By analyzing cuttings, drilling mud, and drilling parameters for hydrocarbon-associated phenomena, we can develop a great deal of information and understanding concerning the physical properties of a well from the surface to final depth. A critical function in data analysis is familiarity with the different sensors used for gathering surface data. The primary types of surface data sensors are discussed in this page. Current depth-tracking sensors digitally count the amount of rotational movement as the draw-works drum turns when the drilling line moves up or down. Each count represents a fixed amount of distance traveled, which can be related directly to depth movement (increasing or decreasing depth).

These tools characterize the reservoir fluids that have become entrained in the drilling fluid as it is returned to the surface. The total gas analyzer (TGA), also referred to as the total hydrocarbon analyzer (THA), measures the total amount of gas, typically the total amount of combustible gas. The usual unit of TGA measurement is total methane equivalents (TME), which is essentially the BTU content of the gas extracted from the drilling fluid, expressed as that which would be obtained from an equivalent concentration of pure methane in air. The TGA, while giving an undifferentiated indication of gas entrained in the drilling fluid, has the advantage of operating in a continuous mode. There are several analytical techniques used at the rig site to measure the molecular composition and component concentrations of the reservoir fluids entrained to the surface in the drilling fluid.

Measurement While Drilling - A New Tool (includes associated papers 15328 and 15343).

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.

Although many measurements are taken while drilling, the term MWD refers to measurements taken downhole with an electromechanical device located in the bottomhole assembly (BHA). Telemetry methods had difficulty in coping with the large volumes of downhole data, so the definition of MWD was broadened to include data that were stored in tool memory and recovered when the tool was returned to the surface. Power systems in MWD generally may be classified as one of two types: battery or turbine. Both types of power systems have inherent advantages and liabilities. In many MWD systems, a combination of these two types of power systems is used to provide power to the MWD tool so power will not be interrupted during intermittent drilling-fluid flow conditions.

The aim of drilling-dynamics measurement is to make drilling the well more efficient and to minimize nonproductive time (NPT). Approximately 75% of all lost-time incidents of more than 6 hours are caused by drilling-mechanics failures.[1] Therefore, extensive effort is made to ensure that the drilling-mechanics information acquired is converted to a format usable by the driller and that usable data are provided to the rig floor. Formation testing while drilling (FTWD) provides key formation pressures for drilling optimization. The data provided by these measurements are intended to enable informed, timely decisions by the drilling staff and thereby improve drilling efficiency.

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.

Ultrasonic caliper measurements while drilling were introduced principally for improving neutron and density measurements. Caliper transducers consist of two or more piezoelectric-crystal stacks placed in the wall of the drill collar. These transducers generate a high-frequency acoustic signal, which is reflected by a nearby surface (ideally, the borehole wall). The quality of the reflection is determined by the acoustic-impedance mismatch between the original and reflected signals. Often, there are difficulties in obtaining caliper measurement in wells with high drilling-fluid weights.

Introduction 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. A directional well can be divided into three main sections--the surface hole, overburden section, and reservoir penetration. Different factors are involved at each stage within the overall constraints of optimum reservoir penetration. Most directional wells are drilled from multiwell installations, platforms, or drillsites. Minimizing the cost or environmental footprint requires that wells be spaced as closely as possible. It has been found that spacing on the order of 2 m (6 ft) can be achieved. At the start of the well, the overriding constraint on the well path is the presence of other wells. Careful planning is required to assign well slots to bottomhole locations in a manner that avoids the need for complex directional steering within the cluster of wells. At its worst, the opportunity to reach certain targets from the installation can be lost if not carefully planned from the outset. Visualizing the relative positions of adjacent wells is important for correct decisions to be made about placing the well path to minimize the number of adjacent wells that must be shut in as a safety precaution against collisions. The steel in nearby wells requires that special downhole survey techniques be used to ensure accurate positioning. This section is generally planned with very low curvatures to minimize problems in excessive torque and casing wear resulting from high contact forces between drillstrings and the hole wall.

Balance between Formation Damage and Wellbore Damage: What Is the Controlling Factor in UBD Operations?