domain knowledge with machine learning techniques and provides actionable information to support optimal operational decisions. The agile development and deployment generates business values in a short term.
IADC/SPE 189608
Drilling Interbedded and Hard Formations with PDC Bits Considering Structural Integrity Limits
P.E. Pastusek, ExxonMobil Development Co.; D.M. Sanderson, XTO Energy; A. Minkevicius, Z. Blakeman, J.R. Bailey, ExxonMobil Development Co.
Objectives/Scope: Although PDC bits dominate the footage drilled in the oilfield, transitions at interbedded formations and high lateral vibrations are still problematic for PDC bits and reamers. This paper describes design features, operational parameters, and procedures found to substantially reduce cutter damage, often allowing the section to be drilled in one run, resulting in significant cost savings. It also covers data analysis needed to determine if interfacial severity is the key limiter in a given application.
Methods, Procedures, Process: Time and depth based drilling mechanics data are used to determine the sections of the hole that cause the observed cutter damage and optimize parameters. Forensics analysis is used to determine the type of cutter damage seen when drilling these formation intervals. Structural integrity of the cutters is estimated from forensics analysis, lab tests, as well as stress analysis of cutters loaded to replicate the observed damage. Review of the bit and BHA designs often show opportunities for design improvements and cutter selection. Drilling parameters are identified to keep the bit and cutters below the structural integrity limit.
Results, Observations, Conclusions: Drilling interbedded formations causes the cutters near the nose of the profile to fracture from tangential overload, through the diamond table and carbide support. This is a significantly different failure mode than the cutter spalling fracture on the bit shoulder seen with bit whirl.
Review of drilling mechanics data showed significant reamer damage and reductions in ROP at the formation transitions when entering salt with a bit and reamer combination. Drilling parameter and BHA design changes improved drilling performance in these transitions. Finite element studies were requested of bit vendors to estimate the structural integrity of cutters loaded in the tangential direction. Independently, forensic analysis was also used to estimate the range of loads and depth of cut that cause structural overload. Drilling interbedded formations and transitions at a controlled depth of cut, as opposed to WOB control, avoids exceeding the structural limit of the cutters while only part of the cutting structure is drilling the harder formation and the rest of the profile is in softer formation. Depth of cut elements are engaged to keep the bit stable while control drilling. Other design changes are considered to eliminate cutter overload using existing designs as a starting point.
Novel/Additive Information: The structural integrity concept applies to hard, interbedded, conglomerate and/or vuggy formations, as well as formation transitions and shoe drill out and milling operations. Effective drilling of such interfaces can be achieved by knowing the depth of cut that can be sustained in the harder formation, while avoiding damage from vibrations. Cutters must be selected for fracture resistance in the tangential direction, and many bit vendors do not yet track this property.
IADC/SPE 189585
Development of and Validating a Procedure for Drillstring Fatigue Analysis
Chen, Y. Shen, G. Yun, Y. Dong, R. Chen, Schlumberger
Objectives/Scope: Because wells drilled by the oil and gas industry are becoming more complex, the drill string is subjected to additional severe loading conditions, resulting in increased failure risk. It is universally known that fatigue is one of the primary causes of drill string failure, accounting for more than 70% of the failures. Drill string failure generally results in unexpected catastrophic twist-off of BHA components and costly fishing operations. For these reasons, it is important to develop a drill string fatigue life prediction model.
Methods, Procedures, Process: Fatigue is driven by cyclic stresses and accumulates over time. These cyclic stresses can occur in a wide range of conditions, such as rotating the drill string through a high dogleg severity well section, and severe bending due to whirling or buckling of the drill string. The procedure relies on the powerful and accurate 3D finite element model (FEM) based drilling dynamics computation engine, which predicts transient dynamics response and stresses along the drill string under drilling operations loading conditions. First, the section being drilled is subdivided into multiple small intervals. For each interval, simulation is used to predict the drill string deformation and contact force. Stresses can then be evaluated for each component in the drillstring.
Results, Observations, Conclusions: Due to the cumulative nature of fatigue failure, it is necessary to track the cycle of alternative stresses of the drill string while drilling an entire section. For stable rotary drilling, the number of stress cycles can be calculated from the number of rotation revolutions within the interval. In the real-time fatigue monitor application, the actual drill string revolutions measured at the surface can be used directly as the stress cycle. When severe downhole vibration exists, the rain flow counting method is used to count the stress cycles for the complex dynamics stress history. To consider mean stress effect, the Goodman law is used to compute the equivalent alternative stress. With the precollected fatigue SN curves (stress level versus the cycle to failure) for different connection types and drilling tools, the fatigue life consumption in one interval is calculated. Finally, in lieu of Miner’s rule, the fatigue life in all intervals are summed to obtain the cumulative fatigue damage to the drill string. The fatigue model, which has been implemented as one of the key components in the drilling analysis workflow, provides engineers with the analysis capability to identify the potential factors influencing the integrity of BHA components. This paper also presents case studies validating the drill string fatigue prediction model.
Novel/Additive Information: This paper presents a practical and effective procedure for calculating drill string and BHA component life due to fatigue accumulation. This modeling tool enables engineers to employ a systematic approach for quantifying the fatigue risk during the well planning and real-time execution phase.
Wednesday, March 7 (Data and Automation)
Automation Provides Unique Insights Of The Rock Record And Subsurface Through The Delivery Of A Robotic Sample Collection And Analysis Device.
Tonner, A.R. Swanson, R.G. Hollingshead, S.N. Hughes, Diversified Well Logging; S. Secrest, B. McDaniel, PetroLegacy Energy; J. Leeper, Solid Automation
Objectives/Scope: From the very early days of oil and gas exploration, appraisal and development drilling, samples have been collected at the rig by mud logging personnel in order to conduct a preliminary geological analysis of the rock being drilled. This collection typical involves a sample collection recipient, board or bucket in order to collect a sample of rock over the desired interval. The sample is then sieved and cleaned in the appropriate way depending on the type of drilling fluid being used. As penetration rates have increased in some instances to more than 400 ft. / hr. the sample resolution has deteriorated exponentially. From an ergonomics perspective, the highest frequency to which a person onsite can collect a sample is one every 20 minutes. At 300 ft. / hr. this translates to 100 ft. jumps in the rock record. A new device has been developed and deployed which automates this manual process and thus ensures faster and more accurate collection of geological samples of the drilled rock interval.
Methods, Procedures, Process: Sample resolutions of 5ft rock intervals have been attained at 400 ft./ hr. This technology has provided an important technological breakthrough and enables reduction of personnel at the rig site with a subsequent reduction in cost and HSE risk, particularly in areas of H2S. It further has provided for the potential integration with Measurement while drilling personnel. For both conventional and unconventional play development, this has provided oil and gas operators with an important and cost and risk reducing modus operandi compared to conventional drilling and evaluation techniques. The tool was deployed for an operator in Pecos county West Texas where both manually collected traditional mudlog samples and automatically collected samples were taken. The samples were analyzed and compared for rock content. In addition, comparisons were made between point sampling with the automated system versus samples collected over a defined interval manually. Results of these comparisons will be presented.
Results, Observations, Conclusions: A new method of automated drill cuttings sample collection has been successfully deployed. The new method provides a step change improvement in accuracy and resolution for sampling the rock record during drilling.
Novel/Additive Information: Additional data of the rock record provides potential insights to optimize wellbore placement and provide increased geo-mechanical data in order to optimize completions.
IADC/SPE 189591
Recorded Well Data Enriches the Testing of Automation Systems by Using a Deep Neural Network Approach
Yu, S. Chambon, Q. Liu, J. Belaskie, Schlumberger
Objectives/Scope: Drilling automation systems can benefit by using synthetic data. A drilling time-series simulator can enrich the dataset for testing, and enable the inference of the drilling states in real time; however, conventional simulators do not generate real-data features such as noise, gaps. The solution presented is a model that learns from real data, characterizes the different drilling responses, conditions the data with a deep neural network (DNN) approach, and generates a realistic drilling time series.
Methods, Procedures, Process: To simulate the drilling time series, a DNN was used to model the physical properties of the formation, rig, and sensors, and generates data with realistic curve patterns when it is trained with real datasets; e.g., block position, hook load, standpipe pressure, and surface torque. The neural network has multiple convolutional, recurrent, and fully connected layers. The model, is trained with real data, captures the spatio-temporal distributions among data channels, and then uses a windowed input to predict the next data points. These data points are then fed back into the network to repeatedly generate the simulated data sequence.
Results, Observations, Conclusions: Real drilling time series data was fed into the DNN including channels of block position, hook load, pressure, and surface torque. The network contained eight-layer 1D convolutional layers with three max-pooling layers, three recurrent layers of LSTM (long short-term memory), and four fully connected layers. The time window used in the input contained 512 samples for each channel, while the output was to predict the next sample for each channel.
After training the DNN with for hundreds epochs, it can successfully simulate time series data recursively (see figure 1 and 2 for the results). The simulated time series preserved the features of the original training data, while maintaining the data distribution of multiple channels. For example, it showed a consistent “in slips” pattern in the hook load channel when the block moved quickly from the bottom to the top of the interval of interest. In conclusion, the proposed DNN is a low-cost, robust model that simulates a drilling time series with complex spatio-temporal patterns. This model can generate a realistic time series with actual physical features. The simulator greatly helps the inference component of automation systems, enriching the datasets that are available for testing.
Novel/Additive Information: The proposed simulator algorithm is the first known simulator of drilling time series datasets. This simulator models the nontrivial physics laws and properties, including formation, rig, and sensors, and generates data with realistic curve patterns using a DNN approach.
IADC/SPE 189708
Integrated Analytical Trajectory Control Model
Gomez, Robert Gordon University; C. Nunez, Total E&P; R. Samuel, Well Engineering Research Center for Intelligent Automation, University of Houston
Objectives/Scope: Typical trajectory-monitoring models only consider the geometrical approach, without considering the rock mechanics and operational constraints. Trajectory corrections could compromise the wellbore stability and drilling efficiency. For this reason, an integrated analytical model is needed to couple the trajectory-control model with the rock mechanics and mechanical, rotational and hydraulic effects in the trajectory correction. This integrated approach allows to visualize the “big picture” when returning to the designed well path.
Methods, Procedures, Process: The model is divided into three modules. In the first module each survey station from the real trajectory is compared against the planned well path If the well is deviated, the best correction path is obtained by minimizing the energy of the well profile considering the curvature and torsion. In the second module such correction path is validated against the geomechanics model, using the stereogram and mud weight. In the third module, the hydro-mechanical specific energy (HMSE) required to perform the correction is evaluated. The three modules are used iteratively so that all the criteria are met simultaneously.
Results, Observations, Conclusions: The paper provides a roadmap so that the directional driller can use it in the field in real-time. The geomechanics validation ensures that the wellbore stability is not compromised so that the correction results in trouble-free drilling. The HMSE evaluation enables to analyze the drilling efficiency in terms of mechanical rotational and hydraulic energy to identify dysfunctions and other operational causes and effects on the trajectory. To validate the integrated model different deviation scenarios are simulated using the information of real wells already drilled. The results have proven that the smoothest correction path calculated is not always the best path as it may result in operational problems. The use of this integrated model allows to anticipate and mitigate operational problems which translate in improved drilling efficiency. This paper aims to bridge this existing knowledge gap and provides a comprehensive treatise on well trajectory control and, more in general, estimations and their underlying model parameters. The paper describes the details and the new calculation methodology of coupling these various models. The paper presents specific field examples with and without these models where there were wellbore stability problems.
Novel/Additive Information: The combination of the geomechanics model and HMSE with the minimum well profile energy criterion changes the classic trajectory-control methods and adds value in terms of borehole quality in complex wells. Consequently, the coupled model is promising to provide a true integrated trajectory-control approach. The methodology presented in this paper is validated with a scalable coupled geology, geomechanics and geometrical mathematical models.
Wednesday, March 7 (Case Studies I)
IADC/SPE 189699
Offshore Well Intersection and Casing Pull Through to Deliver Pipeline Segment
B.A. Leonard, D.W. Pfeifer, G. Katuaga, P.J. Clark, G.T. Armistead, Chevron Corporation
Objectives/Scope: Planned and executed an offshore well intersection as a unique solution to the challenge of delivering a pipeline segment between two platforms. Logistical difficulties and a large submarine canyon prevented conventional pipeline installation. Chevron decided to utilize drilling rigs to drill a conduit for and then install casing as a pipeline segment.
Methods, Procedures, Process: Two horizontal wells were drilled simultaneously from platforms in shallow water 3 miles apart using a pair of jackup rigs. These wells were drilled to intersect nearly head on beneath the submarine canyon using traditional MWD surveys as well as active magnetic ranging. Once the wells were intersected, one rig latched the drill pipe of the second rig and this combined string was used to pull dry 11 7/8” casing from one rig to the other to serve as the pipeline gas conduit. This casing was then filled with a treated seawater and hydrotested by the rigs to ensure integrity of the pipeline segment.
Results, Observations, Conclusions: With limited local offset information and logistically challenged locations, robust well construction plan served to ensure effective drilling with few delays from subsurface or supply problems. MWD surveys provided sufficiently accurate information to place the wellbores within 250’ and start magnetic ranging to close the final gap and merge the wells.
Novel/Additive Information: This is the first intersection on this scale, performed offshore. The pull through of casing from one rig to the other is a unique activity and required the development of a special assembly to facilitate pumping and rotation during the run. Synchronizing the activities of the two jackup drilling units required the installation of dedicated cameras and communication network to allow the drillers to watch their counterparts in order to move the connected string of pipe in tandem.
