|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Ng, Mui Ted (Eftech Drilling Solutions) | Lum, Terry (Sabah Shell Petroleum Co. Ltd.) | Yeap, Fabian (Sabah Shell Petroleum Co. Ltd.) | Abdul Talib, Sa'aid Hazley (Eftech Drilling Solutions) | Zainal Abiddin, Mohamad Sukor (Eftech Drilling Solutions) | Hooi, E-Wen (Eftech Drilling Solutions)
As the search for hydrocarbon offshore runs deeper and farther from land, it is best we gear ourselves to embrace what it takes for delivering highly deviated deepwater development wells to push the frontiers of petroleum extraction. This paper discusses the monitoring and optimizations of deepwater wells operations in Malaysia by the Shell Malaysia Exploration and Production Real Time Operation Centre (SMEP RTOC).
The scopes of monitoring and optimizations discussed in this paper include: Hydraulics management in narrow pressure margin drilling, including modelling, optimization, measurement and monitoring of equivalent circulating density (ECD). Engineering support in pre-drill study for Managed Pressure Drilling (MPD) application. Mitigation of drilling vibration in highly deviated wells, especially stick-slip vibration. Hole cleaning modelling, monitoring and optimization. Drilling roadmaps and database are archived by RTOC for future wells reference. Drilling operations performance tracking and benchmarking. 24/7 Top Tension Riser, Hawser and mooring lines tension monitoring.
Hydraulics management in narrow pressure margin drilling, including modelling, optimization, measurement and monitoring of equivalent circulating density (ECD).
Engineering support in pre-drill study for Managed Pressure Drilling (MPD) application.
Mitigation of drilling vibration in highly deviated wells, especially stick-slip vibration.
Hole cleaning modelling, monitoring and optimization.
Drilling roadmaps and database are archived by RTOC for future wells reference.
Drilling operations performance tracking and benchmarking.
24/7 Top Tension Riser, Hawser and mooring lines tension monitoring.
Deepwater drilling operation costs are typically significantly higher than shallow water and land rig operations. This is partly due to higher rig rates in deepwater operations. In this case any reduction in Invisible Lost Time (ILT) and Non-Productive Time (NPT) may result in significant cost reduction. Like a safety net that catches anomalies that slipped the first line of defense, RTOC monitoring has the facilities and trained capabilities to oversee and optimize the operations in totality both during real time and post run. An investment in RTOC services in exchange of more cost efficient and safer operations will be justified in the paper.
Real Time Operation Centre (RTOC) is becoming more indispensable over the years. Hawk-eyeing operations in areas where attention is diluted by other tasks on the rig, could probably be the insurance needed in every future oil and gas drilling. The methods, procedures and processes in well operations will definitely advance with time and further developments and innovations in this subject will be closely followed within the industry.
Dobrokhleb, Pavel (Schlumberger) | Truba, Andrey (Schlumberger) | Borges, Sergio (Schlumberger) | Moiseenko, Ivan (Schlumberger) | Vorozheykin, Anatoly (Schlumberger) | Dotsenko, Anton (Schlumberger) | Evdokimov, Stanislav (Schlumberger) | Niverchuk, Andrey (Schlumberger) | Khusaenov, Timur (Schlumberger) | Kurasov, Alexander (Ob LNG) | Davletov, Renat (NOVATEK-YURKHAROVNEFTEGAS) | Galaktionov, Grigory (NOVATEK) | Glebov, Evgeny (NOVATEK) | Shokarev, Ivan (NOVATEK) | Grigoriev, Maxim (NOVATEK STC) | Sidorov, Dmitry (NOVATEK STC) | Zhludov, Alexey (Investgeoservice)
The Yurkharovskoye oil and gas condensate field is one of the main asset of PJSC NOVATEK. Two of the three productive levels (Cenoman and Valangin) are in the active development phase. The Jurassic reservoir, which is characterized by complex geology, high formation pressure (gradient ~ 2.0MPa / 100m) and a low fracturing gradient (FG), is currently in the exploration phase. In 2017, drilling of the first exploration well with a depth of 4855 m with a horizontal ending with multistage formation fracturing in the Jurassic formation was successfully completed. Successful completion of the drilling allowed not only to obtain valuable geological information, but also to choose an approach to the construction of such wells in the future.
