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There are a variety of methods for monitoring immiscible gas injection projects. Some apply both to the pattern type of gas injection projects and to the vertical gravity-drainage type of gas injection projects; others apply only to the gravity-drainage projects. In all cases, individual well production and pressure performance as a function of time must be recorded. The purpose of monitoring activities is to perform real-time analysis of reservoir performance and to consider any remedial actions. These actions include such alternatives as rebalancing the gas rates into the various injectors, rebalancing the flow rates of the various producers, and potentially drilling a few new injection or production wells into areas of the reservoir determined to require more drainage points or to improve the overall sweep efficiency.
BP has acquired UK-based digital energy business Open Energi. The company's digital platform uses real-time data to optimize the performance of energy assets. It connects customers to power markets with the goal of providing flexibility at times of low renewable-energy generation and during price peaks. The share of primary energy from renewables is projected to increase from around 5% in 2018 to 60% by 2050 in the net-zero scenario set out in BP's Energy Outlook. However, because generation from these sources depends on weather conditions, the growth will also bring increased market and price volatility.
Engineering simulation technology company Akselos and energy service company Lamprell have announced the results of an EU-backed wind foundation design project that shows that predictive digital twin technology can reduce the steel weight and associated costs of offshore wind jacket foundations by up to 30%. The European Union awarded Akselos €1.4 million in 2018 to conduct the research and pilot the Global Optimal Design of Support Structures (GODESS) project. The GODESS philosophy has been used as the basis for proof of concept on one of Lamprell's UK offshore wind projects. Lamprell now will apply the findings to reduce the amount of steel it uses to construct its offshore foundations. The results were achieved thanks to Akselos' ground-breaking MIT-licensed simulation technology, Reduced-Basis Finite Element Analysis (RB-FEA), which allows for unprecedented speed and accuracy through real-time data feeds.
The lines between information technology (IT) and operational technology (OT) are starting to blur. IT/OT convergence has already entered full force in areas such as the manufacturing industry, where internet-of-things (IOT) adoption is reaching new heights. As Industry 4.0 expands to other sectors, industries such as oil and gas are starting to undergo IT/OT convergence, too. The industrial world as a whole is becoming increasingly digital and data-driven. Although the oil and gas industry hasn't always been on the cutting edge of technology, it might not have a choice for much longer.
Directional drilling is defined as the practice of controlling the direction and deviation of a wellbore to a predetermined underground target or location. This section describes why directional drilling is required, the sort of well paths that are used, and the tools and methods employed to drill those wells. Field developments, particularly offshore and in the Arctic, involve drilling an optimum number of wells from a single platform or artificial island. Directional drilling has helped by greatly reducing the costs and environmental impact of this application. A well is directionally drilled to reach a producing zone that is otherwise inaccessible with normal vertical-drilling practices.
During the late 1960s, drilling data consisted of manual or mechanical recording systems and hard-copy paper reports completed by rigsite personnel. Computing technology has led to an explosion in the data that can be collected and must be managed for effective use and reporting. Live capture of real-time data fed into engineering and geoscience systems has enabled asset-team members to make more-informed and timely decisions that positively affect wellbore placement, resulting in more-profitable wells for the operator. Advancement of rigsite software systems has seen applications evolve from early mainframe to mini-computer systems to UNIX multitasking systems, Microsoft DOS applications, Microsoft Windows applications, and the current emergence of Intranet or Internet applications. Early systems used by single operators developed in-house have now been replaced by customizable commercial systems shared by a large number of operators.
The most comprehensive data-acquisition systems present at the rigsite are provided by service companies such as mud-logging, Measurement while drilling (MWD)/Logging while drilling (LWD)), and wireline vendors. Real-time data-acquisition systems typically are connected to a suite of surface and downhole sensors that enable live monitoring of the rig-equipment operation and the well-construction process. Service-company systems are typically capable of accepting Wellsite Information Transfer Specification (WITS) inputs from other vendors so that sensor readings from all data-acquisition systems may be collated into a single real-time data set that may be provided to the operator at the end of the well. The combination of surface and downhole sensors with networked graphical data logs and text outputs enables the operator's supervisory staff, service company, and rig contractor to maintain an accurate picture of the drilling or well-services operation, and track well progress to ensure that the new-wellbore placement or completion meets the operator's safety, geologic, and production requirements. Rig-contractor personnel may use any number of commercially available electronic tour-sheet applications that enable them to complete their Intl.
Successful underbalanced drilling (UBD) requires downhole equipment to provide real-time information to the surface for monitoring conditions during drilling operations. Pressure while drilling (PWD) sensors have proved invaluable in every UBD operation to date, when they have been included in the drillstring and operated without downtime. However, quite a number of these sensors have proved problematic, because of the vibration problems and fast drilling rates encountered with UBD. Adding a downhole gauge or sensor on the injection side and in the drillstring has a few of the following benefits: enhanced UBD operation, help optimize the drilling process, and increase the operator's knowledge of the reservoir. The most common technique for transmitting measurement while drilling (MWD) data uses the drilling fluid pumped down through the drillstring as a transmission medium for acoustic waves.
To say that the shale sector is on the cusp of a new era, one where fast-flowing streams of real-time well data and on-the-fly fracture designs are the norm, is not something one does lightly. It represents a step change that engineers have been told is just around the corner for several years. They've been promised software that will churn out truly optimized recipes of proppant concentration, rate, total volume, etc. to match each fracture stage's piece of the rock. In a neat world, this nets better production from good stages while injecting less capital into bad stages--the ultimate win-win for a sector that spends 60–70% of well costs on the completion. We can pluck example after example from industry literature to prove the incremental existence of such tailor-made well pads.
As industry buzzwords go, "automation" has spent its time in oilfield vernacular climbing the ranks of widely used terms. It now resides as one of the go-to designations for signs of advancement in any number of disciplines. Its use has been tied most frequently with drilling operations as contractors look to keep employees out of harm's way via a robotic takeover of most motion-intensive jobs on the rig's drill floor--basically anything that grips, clamps, or spins. More recently, the term has moved away from the drill floor and into other well construction operations allowing for things such as remote, real-time measurements without the need for boots on the ground. For areas like west Texas and the Permian Basin shales, having the option for remote readouts and a component of automation that can allow for corrective actions should the need arise can go a long way in terms of safety and efficiency gains as well as better manpower application.