IADC/SPE 189597
Unconventional Drilling in the New Mexico Delaware Basin Case History
J.B. Willis, Occidental Oil and Gas Corporation; D. Tellez Muradas, R. Neel, G.A. Caraway, D.W. Adam, J. Rodriguez, Occidental Oil & Gas Corp
Objectives/Scope: The practices, designs, and experiences from drilling more than 170 unconventional horizontal wells in the New Mexico Delaware Basin are presented. The area has been intensely active in 2017, driving interest in drilling performance and operational efficiencies.
Methods, Procedures, Process: Geological conditions addressed include high-pressure flows, lost circulation, salt and anhydrite, and the selection of target intervals. Successful practices covered include rig design, pad layout, casing design and setting depth, bits, downhole motors and tools, rotary steerable systems, and others. Mud systems covered include brine, mixed-metal hydroxide, invert and direct emulsions. Rotary steerable drilling assembly performance is compared to motors in vertical, curve, and lateral sections, with practical conclusions. Drilling dynamics management techniques include bit and bottom-hole-assembly design, and operating practices. The prediction, prevention, and effect of downhole vibrations is thoroughly addressed, with an emphasis on stick-slip.
Results, Observations, Conclusions: Overall drilling time was reduced by around 50% in the period from 2014 to 2017 through the practices that are covered, and improvements continue. During the same period, lateral lengths have increased from 5,000 ft to commonly 10,000 ft. Rig capabilities, pad layout, casing designs, drilling fluids, drilling dynamics practices, and other designs improved significantly over the past 3 years. A methodical approach to vibrations is critical to consistent performance. Direct Emulsion mud has shown promising results as a low-density fluid with salt-saturated water phase. Casing designs were optimized to eliminate strings in some cases, and to reduce hole sizes in other cases. Rig modifications were required to support long laterals and larger drill pipe sizes. Improved data systems and rig automation processes continue to improve operations. A systematic trial and documentation process aided in rapidly learning and disseminating practices through the rig fleet.
Novel/Additive Information: The economic success of New Mexico unconventional developments is heavily dependent on minimizing well cost. It is a difficult area requiring complex optimization. This paper will be thorough in breadth, concisely documenting practices of interest to others operating in New Mexico or similar unconventional areas. The practices and conclusions are supported by extensive operational data.
IADC/SPE 189678
Real-Time Eye-Tracking System to Evaluate and Enhance Situation Awareness and Process Safety in Drilling Operations
Kiran, S. Salehi, J. Jeon, University of Oklahoma; Z. Kang, Department Industrial & System Engineering, University of Oklahoma
Objectives/Scope: Lack of situation awareness in drilling operations has become an important factor of causing safety accidents or cause of non-productive time. A review of testimony from offshore rigs worker suggests distraction and lack of awareness as one of the crucial issues impacting performance.
Methods, Procedures, Process: An eye-tracker detection system can detect whether the driller is tired, such as dozing or inattention, or distracted so as to generate some warning alarms to alert the driller. Therefore, the system can reduce not only accidents but also reducing none-productive time by improving the efficiency. Because human eyes express the most direct reaction when dozing, eye blinking is usually used as the basis for fatigue detection by researchers. In recent years image processing on human faces has been used in many applications, such as face recognition, face analysis, eye detection, gaze tracking, etc. When observing a facial image, the most perceptible facial features are usually the places with obvious edges, particularly the ocular outlines. Since eyes have the nature of sophisticated edges, many researches use this attribute for eye detection. Furthermore, eye-tracking based techniques had successful outcomes in aviation industry and traffic control room. Eye tracking research is useful for evaluating usability or analyzing human performance and more importantly understanding underlying cognitive processes based on the eye-mind hypothesis.
Results, Observations, Conclusions: The study here presents results from experiments conducted in a virtual reality drilling simulator equipped with real-time eye-tracking detection system. An algorithm was developed to characterize, compare, and analyze eye movement sequences that occur during visual tracking of multiple moving targets while conducting different tasks in drilling operations. Collecting eye tracking data helped to quantify and evaluate awareness while conducting different drilling operations in the simulator (Figure 1). One element of detection system is based on colors of the eyes ball and eye movement in the captured frames. Furthermore, the obtained eye images are converted so to distinguish eyeball pixels and to determine whether the eyes are open or closed for judging driller’s awareness (Figure 2). Results concluded from this study indicates that, the system can correctly detect lack of awareness marked by humans. The average correct rate on test videos for eye detection and tracking can reach to 90%. The results show very promising application of this technology on drilling rigs.
Novel/Additive Information: Content analysis of communication log files and eye tracking analysis can enlighten the participant’s situation awareness. The applied methodology in this study has high potential for implementing in drilling operations.
IADC/SPE 189660
Case Study: Reactive Torque Failure Prevention
Pettit, T H Hill Associates
Objectives/Scope: Reactive torque failures occur when an underreamer or hole opener stalls suddenly. The right-handed momentum in the components underneath the stalled tool applies a left-handed torque to the connections. If this left-handed torque is high enough, the connection can back off. In fact, an operator had a reactive torque failure in just this manner. We study that failure as an example in this paper, outlining the way to prevent it in the future. In short, the makeup torque applied to the connection must remain higher than the left-handed torque that the tool might see. While simple enough, the complication comes when trying to calculate the magnitude of left-handed torque under a stalled underreamer.
Methods, Procedures, Process: The simplest method is to apply an energy approach when calculating the left-handed torque. This is straightforward mathematically, and in most cases it is conservative due to the lossless assumptions that are used. Unfortunately it is becoming common that something more sophisticated is necessary. This is due to the fact that vibrations are typically ignored in a simple energy model. Since in many holes friction will quickly damp out any vibrations caused, this often does not cause problems. However, if reaming a very big hole—as was the case in our study, and is often true of the larger hole sizes in deepwater operations—the friction may be low enough that torsional vibrations will play a significant role.
Results, Observations, Conclusions: In order to calculate the reactive torque that might be applied in these latter instances, a numerical approach must be employed that considers the torsional shock wave applied to the components underneath the stalled hole opener.
Novel/Additive Information: This paper considers these different mathematical approaches, particularly as they were applied to both the reactive torque failure and the resulting preventative design processes.
Wednesday, March 7 (Drilling Dynamics and Mechanics)
IADC/SPE 189630
Lab-Scale Drilling Rig Autonomously Mitigates Downhole Dysfunctions and Geohazards Through Bit Design, Control System and Machine Learning
Zarate Losoya, T. Cunningham, I. El-Sayed, S. Noynaert, Texas A&M University; F. Florence, Rig Operations
Objectives/Scope: Oilfield economic conditions today continue to emphasize the need to recognize and respond to drilling dysfunctions quickly to help contain drilling costs. Drill string vibrations reduce bit life and may lead to catastrophic equipment failures downhole. Poor directional control and tortuous wellbores may lead to lower economic output from the well. It is important for drilling engineers planning wells to fully understand the cause of such dysfunctions and to develop means to mitigate their impact.
Methods, Procedures, Process: SPE’s Drilling Systems Automation Technical Section (DSATS) now enters its third year of an international competition for universities to design and build a small drilling rig that can drill hands-free in an unknown formation. Students must demonstrate technical skills to understand the drilling dysfunctions that can affect their rig’s performance and calculate the magnitude of the effects on the drilling program. This year, students must design and build a downhole sensor integrated into their control scheme. They have applied several different sensor-types and unique telemetry techniques in 3D-printed subs that follow a 1-1/8 inch bit. Some are using wired pipe while others use RF telemetry. The data is being used for navigation and vibration mitigation in real-time without human intervention. The teams realize that the measurement and control aspects of drilling are as important as the equipment design, and they must model the rig-states and determine appropriate response algorithms. Issues must be identified and drilling parameters adjusted before dysfunctions spiral out of control. Teams often conduct a series of drill-off tests in various rock types to pre-tune their drilling algorithms, Simply waiting for the results of a real-time drill-off test, as is commonly done in the industry today, just isn’t fast enough. With improved state-detection algorithms and new optimization techniques the right choice of drilling parameters is immediately selected. DSATS intentionally complicates their task by choosing a thin-walled tube and limited means of applying downhole WOB, which essentially ensures buckling and whirl conditions. DSATS also provides a rock sample of varying material, unknown formation dip and always a “surprise.” This year’s test includes material that should cause stick-slip in addition to the usual problems of directional control and extreme vibrations.
Results, Observations, Conclusions: This paper presents the results of on-site testing of the winning team that drills a high-quality wellbore in the shortest amount of time. It also details the decision process for the rig design choices based on background lab tests and engineering calculations. In addition to the creation of hardware and software tools for ROP optimization and mitigation of drilling dysfunctions, students must show proficiency in sensors, sensor calibration, data quality, data handling and new data display methods.
Novel/Additive Information: The latest student designs include servo motor driven stabilizers and distance sensors, a hybrid rotary-hammer bit, and hardware abstractions of the rig implemented in advanced drilling algorithms. We expect that their innovative features will soon find their way into equipment and tools used throughout the industry.
IADC/SPE 189673
Improved Methods to Understand and Mitigate Stick-Slip Torsional Vibrations
IADC/SPE 189710
Measurement of Dynamics Phenomena in Downhole Tools – Requirements, Theory and Interpretation
Hohl, C. Herbig, P. Arevalo, Baker Hughes; H. Reckmann, Baker Hughes Inc; J.D. Macpherson, Baker Hughes
Objectives/Scope: Downhole tools in bottom-hole assemblies are subject to high dynamic loads during drilling operations. Negative impacts of these loads can be inefficient drilling with low rate of penetration (ROP), reduced measurement and service quality and downhole tool failures and associated non-productive time.
The dynamic phenomena can be categorized by direction into axial, torsional and lateral vibrations and by excitation mechanism into forced excitation, self-excitation and parameter excitation. Forced vibrations are mainly caused by imbalances in the drilling system or by the working principle of downhole tools like the mud motor. Self-excitation mechanisms can cause dysfunctions like stick/slip, bit bounce and backward whirl and are mostly driven by the interaction of the bit, reamer or drilling system with the formation.
Methods, Procedures, Process: The diverse vibration phenomena need tailored mitigation strategies. The mitigation strategies are to some extend contradictory. Misinterpretation of downhole measurements can lead to even worse vibration levels with severe consequences for reliability, ROP and measurement quality.
As a consequence specific requirements for measurement devices are needed to identify the vibration phenomena. The distinct differentiation into the drilling phenomena can then again be used to choose appropriate mitigation strategies.
Results, Observations, Conclusions: The requirements that are needed for dynamics measurement devices are analyzed and defined in this paper. Specification, number and placement of sensors and the associated sampling rate are examined to distinguish between different vibration directions and phenomena. The usefulness of the requirements are demonstrated for different examples of stick/slip and high-frequency torsional oscillations, lateral vibrations and backward/forward whirl, axial vibrations and impacts between the drilling system and the formation. The results of kinematic and kinetic modeling are analyzed and compared to high-speed vibration data from field runs measured with the latest generation of vibration measurement tools. Possible misinterpretation of vibration conditions in case of inappropriate measurements is shown. The results are discussed by comparing the theoretical modeling with laboratory data and field data.
Novel/Additive Information: The defined requirements and guidelines enable a flawless interpretation of downhole vibration measurements and unveil drilling optimization opportunities. Different vibration phenomena can be identified reliably and appropriate mitigation strategies applied in real-time on the rig-side by the driller or in automation approaches reducing the vibration load on the system and increasing its reliability and performance.
IADC/SPE 189600
Backward Whirl Testing and Modeling With Realistic Borehole Contacts for Enhanced Drilling Tool Reliability
T.M. Popp, H.C. Stibbe, D. Heinisch, H. Reckmann, Baker Hughes; P.D. Spanos, Rice University
Objectives/Scope: Drill string-borehole contact may result in backward whirl, a common and catastrophic phenomenon. To increase BHA reliability, decrease premature failure, and ultimately improve service delivery, an in-house backward whirl testing rig was developed to investigate dynamic loads. Continuous and discontinuous borehole profiles yield different vibration levels and spectral content. Results are compared with field data and simulations. Analytical and FEM models elucidate the dynamic loads and stresses; models are validated against backward whirl test results.
Methods, Procedures, Process: A 6 ¾-in BHA is tested with an 8.5-in borehole using a continuous and discontinuous borehole profile; the same setups are investigated in the simulations. The finite element model is based on a 3D solid dynamic model that includes nonlinear contacts and material anisotropy. Details on boundary conditions, constraints, and applied physics are described; resulting loads and stresses are retrieved. In addition, a simplified lumped-parameter model is established to obtain results more expeditiously than the 3D solid finite element model; it is based on a two degree-of-freedom whirl model in polar coordinates (radial and tangential coordinates).
Results, Observations, Conclusions: Tests demonstrate that backward whirl may occur from friction induced contact with different borehole profiles. A discontinuous profile yields drastically higher dynamic loads. Backward whirl tests are conducted within a rotary speed range of 40 to 90 rpm within a continuous profile, and result in lateral acceleration loads from 2 to 5 grms. Identical tests are conducted with a discontinuous profile and yield loads from 4 to 12 grms (field loads of 5 grms and greater are considered high risk levels). Spectral energy is contained within 150 Hz for tests using a continuous profile. In comparison, energy content remains significant to 1000 Hz for tests using a discontinuous profile; higher frequency content is especially detrimental to BHA electronics. Sensors measure vibration loads along the test BHA, which provides validation for analytic and numerical models. Load values are extracted from the lumped-parameter and finite element models and compared with backward whirl test results. Results show that acceleration amplitudes and grms values are consistent between the models and tests. The full-scale backward whirl test rig, along with validated models, provides a comprehensive test regime to study dynamic load effects on tool life, and helps increase reliability on downhole drilling BHAs.
