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PEH:Drilling-Data Acquisition

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Petroleum Engineering Handbook

Larry W. Lake, Editor-in-Chief

Volume II - Drilling Engineering

Robert F. Mitchell, Editor

Chapter 15 - Drilling-Data Acquisition

By Iain Dowell, Halliburton Energy Services, Andrew Mills, Esso Australia Ltd.; Marcus Ridgway and Matt Lora, Landmark Graphics Corp.

Pgs. 647-685

ISBN 978-1-55563-114-7
Get permission for reuse

The prototype data-collection system for drilling wells previously consisted of paper reports from data collected and recorded by hand, culminating in the daily "morning report" of well progress. Because of the progress in computer hardware and software over the past 20 years, spurred by the increased use of measurement-while-drilling (MWD) and logging-while-drilling (LWD) tools, wellsite data collection, storage, and use have increased many times above the meager data available only a few years ago.

Surface-Data Sensors

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. These sensors can be grouped as follows:

  • Depth Tracking.
  • Flow-In Tracking.
  • Pressure Tracking.
  • Flow-Out Tracking.
  • Drill Monitoring.
  • Pit Monitoring.
  • Gas Detection.

Depth-Tracking Sensors

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). Moreover, the amount of movement also can be tied into a time-based counter, which will give either an instantaneous or an average rate of penetration (ROP).

Alternatively, some companies still use a pressurized depth-tracking/ROP sensor. The pressurized ROP system works on the principle of the change in hydrostatic pressure in a column of water as the height of that column is varied. This change can then be indirectly related to a depth measurement. Again, a time-based counter is used to calculate an instantaneous or average ROP.

Additionally, accurate depth measurement on offshore rigs such as semisubmersibles, submersibles, and drill ships is affected by both lateral (tidal movement) and axial (the up-and-down motion of the rig, also called "rig heave") effects. To properly compensate for this, most of these rigs have a rig-compensator system installed on their traveling block. As the rig moves up, the compensator opens, thereby allowing the bit to stay on bottom. Similarly, as the rig moves down, the compensator must shut to keep the same relative bit position and weight on the bit.

The same digital sensors are attached to the compensators so that any change in movement can be taken into account, allowing accurate depth measurement (Fig. 15.1).

Flow-In Tracking Sensors

Flow-tracking sensors are used to monitor fluid-flow rate being applied downhole as well as the pump strokes required to achieve this flow rate. Data gathered from these sensors are essential inputs to calculating drilling-fluid hydraulics, well control, and cuttings lag. Monitoring changes in trends may also indicate potential downhole problems such as kicks or loss of circulation.

Two commonly used types are proximity and/or whisker switches. A proximity switch, activated either by an electromagnet (coil) or a permanent magnet, acts as a digital relay switch when it incorporates electrical continuity. A whisker switch, on the other hand, is a microswitch that is activated only when an external rod (called a whisker) forces a piston to raise a ball bearing to initiate contact against it (Fig. 15.2). Both types are digital counters; an increase in counts will correspond to a specific increase in both flow rate and pump rate.

Pressure-Tracking Sensors

Pressure-tracking sensors are used mainly to monitor surface pressure being applied downhole. Data gathered from these sensors are used either to validate calculated values or to confirm potential downhole problems such as washouts, kicks, or loss of circulation.

Two types of sensors are available, and both monitor pressure from a high-pressure diaphragm unit (knock-on head) located on either the standpipe or the pump manifold. The first sensor type derives its physical input from mud pressure expanding a rubber (or viton when high temperature is involved) diaphragm within the knock-on head. This expansion proportionally increases the pressure in the hydraulic-oil-filled system and, in doing so, relays the mud pressure to the appropriate transducer. The second sensor type makes a direct connection with the standpipe manifold itself (i.e., the transducer face is in contact with the mud; see Fig. 15.3).

Flow-Out Tracking Sensor

Commonly called a "flow paddle," this sensor measures flow rate coming out of the annulus using a strain-gauge analog transducer (Fig. 15.4). Changes in resistance values are directly related to either an increase or a decrease in mud-flow rate. This sensor provides an early warning of either a kick condition (sudden increase in flow rate) or a loss of circulation (sudden decrease in flow rate).

Drill-Monitor Sensors

Drill-monitor sensors monitor surface revolutions-per-minute (RPM) values, rotary torque, and hook load. The torque sensor is a clamp (Fig. 15.5) that sits around the main power cable to the top-drive system (TDS). It works on the principle of the deformation of Hall-effect chips by the magnetic field produced around the cable owing to the current being drawn through it (i.e., the greater the torque being produced as the pipe rotates, the greater the current drawn by the TDS and therefore the greater the Hall effect). (Note: the Hall effect is a transverse voltage caused by electric current flow in a magnetic field.) Torque changes can then be related to either formation lithology or downhole drilling problems such as pipe stick/slip or motor stalling.

A digital rotary sensor is similar to a proximity sensor used in a pump. It is shaped differently but acts on the same principle. RPM changes are used to drill the well efficiently and minimize downhole vibration effects.

The combined weight of the bit, bottomhole assembly (BHA), drillpipe, etc., is called the string weight (SW). The block weight (BW) is the weight of the lines and blocks (including top drive or kelly). When the bit is on bottom (i.e., drilling), the hook load is seen to reduce. The amount of weight suspended by the bottom of the hole is the amount of weight on bit (WOB), as shown below:


This hook-load sensor uses the same transducer type as in a pressure-tracking sensor. As the deadline experiences strain, the reservoir has load applied across it, which pressures the hydraulic fluid. This pressure increase is translated to a measurement value (Fig. 15.6). These measurement values are then correlated to potential downhole problems such as kicks or stuck pipe.