Joint efforts of the field operator, drilling contractor and oilfield services company have developed a drilling system that included a full range of engineering solutions that ensure an efficient and accident-free well construction process: completion, directional drilling, bits, drilling fluids, geomechanics and managed pressure drilling (MPD). Previous experience in the construction of directional wells was associated with mud losses due to fracturing, blow outs and wellbore collapse. At the design planning stage, the well design was optimized, the completion system was developed, the formulations of high-density drilling muds with low rheology were selected, a choice of technologies was made and much more. Each stage of the well construction was worked out and a scheme of operative interaction between the parties was developed, which allowed timely correction of the work program based on an actual information.
Even at the design planning stage geomechanical modeling allowed design optimization and choose a safe trajectory of the well, and its update, based on the actual information, allowed to reduce the risks. Specially for this well, the formulation of the hydrocarbon-based solution was developed, which, despite its high density, was distinguished by low rheological properties. An important aspect of the preparation was the selection of bottomhole assembly and drilling regimes, which, on the one hand, should ensure efficient drilling, and on the other, generate the smallest possible equivalent circulation density (ECD). The use of MPD technology has made possible to maintain the ECD and ESP (equivalent static pressure) at the same level and to compensate for the pressure fluctuations during circulation and movement of the drill string while trips. To select the BHA, a special program complex was used to simulate the dynamics of its behavior at the bottomhole. Logging tools at BHA provided important real-time information that was used to manage the drilling process and make operational decisions. The hybrid rotary steerable system (RSS) allowed to drill the well in the riskiest intervals with a minimum angle and to provide a high dog leg and hit the target. The completion system for multistage fracturing with swellable packers required preparation of the wellbore and planning of all the necessary operations in order not to initiate hydraulic fracturing, wellbore collapse and failure to reach the target depth.
The project of NOVATEK-Yurkharovneftegaz is a bright example when modern technologies and effective interaction of participants allow successfully solving problems that were previously considered as difficult to implement and open new horizons for developing hard-to-reach deposits in extreme conditions. Successful experience gained during the project will ensure the efficient construction of wells in the field.
Review our data policy for information about these graphics and how they may be used. The formation of scale deposits upon tubing, casing, perforations, and even on the formation face itself, can severely constrict fluid flow and reduce the production rate of oil and gas wells. In addition to lost production, a considerable portion of the workover budget is expended in efforts to remove these deposits and prevent their recurrence. As a consequence, scale prevention has been and continues to be a common exercise and is successfully applied in many areas. Although the principles behind scale formation and prevention are generally well understood, there are many new forms of scale prevention and new scale inhibitor application technologies. Some people consider scale prevention a mature subject matter area with “nothing new under the sun,” but in fact there are many new developments, some of which will be highlighted in this presentation. This presentation will review the major elements ...
Several mature fields in the North Sea experience significant challenges relating to high pressures and temperatures accompanied with the infill drilling challenge of very narrow margins between pore and fracture pressures. To navigate these narrow mud weight windows, it is critical to understand the bottom hole pressure. However, in the cases of fractured formations above the target zones, severe losses can be encountered during drilling and cementing operations often leading to the inability to maintain a full mud column at all times and even threaten the ability to reach TD.
The operator therefore decided to investigate the use of a new acoustic telemetry system that could provide internal and external pressure measurements, (along with other downhole measurements) independently of traditional mud pulse telemetry in the drilling assembly. Real-time distributed pressure data essential to understanding the downhole conditions could therefore be provided regardless of circulation, even under severe losses or during tripping and cementing operations.
This acoustic telemetry network was deployed on several wells through multiple hole sizes and including losses management, liner running and cementing operations.