Novel/Additive Information: Backward whirl testing of full scale drilling tools with realistic, discontinuous borehole contact is a new approach to correlate testing with field measurements. These tests, supplemented with validated modeling, provide critical information on loads and stresses present during downhole vibration with discontinuous contact. Designing new products with this insight and testing capability leads to improved design and enhanced tool reliability, ultimately improving drilling performance.
IADC/SPE 189642
On the Importance of Boundary Conditions for Real-time Transient Drillstring Mechanical Estimations
Cayeux, Intl Research Inst of Stavanger
Objectives/Scope: The extraction of mechanical friction, during drilling operations, is an important source of information to estimate whether the downhole conditions are sub-optimal, like for instance because of poor cuttings transport or additional tortuosity induced by the directional work. Traditionally, the friction factors are extracted using steady state torque and drag models. But, there are contexts, like when drilling from a floater, where it is difficult to find any periods where stable conditions can be observed.
Methods, Procedures, Process: A possible solution to this problem consists in running, in real-time, a transient torque and drag model connected to a high refresh-rate feed of measurements taken by the drilling machines sensors and to utilize continuous calibration methods to extract information about the unknown or ill-defined parameters that influences the drill-string mechanical system. For those parameters that should stay constant throughout a bottom hole assembly (BHA) run, the estimation method shall account for the totality of the observations and therefore utilizes calibration methods based on statistical global optimization principles, while time-dependent parameters are estimated using a filtering technique.
Results, Observations, Conclusions: This approach is only valid when utilizing a trustworthy transient drill-string mechanical model. Comparisons between estimated values from transient torque and drag models and actual measurements have highlighted the importance of a sound modeling at the boundaries of the mechanical system. For instance, when modeling precisely the top-drive and the hoisting system mechanical behavior with its associated heave compensation system, it is then possible to obtain a good match between estimated and observed top-drive torques and top-of-string forces, while the bit is off bottom. Furthermore, it requires a precise modeling of the bit/formation interaction, and the under-reamer/formation interaction in case of hole enlargement, to get a truthful dynamic response of the model when the bit is on bottom and only passive heave compensations is used. Associated with its continuously updated calibration of the ill-defined parameters of the system, such a transient torque and drag model allows to visualize, in real-time, the internal displacements of the drill-string even in the most complex drilling conditions.
Novel/Additive Information: Until recently, drill-string dynamic modeling has mostly focused on the lower part of the drill-string, i.e. just above the BHA, and has been reserved to post-analysis evaluations, as existing solutions have been very computer intensive. This paper describes a solution that runs in real-time and that considers the whole drill-string, allowing for the extension of drilling automation functions to very dynamic conditions like those encountered on a floater.
IADC/SPE 189582
A New Workflow for Estimating Bit Wear and Monitoring Drilling Efficiency in Real-Time During Drilling Operations
Millan, M. Ringer, Schlumberger
Objectives/Scope: This paper presents a new workflow for monitoring drilling efficiency in real time during drilling operations. Based on a bit-rock interaction model, the new workflow provides parameter estimations, such as bit wear and in-situ rock strength, obtained from typical real-time drilling measurements. The model can be used to predict rate of penetration (ROP) ahead of the bit, optimize drilling operating parameters, and determine the potential benefits of tripping out to change the bit.
Methods, Procedures, Process: The new workflow, based on a bit-rock interaction model, describes the response of a PDC bit by considering separately the forces acting on the face and wear flat of PDC cutters. The parameters of the model are estimated in a novel two-stage approach: first, the parameters relating to friction are estimated using time-based data captured during drillon and drilloff events. Then, the bit wear and rock strength are estimated using depth-averaged data. Innovative techniques are used to better constrain and enhance the estimation of these parameters, such as ensuring the bit wear does not decrease with depth.
Results, Observations, Conclusions: The new workflow was validated using laboratory tests, downhole data, and real-time data measured at the surface. All stages of the process were then combined into a single automated workflow and have been deployed on several operations to monitor and optimize drilling efficiency. A number of case studies are presented in this paper to illustrate application of the new approach and show the bit wear and rock strength estimations based solely on real-time drilling data. In particular, estimating the bit wear at the end of each well section is compared to the IADC dull bit grading guidelines, and the predicted ROP is compared with the measured ROP in future wellbore sections to be drilled. An additional output from the new workflow is the ability to assess the impact the different drilling operating parameters have, as well as estimating the time potentially saved should the drill string be tripped out for a bit change. Finally, the resulting bit-rock interaction model can be used to predict ROP in future wells.
Novel/Additive Information: The workflow presented in this paper is a powerful method for monitoring real-time drilling efficiency through estimating bit wear, in-situ rock strength, and future ROP. This new method uses a novel approach that combines time-based and depth-based drilling data and innovative data processing algorithms to further constrain and enhance these estimated parameters. The new method is totally automatic and has been shown to facilitate optimizing drilling efficiency in real- time.
Wednesday, March 7 (Drilling Fluids and Wellbore Strengthening)
IADC/SPE 189648
In-situ Fluid Rheological Behavior Characterization Using Data Analytics Techniques
Ettehadi Osgouei, R. May, T. Dahl, Baker Hughes; D.K. Clapper, R.T. Swartwout, Baker Hughes
Objectives/Scope: The accurate characterization of drilling fluid rheological properties at the target downhole temperature and pressure is essential for designing the hydraulic program as well as for managing potential challenges during the drilling operation. HTHP rheometer is the common experimental method used to measure drilling fluid rheological properties at high temperature and high pressure (HTHP). This method is costly and time consuming and requires skilled fluids laboratory personnel to carry out the tests. This paper/study presents an analytics based method to estimate drilling fluid rheological properties at target downhole temperature and pressure and provide the required inputs for hydraulic modeling during well planning, and for real-time monitoring and automation. The performance of developed method is evaluated by utilizing data obtained from Mud Check test and HTHP Viscosity measurements of synthetic and oil based drilling fluids samples.
Methods, Procedures, Process: Drilling fluids samples were collected from the rigs in operations around the world. An algorithm is developed to retrieve data out of unstructured field service laboratory databases and to uncover hidden patterns by utilizing the text pattern matching, text analytics, table-based approach, data visualization and classification techniques. Several computational intelligence techniques and statistical methods are applied to extract the insights data holds by defining the relationship between variables measured in the Mud Check tests and HTHP rheometer data. 70 percent of extracted data is used to train the data driven-model to predict drilling fluids rheological behavior at the target downhole temperature and pressure.
Results, Observations, Conclusions: The model is further tested with a non-overlapping data set (30% of extracted data) which confirms that the model can characterize the drilling fluid rheology at the target downhole temperature and pressure with acceptable accuracy. This study indicates that in addition to temperature and pressure, several parameters including but not limited to density, salt concentration, low and high gravity solid volume percentage, oil-water ratio, and oil phase volume percentage should be considered to accurately predict the rheological properties of drilling fluids at downhole conditions. Since the method presented here depends on several variables measured in the Mud Check tests, it can effectively be employed independent of location or formation.
Novel/Additive Information: The developed method can be utilized at the rig-site by field personnel to estimate downhole rheological properties of drilling fluids by ensuring a small error margin and without using the expansive test equipment and time-consuming procedures.
IADC/SPE 189633
How to Test for Compatibility between Fluids and Shales
van Oort, The University of Texas At Austin
Objectives/Scope: Fluid-shale compatibility testing is as old as the fluid industry itself. When drilling fluids started to be deliberately used for hole-making, the (in-) compatibility of these fluids with clay-rich shale formations became immediately apparent, and industry scientists have been trying to make sense of it all ever since. With a plethora of possible shale tests available, a key question remains: what are the best, most representative tests to characterize fluid-shale interactions and avoid making decisions based on less sensitive tests that may suffer from artifacts and yield misleading results?
Methods, Procedures, Process: This paper argues for the use of a representative set of shale tests that includes accretion tests, cuttings dispersion tests and mud pressure transmission tests, while pointing out issues and problems with other tests such as atmospheric swelling tests and capillary suction tests, which still find wide-scale application in the industry. Moreover, it introduces a novel, low cost borehole stability test in the form of a modified thick wall cylinder test. This new test exposes a cylindrical shale samples, confined under downhole temperature and pressure, to mud formulations at overbalance for a specified period of time and assesses the failure strength of the sample thereafter. The test is thereby capable of mimicking the results of much more sophisticated, and much more expensive, test protocols such as the downhole simulation cell test.
Results, Observations, Conclusions: The details on the new test protocols are given here. Moreover, it is shown how the proposed test protocols can be used for the comprehensive qualification of the merits of new nano-particle and high-salinity water-based fluid formulations. The results of extensive comparative fluid tests, carried out in request by oil and gas operators, to determine the optimum fluid formulation for drilling, completion and water-injection purposes in the field will be given, together with the ultimate results of selected optimum candidate solutions in field applications.
Novel/Additive Information: Basic and costly mistakes are still being made regarding fluid selection for shale-related field applications, despite decades of work on shale-fluid compatibility investigation. The information presented in this paper will allow fluid practitioners and drilling/completion/stimulation engineers to better select optimum fluids for their field applications.
IADC/SPE 189577
Nanocellulose and Biopolymer Blends For High-Performance Water-Based Drilling Fluids
L.J. Hall, Formerly Halliburton; J.P. Deville, C.M. Santos, Halliburton; O.J. Rojas, C.S. Araujo, North Carolina State University
Objectives/Scope: Water-based drilling fluids are an economical and environmentally appealing option for wellbore construction. Both conventional and high performance water-based systems typically use biopolymers to provide viscosity, suspend solids, and control fluid loss in the wellbore. Some examples include both naturally occurring biomaterials produced by plants or bacteria (e.g., starch, guar, xanthan), as well as their chemically modified analogues. However, new materials that could improve efficiency, rate of penetration (ROP), or high-pressure/high-temperature (HP/HT) performance are necessary to expand the use of economical water-based systems in increasingly demanding conditions. Recently identified nanostructured biomaterials, such as nanocellulose, have been shown to have outstanding mechanical, structuring, and thermal properties, and are also known to be potent viscosifiers at low concentrations. This paper presents a study that investigates the performance of water-based fluids by either replacing or augmenting their common oilfield biopolymers with cellulose nanofibrils (CNFs).
Methods, Procedures, Process: In this study, CNFs produced from technical grade kraft pulp were compared to commercial biopolymer viscosifiers, such as xanthan and guar gum, in terms of performance in a water-based drilling fluid. Measurements were made of rheology, thermal stability, filtration behavior, and equivalent surface charge as they relate to desirable fluid properties. Temperature stability of nanocellulose water-based fluids was significantly improved over commonly used xanthan gum viscosifier in terms of maintaining control of fluid rheology. Furthermore, highly unexpected synergies were discovered when the CNFs were blended with secondary biopolymers. Increases or decreases in system viscosity were observed that were dependent upon the type of biopolymer mixed with nanocellulose, but independent of the mass balance of the ingredients. In some mixtures, lower biopolymer concentrations produced increases in viscosity within mixed systems while other mixtures decreased viscosity with increased concentrations.
Results, Observations, Conclusions: The implications of these unusual findings suggest that performance efficiency can be tailored simply by mixing CNFs with biopolymers that are already used extensively in water-based fluids, allowing an operation to use less material. This discovery can enable a new method to maintain drilling fluid properties during drilling operations with the added benefit of increased temperature stability.
Novel/Additive Information: By modifying the surface of CNFs with secondary biopolymers, a wide range of fluid behaviors were achieved through changes in surface chemistry, surface morphology, and gel network formation. Such nanocellulose fluid systems could serve as a renewable, nontoxic, and potentially cheaper alternative to synthetic polymers in high performance water-based fluids with the added benefit of controlling and improving fluid properties through mixture with common oilfield biopolymers.
IADC/SPE 189589
A Practical Model for Wellbore Strengthening
Chellappah, BP Exploration; R. Majidi, BP America Inc; M.S. Aston, BP Exploration; J.M. Cook, Schlumberger
Objectives/Scope: This paper presents a new model that integrates relevant aspects of geomechanics and drilling fluids to provide practical solutions for wellbore strengthening.
Methods, Procedures, Process: This integrated approach accounts for the influence of stress state, rock properties, wellbore design parameters, and the impact of particle-laden fluids on the creation, growth, and arrest of an induced fracture. Based on the new model, a workflow is proposed that uses five key steps to select the appropriate blend of lost circulation material (LCM) for wellbore strengthening.
Results, Observations, Conclusions: Firstly, a dimensionless parameter called the Wellbore Strengthening Index (WSI) is introduced to quantify the magnitude of wellbore strengthening required. WSI can be considered as a measure of strengthening (difference between the wellbore pressure and the far-field minimum stress) normalised to the rock stiffness. The second step estimates the required LCM concentration using a linear relationship with WSI. Next, a semi-empirical correlation is used to relate LCM concentration to fracture dimensions (variable length); laboratory-scale experimental data is presented to substantiate this correlation. In step four, a closed-form equation is proposed and used to estimate the induced fracture width at the time of sealing. Finally, in step five, appropriately sized LCM products are selected to efficiently seal the fractures.
Novel/Additive Information: This coupled geomechanics-fluids approach improves on existing models such as Stress Cage. Well-defined constants within the model give it the flexibility to be calibrated to field data. The proposed workflow is relatively straightforward to code into a practical and user-friendly design tool for wellbore strengthening. Work is ongoing to validate the model in the field.
IADC/SPE 189584
A Practical Method to Monitor Wellbore Strengthening Particle Concentration
M.W. Alberty, Z. Yao, Hess Corp.
