Xue, Qilong (China University of Geosciences-Beijing) | Huang, Leilei (China University of Geosciences-Beijing) | Wang, Jin (China University of Geosciences-Beijing) | Li, Lixin (Chinese Academy of Geological Sciences) | Liu, Baolin (China University of Geosciences-Beijing)
Drillstring vibrations are an important cause of premature failure of drillstring components and drilling inefficiency, in particular, torsional vibration is more important. A large amount of research on torsional drillstring vibrations has been conducted in the last few decades. Stick/slip is a severe type of torsional drillstring oscillation that affects the efficiency of the drilling process and can cause bit damage as well as drillstring failure.
For rotary steerable system (RSS), the stick-slip vibration is introduced as a new mechanism to explain the large amplitude torsional oscillation of the drillstring. we aim for an improved understanding of the causes for torsional vibrations in RSS and torsional vibrations with and without stick-slip are observed.
We show that the RSS implementing agencies pushing the borehole wall caused the drill bit torsional vibration more serious. The results contribute to the better understanding of the dynamics of the push-the-bit RSS. Chaotic vibration is mainly caused by elasticity of the drillstring and changing frictional forces at the bottom tool, static frictional forces are higher than the kinetic frictional forces which make the bit act in a manner where it sticks and then slips, and presents complex dynamic behavior, which makes down-hole dynamic responses difficult to predict.
In the Rotary Steerable System (RSS), frictional force between the pads and borehole wall will make the drill bit instantaneous rotational speed reduces. The pads of the implementing agencies in RSS constantly pushed against the borehole wall, making bottom hole by a cycle of nonlinear damping force, which is lead to the bottom drilling tool movement of chaos and disorder.
Drilling systems automation requires a downhole digital backbone for closed-loop control, as do many other real-time drilling, completion and production operations. The absence of a reliable, high data bandwidth, bi-directional communication method between surface and downhole is a barrier to digitalization and automation of the oil field. This paper describes the development and successful drilling field trial of a micro-repeater wired pipe – effectively "smart pipe" – that removes this barrier.
The developed system uses battery-powered micro-repeaters (a fail-safe signal booster) placed within the box of each tubular and fully encapsulated dual RF-resonant antennas to transmit data between tubulars. The current system delivers 1-Mbps backbone data rate with a maximum payload of 720 kbps, and with a very low latency of 15 μsec/km, making it ideal for control-loop applications. The system design focusses on reliability: failure of multiple components will not affect telemetry. The prototype system has been rigorously field tested during drilling in Oklahoma.
Testing occurred on a drilling rig in Beggs, Oklahoma. The first trial (2016) covered drilling operations, the second (2017) covered controlling downhole technology; both were successful. The drilling trial demonstrated fitting the system to pipe with conventional API connections, standard rig-floor pipe handling, reliable wireless transmission between surface receivers and wired pipe network, the use of multiple along-string measurements of temperature and vibration, and simulated component failure. Of particular note was the surface system: it is wireless and no modification to the drilling rig was required.
Conventional tubulars can be refit with the system, which removes a barrier to the use of wired pipe for automation and LWD/MWD measurements in lower cost onshore operations. There is a benefit for drilling operations: all pipe joints contain a micro-repeater and are addressable for "smart pipe" applications such as an electronic pipe tally, and pipe condition monitoring. Drilling operations are the first users of the system, but it serves other operations, for example tubing conveyed wireline operations. The smart wired pipe concept is truly innovative. It enables drilling systems automation and logging-while-drilling applications, such as seismic-while-drilling with along-string sensors, by providing a fully open acquisition and control platform to the industry.
Estimating hydraulic frictional loss in narrow annuli is challenging, especially for deepwater offshore wells with extremely narrow drilling margins. The challenge arises from annuli that are formed by big bore packers like Gravel Pack Packers, where the annular clearance isextremely small. In cases where open hole completions are run with MPD (Managed Pressure Drilling), the well typically would be displaced to heavier weight fluids before the packer is set and MPD is isolated. This paper illustrates the complications and limitations for estimating friction loss due to the narrow annuli when using drilling hydraulic programs.
Accurate estimation of hydraulic friction loss is extremely essential when using MPD system to maintain BHP(bottomhole pressure) while drilling, tripping, cementing etc. While drilling, the hydraulic models would typically be calibrated to PWD (pressure while drilling) in the BHA (bottomhole assembly), but when running liners, casings or completion systems, the lack of PWD complicates hydraulics and friction loss estimations. This phenomenon is accentuated when displacing the well from lighter drilling fluids to heaviercompletion fluids,especially when the completion fluid reaches the narrow annuli and displays sudden increase in frictional loss value due to the hydraulic model limitations.