The initial primary purpose of running the network was the ability to monitor the top of the mud at all times, even in significant loss situations. As real-time data was acquired it became apparent that the data could also be used in real-time to aid and help quantify the actual downhole pressures. The use of this downhole data was modified and new calculations designed for simpler visualization of equivalent circulating densities at the shoe, bit and identified weak zones in the well at depths beyond the acoustic tools themselves. This data was used to manage the bottom hole pressure within a 300 psi mud weight window to ultimately enable the well to be delivered to planned TD.
The tool and calculations helped verify managed pressure connections and subsequent pump ramp up and down operations to minimize pressure fluctuations in the well. Additionally the data was used during dynamic formation integrity testing and to measure and calculate ECD at various positions along the drillstring and casing when downhole PWD measurements were unavailable.
This paper will describe how the implementation of new technology through the downhole acoustic network was deployed and the lessons learned in how the real-time data was used, changed and adapted in this particular well. Due to this deployment the acoustic telemetry network will now be used on upcoming equally challenging wells and its range of operations expanded to include drilling, tripping and liner cementing operations.
Siqueira Vanni, Guilherme (Petrobras) | Alonso Fernandes, André (Petrobras) | Tacio Teixeira, Gleber (Petrobras) | Vieira Martins Lage, Antonio Carlos (Petrobras) | Leibsohn Martins, André (Petrobras) | de Souza Terra, Felipe (Petrobras) | de Souza Cruz, Marcelo (Engineering Simulation and Scientific Software) | Rodrigues G. da Silva, Fabio (Engineering Simulation and Scientific Software) | Édio Dannenhauer, Cristiano (Engineering Simulation and Scientific Software)
Given the complexity related to deepwater drilling with narrow operational windows, any effort to increase the confidence on the safety guidelines should be encouraged. There are many procedures in MPD operations that can be verified and validated during the operations, in order to avoid unforeseen situations.
As initiatives to optimize the drilling process in real time are extremely important, the present study focuses on the development of specific methodologies to support MPD operations, which are implemented on a real time drilling diagnosis software [
It is very useful to review the drilling plan in various situations. With the use of MPD monitoring module is possible to obtain, from the DPPT (Dynamic Pore Pressure Test) and DFIT (Dynamic Formation Integrity Test) procedures, more precise values to compose the operating window. As a consequence of appliying it together with precise hydraulics, cutting transport and torque and drag models, the developed methodology proposes, as output, the ideal operating parameters, such as choke pressure, pump flow rate or adjustments related to the drilling fluid properties. The methodology always considers the best approach to meet the restrictions imposed by the operational window, avoiding drilling problems. Alternatively, if a change on the operating parameters is not sufficient, it also simulates the best position for the Anchor Point.
The developed methodology was successfully applied in a number of MPD wells recently drilled in distinct deepwater locations, in Brazil. The real time optimization procedures proposed in the present paper are a further step to ensure the reliability of MPD operations in challenging scenarios, aiming enhanced efficiency and safety.