Objectives/Scope: The StressCage methodology of wellbore strengthening uses sized particles to bridge and seal induced fractures, increasing fracture resistance in permeable formations. The size distribution of the particles, or fracture prevention material (FPM), that are added to the mud is engineered to ensure a correctly sized particle enters and bridges the induced fracture before it grows beyond its design width and length. A minimum concentration of FPM is determined through a physics based numerical calculation to derive a mud formulation based on the particle size distribution (PSD) and density of the selected mud additives. This minimum concentration and particle size distribution of FPM must be maintained at all times that the well pressure exceeds the fracture gradient or previously generated fracture resistance of the formation in order to prevent the failure of the StressCage and the subsequent loss of well integrity. The concentration should be monitored to ensure the minimum concentration is maintained.
Methods, Procedures, Process: A number of methods have been used to monitor FPM concentration in the mud. Most methods sample the mud returning from the well before arriving at the mud shakers, pass the collected mud sample through stacked sieves, then remove the liquid mud coating the particulates using either centrifuges or drying ovens, and weigh the resulting residue to determine the return concentration. The lag time for results in deepwater wells can be 5 to 10 hours, depending upon the time required to circulate the mud up the well and dry the samples. This lag time delays results so long that they are ineffective in preventing the FPM concentration from decreasing to less than the minimum required.
Results, Observations, Conclusions: A simple and fast method has been developed that requires minimal special equipment. A reference sample is collected from a reserve mud pit carefully prepared with the target minimum FPM concentration. The mud is then run though a set of selected stacked sieves. The reference tare weights of the wet FPM collected in each sieve is then used as a reference for monitoring the active system. The reference wet FPM weight is then compared to mud samples collected from the suction pit of the active system as the well progresses. The difference in the weight observations is then used to determine appropriate additions to maintain or exceed the minimum requirements.
Novel/Additive Information: This new methods has been successfully applied in deepwater wells and has proven to be quick and effective.
IADC/SPE 189574
Engineered Nutshell Particles for Wellbore Strengthening
Chellappah, M.S. Aston, BP Exploration; S. Savari, Halliburton Co.; D.L. Whitfill, Halliburton
Objectives/Scope: Drilling fluid designs for wellbore strengthening have improved through the development of engineered nutshell products, which have replaced conventional marble. In several successful field applications, engineered nutshell products have greatly simplified rigsite logistics and particle-size distribution maintenance during drilling.
Methods, Procedures, Process: Laboratory attrition and erosion tests were performed to quantify nutshell particle attrition and potential erosion of surface equipment. Slot tests were performed to assess fracture-sealing performance. A coupled sieve analysis and flotation procedure was developed to monitor the nutshell particle size and concentration in the field during drilling. A tool was developed to consistently recommend product addition rates for maintenance based on the severity of particle degradation. This tool was also used to quantify and compare the field attrition tendencies of both nutshell and conventional marble products.
Results, Observations, Conclusions: Engineered nutshell particles were shown to have greater survivability than the more conventional marble particles. Solids addition rates necessary to maintain the larger nutshell particles during drilling were approximately 80% lower than with comparable marble-based systems. An example is given to illustrate how maintenance could be achieved by addition of the nutshell particles directly to the mud (hopper-based addition) without the need to prepare a concentrate. This was not possible using marble-based systems which required mixing and shipping out an additional 1000-1500 barrels of wellbore strengthening concentrate. In another example, the reduced treatment rates with nutshell removed solids addition as the limiting factor to drilling rate, thus enabling higher rate of penetrations (ROPs). Owing to losses experienced in an offset well using marble, contingency plans were drawn up to deploy a Solid Expandable Tubular (SET) to isolate the depleted sands. No losses were experienced with the engineered nutshell system, and hence the SET was not required. The engineered nutshell sizes also overcame some prior issues with a ‘conventional’ nutshell-based product which damaged mud pump efficiency by up to 40%.
Novel/Additive Information: The engineered nutshell-based wellbore strengthening systems are now being regularly used in the field and offer several advantages compared to the more conventional marble-based systems. Rigorous laboratory testing and field applications have proven the benefits, which become more pronounced with increasing depletion.
Wednesday, March 7 (Data Analytics)
IADC/SPE 189663
Optimizing Remote Operations Support Using an Effective Real-Time Model for Improved Drilling Performance
Robert, W.S. Fiffick, D. Davis, R. Guillory, Canrig Drilling Technology LTD.; J. Myers, Nabors Drilling Solutions; C. Mandava, Nabors Industries
Objectives/Scope: A leading integrated drilling equipment and drilling operations company has successfully implemented a real-time operations strategy to optimize field service performance and decrease non-productive time. Through proactive collaboration, the organization has improved overall reliability and productivity for their drilling equipment and for the overall drilling operations.
Methods, Procedures, Process: Over the past decade, advancements in drilling technology and supporting systems have been developed and implemented. This study will detail some of the key systems within the real-time operations center, field service, and drilling technology that have led to improved drilling performance; ultimately leading to a greater efficiencies and decreased down time. This paper will discuss the relationship between remote support, field operations, drilling technology, and other support components.
Results, Observations, Conclusions: Implementing these advanced support strategies have resulted in more critical issues being resolved remotely, improved response times for field service, and improved overall resolution times. Furthermore, customer satisfaction ratings, productive time, and many overall performance KPIs have dramatically improved.
Real Time Operations Center
• Improved Documentation and Reporting
• Expedited escalation and response during major events
• Improved overall training & competency
• Improved KPI reporting through use of Field Service Software
• Improved handoff between Remote Operations Center and Field Service Support Technicians
• Increased remote resolution rate
• Consistent RCRA process to support continuous improvement and lessons learned (and to ensure those lessons are acted upon).
Equipment and Software
• Automated alerts generated from rig equipment
• Detailed Real Time rig data
• Remote interfaces between operations center and the drilling rig
• Field Service Software for improved KPI reporting optimizing communication with all appropriate stakeholders
• Preventative Maintenance Programs (through real time monitoring & alarms)
Field Service
• Competency based training increasing skills leading to reduced resolution times
• Improved response times due to geographic placement of technical support
• Improved communications and improved customer experience
• Improved first time resolution rates
• Preventative Maintenance Programs (through field inspections)
Novel/Additive Information: While many in the industry talk about the possibility of providing optimal after sales support, one organization has been able to successfully implement innovative strategies, decreasing downtime to record lows. This model continues to drive best in class drilling performance and establishes a higher standard of support required for the future of the drilling industry.
IADC/SPE 189576
A Comprehensive Real-Time Data Analysis Tool for Fluid Gains and Losses
Andia, R.V. Sant, N. Whiteley, BP
Objectives/Scope: This paper describes a comprehensive approach to aid the monitoring and trending of wellbore fluid gains and losses during well construction drilling and completion operations. A software tool was built that is able to integrate real-time data with algorithms to provide early warning indicators for potential well control and lost circulation events. The focus is primarily on amalgamating relevant formation evaluation data, drilling and circulating parameters as well as pre-drill or real-time pore pressure and fracture gradient analyses.
Methods, Procedures, Process: In order to build a comprehensive real-time data analysis tool for managing the fluid in the well, three key parameters were identified as essential for monitoring: surface fluid volumes, surface and downhole drilling parameters and formation properties, and gas events in the wellbore and at the surface. A number of integrated algorithms and displays that operate within a real-time data platform were designed to utilize these measurements in real-time against relevant well construction information. The primary aim is to provide a medium for visualization of events and informative trends; along with alerts when these parameters fall outside user-specified thresholds. Presenting this collated information in real-time provides shared awareness of fluid gain/loss risks and events to personnel that work in a real-time monitoring center as well as to offshore and onshore operation teams.
Results, Observations, Conclusions: The main result of this project is the creation of eight capabilities that aid the monitoring of fluid gains and losses during well construction operations: a two-dimensional wellbore schematic, a depth-based pore pressure fracture gradient analysis display, a time-based pore pressure fracture gradient analysis display, a flow in versus flow out analysis display, an automatic trip table, a flow back fingerprinting tool, a gas monitoring tool, and a pressure while drilling tool for monitoring wellbore breathing. A number of algorithms integrated to these tools work in the background and allow, for example, them to identify specific gas events (e.g., pumps-off, connection) and estimate their arrival times at surface, calculate the drilling mud window and define the risks of gain and loss events at the bit and ahead of the bit (using pre-drill data), compare pit flow back volume profiles via an overlay and provide alerts when these volumes increase above specified thresholds. The software tool was developed over three years and trialed on two wells with offshore and onshore operations personnel. It is now being deployed and used by technical specialists that work in a real-time monitoring center and operation support teams in the office.
Novel/Additive Information: Drilling parameters and formation evaluation data are readily available at the rig and in real-time at office locations. However, the ability to systematically extract value in real-time regarding fluid gains and losses during well construction from multiple data sources is not yet ubiquitous. This project demonstrates that a number of tools can be used simultaneously in real-time to systematically convert and collate well site data and present this in standard visual interfaces to various personnel involved with well construction operations.
IADC/SPE 189595
Rapid Development of Real-Time Drilling Analytics System
Cao, C.W. Loesel, S.S. Paranji, Anadarko Petroleum Corporation
Objectives/Scope: This paper serves to provide a technical overview of the Real-Time Drilling (RTD) analytics system currently developed and deployed, as well as, to highlight new functionality being considered for future development. It also serves to share practices used in managing the RTD analytics project which have resulted in the efficient delivery of work products.
Methods, Procedures, Process: Technology: In order to have an open RTD analytics system, a decision was made to develop an in-house RTD analytics system based on a generic complex-event processing framework. The system consists of three subsystems: data acquisition, analytics, and a GUI front end. The open analytics system refers to a framework where various analytics modules can be developed in-house and added to the system, including physics based engineering models and data driven or machine learning models. It further refers to a generic real-time analytics system where the data acquisition layer is inter-changeable, and not limited to the RTD data. Currently in the analytics subsystem, the drilling operation activity recognition module and the sliding drilling guidance module are online; the drilling key performance indicators module and the real-time torque and drag module are online for debugging/testing; the rotational drilling guidance module is ready to be included in the system; and two more modules will be developed and added to the system soon: the real-time drilling fluid hydraulic module and the machine learning based GeoSteering module. More physics based engineering modules or machine learning modules will be added to the system as necessary in the future. Project Management: For efficiency, a small core team (one data scientist, one drilling engineer) with two part-time developers was formed with clear roles and responsibilities. The team executed in an autonomous mode, with servant leadership type support and strategic direction from management. At a tactical level, the team has daily short SCRUM meetings to define and prioritize tasks. Floating resources are available for the team to incorporate so as to deliver some sub-tasks quickly, if necessary.
Results, Observations, Conclusions: Within three months, an RTD analytics system with two analytics modules was built from scratch and placed online in production. This real-time decision-support tool has been fully accepted by the business and has become a powerful tool for the whole drilling engineering team. Within this open system, it is expected that more new modules will be added to the system on a monthly basis.
Novel/Additive Information: Compared to a more traditional multi-year effort and cost intensive RTD development project, our design to production time has been faster and has cost much less due to the novel and agile development approach. We want to share our experiences with the industry in the way we are positioning, designing, and materializing our RTD analytics system, and the way we are efficiently managing our RTD project.
IADC/SPE 189707
Drilling as an Evaluation Tool in Horizontal Shale Wells
Mace, Greylock Energy
Objectives/Scope: The development of unconventional resource plays in the United States has led to numerous changes in the fields of drilling engineering and reservoir evaluation. During the initial years of high commodity prices, the act of drilling a horizontal shale well became more of a service and less of a science in an effort to increasing speed of development. Reservoir evaluation through logging suites and core analysis was cast as an unnecessary cost and shale reservoirs were deemed to be “statistical plays”. Recent downward force on commodity prices has threatened the viability of many active fields and pushed operators into developing only the core of the core acreage in an effort to sustain positive well economics.
This new “lower for longer” pricing environment has spurred ingenuity in an effort to elevate non-core acreage to core acreage status and enhance well productivity. Operators have shifted their views on reservoir evaluation by running logging-while-drilling (LWD) tools behind the bit, logging through the bit on wiper trips, or cased hole logs such as a pulsed neutron and dipole sonic. Of interest in this paper is the use of drilling data as an analog for conventional logging suites, which add time, cost, and risk to well. By applying mechanical specific energy (MSE) data generated by the penetration of the formation, drilling engineers can turn an often disregarded data set into both cost savings and enhanced well productivity. We will compare and analyze the ability of MSE to replace the conventional data source in designing a targeted completion on the lateral section of a shale well.
Methods, Procedures, Process: The values for mechanical specific energy (MSE) are calculated across the lateral section. We have directly compared MSE to unconfined compressive strength (UCS) across several fracture stages in a Marcellus Shale horizontal. The MSE and UCS values are compared at the perforation depths suggested by an engineered completion design. The standard deviation of these values is of most importance, as a variance in rock strength can create a preferential diversion of fracturing fluids and proppant.
Results, Observations, Conclusions: The application of MSE as a replacement for geomechanical information in horizontal shale wells is successfully developed for the above case. Drilling data can be leveraged as an evaluation tool for completion quality along the lateral section. By expanding the uses of the drilling data set, operators can continue to positively impact well productivity. Existing MSE data sets are applicable to recompletions as well as drilled but uncompleted wells.
Novel/Additive Information: Like many others, we have attempted to leverage information captured while drilling to improve our understanding of the reservoir. Generating this incremental data set from the often barren reservoir evaluation budget of a development drilling program is a true value add for shale operators. We have progressed the concept of mechanical specific energy by directly comparing it to geomechanical properties derived from a sonic logging suite (specifically, unconfined compressive strength). By comparing an engineered completion design that was generated without knowledge of the MSE data set, we have confirmed the applicability of MSE values as a substitute for geomechanical logging suites (and therefore, engineered completion designs) in this area of the Marcellus Shale basin.
