Dupal, K. (Shell International Exploration and Production Inc.) | Curtiss, J. P. (Shell International Exploration and Production Inc.) | van Noort, R. H. (Shell International Exploration and Production Inc.) | Mack, C. (Shell International Exploration and Production Inc.) | Greer, S. (Stena Drilling)
Operations were being conducted with a drill ship in deepwater, harsh environment conditions offshore Nova Scotia. After securing the well, the rig disconnected the Lower Marine Riser Package (LMRP) from the lower Blow Out Preventer (BOP). After disconnecting, dynamic loads caused an uplift of the marine riser, ultimately resulting in a failure of the tensioner ring support and loss of the riser/LMRP to the seabed. No personnel were injured in this incident and no spilling of synthetic base mud to the environment occurred. This paper provides a summary of the root causes and contributing factors for the incident.
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)
Moonpool video camera recording of riser and tensioners during and after disconnect
Analytical models for vessel & marine riser dynamics, including the riser tensioner anti-recoil system
Rig/moonpool geometry, riser tensioner ring design, and space-out
Based on initial findings, further studies and analyses were conducted to better understand the dynamic behavior during the transition phase from initial disconnect to the hang-off position.
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 two barriers, a storm packer and closed 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 ring and landed back onto the tensioner ring off-center. This uneven loading caused the tensioner ring halves 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 adding additional air to tensioner system and re-setting of the Riser Anti Recoil System (RARS) prior to final hang-off condition. Contributing factors included the dynamic behavior of the riser and a lack of specific procedures for addressing the dynamic system conditions during the critical transition phase.
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.
Dooply, Mohammed (Schlumberger) | Sianipar, Sakti (Schlumberger) | Rodriguez, Faiber (Schlumberger) | Poole, David (Chevron) | Fuenmayor, Cesar (Chevron) | Carrasquilla, Juan (Schlumberger) | Rosero, Ivan (Schlumberger)
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.
Cementing tight annulus normally requires managing high placement pressures within the tubulars mechanical limits. Field measurements from case studies in Gulf of Mexico, were analyzed comparing 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 contaminated mixture also provided an input for better interpretation of cementing surface pressure response. These analyses, including estimating hook load variations while cementing, allow selection of appropriate fluid placement rate without exceeding the mechanical limits while also achieving effective fluid displacement.
Comparison analysis of measured and simulated data shows that use of 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 in deepwater drilling environment.
Liu, Chao (Aramco Services Company: Aramco Research Center-Houston) | Han, Yanhui (Aramco Services Company: Aramco Research Center-Houston) | Abousleiman, Younane (PoroMechanics Institute, University of Oklahoma)
The recently formulated theory of dual-porosity dual-permeability porochemoelectroelasticity is applied to derive the analytical solutions for an inclined wellbore drilled through a shale formation, accounting for the effects of natural fractures and shale chemical activity (
The analytical solution is applied to study two field cases. The Hoek-Brown failure criterion is employed to evaluate wellbore collapse and mud densities. The two case studies indicate that the analytical solution explains the wellbore failure and is capable of predicting the used safe drilling mudweight. Back analysis on the field data with a sensitivity study is able to estimate the range of the fracture permeability once the matrix permeability is defined.
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). 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.
Due to the highly dynamic and transient nature of the cleanup process, the use of a dynamic simulator was required to effectively capture the physics of the concurrent flow of the various phases present in the system. An extensive modelling 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 distributions in the wellbore. The constrained flowrate cases were considered to represent the constraint on the rig (restricted because of surface handling capacity issues).
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.
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.
Mud cake evolution and plastering have been identified as important wellbore strengthening mechanisms. They serve to reduce losses through pore throats and fractures, while impeding the growth of induced fractures. Recent experimental and analytical studies have also revealed the complexities in drilling fluids’ invasion profiles and mud cake buildup. These complexities arise from the changing wellbore conditions observed in an actual field scenario. It is important to investigate the effects of these conditions on drilling fluid invasion for near-wellbore strengthening application.
To achieve this goal, some dynamic wellbore conditions which are close-to-real field conditions were simulated in a controlled laboratory setup. The following conditions were investigated: rotary speed, temperature, type of lost circulation material (LCM), concentration of LCM, differential pressure, eccentricity, rock permeability, and fracture width. In the experimental setup, the geometry of the shaft that simulates drill pipe rotation allowed for mud cake evolution and plastering around the inner diameter of the thick-walled cylindrical porous media. Water-based mud (WBM) recipes were formulated for different porous media types. The rheological profile for each mud recipe was investigated for operating temperature limit. Dynamic drilling fluid invasion experiments were conducted with thick-walled cylindrical Buff Berea sandstone, Upper Grey sandstone, and fracture slots with varying widths.
The results indicate that temperature, rock permeability, fracture width, and LCM type and concentration are the most influential factors that control dynamic fluid invasion profiles. Increase in granular LCM concentration at elevated temperature is not completely effective in reducing pore-scale fluid invasion. Spurt invasion, rock porosity, permeability, and fracture width are important determinants of mud cake evolution. Increase in fiber LCM concentration showed effective mud cake evolution in the fracture slots. The results from testing mud cake stability revealed mud cake rupturing on three experiments out of the nine that were performed. The novelty in this approach is the use of thick-walled cylindrical cores and fracture slots to profile dynamic fluid invasion of different fluid recipes. Pressure, temperature, and pipe rotation were combined to simulate wellbore conditions under which fluid loss, cake growth, and plastering occur. This approach can be used in drilling fluid design for minimizing fluid loss, cost, and selection of operating conditions.
