Computer-controlled drilling is slowly changing how the oil and gas industry discovers natural resources. Automated drilling can reduce the number of injuries to zero and increase productivity and accuracy. Global oil prices and a surplus of gas have caused an improvement in the economics of automated projects. Meanwhile, in North America, human-operated drilling has greatly improved. According to a 2011 issue of Drilling Contractor, the first generation of Shell's automated control system already showed a 70% improvement in rate of penetration (ROP) in test areas.
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 Early systems used by single operators developed in-house have now been replaced by customizable commercial systems shared by a large number of operators.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. 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. Mud-pulse telemetry transmits data to the surface by modifying the flow of mud in the drillpipe in such a way that there are changes in fluid pressure at surface.
In situations in which predrill analysis reveals high risk but has a large uncertainty, it is possible to mitigate that risk by carrying out geomechanical analysis in real time. Performing real time assessment requires acquisition of a variety of data while drilling. The measurement can also be used to show where transient pressure events such as surging and breaking the gel strength of the mud exceed fracture pressure, or where swabbing reduces the pressure below the pore or collapse pressure of the wellbore. Direct pore-pressure measurements while drilling can provide critical data to calibrate pore-pressure predictions in permeable formations. Extended leakoff tests are strongly recommended.
Preventing such failures is critical to maintaining well production. Holes in the casing are visible in the series of ultrasonic images that are based on amplitude (left) and corrected travel time (right). The center 3D images show the pipe in 90 quadrants. The image shading is generated from the amplitude data (courtesy of SPE). In this example, casing radius and shape are presented as log curves and image maps and deformed casing is easily identified (courtesy of Baker Atlas). The acoustic caliper generated from the pulse/echo travel time provides the casing inside diameter (an average of all transducers or a single circumferential scan).
The acquisition of bottomhole pressure and temperature data can be planned and executed in a cost-effective manner with a minimum disruption to normal operating routines. In many cases, early on-site interpretation is useful in guiding decisions about continuing the acquisition program. Measurements can be transmitted to the surface, usually via an electric cable, or recorded in downhole memory powered by batteries. SRO has the obvious advantage of providing data in real time. Real-time readouts are especially beneficial for transient measurements that require time for the pressure to stabilize and radial flow to develop.
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.