This paper focuses on the limitations of estimating the frictional loss in narrow annulus created by the Gravel Pack Packers,when predicted using the drillinghydraulicmodels, and proposes a solution for mitigating such anomalies in calculations. To assess the sudden changes in the pressure loss estimations, the paper further utilizes CFD (Computational Fluid Dynamics) and the frictional loss estimations in these narrow annuli. As an outcome of the study, the paper proposes unique solutions to estimate the frictional pressure loss due to narrow annuli.
Extremely tortuous wells pose many wellbore quality repercussions and poorly affects several well drilling and production-based operations. To date, many indices have been developed for accurate tortuosity identification, but few have had the capability to efficiently mirror and quantify micro-tortuosity in realtime. This study applies a previously-proposed novel algorithm studied by some researchers to quantify well trajectory tortuosity using simple and readily available survey data. The process is followed and validated using twenty wells located in the Permian Basin. Python code was written to identify proper inflection points at the midpoint of the curve turns and using inclination and azimuth indices, a 3D overall TI index was generated for each well. The technique is inspired from the discipline of ophthalmology, specifically a method to determine tortuosity from retinal blood vessels.
Cement holds the most critical role for providing long-term zonal isolation for permanent abandonment phase. The loss of cement integrity is undesirable as it may threaten the surrounding environment and safety on the surface. The quality of cured cement is commonly associated with the properties of cement material and cement placement in the wellbore. However, there are still limited investigations that link these factors specifically to the sealing ability of cement plug, especially with the lack of proper equipment in the past.
In the present work, a small-scale laboratory setup has been constructed to test the sealing performance of a cement plug. The cement plug is contained inside a test cell, connected to a pressurizing system and placed inside a heating cabinet. Consequently, the test can be simulated at downhole conditions in a controlled manner. By using this setup, it is possible to monitor the minimum pressure required for the plug to fail and the gas leak rate.
Two different cement systems, neat- and silica-cement, were prepared as plugging materials. Both cement systems are placed inside pipes with three different levels of surface roughness and then tested. Results show that the inner surface roughness of the pipes affects cement plug sealing significantly, and the effect is independent of the type of cement systems. Plugs placed inside a very-rough pipe significantly reduce the gas leak rate. Our results also show that an immediate gas leak occurs in all samples from leak paths formed at the cement/steel interface.
Pehlivantürk, Can (The University of Texas at Austin) | D'Angelo, John (The University of Texas at Austin) | Cao, Dingzhou (Anadarko Petroleum Corporation) | Chen, Dongmei (The University of Texas at Austin) | Ashok, Pradeepkumar (The University of Texas at Austin) | Van Oort, Eric (The University of Texas at Austin)
The amount of uncertainty related to directional drilling makes it challenging to accurately model and predict the results of drilling actions, leaving much to human know-how and interpretation. Additionally, few path planning methods in the literature consider the directional steering tool being used which results in a loss of optimality when sliding and rotating instructions are fitted on a geometric optimal path. The formulation of the optimization problem varies greatly between rotary steerable systems (RSS) and mud-motor configurations. Additional cost functions and constraints are present for mud-motor use, which significantly increases the problem complexity. A slide drilling guidance system is proposed to combat this issue and to help automate directional drilling. The guidance system leverages three main modules. The first is a computationally efficient, non-linear wellbore propagation model. The second is a set of cost functions that aims to quantitatively represent the actual value of the well, representing production loss, drilling time, completion cost, and wellbore quality. The last module is a Genetic Algorithm (GA) solver that generates sets of optimal drilling instructions. The guidance system is built into a software package that utilizes an intuitive, easily-accessible Graphical User Interface (GUI) to be an effective advisory tool for the directional driller. The software is currently being implemented into the Real Time Drilling (RTD) system by an operator.
Solid particles in suspension in a fluid, like barite, lost circulation material (LCM), cuttings or cavings, influence the pressure losses that are experienced when pumping or moving a drill-string in a borehole. As the volume fractions of those different solid particles varies along the hydraulic circuit, it is desirable to estimate the impact of local solid concentrations on pressure drops.
The influence of solid particles on the rheological behavior of fluid has mostly been studied for Newtonian fluids, but very little experimental work has been published for non-Newtonian fluids like drilling muds. For that reason, a series of measurements, made with a scientific rheometer has been conducted on a typical KCl/Polymer water-based mud. The experimental investigation covers the effect of particle concentration on the rheological behavior of the mix, in conjunction with the particle size.
The change of rheological behavior is slow at low solid concentrations but increases exponentially with larger proportions of solid in suspension. Furthermore, the increase of effective viscosity is larger with fine particles than with coarser ones. Empirical formulas are proposed to describe how the original Herschel-Bulkley rheological behavior of a base fluid can be modified to incorporate the effects of the variation of solid concentrations in the fluid mix.
