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).

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.

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.

The last several years has seen an increasing trend toward more depleted reservoirs and more challenging wells with tighter mudweight windows. Managed Pressure Drilling has been employed in these challenging well conditions, however industry take up has been slow for a number of reasons including technical, economic and deployment related. Those wells that have utilized Managed Pressure Drilling have tended to focus on the drilling related aspects of well construction. However, other areas of well construction such as casing and liner running and cementing and completion installation are equally and in some cases even more technically challenging. One area that has potentially hindered the uptake of Managed Pressure Drilling is that in general, and in particular in the well construction operations outside of on bottom drilling there has been no access to real-time downhole data. In particular this is related to real-time pressure data. Whilst cementing, displacing or completing then multiple fluid types and densities may be circulating both inside and outside the drillpipe, leading to significant challenges in simulations and models derived from surface data. To overcome this a new acoustic telemetry and measurement network is being deployed in depleted reservoir and managed pressure drilling operations to provide real-time downhole and along string measurements of pressures, temperatures and weights. Real-time data case histories will be shown from the Gulf of Mexico and the North Sea illustrating how this is being used to drive real-time decisions during drilling, cementing and completion installation operations in tight margin windows, depleted reservoir conditions and under managed pressure drilling operations.

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 [5].

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 (Kvernland et al., 2018). The simulations were perfomed using a purpose-developed software which utilizes such input variables as wave height, pump flow, drill pipe movements, rig characteristic (RAO), drilling fluid properties as well as well design, drill pipe and Bottom Hole Assembly (BHA) data to simulate downhole pressure, induced by rig heave. The simulator is designed to model dynamic interactions between the drilling fluid and the drill string in a rigorous manner, which gives it ability to accurately predict fast downhole changes, such as ones induced by ocean waves.

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.

The industry is undergoing a transition into efficient technologies and it has digitalization written all over it. Digitalization not only should be about data, a fancy software, touchscreens and the internet, it is important that solutions are able to connect within existing work processes and with people for companies to truly lead to more efficient and safer drilling operations.

Oil and gas industries are now moving towards using Digital Twin's during the life-cycle of well construction. The concept of Digital Twins was first introduced by Dr. Michael Grieves at the University of Michigan in 2002 through Grieves’ Executive Course on Product Lifecycle Management. Digital Twin is a digital copy of the physical systems and act as a connection between physics and digital world. The digital system gets the real-time data from the mechanical systems which include all functionality and operational status of the physical system. An example from another industry; A Formula 1 team uses data from many sensors used in the car, harnessing data and using algorithms to make projections about what's ahead, and apply complex computer models to relay optimal race strategies back to the driver. Ultimately, to drive faster and safer.

By means of the digital twin of the drilling wells during the life cycle of the drilling by combining digital and real-time data together with predictive diagnostic messages there is seen a lot of advantageous in the improvement of accuracy in decision making and results. This again will help the industry to increase safety, improve efficiency and gain the best economic-value-based decision. A Digital Twin driven by real-time data helps to give operations the optimal plan with focus on safety, risk reduction and improved performance.

In this paper, the concept will first be explained in creating and utilizing a Digital Twin of your well for drilling and how it will directly influence how Drilling/well engineers, managers and supervisors plan, prepare and monitor their drilling operations and then implement learnings on future wells; for faster and improved decision making with direct relation to predicting and avoiding/mitigating NPT while also optimizing operations along with it. Case examples will be shared, showing value from use of the Digital Twin from first introduced in 2008 up until now where operators around the globe have implemented it for multiple uses in the drilling lifecycle.

Objective of the paper is to describe and present results of using a "Digital Twin" in Drilling Operations (Planning and Engineering, Training and Operational Support) in the last 10 years for Operators worldwide. The concept of Digital Twin was first introduced by Michael Grieves at the University of Michigan in 2003 through Grieves’ Executive Course on Product Lifecycle Management.

Winning a Formula 1 race is no longer just about building the fastest car, hiring the bravest driver and praying for luck. These days, when a McLaren technology group races in Monaco or Singapore, it beams data from hundreds of sensors wired in the car to Woking, England. There, analysts study that data and use complex computer models to relay optimal race strategies back to the driver. The McLaren race crew and the online retailers both harness data and use algorithms to make reasonable projections about the future, Parris explains. The concept is called Digital Twin [1].

A Digital Twin contains information such as a piece of equipment or asset, including its physical description, instrumentation, data and history. A Digital Twin can be created for assets ranging from a well to a piece of equipment to an entire oilfield. For example, a subsea system could have a Digital Twin via a simulation model of a subsea system's components, including the blowout preventer, tiebacks, risers, manifolds, umbilical and moorings.

Drilling and extracting simulations can determine whether virtual designs can actually be built using the machines available," GE said. "Last but not least, real-time data feeds from sensors in a physical operating asset are now used to know the exact state and condition of an operating-asset product, no matter where it is in the world"[2].

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.