IADC/SPE 189605
Automated Large Data Processing: A Storyboarding Process to Quickly Extract Knowledge from Large Drilling Datasets
G.S. Saini, H. Chan, The University of Texas at Austin; P. Ashok, University of Texas At Austin; E. van Oort, The University of Texas At Austin; M.R. Isbell, Hess Corp.
Objectives/Scope: Today, large volumes of data are collected during the drilling process. However the business value of such data is limited unless it can be analyzed quickly to derive practical knowledge that can then be applied on subsequent wells. The sheer quantity and messiness of data can overwhelm engineers and often leaves them at a loss on how to extract value. An automated process is therefore necessary, for engineers to extract knowledge quickly and efficiently.
Methods, Procedures, Process: The team identified a set of 10 questions whose answers provide immediate knowledge to help improve the drilling of subsequent wells. Each of these ten questions is best answered through a storyboarding process. This involves the automatic creation of a series of one page visuals with just the right amount of information on each page to defend and validate the answers to the questions. The structuring of the all data (well-site data, survey data, geology data, well plans, etc.) enables the rapid automated creation of these visuals though software and is an important step in the process.
Results, Observations, Conclusions: This work describes the storyboarding process applied to a dataset that was more than 100 GB, from 16 shale wells drilled in North America. Examples of questions that could be quickly answered using the process are – What was the best drilled well on the pad? Did a particular BHA improve drilling in a particular sections of the well? etc. Scripts were written in Matlab, R and Python, to automatically grab the raw data and process it, thereby generating more than 20 different types of one-page visuals, which are suited to create presentation slides that answer these questions. The illustrated information includes insights in BHA performance, wellbore tortuosity and quality, vibrations, weight on bit transfer, and other drilling dynamics. Identifying the relevant KPIs to answer the many questions, and presenting exactly the right information from the vast amounts of data to satisfactorily answer such questions was a challenge. Ultimately, we were able to arrive at the right visuals for the various questions and this paper documents and describes a few of the questions and the visuals used to answer those questions. Structuring of data was key to automating the process, and that is also described in this paper.
Novel/Additive Information: The value of raw data decreases exponentially with time. This paper provides an automated process to quickly derive practical usable knowledge from large and messy datasets. The concept of storyboarding as a means to obtain stakeholder buy-in is not readily applied in the drilling industry today and is novel. The structuring of data is also important and it is approached in this project form a post well drilling analysis point of view.
IADC/SPE 189604
Well Integrity: Coupling Data-driven and Physics of Failure Methods
Das, SafeQ Services; R. Samuel, University of Houston
Objectives/Scope: A hybrid model based on Physics of failure and Data-driven algorithms is developed that can estimate remaining useful life of production casing (well barrier) in sour well conditions. The dynamic state of the operational integrity of well is assessed by updating the reliability of well barrier under operational loads.
Methods, Procedures, Process: The interactions between the casing and surrounding formation, and effects of tribocorrosion on the casing are considered. Tribocorrosion is the process of degradation of a material resulting from a sequential process of (i) mechanical wear (due to sliding, friction, or impact) followed by (ii) a corrosive action of the surrounding environment. The model includes simulating casing wear due to drilling, and enhanced degradation due to sour conditions in the well.
Results, Observations, Conclusions: The main capability of the model is to help well integrity analyst with insight of future health states of a monitored well. This is achieved in two main steps; the first being the offline module comprised of degradation models. The second is the pattern recognition based on well log and features mapping, and estimation of remaining useful life of well barrier.
The production casing grade P-110 undergo reduction in strength due to wear during drilling, stress and hydrogen induced cracking. The failure probability of reduced strength of casing changes with time. The remaining useful life is calculated for the depths of interest and time along with 95% confidence intervals. A comparative analysis is carried out using the industry standard soft-string model versus a more comprehensive stiff-string model to estimate wear.
Novel/Additive Information: The paper presents a unique approach to predict the remaining useful life of a well barrier and the dynamic state of the well’s operational integrity. The prediction is not solely based on statistical modeling but also incorporates barrier engineering and physics of failure in the model.
Thursday, March 8 (Tubulars I)
IADC/SPE 189681
The Barlow Equation for Tubular Burst: a Muddled History
A.J. Adams, K. Grundy, C.M. Kelly, Nexen Petroleum UK Ltd; B. Lin, P.W. Moore, U.S. Steel Tubular Products
Objectives/Scope: The Barlow equation for tubular burst is widely used in API and ISO standards, but its provenance and accuracy have never been established: indeed, until very recently, the original reference had been lost to the industry. This has led to doubt and confusion about its use.
This paper presents the work done by ISO TC67 SC5 workgroup 2B to remedy this, and explains the background and technical basis for the upcoming revisions to API TR 5C3 / ISO 10400.
Methods, Procedures, Process: It is shown that Barlow’s 1836 derivation violates the 3D equilibrium condition, and the result is therefore incorrect as originally purposed (a thick wall hoop stress). Moreover, hoop stress is a uniaxial (1D) check: the modern approach is 2D or 3D checking, based on a material failure condition such as Von Mises (VME). However, the result also happens to represent the thin wall approximation to the biaxial (hoop plus radial) VME failure pressure. Remarkably, this does not seem to have been recognized in previous work. The derivation is given, and the assumptions and limitations explained.
Results, Observations, Conclusions: 1) The Barlow equation as originally purposed (a thick wall hoop stress result) is incorrect.
2) Moreover, hoop stress is a uniaxial (1D) check, and modern design requires 2D or 3D stress checking, using a material failure condition such as VME.
3) However, the equation also happens to represent the thin wall approximation to the biaxial (hoop plus radial) VME failure pressure.
4) This is pure serendipity, and does not appear to have been noticed by previous workers.
5) It explains why the Barlow equation, though incorrect as purposed, gives rather good agreement with test results for tubular ductile burst pressure.
6) We have been using the right equation for the wrong reasons.
7) This clears up all the often-heard questions like “why doesn’t Barlow agree with Lamé?”, “is it a thin or a thick wall result?”, “where does it comes from?”, and so on.
8) This brings clarity and confidence to a key area of casing and tubing design.
Novel/Additive Information: The paper gives the background to the new provisions on casing and tubing burst strength shortly to be published in API TR 5C3 / ISO TR 10400. This is essential knowledge for all engineers involved in tubular design.
IADC/SPE 189664
Application of a New Dynamic Tubular Stress Model with Friction
N.R. Zwarich, ConocoPhillips; A.R. McSpadden, M.A. Goodman, R. Trevisan, Altus Well Experts Inc.; R.F. Mitchell, Well Complete
Objectives/Scope: A new dynamic model for casing and tubing design with friction has been developed. This paper applies the model to two field case studies. One is an actual installation of a single-trip, multi-zone intelligent completion in an offshore highly-deviated ERD well. The second case is a horizontal unconventional well with fracture stimulation down the production casing. This is the first application of a comprehensive model with complete friction history to both installation and in-service loads.
Methods, Procedures, Process: The field cases demonstrate results of a novel dynamic model for tubular stress and displacement with changing friction loads. Recorded hookload data during completion running and calibration of effective wellbore friction coefficients provided validation of the model. Accumulation of localized stresses at critical well locations is considered. The sensitivity of worst case downhole forces to the order of operational life cycle loads, including stimulation, production and gas-lift, was assessed. Stresses and displacements associated with each step of the setting process for multiple isolation packers were simulated. Theory and detailed description of the dynamic model are presented in an associated paper.
Results, Observations, Conclusions: A dynamic model of tubing forces is necessary to predict local pipe velocity which in turn determines the magnitude and direction of the localized friction vector. Distribution and orientation of wellbore friction contact is determined by the pipe running events but then is subject to change as cement and packers are set and as downhole operating conditions change. Order of life-cycle conditions such as stimulation followed by production versus production followed by workover has significant impact on the magnitude of forces at worst-case locations. The investigation included the change in tubing-wellbore frictional contact when completion brine is displaced with dry injection gas in conversion to gas-lift. The model demonstrated the significance of a different order of linked operations and showed that the standard available analysis tools may overlook or fail to identify worst-case loads. Potential for acute load localization due to successive stimulation and production events was quantified. Impact of migration of friction loads during cyclical load events was also evaluated. The predicted initial axial load profiles were verified with recorded hook loads and corroborated with standard torque and drag model results. Comparisons are made against a previously published analytical technique.
Novel/Additive Information: For the first time, a dynamic friction model enables seamless integration of running loads into a fully sequential analysis of subsequent well life-cycle loads for landed strings. Current industry models separate installation loads from the in-service life envelope. Ability to predict the changing friction orientation on installed tubulars is significant. Modelling life-cycle loads in true sequence provides more accurate results for tubular design and enables a true analysis on real-world order of well events.
IADC/SPE 189588
Breaking The Performance/cost Paradigm In Drill Pipe Connections In Extended Reach Drilling.
Plessis, NOV Grant Prideco; A. Muradov, National Oilwell Varco; G.R. Brown, NOV Grant Prideco; J. Dugas, B. White, Quail Tools LP; D. Daley, Concho
Objectives/Scope: Various generations of double-shouldered drill pipe connections have been developed in the past 30 to 40 years with performance as a primary driver. The objective was to bring improvements in torque and hydraulics to satisfy drillers’ needs. The record ERD wells could not have been delivered without these technological advancements. The driver for these developments very much improved performances, with limited focus on cost, as these technologies were so enabling that the associated costs were deemed acceptable.
When these same connections started to be used on land rigs to deliver wells in a factory drilling fashion, where cost control is of higher importance, the cost of maintaining these premium connections started to become more apparent. It, therefore, became obvious, that a different approach was needed to meet the combined need for performance, as well as a lower cost of ownership post acquisition.
Methods, Procedures, Process: A comprehensive 2-year research and development (R&D) program was carried out to evaluate various design options. The chosen design allows better control of stress inside the connection. This allows users to benefit from other design features besides the torque and hydraulics of a streamlined connection. The R&D program included numeric simulation and mechanical lab testing. More specific elements of the design allowed more tolerance related to field damage of the connection, less material loss on repairs, and more importantly, a ruggedness so that the connection can remain in the field longer rather than needing to be repaired so often.
The final stage of qualification was a field trial at the manufacturer’s test rig facility. A post field trial inspection confirmed the improved serviceability and ruggedness, qualifying the connection for commercial release.
Results, Observations, Conclusions: The 4th generation double-shouldered connection was first put to task in the Permian basin. A rental string was dispatched to a land rig and used to drill the longest and fastest lateral in the area. The tapered 5 -½ in. by 5 in. drill pipe string, which comes with tool joints of a similar size (this of 5” drill pipe), drilled the well and saved 2 days off the estimated drilling plan. Subsequently, more strings have been deployed, and more data shall be gathered in this paper to demonstrate the low repair rate.
Noel/Additive Information: A new approach has been used to design a connection that performs at high torque levels but also demonstrates improved serviceability and a ruggedness approaching that of an API rotary shoulder connection.
Wednesday, March 8 (Data and Automation II)
IADC/SPE 189626
Operators’ Group, Rig Contractors, and OEM/Service Company
Work to Solve Rig Data Quality Issues
Behounek, Apache Corp.; D.H. Nguyen, ConocoPhillips Co; S. Halloran, Ensign Energy Services, Inc.; M.R. Isbell, Hess Corp.; C. Mandava, Nabors Industries; N. Vinay, Nabors Corporate Services, Inc; J. McMullen, Noble Corporation; C.A. Hoefling, National Oilwell Varco Downhole Tools Division
Objectives/Scope: In the current climate, Operators must reduce drilling costs and are turning to well data analytics, real time advisory, and automation systems to make sustainable improvements. Rig surface sensor data is critical to this drive; however, documented issues with consistent, reliable quality data complicates and delays the value from these systems. The Operators Group for Data Quality (OGDQ) looks to accelerate rapid adoption of key measurement specifications, data storage, transmission, transformation, and integration through an International Association of Drilling Contractors (IADC) contract framework.
Methods, Procedures, Process: The OGDQ worked with both the IADC Contracts and Advanced Rig Technology (ART) committees to advance a standard contract addendum framework as part of the OGDQ efforts to address operational data quality issues and to drive alignment and improvements among Operators, Rig Contractors, and Service Companies.
The paper outlines the process from initial identification of the problem, field verification, developing measurement specifications, constructing contract language, and working with the IADC to reach agreement across organizations. The overall development timeline includes agreement and publication by IADC end 2017.
Results, Observations, Conclusions: Improving the quality of drilling data is essential to personnel at the rig and in the office tasked with decision making in a fast-paced well program and the data driven systems developed to assist in managing well delivery. Rig studies show several cases where Operators independently u
ncovered systematic errors in eight (8) key measurements. Agreement on these data quality practices amongst Operators and with the support from a recognized industry organization is crucial for widespread, quick adoption.
A data quality standard in a contract specification will:
– Set minimum consistent data requirements and quality of delivery across multiple Operators which will enable the ability for Contractors to comply due to less variability on data requirements
– Improve shared data learnings across the industry thereby elevating the industry as a whole, serving as a foundation for the future of automation.
– Allow flexibility by requiring that data quality processes be in place, but without specifying the specific method employed.
– Drive consistency in the data quality framework used with other industry data i.e. LWD and wireline logging data.
Novel/Additive Information: An industry data quality contract specification will have a profound effect on drilling operations. It will become a requirement for sensor quality, calibration, verification, and maintenance. It will significantly enable improved drilling operations, drilling analysis, and ‘big data’ processing by correcting many errors that exist today from poor data quality. The paper will outline the methodology used in the contract addendum and explore some drilling data use cases to illustrate its application.