All these results are based on measurements made with a scientific rheometer. As computerized and high precision rheometers are usually not available at the rig site, we describe a methodology to utilize standard model 35 rheometer measurements to estimate the pressure loss gradient as a function of the volumetric solid content.
In an exploration well being drilled in a unique depositional environment, a rapid increase in pore pressure was anticipated, potentially reaching HP/HT conditions of up to 12,000 psi and over 180 C. The absence of close offset wells resulted in a large uncertainty in the magnitude of the pore pressure. This drove the planned casing design, which was limited by kick tolerance and potentially narrow margins between pore pressure and fracture gradient, resulting in planning for up to six casing strings. To respond to this challenge, standard engineering practices were augmented with additional monitoring and predictive modelling solutions to improve well control and to predict and explain complex well behaviour and mitigate the associated drilling risks. The models were calibrated with measured mud properties and wellbore temperatures and pressures during operations. They were then used to simulate, explain, and predict variations in downhole pressures and surface mud volumes. Various innovative applications were used to guide safe operational decision-making. Where conventional practices would not have allowed, this modelling enabled total depth of the well to be reached while incurring minimal nonproductive time and no well control incidents. By understanding wellbore conditions using advanced well control and temperature simulators, abnormalities normally failing the conventional practices could be detected and explained. This improved well control, safety, rig performance, and effective application of resources.
The main objective of this study was to understand the impact high-resolution measurement-while-drilling (MWD) surveys have on casing standoff and mud removal simulations and its impact on final cement program design and risk analysis.
High-resolution surveys use a combination of static and continuous MWD inclination data to characterize the well trajectory at 3-m (10-ft) intervals rather than the current industry practices at every stand; i.e., 30 m (100 ft). However, several case studies had demonstrated that surveying the well path at these intervals is often not sufficient to capture the true characterization of the well in question. This result, in some scenarios, leads to significant errors in the final reported dogleg severity (DLS) and tortuosity; therefore, resulting in optimistic well engineering simulations due the hidden additional tortuosity not applied in the models.
Two North Sea wells were analyzed when using conventional trajectories defined at each drillstring stand as well as using high-resolution trajectories to evaluate the impact on casing centralization and mud removal simulations.
The latest generation cementing software for placement simulation was used in this study. The simulation has the capabilities to deal with computing pipe standoff and angle direction in a 3D annulus, including gravitational forces for accurate mud displacement and removal.
This study confirmed that high-resolution MWD survey data can provide additional precise input for casing standoff and mud removal simulation, resulting in a more realistic simulation result due to the appearance of microtortuosity and DLS. Simulation results using high-resolution directional survey data identified conditions where the original mud removal assessment using a standard survey was overestimated due to higher standoff. This result allows an appropriate level of risk assessment and cement job design optimization to improve both the casing standoff and mud removal, which will eventually impact the well integrity quality.
This study proved that centralization and mud removal simulations can be, in some scenarios, optimistic if performed using standard trajectories. The results also proved that the risk assessments for the cement program designs will be evaluated differently because the enhanced simulations provide a more accurate result, which impacts the final centralization and mud removal to ensure effective zonal isolation.
More-accurate estimates of the fatigue damage on subsea wellhead might prolong the service lifetime of the equipment. Nevertheless, there might come a point during the life of a well on which the fatigue capacity is nearly depleted, without the possibility of further interventions being carried out, and thus imposing the abandonment of the well. This paper studies how employing a BOP tethering system may reduce the bending moment load transferred to the wellhead.
A BOP tethering system may be described as an assembly of anchors disposed around the subsea wellhead, which are connected to the BOP by mooring lines. The goal of the system is to reduce dynamic loads transferred to critical wellhead fatigue components and minimize the damage rates by decreasing the bending moment that is transferred from the riser to the wellhead.
The scope of a wellhead fatigue assessment comprises a riser response analysis. This paper presents the expected reduction on the calculated fluctuating bending moment load transferred to the wellhead for a series of possible configurations of the tethering system.
The results of the study conducted have shown that tethering the BOP system during drilling or re-entry operations has potential to decrease accumulated fatigue damage in the wellhead and can be regarded as an alternative for mitigating wellhead fatigue. The gains in petroleum production because of the increased operational life of the well have the potential to surpass the costs inherent to installing the tethering system. The results of simulations for different design options have shown the potential of this approach to increase the remaining service life of a wellhead, potentially doubling it. Even if installation restrictions prevent the optimum design to be used, this approach could still be advantageous.
Mitigating wellhead fatigue may prevent early well abandonment. Approaches considered to mitigate wellhead fatigue by actively reducing the load transferred to the wellhead, such as a reactive flex-joint, have been presented before. The BOP tethering system is an alternative to these previous systems and provides operators an additional solution for consideration to their specific needs.