A Digital Twin is a software representation of a facility which can be used to understand, predict, and optimize performance to help to achieve top performance and recover future operational losses. The Digital twin consists of three components: a process model, a set of control algorithms, and knowledge.
Usually the time for commissioning a project exceeds the initial estimations, therefore delays in project completion are quite common. This is often because ICSS testing is done on a static system which does not account for how the system will react dynamically to certain scenarios such as start-ups and shutdowns. Issues such as configuration errors, loop behaviors, start-up over-rides, dead-lock inter-trips and sequence logic are difficult to predict and are impossible to anticipate during static testing. Such delays lead to higher costs and therefore reduced revenue.
This paper aims to describe the most innovative approach to Project & Operational Certainty, which addresses these issues by using a Digital Twin for commissioning support and training. One successful use of this approach was in the Culzean project, an ultra-high-pressure high temperature (UHP/HT) gas condensate development in the UK sector of the Central North Sea. A high-fidelity process model was built and fitted to the actual plant performance based on equipment data sheets. This was connected to ICSS database and graphics, offering a realistic environment, very close to the one offshore, which had the same look and feel for the operators.
Dynamic tests conducted on the Digital Twin predicted issues on the real system, which enabled potential solutions to be tested, leading to a significant decrease in the time spent and cost during commissioning. All the operating procedures were dynamically tested, which enabled us to correct errors, saving time before First Gas. Additionally, all CRO (Control Room Operators) and field technicians were trained and made familiar with the system months in advance, aiming to avoid future unnecessary trips during First Gas.
Finally, all the control loops were fine tuned in the Digital Twin and parameters were passed to off shore, to be used as first starting point. It is expected that these parameters will be very close to fine operational points, as the model used is high fidelity model and very close to real system offshore.
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.
Gao, Wenkai (CNPC Engineering Technology R&D Company Limited) | Liu, Ke (CNPC Engineering Technology R&D Company Limited) | Jia, Hengtian (CNPC Engineering Technology R&D Company Limited) | Hong, Difeng (CNPC Engineering Technology R&D Company Limited) | Teng, Xinmiao (CNPC Engineering Technology R&D Company Limited)
The problem of high temperature and the challenge to the existing downhole equipments are becoming increasingly prominent, where the drilling depth is severely restricted. The conventional measurement while drilling tools with common electronics will experience very high failure rates at these conditions. One of the solutions is called the active cooling technology, which can transfer the heat from electronics system to downhole environment. By this way, the temperature control of downhole instrument circuit system is realized. The active cooling technology is expounded in this paper, expecially about the principles and development status of each system. After evaluating and analyzing the characteristics of this technology, the function of heat transfer and constituent elements for the cooling system are summarized. The study from this work demonstrates the future work for downhole cooling technology: large refrigeration capacity, small size, strong adaptability and modularization.
An early commitment to integrate MPD into an HP/HT drilling operation can make MPD more than just an enabling tool and turn it into a performance tool that offers significant operational benefits. The optimization model presented in the complete paper is the first multioperator offshore network-optimization model that considers decommissioning in the Netherlands. A study was required to determine the origin of the tremor, evaluate if it could be followed by other tremors in the future, and estimate its magnitude. A reservoir-monitoring system has been installed on a medium-heavy-oil onshore field in the context of redevelopment by gravity-assisted steamflood.
This paper presents a newly designed triaxial fracturing system and describes a series of experiments that verified the validity of tool-free chemical diversion for multistage fracturing of openhole horizontal wells. The case history presented in the complete paper describes the performance of an acid-fracturing intervention in an HP/HT well in which this intervention was the last procedure considered to evaluate the productivity of a Marrat Formation well.
The benchmark comes as operator Eni solidifies concession agreements and ramps up exploration and development in the North African country. Touted as the Mediterranean Sea’s largest-ever gas discovery, the “supergiant” Zohr field is expected to cover much of Egypt’s gas demand in the coming decades. Untapped offshore gas reservoirs could easily meet all of the country's domestic needs, while the rest could supply regional neighbors.
Energy consultancy Wood Mackenzie estimates the find holds some 2 Tcf of gas, making it this year’s seventh-largest discovery worldwide. Malaysia’s Petronas, Shell Malaysia, and Thailand’s PTTEP are now in the midst of full-scale digital adoption. The companies are beginning to see results, but none is counting on a “big bang” in development of the technology soon. The state-owned firm is looking within its home country, around Southeast Asia, and to the Americas—including shale—in an effort to maintain its forecast average yearly production of 1.7 million BOE/D over the next 5 years. This paper describes challenges faced in a company’s first deepwater asset in Malaysia and the methods used to overcome these issues in the planning stage.
We must concentrate our paper selection on technology and operating methods that make HP/HT drilling operations faster, safer, and more cost-efficient. If above-threshold drilling costs shelve a project, the project will not fly. And without projects, HP/HT know-how and equipment quickly disappears. This paper discusses the successful application of managed-pressure drilling (MPD) in the basin with reduction in risks and well costs. This paper discusses how managed-pressure-drilling (MPD) technology led to cost savings in two wells drilled in the Hai Thach gas field offshore southern Vietnam.
Flow assurance in the oil and gas industry refers to the systems put in place to guarantee uninterrupted profitable and sustainable flow of hydrocarbons from the reservoir to surface facilities and ultimately to refineries. Flow assurance challenges include: inorganic scale, asphaltene, wax, corrosion, hydrates, etc. Managing these challenges is becoming more complex because of development of fields under harsher conditions e.g. HPHT reservoirs, sour reservoirs, heavy oil; in addition to further implementation of EOR (gas injection, chemical, surfactant and polymer floods). Different engineering and chemical solutions can be put in place to manage these challenges. All cancellations must be received no later than 14 days prior to the course start date.