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.
These equations represent conservation of mass of each of n components in each gridblock over a timestep Δt from tn to tn 1. The first n (primary) equations simply express conservation of mass for each of n components such as oil, gas, methane, CO2, and water, denoted by subscript I 1,2,…, n. In the thermal case, one of the "components" is energy and its equation expresses conservation of energy. An additional m (secondary or constraint) equations express constraints such as equal fugacities of each component in all phases where it is present, and the volume balance Sw So Sg Ssolid 1.0, where S solid represents any immobile phase such as precipitated solid salt or coke. There must be n m variables (unknowns) corresponding to these n m equations. For example, consider the isothermal, three-phase, compositional case with all components present in all three phases. There are m 2n 1 constraint equations consisting of the volume balance and the 2n equations expressing equal fugacities of ...
The motivation for high-performance computing in reservoir simulation has always existed. From the earliest simulation models, computing resources have been severely taxed simply because the level of complexity desired by the engineer almost always exceeded the speed and memory of the hardware. The high-speed vector processors such as the Cray of the late 1970s and early 1980s led to orders-of-magnitude improvement in speed of computation and led to production models of several hundred thousand cells. The relief brought by these models, unfortunately, was short-lived. The desire for increased physics of compositional modeling and the introduction of geostatistically/structurally based geological models led to increases in computational complexity even beyond the large-scale models of the vector processors.
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.
In artificial lift with electrical submersible pumps, the surface controller provides power to the ESP motors and protects the downhole ESP components. There are three types of motor controllers used on ESP applications and all are generally specifically designed for application with ESPs. They include the switchboard, soft starter, and the variable speed controller. All units vary in design, physical size, and power ratings. Normally, all utilize solid state circuitry to provide protection, as well as a means of control for the ESP system. Motor controller designs vary in complexity from the very simple and basic to the very sophisticated, which offer numerous options to enhance the methods of control, protection, and monitoring of the ESP operation. The selection of the type of controller and optional features depends on the application, supporting economics, and the preferred method of control. The switchboard, fixed-speed controller, or across-the-line starter consists of a manual fused disconnect switch or circuit breaker, a motor starter, and a control power transformer.