IADC/SPE 189636
An Algorithm to Automatically Zero Weight on Bit and Differential Pressure and Resulting Improvements in Data Quality
Neufeldt, S.W. Lai, S.D. Kristjansson, Pason Systems Corporation
Objectives/Scope: Weight on Bit (WOB) and differential pressure (DIFP) are critical parameters used to control the speed and efficiency of the drilling process. Improper zeroing (or “taring”) of these parameters can result in significant measurement error which leads to non-optimized drilling. In this paper, we quantify the errors due to improper zeroing practices and present an algorithm which can be used to automatically zero WOB and DIFP.
Methods, Procedures, Process: The current practice of zeroing WOB and DIFP is analyzed on 10 onshore rigs and 36 wells. Matlab is used to find zeroing events in well logfiles, and sensor data is analyzed to determine if the zeroing operation was performed in a consistent manner. Two algorithms are developed to determine the correct time to zero WOB and DIFP based on other rig parameters such as RPM, block speed, and pump rate. These algorithms are applied to the data, and new values for WOB and DIFP are used to determine the average measurement error that occurred due to improper zeroing.
Results, Observations, Conclusions: The results from this paper show that there is a remarkable level of inconsistency when taring is initiated manually by the driller. Analysis of all drilling stands in 36 wells shows that WOB zeroing is performed under proper conditions only 8% of the time, and is not performed on 69% of stands. DIFP zeroing is performed correctly 40% of the time, and is absent for 50% of stands. These findings are significant as drill string weight and hydrostatic pressure change after every stand, and require corresponding recalibrations. Comparison with algorithms that find the ideal zeroing points shows that the average WOB error due to improper zeroing is 18% and 16% in vertical and lateral sections, respectively. The average DIFP error is 18% and 10% in the vertical and lateral, respectively. Deeper inspection reveals that large errors result when drillers forget to zero WOB and DIFP in the vertical, where drill string weight and hydrostatic pressure increase rapidly with depth. Large errors also result when zeroing is performed before block speed and mud flow are at their final values. This is pronounced in the horizontal section where hookload has a large transient range due to strong drag forces within the hole.
Novel/Additive Information: This paper exposes a significant source of measurement error in the drilling process. To the authors’ knowledge, this is the first in-depth study on the non-idealities of the taring process at the rig. The algorithms presented in this paper can be used to (1) improve the quality of real-time data at the rig, and (2) increase the accuracy of historical data used for drilling optimization.
IADC/SPE 189683
Measuring Land Drilling Performance
J.B. Willis, Occidental Oil and Gas Corp; R.A. Jackson, Occidental Oil and Gas Corporation
Objectives/Scope: Managers seek understanding of drilling performance, and visibility of how individual groups contribute to drilling results. A process is described in detail that dramatically improves executive understanding of drilling cost and performance. The principles are applicable to any drilling program (and even other, non-drilling operations), but are best suited to land drilling programs with many wells of a given type.
Methods, Procedures, Process: In this method, a baseline budget is established for each specific type of well. Then, as the program changes, a “revised budget” is created based on the wells actually drilled and currently planned. The monthly “revised budget” measures actual drilling performance against a consistent benchmark. The definition of well types, tracking of costs, adjusting for unusual situations, and calculation techniques to apply the technique are discussed in detail. The “revsied budget” process is used in alignment with traditional operational measures, providing a complete spectrum of performance measures for all levels of the organization. The full range of measures and how they align are discussed.
Results, Observations, Conclusions: The “revised budget” method provides a clear perspective of drilling performance, far more insightful a simple “actual vs budget” analysis. Additionally, deviations from benchmarks are quantified by performance, pricing, and scope changes. These three categories correspond to the organization groups that contribute to performance. The use of the revised-budget technique focuses discussion on the right issues (performance, pricing, and scope) and the right organizational group. Historically, discussion of cost deviations often bogged down in debate over which group was responsible. With the system described, the contribution of each group to results is clearly identified. The process describes performance in terminology familiar to executives, yet still measures drilling performance with sufficient granularity to drive action and results. The “revised budget” technique does not replace, but rather enhances the use of traditional drilling analysis methods such as cost-per-foot, feet-per-day, flat time, non-productive time, and others. Traditional drilling analysis methods are of most value to drilling groups in seeking specific actions that will improve results. The system is the result of 10 years of evolution of measures to manage drilling more than 16,000 wells in the US, South America, and the Middle East. The system has delivered best-in-class performance.
Novel/Additive Information: The novel aspect of the system is that it is a complete system, encompassing a workable benchmark, a process to adapt to the constant changes in the drilling program, a method to identify how each group involved in drilling contributes of to the final cost, and a connection to traditional drilling performance metrics. The “revised budget” technique using granular benchmarks is applicable to many types of operations and solves a chronic budget review problem.
Thursday, March 8 (Managed Pressure Drilling)
IADC/SPE 189645
Design and Manufacture of an Original Equipment Manufacturer Deepwater Managed Pressure Drilling Integrated Solution
Dow, C. Kamps, Schlumberger; J. Baker, Schlumberger Dynamic Pressure Management; S. Likki, C. Guzman, Schlumberger; B.W. Liezenberg, Schlumberger Dynamic Pressure Management; J. Guidry, Schlumberger
Objectives/Scope: Industry deepwater exploration and development continues to encounter complex reservoir challenges, demanding an alternative to conventional drilling. Applied backpressure Managed Pressure Drilling has proven to be a solution suitable for similar challenges on land and shallow water. Some projects around the world have expanded the application to deepwater. The degree of complexity taking this solution to deepwater remains niche, however, with only a few proven cases. To deliver a successful solution, operators have relied on integrating components from multiple providers to ensure a complete solution. The package is customized for each drilling rig, further adding complexity to the integration exercise. Because each component of the system is delivered from separate suppliers, the certification of the system by an appropriate agency must then be approved on a case-by-case basis to guarantee insurability of the offshore drilling unit. Beyond certification, the ability to optimize the package was limited by barriers inherent in a multi-supplier solution.
Methods, Procedures, Process: In 2016, a drilling contractor requested an integrated deepwater MPD package, aimed at adding versatility to their rig fleet. A fully integrated, single Original Equipment Manufacturer solution was designed and manufactured to meet the objective of MPD enablement for a package designed to move throughout the fleet. The design, manufacture, install and system integrity test of all components for two drilling rigs took place over a 12-month period. The system was witnessed and approved by DNV and is due for first field deployment in late 2017.
Results, Observations, Conclusions: This paper describes the complexities of delivering a fully integrated deepwater MPD package, including RCD, riser gas handling system, MPD control system and pressure and flow management hardware as a first artifact with DNVGL OS-E101 classification.
Novel/Additive Information: The solution described is an industry first complete OEM deepwater MPD system.
IADC/SPE 189578
Using Simulator to prepare for Total Loss risk scenarios utilizing Controlled Mud Cap Drilling in the Barents-sea
S.I. Oedegaard, eDrilling; L. Hollman, Blade Energy Partners; G. Smaaskjaer, Lundin Norway AS; E. Claudey, Enhanced Drilling; Ø. Mehus, Oiltec Solutions; T. Andreassen, Maersk Training; J. Nabavi, eDrilling
Objectives/Scope: The objective was to be prepared for Total and sudden loss scenarios in a challenging well in the Barents sea. A dual-gradient Controlled Mud Level (CML) system with Controlled Mud Cap Drilling (CMCD) mode was installed on the rig to handle Total loss scenarios. An advanced dynamic Simulator with the actual well configuration loaded was used to prepare the Drilling team and involved Service personnel for the operation.
Methods, Procedures, Process: Experience from previous wells in the area identified the risk of drilling into carbonate zones and leading to Total and sudden Loss scenarios. An advanced dynamic simulator was used to reflect the details of the CML system to be used. The rig crew together with the CML operator and other involved service personnel was trained on how to handle Total Loss scenarios by going from CML to CMCD mode. All relevant operational procedures was used as a basis for creating scenarios for training and operational preparations for the whole drilling team.
Results, Observations, Conclusions: This paper will briefly present the Simulator set-up, the operation/training procedures and results from the training. Feedback from operation itself will also be described including lesson-learned from utilizing a full-scale dynamic Simulator with the actual well loaded during preparation for operation.
Novel/Additive Information: Drill Well In Simulator with focus on the well behavior with realistic feedback from a novel dynamic downhole simulator integrating a topside equipment simulator.
IADC/SPE 189657
Attenuating Heave-induced Pressure Oscillations using Automated Down-hole ChokingKvernland, M.Ø. Christensen, Heavelock AS; H. Borgen, Techni AS; J. Godhavn, Statoil ASA; O.M. Aamo, S. Sangesland, Norwegian University of Science & Technology
Objectives/Scope: The most important contributor to improved oil recovery (IOR) is the drilling of new wells. To drill in depleted fields with narrow pressure margins, managed pressure drilling techniques (MPD) can be used since they allow annular pressure to be controlled quickly using a control choke installed on the rig. However, there are challenges with MPD when drilling from floating structures since rig heaving brought on by waves induces pressure fluctuations down-hole during connections that may exceed the margins of operation significantly.
To deal with the heave problem described above, it has been suggested that the MPD choke be used to actively attenuate the heave-induced down-hole pressure oscillations. The idea has been investigated theoretically showing that it is possible from a theoretical systems and control point of view, provided one can predict the rig motion, drill string movement and fluid dynamics of the well accurately. An elaborate simulations study of a realistic system was then carried out, revealing severe shortcomings of this approach caused by the combination of the long well with complicated multiphase flow in the annulus and unpredictability of ocean waves.
Methods, Procedures, Process: In this paper, we propose to circumvent these problems by moving sensing, computational, and actuation capability down-hole by developing an intelligent control choke to be installed as part of the bottom-hole-assembly (see Figure 1). The paper consists of three main parts. The first part gives a description of the concept of down-hole choking and shows in detail the design of a small-scale prototype lab along with successful experimental results.
Results, Observations, Conclusions: The second part contains an elaborate numerical model of the coupled dynamics of the flows and drill string, applied to a set of realistic cases. Simulations of down-hole pressure oscillations for the uncontrolled and controlled cases are compared, and requirements of the down-hole choke are identified. Figure 2 shows an example. The upper graph shows the movement of the pipe: in the first orange area, the drill string is tripped out 5 meters; in the purple area, the string is in slips and heaving with the rig, and; in the second orange area, the string is tripped 5 meters in and drilling is commenced. The middle graph shows the down-hole pressure induced by the heave, while the lower graph compares this with the down-hole choking case. Clearly, there is a major reduction in pressure oscillations. The third part of the paper contains a discussion of feasibility of designing a down-hole choke that meets the requirements, including consideration of geometry, materials, power systems, and electronics.
Novel/Additive Information: Down-hole choking seems to be a viable solution for the heave-problem and can provide benefits such as less non-productive-time while waiting for better weather and improved well control and safety.
Thursday, March 8 (Tubulars II)
IADC/SPE 189669
Unlocking Reserves in a Companies Operated High-Pressure Gas Field Through Reliability Based Casing Design
R.A. Miller, R.R. Ramtahal, O. Owoeye, BP
Objectives/Scope: The Shah Deniz project team has looked into increased reserves recovery by lowering the reservoir abandonment pressure below the initial design value. Through a multi-disciplinary approach, design assumptions and equipment ratings were systematically reviewed to determine which aspects factored into the decision to change reservoir management. Collapse loading of the 10 inch production liner was identified as a key variable.
Methods, Procedures, Process: The conventional design factor, a ratio of the design load to the API collapse rating, was deemed to be an insufficient way of characterizing design margin, primarily due to the perception of conservatism in the rating. While design factors are convenient for screening a casing string against an agreed-upon set of inputs and assumptions, there is little insight gained from comparing a 1.03 design factor to a 1.02 other than one value is higher than the other. The team embarked on a scope of work to characterize the probability of collapse as a function of reservoir abandonment pressure using reliability based design.
Results, Observations, Conclusions: Physical testing was conducted to characterize the distribution of collapse resistance and the distribution of dimensional and strength parameters which govern collapse. The quality data sets are combined using the Klever-Tamano limit state equation to indirectly derive a distribution of collapse resistance. The destructive collapse tests provide both a direct measure of the distribution of collapse and a way to calibrate the limit state equation model uncertainty. Both the direct and indirect methods are useful in determining the probability of collapse for a particular load. Load uncertainty was characterized by considering variability of conditions across the wellstock, including depth, temperature and completion configuration. Casing wear was also considered in the assessment.
Novel/Additive Information: This paper outlines the reliability based design methodology used to support the decision to lower reservoir abandonment pressures. Details on how to construct the statistical collapse model are provided along with a discussion on interpretation and continuous improvement activities.
IADC/SPE 189632
Qualification Methodology for Advanced Rotary Shouldered Threaded Connections
Du, F. Song, K. Li, T. Collins*, K. Moriarty**, Schlumberger
Objectives/Scope: A qualification methodology for advanced rotary shouldered thread connections is presented. It covers physical tests on connection prototypes and virtual tests using modeling and simulation techniques.
Methods, Procedures, Process: The methodology has been applied to qualify a high-strength, fatigue resistant thread connection design that was recently developed and released for field testing. The qualification process consists of in-lab makeup and breakout tests, on-rig makeup and breakout tests, sealability tests, fatigue tests, torsional yield limit tests, and tensile capacity tests.