The most important contributer to Improved Oil Recovery (IOR) on mature fields is drilling of infill wells. Managed Pressure Drilling (MPD) and Continuous Circulation System (CCS) techniques can be used for improved control of bottomhole pressure when drilling wells in depleted fields with narrow pressure windows, but rig heave is a challenge when drilling from floating drilling units. Rig heave, caused by sea waves, induces pressure oscillations downhole that may exceed the operational pressure window. These oscillations are called "surge & swab" and occur both during tripping in and out of hole as well as during drill pipe connections, when the topside heave compensation system used during drilling is disabled because the drill pipe is put in slips. Downhole choking was introduced as a method to reduce downhole pressure oscillations induced by the rig heave and the concept was tested in laboratory scale and using computer simulations (
This paper gives an overview of the surge & swab simulator, describing its capabilities and limitations. Data from drilling of a North Sea well is then used to validate the simulations made using the software. The well, used as example in this paper, was drilled conventionally from a floating rig. The downhole pressure variations recorded during three different drill pipe connections are compared with simulated downhole pressure. The simulations are based on the recorded rig heave as well as the actual drilling fluid, well design and drill pipe data. Results show that there is a good correlation between simulated and actual measured downhole pressure. The surge & swab simulation software is then used to simulate the same drilling pipe connections using three different techniques and combinations of techniques utilized for improved downhole pressure control: (1) Managed Pressure Drilling (MPD) (2) Managed Pressure Drilling combined with Continuous Circulation System (CCS) and (3) MPD combined with CCS and a downhole choke. Results show that rig heave-induced downhole pressure variations are reduced to a level which is considered acceptable for drilling a well with narrow pressure window for the last two cases, while utilization of backpressure MPD alone is not sufficient. The combination of MPD and CCS reduced surge & swab for two out of three connections. For the third and deepest connection, the surge & swab increased. The largest reduction in significant downhole pressure variations (43-68 % vs. conventional drilling for the three connections) occurs when MPD and CCS are combined with downhole choking.
Future work will consist of further developing the surge & swab simulator so that it will be possible to utilize it in well planning and as real-time decision support during drilling operations. The simulator will also be developed to include possibility of simulating various well completion operations such as running casings and liners. A prototype of the downhole choke is currently being tested at the mud loop of the Ullrigg test rig facility in Stavanger, Norway, and the next development phase consists of designing and building a complete downhole tool for testing in a well.
Narrow mud windows often cause a lot of trouble when using conventional drilling techniques due to the difficulty of maintaining the bottomhole pressure between the maximum pore pressure and minimum fracture pressures of the exposed formations. This can lead to wellbore influx, formation damage and fluid loss. Managed pressure drilling (MPD) is an adjustable drilling technique that will help balance and maintain the annulus pressure, within a desired margin. Using MPD will enhance drilling performance, reduce nonproductive time (NPT), and increase safety.
Operators usually acquire fluid property measurement by either PVT analysis to account for downhole effect of pressure and temperature on density and rheology, or using experimental lab data with downhole fluid properties. These measurements are used to calculate the equivalent circulating density, and control surface back pressure (SBP) via MPD surface choke.
Acquiring real-time downhole data for fluid properties like density and rheology, at a high frequency, will lead to precise calculations of the equivalent circulating density (ECD), and the annular frictional losses. Real-time monitoring of ECD and pressure drop allows for optimal control over the annular pressure throughout the drilled section, which in turn reduces the risk of kick occurrence and lost circulation.
Satisfactory results were achieved with the use of real-time data in MPD; where no stuck pipe or well control incidents were recorded. In this paper, we will demonstrate the steps taken to obtain real-time data measurements of the properties and the operational details that led to improved performance of MPD.
This paper introduces an active wellbore sealing system for use in Managed Pressure Drilling (MPD) incorporating a wellbore seal condition monitoring system. The paper will discuss how finite element analysis which has previously been validated with full scale testing can be expanded to develop the condition monitoring system.
In contrast to a passive rotating control device, an active MPD wellbore sealing system requires hydraulic pressure to engage a sealing element and form a wellbore seal. The paper will investigate the relationship between wellbore sealing pressure and hydraulic fluid parameters using the results of finite element analysis on a sealing technology which has been previously operated offshore in addition to extensive full-scale testing in a lab environment.
The paper will show how the required hydraulic fluid requirements to form a wellbore seal change over time due to sealing element wear. The information can be used to predict the remaining life of the existing sealing element as well as proactively alarm the driller of the need to replace a seal sleeve due to a sudden deviation from expected behavior. The implementation of a real-time, condition monitoring system for the MPD wellbore seal is intended to increase the rig's confidence toward using MPD for challenging hole sections as well as circulating out small influxes from the well without closing the SSBOP, further reducing the risk of stuck pipe events.
