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.
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.
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.
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.
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.
Utilizing azimuthal gamma imaging, continuous inclination, and downhole bending moment measurements to understand thinly layered shale lithology while maintaining the wellbore within the target formation has led to improvements in placement and drilling time reduction. A close examination of this approach in six wells in the Midland Basin demonstrates that utilizing a stabilized bottom-hole assembly (BHA) while drilling horizontally can result in a ‘locked-in’ phenomenon from contrasting hardness of the layers immediately above and below the wellbore. With proper interpretation of real-time downhole measurements, drillers are able to keep the well path in the target zone with minimal slide drilling. The ‘locked-in’ phenomenon was used most effectively in the Wolfcamp A formation where the thin beds are homogenous and laterally continuous. The phenomenon could not be leveraged as effectively in the Wolfcamp B, whose geology is a product of higher energy deposition when compared to the Wolfcamp A.
Maidla, Eric (ProNova - TDE Petroleum Data Solutions, Inc.) | Maidla, William (ProNova - TDE Petroleum Data Solutions, Inc.) | Rigg, John (ProNova - TDE Petroleum Data Solutions, Inc.) | Crumrine, Michael (ProNova - TDE Petroleum Data Solutions, Inc.) | Wolf-Zoellner, Philipp (ProNova - TDE Petroleum Data Solutions, Inc.)
The authors have been contacted by many people in the industry lately that are incorrectly utilizing big data to produce correlations that attempt to identify operational "sweet spots". This paper will show examples and address the need to add several steps to big data before any meaningful correlation results can be obtained, mainly understanding (and this is not a comprehensive list): The sensors involved and their limitations; The errors in the placement of these sensors (e.g. hook load sensor on the deadline); The frequency of the data and how this impacts the analysis (some companies provide 10-second data); The quality of the data itself; The appropriate filtering of data to ensure apples-to-apples comparisons; The rig state must be known Understanding of the physics involved.
The sensors involved and their limitations;
The errors in the placement of these sensors (e.g. hook load sensor on the deadline);
The frequency of the data and how this impacts the analysis (some companies provide 10-second data);
The quality of the data itself;
The appropriate filtering of data to ensure apples-to-apples comparisons;
The rig state must be known
Understanding of the physics involved.
A model of the diffusion of methane into a wellbore in overbalance with Oil Based Mud is described. In some situations, methane diffusion may 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 off-shore well in the North Sea, showing promising agreement with the model.
The tools used are: a) a 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, and 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 measuring the amount of C1 through C5 continuously. The measurements were analyzed using a PVT simulation program.
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 a 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.
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.
Fluid-shale compatibility testing is as old as the drilling fluid industry itself, and remains a highly relevant topic as drilling applications explore new, more complex territory. Incompatibilities of fluids with clay-rich shale formations can lead to a plethora of operational problems, ranging from minor dispersion and accretion issues to major stuck pipe and production impairment events. The nature of fluid-shale interactions has confounded scientists since the birth of the drilling fluid industry, and has led to a variety of different test methods and protocols, many now decades old. The question remains: what are the best, most representative fluid-shale compatibility tests to characterize fluid-shale interactions and avoid making costly mistakes based on misleading test results?
Historical fluid-shale compatibility tests are often severely limited by over-emphasizing the role of clay swelling behavior, by not paying attention to shale sample condition, and by not being specific with regard to the intended purpose. Test selection is often based on a superficial assessment of the "reactivity" of the shale, and results are indiscriminately applied whether the intended purpose is maintaining cuttings integrity, promoting borehole stability or avoiding reservoir incompatibility to name a few. This paper points out the various pitfalls and problems associated with conventional tests such as atmospheric swelling tests and capillary suction time tests, which still find wide-scale application in the oil and gas industry. A case is made to abandon such tests in future. New sets of tests are proposed that may overcome the drawbacks of the conventional tests. These tests are also conducted with a clear purpose in mind. For instance, to evaluate borehole stability, it is argued to forego traditional swelling tests and instead focus on triaxial failure testing, mud pressure transmission testing and borehole collapse testing. The latter can be accomplished with a novel, low-cost alternative to the downhole simulation cell test in the form of a modified thick walled cylinder test. This new test exposes 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.
Recommendations for shale characterization and to investigate fluid shale interactions relevant to shale cuttings integrity, borehole stability and reservoir compatibility for conventional and unconventional reservoirs are given here. The tests are illustrated with representative results obtained for novel mud systems such as high-salinity fluids and muds containing nano-particles. Recommendations with respect to applying laboratory results to field operations are provided.
Behounek, M. (Apache Corp) | Nguyen, D. (ConocoPhillips) | Halloran, S. (Ensign Energy Services) | Isbell, M. (Hess Corp) | Mandava, C. (Nabors) | Vinay, N. (Nabors) | McMullen, J. (Noble Corporation) | Hoefling, C. (NOV)
In the current economic climate Operators must reduce drilling costs, so they are turning to well data analytics, real-time advisory, and automation systems to make sustainable improvements (
For this paper, the OGDQ worked with Rig Contractors and an OEM/Service Company to advance recommended data quality components in work processes and commercial agreements. By bringing transparency to the process, the authors hope to contribute to the efforts to address operational data quality issues and to drive alignment and improvements among Operators, Rig Contractors, OEMs, and Service Companies. This paper outlines an approach to putting data quality into practice, including initially identifying the problem, field verification, developing key measurement specifications, constructing framework components, and anticipating management of change issues.
Quality drilling data is essential to both rig and office personnel who are tasked with decision making for fast-paced well programs. Quality drilling data is also essential for the data-driven systems developed to assist in managing well delivery. Rig studies show several cases where Operators independently uncovered systematic errors for 10 key measurements used for drilling process decision making ( Rotary/Top Drive Torque Joint Makeup/Breakout Torque Hookload Rotary/Top Drive Rotational Speed Stand Pipe Pressure Drilling Fluid Pump Rate Drilling Fluid Tank/Pit Volume Drilling Fluid Density Drilling Fluid Viscosity Block Position
Rotary/Top Drive Torque
Joint Makeup/Breakout Torque
Rotary/Top Drive Rotational Speed
Stand Pipe Pressure
Drilling Fluid Pump Rate
Drilling Fluid Tank/Pit Volume
Drilling Fluid Density
Drilling Fluid Viscosity
Widespread agreement on data quality practices among Operators, Rig Contractors, OEMs, and Service Companies is crucial for their quick adoption, and an industry-wide approach has a profound effect on drilling operations. Widely adopted practices will support and drive requirements for sensor quality, calibration, field verification, and maintenance. This standardization will, in turn, significantly enable improved drilling operations, drilling analysis, and big data processing by correcting many errors resulting from poor data quality. This paper outlines the methodology used to develop a guide for commercial drilling components, and illustrates the application of this guide with selected drilling data use cases.