Results, Observations, Conclusions: During the development of the connections, modeling and simulation techniques were extensively used to optimize the design prior to physical prototyping and testing. Some of the qualifications tests, such as torsional yield limit tests and tensile capacity tests, were carried out by using advanced modeling and simulation techniques. Since fatigue tests under nominal loads take a long time to complete, several accelerated fatigue tests under calculated overloads were conducted to assess whether the designed connections would meet the fatigue life requirements with low risk. Once positive results were obtained from the accelerated fatigue tests, fatigue tests under nominal loads required by the product specifications were completed. Based on the qualification results of the connections, it was found that the predicted performance of the connections, such as fatigue life, critical sealing pressure, and breakout torque matched with the physical test results well.
Novel/Additive Information: In the past, numerous rotary shouldered thread connections have been developed in the Oil and Gas industry. However, there has been no formally defined qualification procedure for threaded connections. This paper is the first time to systematically introduce a complete qualification procedure of rotary shouldered thread connections.
IADC/SPE 189670
New Design Limits Plot for Overview of Load-Resistance Relationship in Wellbore Tubular Design
Liu, R. Samuel, A.C. Gonzales, Y. Kang, Halliburton
Objectives/Scope: In the tubular design of oil and gas wells, visualization of the loads and design limits (resistance over design factor) in a single 2-D plot can give well designers a safety-factor overview of a particular string section. This plot is called the design limits plot (DLP). The purpose of this paper is to illustrate the theoretical foundation and construction procedure of a new DLP, which is believed to more accurately represent the safety factors.
Methods, Procedures, Process: The new DLP was built by plotting differential pressure, ΔP, vs. equivalent axial force Feq, for both envelopes (design limits) and load points. Temperature-deration effects were applied to load points instead of envelopes so that the safety factor could be neatly represented by the relative load-point location with respect to the room-temperature envelope. For comparison, the triaxial yield envelope was plotted together with API envelopes (axial, burst, and collapse). Since X-axis values were pressure-dependent in new the DLP, both tension and compression limits could be adjusted, if necessary, to ensure all ‘unsafe’ load points were outside the API envelope.
Results, Observations, Conclusions: The new DLP using Feq [=F_a+min(P_i,P_o )×A_s, where Fa is the true axial force, As is the cross-sectional area, and Pi and Po are the internal and external pressures, respectively] still has the same triaxial yield ellipse as the traditional DLP using the true axial force, Fa, because the latter elliptical envelope is plotted assumingmin(P_i,P_o )=0. The new DLP, however, includes the effects of counter-load pressure (i.e., Pi for collapse load and Po for burst load). Compared with DLPs of ΔP vs. effective axial force, Feff (=F_a-P_i A_i+P_o A_o, where Ai and Ao are the inner and outer circle areas, respectively), the new DLP has a tilted elliptical envelope, which offers a direct reading of the pipe burst/collapse ratings. A field example will be presented that demonstrates the application of the new DLP for wellbore tubular design. It will be shown that for load cases in which counter-load pressures are high, the new DLP represents the safety factors more accurately and comprehensively.
Novel/Additive Information: Using the equivalent axial force instead of the true axial force in the new DLP allows for better consistency with both the von Mises triaxial yield criterion and the API 5C3 2015 addendum. The new DLP not only represents a more accurate overview of safety factors, but also facilitates direct reading of pipe burst/collapse ratings.
IADC/SPE 189693
Premature Failures of Rotary-Shouldered Connections (RSC) due to Improper Re-cut and Repair Procedures
S.R. Koneti, S. Gokhale, T H Hill Associates
Objectives/Scope: Premature failures of rotary-shouldered connections (RSC) resulting from improper re-cut and repair operations performed on used connections can cause immense financial loss to oil and gas operators. One of the reasons for utilization of improper re-cut and repair procedures is the intent of limiting the loss of tool length during thread repair operations. However, this leads in remnant and residual damage which can compromise the connection performance and lead to premature connection failures.
Methods, Procedures, Process: To study the issue, finite element analysis (FEA) modeling was utilized to determine the distribution of the stresses in RSC and to map the stress profile at critical locations which could be affected by improper repair operations. In addition, two case studies where the connections of the components failed prematurely in their first run after the connections were freshly re-cut were investigated. The thread repair protocols and post threading nondestructive inspections were reviewed. Optical and scanning electron microscopy techniques were utilized to characterize the failure mechanism along with the location of the failures. The failures were not located at the last engaged threads of the connection, which is not typical. Both case studies indicated that the residual damage left from the execution of improper thread recut operations had led to the thread failures at non-standard locations.
Results, Observations, Conclusions: The paper presents the case studies, the details of the metallurgical analysis along with the FEA simulation data. The paper lists the various options available for thread repair along with the commercial benefits associated with these repair options in terms of tool length savings. The paper also presents the failure risks associated with the thread repair techniques.
Novel/Additive Information: Additionally, the paper discusses the correct re-cut and repair procedures for RSC along with required NDE inspections that need to be performed after the repair of the connection. By applying and following the recommended repair and inspection protocols, premature connection failures resulting from improper thread repair may be eliminated.
IADC/SPE 189690
Tubular Ratings Used in Well Containment Screening Tool
S.M. Rahman, S.L. Mason, U.B. Sathuvalli, P. Lumley, Blade Energy Partners
Objectives/Scope: One of the items that a drilling operator must submit with the Application for Permit to Drill (APD) to the Bureau of Safety and Environmental Enforcement (BSEE) is the Well Containment Screening Tool (WCST). The screening tool is used to demonstrate that the well is adequately designed to contain an uncontrolled flow.
Methods, Procedures, Process: Worst Case Discharge (WCD) loads are considered as survival loads and the expected design factor is 1.0 for both burst and collapse loading scenarios. Two levels of screening are performed in the WCST. Level 1 screening ensures that the well can be fully shut-in without causing underground flow. Failing Level 1 screening, or if a trapped annulus exists, Level 2 screening is required to ensure that well integrity for an unrestricted flow and subsequent full shut-in are achieved.
Results, Observations, Conclusions: In both Levels, the mechanical integrity of the tubulars is one of the three categories that the WCST does screen. A common mistake when completing the WCST is the incorrect entry of the collapse/burst ratings. The permitting data are submitted via eWell by the operator during the APD process. It is not clear and BSEE does not provide any guidelines of what tubular ratings should be used to account for the effects of downhole temperature. Using manufacturer provided ratings will be less than conservative. The burst rating should be derated for the temperature at the depth of interest the yield strength decreases with high temperature. The collapse rating should be derated not only for the temperature, but also for axial tension, if any at the depth of interest for the WCD load. The temperature derated burst and collapse ratings can be easily estimated when expected WCD temperature is known. The tension derated collapse rating is not easily obtained without a complete examination of the load. The current version of WCST is not adequate for performing this task and lead to a potentially non-conservative conclusion.
Novel/Additive Information: This paper discusses the impact of temperature and tension on the WCD loads and how to use the WCST more accurately.
Thursday, March 8 (Bits and Downhole Tools)
IADC/SPE 189638
Footage in STACK lateral of Oklahoma Increased by 205% Through New Non-Planar PDC Cutter Geometry Development and Implementation
N.J. Lyons, K.T. Izbinski, A. Pauli, D.E. Gavia, Baker Hughes GE; M. Hoffman, B. Cantrell, S. Bryant, Cimarex Energy Co.
Objectives/Scope: The development of improved synthesis techniques for Polycrystalline Diamond Compacts (PDC) positively impacted fixed cutter drill bit performance. Coupled with these advances, recent developments in cutter geometry show improved cutter performance in many applications. Laboratory and field testing has demonstrated that modifying the face geometry of the PDC cutter used in a fixed cutter bit is one of the most direct ways to affect the efficiency and longevity of the bit’s cutting structure. This paper describes a new non-planar cutter face geometry which has increased footage drilled, rate of penetration (ROP), and improved the bit dull condition in the Meramec formation in western Oklahoma’s STACK play.
Methods, Procedures, Process: A drilling mechanics focused team created a finite element analysis (FEA) model of the rock cutting process to optimize cutter face geometry for improved cutting efficiency. The new non-planar geometry allowed for better cutting efficiency, and improved cutter cooling. Multiple lab tests were then used to verify the model’s predictions.
Results, Observations, Conclusions: Results from single cutter lab tests showed an 11% increase in cutting distance as measured in a vertical turret lathe test, a 30% decrease in cutting edge temperature from a pressurized cutting test, and a 10% increase in load capacity compared to a previous non-planar geometry in a face load test. Full scale pressurized drilling tests in the lab showed a PDC bit with the new geometry was 15% less aggressive with equivalent to lower mechanical specific energy (MSE) when compared to the same PDC bit with a previous generation non-planar cutter. Field tests were conducted with the new non-planar geometry applied to a commercial 13mm cutter on a standard 8-1/2 in. drill bit design used in the Meramec Lateral application. The paper reviews in detail three test cases in this multiple bit lateral section using the same bit design with and without the new non-planar cutters. In two test wells, we saw direct improvement of 189% distance drilled on average and 20.5% boost in ROP. At least 17 bit runs have been completed this application using the new non-planar feature proving it to be a beneficial enhancement. Similar performance improvement is being observed in other applications as well.
Novel/Additive Information: The optimized cutter geometry has led to further and faster runs, resulting in significant time savings, and improved consistency. The use of advanced cutter geometries provides a significant boost in drilling performance beyond that normally achieved through fixed cutter bit design optimization and materials improvements.
IADC/SPE 189649
Stabilizer Selection Based on Physics and Lessons Learned
P.E. Pastusek, ExxonMobil Development Co.
Objectives/Scope: The objective of this paper is to share lessons on stabilizer selection with the industry that minimize drilling and tripping problems. Ideally the stabilizers and BHA will drill a round, ledge free hole, without patterns, with minimum vibration, minimum unplanned dog legs, that reach all directional targets in one run per section. They should not constrain ROP, be able to trip in and out on elevators past ledges and hole irregularities without the need for rotation.
Methods, Procedures, Process: These lessons were based on a number of forensics observations while drilling and tripping and a physical understanding of the BHA and its effects on vibrations, trajectory, and tripping in high angle holes.
A draft of these lessons were presented at a SPE Gulf Coast section meeting in 2015 and were sent to all that requested them as well as suppliers used by this operator for comments and suggestions. It is hoped that this publication and the reasoning behind the lessons will help improve this often neglected tool.
Results, Observations, Conclusions: A few significant events initiated this work. The first was a mechanical sticking event in 17 ½ inch hole where the BHA could be rotated and moved downward, but hung up trying to trip out. The formation being drilled at high angle was a vuggy limestone. Inspection of the BHA and stabilizer design found that there was a sharp, 75 degree, transition taper on one of the rotary steerable system stabilizers. This coupled with a formation ledge made it impossible to ream or trip, resulting in a lost BHA and sidetrack.
The second key event was a 6 ¾ BHA that required control drilling to avoid plugging the near bit stabilizer. This showed up as an increase in standpipe pressure and a decrease in an annular pressure gauge located above this stabilizer. The root cause was low bypass area on the near bit stabilizer.
The third event was in 12 ¼ inch high angle hole in soft rock. This required circulation on the trip out of the hole on some wells and not others. The wells requiring circulation on the trip out had high spiral stabilizers that packed off rather than passing the cuttings bed.
Novel/Additive Information: A practical set of lessons have been developed that may be used as a starting point for developing industry best practices. The physics behind these lessons are given so that they can be improved over time.
One improvement expected is the requirement for low coefficient of friction on the stabilizer OD to minimize whirl and on the end tapers to reduce tripping hang up.
IADC/SPE 189671
Novel Drill Bit Technology Combined with System Matcher Increases (Torque) Efficiency and Reduces Stick-Slip and Vibrations
Rahmani, N. Omidvar, C. Hanley, National Oilwell Varco
Objectives/Scope: Performance challenges for deepwater applications from a drill bit standpoint were identified as: (1) high surface torque in salt is an ROP limiter, (2) inability to control depth of cut in soft rocks including shale and salt and when drilling in interbedded formations results in torsional oscillations and stick-slip, and (3) improper combination of bit and reamer induces drillstring vibrations. This paper presents the development of a new set of features and analysis tools to address those problems.
Methods, Procedures, Process: Salt mechanical behavior was evaluated using triaxial testing under confining pressures up to 5,000 psi. Full scale pressurized testing was then conducted to evaluate salt drilling behavior versus rock characteristics. Specific challenges were addressed respectively as follows: (1) non-planar PDC geometries were tested in salt, among other rocks, to identify a geometry which results in maximum increase in ROP at any given torque, (2) new insert shapes were developed and tested for more effective and accurate depth of control, and (3) a full drillstring analysis model was developed with ability to predict downhole and surface torque, WOB, and drillstring dynamics.
Results, Observations, Conclusions: New shaped cutters and inserts were evaluated by full scale pressurized laboratory testing using 8 1/2″ and 9 1/2″ bits in pressures up to 1800 psi. New shaped cutters resulted in an increased ROP/torque ratio in different rock including salt up to 34%. The cutters also increased ROP/WOB ratio up to 42%. The new insert shapes were proved to be more effective in controlling depth of cut, resulting in an extra 35% reduction in torque/WOB ratio compared with standard insert shapes. The drillstring analysis tool was evaluated for different scenarios with or without a reamer. One of the advantages of the software over similar tools is the ability to predict bit and reamer forces for the given application using rock mechanical properties, mud weight, and depth as inputs. The analysis was applied to several field applications including some in the Middle East, North Sea, and Latin America with good correlations versus field data. In one example, the software was used to pair a reamer with the best option between three bits for a given drillstring. In another example, three different BHA configurations were evaluated to identify the best option regarding both drilling performance and vibration control. The new shaped cutters and depth of cut control components are expected to be field tested in the next few months.