The active MPD wellbore sealing system is a non-rotating, offshore wellbore annular sealing device which is integrated into the riser. It contains a seal of elastomeric composition which seals against drill pipe during all tripping and drilling operations. As the seal wears, the hydraulic closing fluid requirement to maintain an annular seal changes, which indicates the amount of seal material remaining.
AbstractMPD enables drillers to navigate through narrow drilling windows to reach designed target depths. After a hole section is drilled, pressure management is still required to pull drill strings out and run and cement liners. Conventional cementing programs and procedures may not be practical for a challenging hole section that has been drilled by MPD. Elaborate wellbore pressure management is required to ensure safe and efficient cementing operations. The same closed loop circulation system utilized for drilling is used to manage the wellbore pressure during cement operations. The technique of pressure management during liner cement jobs was utilized repeatedly by a major client in one of the most challenging HPHT campaigns in the North Sea. This paper provides an insight into the technique as well as information on the procedures, challenges and lessons learned pertinent to these operations. Various cases studies describing the setup, planning and execution of operations, simulation vs measured data will be compared.Drilling wells in complex environments with century-old technology is difficult at best and unsafe at worst. From drilling through narrow pore-pressure/fracture-pressure gradient windows to mitigating kicks and differential sticking, managed pressure drilling (MPD) succeeds when conventional techniques are likely to fail. MPD entails the use of specialized equipment to control wellbore pressure profiles more precisely than is possible with conventional drilling methods. MPD enables drillers to navigate through narrow drilling windows to reach designed target depths. After a hole section is drilled, pressure management is still required to pull drill strings out and run and cement liners. Conventional cementing programs and procedures may not be practical for a challenging hole section that has been drilled by MPD. Elaborate wellbore pressure management is required to ensure safe and efficient cementing operations. The same closed loop circulation system utilized for drilling is used to manage the wellbore pressure during cement operations. A case study describing the setup, planning and execution of operations, and simulation is presented in this paper.
AbstractPhysics-based hydraulic models are essential for proceeding to a high level of automation in drilling. Mathematical models can facilitate process understanding and problem detection, and determine appropriate actions in case of mismatch between model and data. Furthermore, calculations may replace measurements where and when the latter are not available, as normally occurs during connections or when instruments or signal transmissions fail. However, advanced hydraulic models rely on a large set of inputs, such as pipe and wellbore geometry, various tuning parameters and fluid properties. The models are therefore time-consuming and difficult to configure in the field, where third-party experts may be needed at each well, to properly initiate the automation system and adjust it during the drilling process. Although the methods described in this paper are relevant to any critical drilling operation, they are applied to Managed Pressure Drilling (MPD) as a widely deployed example of drilling automation. In MPD, hydraulic models predict downhole conditions and determine the requisite choke pressure for automatic adjustment. A new method for automatic configuration of key model parameters simplifies the tedious job of setting up the model and ensures that the automation system remains tuned to the well, even without onsite model tuning expertise.The proposed scheme is based on a simple method for separating inaccuracies due to co-linearity in frictional pressure losses and static mud weight. The search for optimal correction factors is based on a sequence of small oscillations of pump rate that can be applied during drilling without interrupting the operation. A massively parallel computing architecture improves the speed of the calibration algorithm proportional to the number of available CPU cores. A set of hydraulic model instances runs in parallel, allowing for efficient testing of changes in input signals within ranges of uncertainty. A method for selecting a subset of the best models that more accurately represent a given well is proposed.Computer simulations demonstrate how the novel calibration scheme allows automatic tuning of the friction factor and density correction factor, giving accurate prediction of the bottom hole pressure (BHP). The tuning scheme is run with a parallel architecture to demonstrate that correct values of unknown configuration parameters can be automatically determined sufficiently fast for real-time drilling control or as an advisory tool.The deployment of automation systems in drilling is hampered by the need for dedicated expert personnel to maintain systems that could have reduced the personnel needed on the rig. The proposed automated physics-based model tuning contributes to removing this roadblock, aiming at making automation systems a more cost-efficient option for drilling operations.