Over the past three years, the oil and gas industry has experienced its deepest downturn since the 1980s. Recovery has been slow, setting the deepwater industry at a strategic inflection point where step changes are necessary to remain competitive. Considering that deepwater upstream capital projects are some of the most expensive projects in the industry, capital costs on a per well basis must be reduced in order for deepwater to continue to attract capital. Achieving operational excellence by embracing the big data revolution will help answer the challenge in thriving in a low-cost oil environment.
Oil and gas operators as well as others suffer from data overload. A major challenge in the process of achieving operational excellence is to find a way harness big data and capitalize on its benefits. The paper outlines the solution that a major operator and service company developed that established a unique well construction optimization process, improved consistency and moved every operation closer to the technical limit.
The solution was developed for the major operator in Gulf of Mexico (GOM) deepwater fleet and was successful in reducing the well cycle times by: Applying a unique approach and workflow to transform big data into usable knowledge and enable critical thinking in the process of data analysis. This led to challenging current established operational procedures, making adjustments to actual well conditions and maximizing the efficiency of the rig. Enhancing a standard set of key performance indicators (KPIs) so that each operation is measured and the performance is understood. Establishing an effective in-house real-time data analysis center that fully supports the integrated drilling teams in order to drive data-driven decision making. Utilizing concise visualization of surface digital data so that clarity from the data can be gained and insights communicated to the rig teams.
Applying a unique approach and workflow to transform big data into usable knowledge and enable critical thinking in the process of data analysis. This led to challenging current established operational procedures, making adjustments to actual well conditions and maximizing the efficiency of the rig.
Enhancing a standard set of key performance indicators (KPIs) so that each operation is measured and the performance is understood.
Establishing an effective in-house real-time data analysis center that fully supports the integrated drilling teams in order to drive data-driven decision making.
Utilizing concise visualization of surface digital data so that clarity from the data can be gained and insights communicated to the rig teams.
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 existing 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 perfect 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.
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.
These workflows and tolerances have been implemented in three horizontal wellbores traversing seven same-formation pre-existing horizontal wellbores. The anti-collision method was 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.
The methods 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.
Stefánsson, Ari (HS Orka) | Duerholt, Ralf (Baker Hughes, a GE company) | Schroder, Jon (Baker Hughes, a GE company) | Macpherson, John (Baker Hughes, a GE company) | Hohl, Carsten (Baker Hughes, a GE company) | Kruspe, Thomas (Baker Hughes, a GE company) | Eriksen, Tor-Jan (Baker Hughes, a GE company)
The typical rating for downhole measurement-while-drilling equipment for oil and gas drilling is between 150°C and 175°C. There are currently few available drilling systems rated for operation at temperatures above 200°C. 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 300°C. It also describes the development and testing of a 300°C capable measurement-while-drilling platform.
The development of 300°C technologies for geothermal drilling also extends tool capabilities, longevity and reliability at lower oilfield temperatures. New technologies developed in this project include 300°C drill bits, metal-to-metal motors, and drilling fluid, and an advanced hybrid electronics and downhole cooling system 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. The US Department of Energy Geothermal Technologies Office partially funded the project.
The use of a sub-optimal drilling system due to the 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 300°C drilling system. It describes successful laboratory testing of individual bottom-hole-assembly components, and full-scale integration tests on an in-house research rig. The paper also describes the successful deployment of the 300°C drilling system in the exploratory geothermal well IDDP-2 as part of the Iceland Deep Drilling Project. The well reached a measured depth of 4659m, by far the deepest in Iceland. The paper includes drilling performance data and the results of post-run analysis of bits and motors used in this well, which confirm the encouraging results obtained during laboratory tests. The paper also discusses testing and performance of the 300°C rated measurement-while-drilling components – hybrid electronics, power and telemetry - and the performance of the drilling tolerant cooling system.
This is the industry's first 300°C capable drilling system, comprising metal-to-metal motors, drill bits, drilling fluid and accompanying measurement-while-drilling system. These new technologies provide opportunities for drilling oil and gas wells in previously undrillable ultra-high temperature environments.
In the tubular design of oil and gas wells, visualization of the loads and design limits (resistance over design factor) in a single 2D plot can help provide well designers a safety-factor overview of a particular string section. This plot is called a design limits plot (DLP). This paper illustrates the theoretical foundation and construction procedure of a new DLP, which is believed to more accurately represent safety factors.
The new DLP was built by plotting differential pressure, ΔP, vs. equivalent axial load Feq (= Fa +
A field example is presented that demonstrates the application of the new DLP for wellbore tubular design. It is shown that, for load cases in which counter-load pressures (which are defined as
Using the equivalent axial load instead of the axial force in the new DLP allows for better consistency with both the von Mises triaxial yield criterion and the
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.
In order to build a comprehensive real-time data analysis tool for managing the fluid in the well, three groups of parameters were identified as essential for monitoring: surface fluid flows and volumes, surface and downhole drilling parameters and formation properties, and gas events in the wellbore and at the surface. Eight capabilities were created to aid the monitoring of the identified key parameters. These capabilities depend on a number of integrated algorithms and displays that operate within a realtime data platform and were designed to utilize measurements in real-time as well as relevant well construction information. The primary aim is to provide a medium for visualization of events and informative trends, along with alerts when parameters fall outside 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. The software tool was developed and tested over three years and trialed in 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.