Novel/Additive Information: Although the project was focused on deepwater drilling challenges, the novel solutions are applicable to a wide range of applications. The new shaped cutters improved efficiency not only in salt but also in other rocks such as shale, sandstone, and limestone. The new depth of cut control components are not only more effective in homogeneous applications but also reduce the torque fluctuations in interbedded formations by 50%.
IADC/SPE 189592
Mud Hammer Drilling in Hard Formations: Bit Design Improvements Lead to ROP Increase
Gerbaud, Mines ParisTech; R. Souchal, M. Tarek, Drillstar Industries
Objectives/Scope: A novel type of high-power percussive drilling system driven by weighted drilling fluid is presented, together with a method to estimate its potential ROP gain over current rotary drilling methods in a given formation.
Unlike existing, commercial “fluid hammer” systems, the goal of the proposed technology is to provice significantly higher impact power levels, enabling a purely percussive drilling action, similar to air hammer systems.
Methods, Procedures, Process: This new drilling system is based on a down-the-hole hammer, capable of delivering high-energy blows at high frequency. This hammer is fitted with specific drilling bits designed according to the targeted formation type and depth.
Weighted mud is used to power the system, making it directly usable on existing rotary drilling rigs, at any depth and with a wide range of mud systems.
Results, Observations, Conclusions: This new technology showed very promising performances during a field test in hard gneiss in August 2016: average ROP increased fourfold, from 1.1 m/hr on previous roller cone bit run to over 4 m/hr, with comparable bit lifetime. These performances translate into significant savings for the operator : the same footage drilled previously in over 3 days’ rig time can now be completed in less than a day.
The test also proved the new system could be used successfully in a field environment, and offered a very promising outlook on bit and hammer lifetime.
Novel/Additive Information: The presented technology brings some significant advantages over existing drilling technologies for hard lithologies :
– The high power output of this new mudhammer increases ROPs severalfold over existing rotary or semi-percussive systems (‘fluid hammers’).
– The purely percussive action drastically reduces the necessary WOB and Torque levels, as the top drive is no longer the main source of drilling power.
– The wide range of tests performed during this study enabled the development of a semi-empirical model to predict drilling performances in a given formation, based on lithology and geomechanical parameters.
– This model is also used to adapt the hammer bit design to drilling conditions (rock properties, overburden pressure, etc.) in order to optimize rock/bit interaction.
IADC/SPE 189667
Drilling in the Delaware Basin With Shaped Diamond Elements Reduces Vibration and Increases Reaching Target Depth
Phillips, C. Rickabaugh, J. Gray, M. Savage, Baker Hughes, a GE Company; J. Ramsey, Anadarko Petroleum Corp
Lateral stability at low depth-of-cut (DOC) has been a key factor affecting the durability and performance of polycrystalline diamond compact (PDC) bits. This paper describes how Shaped Diamond Element (SDE) technology proven in the laboratory and in Delaware Basin well construction can increase stability and boost performance with 66% improved footage while drilling 40% faster. The technology enables modifications to the cutting structure that changes the PDC bit stability response, controlling lateral instabilities.
Methods, Procedures, Process: Full bit laboratory testing was used to measure a PDC bit’s lateral stability during drilling. An experimental, intentionally unstable 8.75-in. 6 blade PDC bit frame was designed as a baseline for testing, and a second bit with the same basic frame was built incorporating the SDE technology. Tests were run to examine the effect of exposure and number of shaped diamond elements on the bit’s stability. The bits were tested at atmospheric pressure, in different rocks to indicate their response in soft and hard formations. The learnings from these tests were then applied to an 8.75-in. 7 bladed PDC bit for use in the Delaware basin. The SDE field test bits were equipped with in-bit sensing to confirm the benefits in operation that were observed in the laboratory test. Data from their runs are compared with offsets to quantify the benefit of the SDE technology over a number of months.
Results, Observations, Conclusions: During laboratory tests in a soft limestone an instability boundary line was determined at 33%, with a higher value indicating a more unstable bit. The baseline bit started at 36% indicating instability at low depths of cut and reached 100% with increasing DOC. The SDE bit designed for early engagement remained stable through the entire test independent of depth of cut achieving a 1% instability level. To establish the design criteria to maximize the stability benefits, the bits were tested with varying number of strategically placed SDE, and varying DOC. During the field runs with this technology, the results indicated an improvement in dull conditions increasing target Depth rate by 26% and increasing the distance drilled by 29%. In one particular case, comparisons of the vibration data from the in-bit sensor showed a 42% reduction in drilling dysfunctions for this given interval, on consecutive wells on the same pad. The reduction in vibration reduced cutting structure damage yielding an increase in rate of penetration (ROP) by 40% and footage by 66% over offsets.
Novel/Additive Information: These dysfunctions associated with lateral instability are increasingly recognized as the most damaging to the bottom-hole assembly (BHA), and it is important that they are mitigated or controlled. The drilling costs and efficiencies today are significantly important; they are the key to reduce any non-productive time (NPT). As the field data demonstrates, shaped diamond elements which engage and cut the rock, can provide stability benefits that improve the bit’s durability without reducing the bit’s performance.
Thursday, March 8 (Case Studies II)
IADC/SPE 189688
Real-time Quantitative Composition Of Formation Fluids While Drilling
Colombel, N. Guerriero, M. Ringer, Schlumberger GSS
Objectives/Scope: Mud-gas technologies for continuous PVT like analysis of reservoir fluids in the drilling mud require the determination of the extractor efficiency for the specific mud system in use. Until now, this was only available at the end of each drilled section. A new calibration process was developed to determine this efficiency ahead the drilling starts, enabling the real time delivery to the operator of the formation light fluid composition while drilling.
Methods, Procedures, Process: The efficiency of the hydrocarbons extraction is different for each drilling mud, thus a calibration process is required during each drilling phase or whenever the mud significantly changes. The current process requires a sample of drilling mud that contains significant traces of alkane. Traditionally, this sample is collected while drilling during a gas peak and stored until the end of the phase, when the calibration can be performed. In the new procedure, a Calibration Mud sample is created, by injecting and emulsifying several alkanes into the mud. The calibration is then performed at any time, especially before drilling has started.
Results, Observations, Conclusions: It is extremely difficult to inject and dissolve gaseous light hydrocarbons into a mud sample at the rigsite. For this reason, we inject a sample of six liquid alkanes into the mud and emulsify it to represent a mud sample containing fluid from the formation. The calibration coefficients for the lighter gas alkanes are then extrapolated using a model of the extraction process.
The new calibration process was first field tested in Brunei. During this test, both the new calibration process and standard calibration (performed at the end of the phase using mud collected while drilling) were performed. Validation of the new technique comes from ensuring the coefficients using our new calibration mud match those coming from the standard calibration. The results were conclusive with similar coefficients obtained. The uncertainty intervals overlap and thus results match: calibration coefficients are statistically equivalent. These results have been confirmed several times during additional field tests performed in Saudi Arabia and in Brazil in a number of wells and with multiple operators.
Thanks to these new calibration procedure, it is now possible to provide PVT like compositional analysis from reservoir fluid in real time.
Novel/Additive Information: The new calibration procedure represents an innovative methodology enabling real-time continuous PVT like analysis of the light hydrocarbons content (C1-C6) of the reservoir fluid entrapped in the drilling fluid, measured at surface. This is the first time that such data can be delivered in real-time. The delivered dataset may have a tremendous impact on several applications like geosteering and well placement and provide most of its benefits once integrated with downhole tool measurements.
IADC/SPE 189616
Measuring Drilled Cuttings and Fluid Recovery by Real Time Mass Balance
B.E. Smith, S. Grubb, M.B. Smith, WellWORC; J.G. Eller, J. Connelly, ConocoPhillips
Objectives/Scope: A mass balance method of calculating drilled cuttings recovery and fluid loss/influx is presented. Field results are shown that illustrate hole cleaning effectiveness, hole enlargement, and wellbore breathing.
Methods, Procedures, Process: A drilling fluid system including mass flow and density meters on the inlet and outlet of the circulating system is used to continuously measure and trend drilling fluid density, flow rate and drilled cuttings recovery. Drilling fluid density measurements of the inlet and outlet flow streams are compensated for temperature and pressure and then used to calculate cuttings recovery based on the drilled rock bulk density. Mass balance calculations also account for drill string fluid displacement and fluid seepage/loss/influx across the face of the borehole.
Results, Observations, Conclusions: Measuring drilled cuttings and fluid recovery by continuous mass balance has been performed successfully in Alaska North Slope drilling programs. More than 100 horizontal lateral wellbores have been measured for drilled cuttings and fluid recovery. The cuttings recovery ratio is the calculated recovery volume divided by the volume of hole drilled and trends hole cleaning performance. Calculated values of cuttings and fluid recovery continuously trended with time and hole depth illustrate the effectiveness of wiper trips, mud carrying capacity, and fluid loss/influx. Cuttings recoveries are a small fraction of the total mass of the circulating system, therefore accurate metering and methods to establish meter bias factors are essential to achieve consistent results. Correlations to excess cuttings recovery and lithology have been made and can lead to understanding drill string weight transfer issues and wellbore competency. Mass balance of the borehole circulating system is independent of pit volumes, and clearly identifies fluid loss and influx intervals and subsequent changes in fluid loss and influx rate.
Novel/Additive Information: Real-time mass balance enables Drillers to associate drilling system performance and wellbore responses:
• Associate cuttings recovery with lithology, drill string toque and drag, ROP, ECD, circulating pressures, and other drilling parameters.
• Low cuttings recovery infers that the drilling circulation system is not adequately cleaning the hole.
• Excess cuttings recovery infers that insufficient wellbore competency is resulting in hole enlargement.
• Fluid circulation and recovery measurements identify losses, influx, and wellbore breathing independent of pit volume monitoring.
IADC/SPE 189601
Improving Surface WOB Accuracy
Kyllingstad, K. Thoresen, NOV
Objectives/Scope: Weight on bit (WOB) is a key variable in the drilling process. Normally it is calculated as the difference between a constant off bottom hook load and the actual hook load. This study evaluates the accuracy of this widely used method and presents new methods for improving the accuracy by applying corrections for various systematic errors.
Methods, Procedures, Process: The study presents mathematical models for how the buoyant string weight varies as a function of many variables, such as axial string speed, rotation speed, mud density and flow rates. Consequently, the reference string weight, also called tare weight, is not a constant but can change significantly after a so-called WOB zeroing procedure. Many of the parameters used in the various correction formulas are uncertain and need to be found experimentally. The paper also describes suitable calibration tests for determining these parameters.
Results, Observations, Conclusions: The paper presents both theoretical results and field test results. The theoretical results include many numerical examples quantifying the various errors that can be modelled and corrected for. Not unexpectedly, the biggest errors arise in sliding drilling where that axial well bore friction has a large influence on the string weight and thereby on WOB. The field test results include comparisons of raw (uncorrected) surface WOB, improved, corrected WOB and downhole WOB measure by a downhole WOB sensor. The conclusion from this is that the corrected surface WOB is far more accurate that the simple surface WOB, and sometimes it is even more accurate than downhole WOB. The relatively poor accuracy of the downhole sensor is probably due internal stresses coming from inner and outer temperature differences in the sensor sub.
Novel/Additive Information: The study shows that the simple but commonly used surface WOB suffers from many systematic errors that can be corrected for. By applying the dominant corrections, the improved surface WOB estimate is far more accurate than what is seen today, especially in sliding drilling.
IADC/SPE 189653
Reducing Stick-Slip by Avoiding Auto-Driller Control Dysfunction
D.W. Adam, Occidental Petroleum
Objectives/Scope: Analysis of historical drilling data revealed stick slip was being initiated by the rig control system when drilling off the differential pressure limit. It was determined through offset analysis that a weight-on-bit road map delivered near-maximum rate of penetration (ROP) and significantly reduces stick-slip by avoiding differential pressure control. Details of the statistical analysis process and results from use of the road map will be presented and compared to historical performance in the New Mexico Delaware Basin.
Methods, Procedures, Process: The road map is developed from top performing offset wells. The standard deviation of the auto-driller’s active control limiters (weight-on-bit (WOB), torque, or differential pressure) is cross-plotted against the standard deviation of the ROP. Intervals in which the differential pressure was the primary control limiter display a high standard deviation, indicating unstable control behavior which translates to dysfunction at the bit. The desired WOB range for the formation interval is the moving average WOB plus the maximum deviations of the non-dysfunctional areas. Operating with slightly reduced WOB maintains slightly lower torque and consequently reduces the need to control mud motor differential pressure.
Results, Observations, Conclusions: The results from the using the parameter road map will be compared to high-performing offset wells. The comparative analysis will focus on ROP, mechanical specific energy (MSE), downhole shock, vibrations, and bit damage. Performance in formations known to cause dysfunction will be highlighted. A dramatic reduction has been observed in the downhole shock and vibration data when compared to the offset wells. Actual depth-of-cut and ROPs through the intermediate interval were not significantly different compared to offset wells which used maximum WOB, limited by differential pressure. Traditional auto-driller limiters (torque and differential pressure) were able to be in the “off” position due to the limits of the system being taken into account in the determination of the road map. Data is presented showing that differential pressure control causes dysfunction due to the increased sensitivity on the proportion-integrating (PI) auto-driller controller. A road map based on realistic maximum WOB for defined areas, delivers similar ROP, but longer bit life due to reduced dysfunction.
Novel/Additive Information: The novelty of the road map is its ability to replicate best demonstrated performance and accelerate the learning curve through a data-driven process. The statistical analysis identifies specific sources of dysfunction and delivers more optimal WOB guidance. The overall system is a step toward more robust automatic control of auto-drillers.