Pit-Monitor Sensor

Most pit-monitor sensors use ultrasonic transit time to measure mud level. The sensor is mounted over the pit above the maximum mud level and continuously sends a sonic wave that is reflected back to the receiver (Fig. 15.7). The transit-time measurement is then directly transformed to a volume measurement. This critical measurement is actively used to monitor potential kicks (rapid increase in pit volume) or loss of circulation (rapid decrease in pit volume).

Gas-Detection Sensors

The gas-detection sensors consist mainly of a gas trap, a pneumatic line linking the gas trap to the gas-detection equipment (which is found inside a mud-logging unit), and the gas-detection instruments (chromatograph and total-gas detectors).

The gas trap is basically a floating chamber with a rotating "agitator" inside. It works on the principle that mud flowing through the gas trap is agitated, thereby releasing the vast majority of any gases contained within the mud. This gas is then extracted from the trap through the unit sample line to be analyzed in the unit (Fig. 15.8).

The principle behind gas chromatography is simple. The gas from an oil well consists of several hydrocarbon components, ranging from light gases (methane) to oil. A gas chromatograph then takes a sample of gas and separates out some of these components for individual analysis. Typically, methane (C1) through pentane (C5) are the gases of interest. These can be plotted individually, or they may be used in gas-ratio analysis for reservoir characterization.

Most logging companies currently use a flame ionization detector (FID) gas chromatograph and total-gas detector (Fig. 15.9). The FID responds primarily to hydrocarbons and has the widest linear range of any detector in common use. The output signal is linear for a given component when concentrations vary from less than one part per million (ppm) to percent levels, and with care, resolution can be obtained in the low part-per-billion (ppb) range. The total-gas detector samples gas in a manner similar to that of a chromatograph, the only difference being that there is no column in the detector and, hence, no separation of components (i.e., it burns the "total" hydrocarbon gas sample as one). This also means that there is no injection time and, therefore, the gas is being sampled continuously (Fig. 15.8).

Additional Sensors

In addition, exploration and production companies may require specialized services such as formation-pressure monitoring and drilling optimization. To effectively support these services, additional sensors may be required such as fluid temperature, density, and conductivity. In areas of high H2S or CO2 gas, corresponding sensors that exclusively monitor these gases may be required as well.

MWD and LWD Applications


No other technology used in petroleum-well construction has evolved more rapidly than MWD and LWD. Early in the history of the oil field, drillers and geologists often debated conditions at the drillbit. With advances in electronic components, materials science, and battery technology, it became technically feasible to make measurements at the bit and transmit them to the surface so that the questions could begin to be answered.

Directional measurements were the first measurements to have commercial application, with almost all use in offshore, directionally drilled wells. As long as MWD achieved certain minimum-reliability targets, it was less costly than single shots, and it gained popularity accordingly. The dual challenges of MWD and LWD technology were reliable operation in the harsh downhole environment and achievement of wireline-quality measurements.

In the early 1980s, qualitative measurements of formation parameters were introduced, often based on early wireline technology. Coring points and casing points were selected using short normal-resistivity and natural gamma ray measurements, but limitations in these measurements kept them from replacing wireline for quantitative formation evaluation. In the late 1980s, the first rigorously quantitative measurements of formation parameters were made. Initially, the measurements were stored in tool memory, but soon the 2-MHz resistivity, neutron porosity, and gamma density measurements were transmitted to the surface in real time. By the early years of the new millennium, there was a rapid expansion of the types of measurement available while drilling, including acoustic, formation pressure, imaging, and seismic.

The terms MWD and LWD are not used consistently throughout the industry. Within the context of this section, the term MWD refers to directional-drilling measurements, and LWD refers to wireline-quality formation measurements made while drilling.

Measurement While Drilling (MWD)

Although many measurements are taken while drilling, the term MWD refers to measurements taken downhole with an electromechanical device located in the 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. All MWD systems typically have three major subcomponents: a power system, a telemetry system, and a directional sensor.

Power Systems. 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. Batteries can provide this power independent of drilling-fluid circulation, and they are necessary if logging will occur during tripping in or out of the hole.

Lithium-thionyl chloride batteries are commonly used in MWD systems because of their excellent combination of high-energy density and superior performance at MWD service temperatures. They provide a stable voltage source until very near the end of their service life, and they do not require complex electronics to condition the supply. These batteries, however, have limited instantaneous energy output, and they may be unsuitable for applications that require a high current drain. Although these batteries are safe at lower temperatures, if heated above 180°C, they can undergo a violent, accelerated reaction and explode with a significant force. As a result, there are restrictions on shipping lithium-thionyl chloride batteries in passenger aircraft. Even though these batteries are very efficient over their service life, they are not rechargeable, and their disposal is subject to strict environmental regulations.

The second source of abundant power generation, turbine power, uses the rig ’ s drilling-fluid flow. Rotational force is transmitted by a turbine rotor to an alternator through a common shaft, generating a three-phase alternating current (AC) of variable frequency. Electronic circuitry rectifies the AC into usable direct current (DC). Turbine rotors for this equipment must accept a wide range of flow rates to accommodate all possible mud-pumping conditions. Similarly, rotors must be capable of tolerating considerable debris and lost-circulation material (LCM) entrained in the drilling fluid.

Telemetry Systems. Mud-pulse telemetry is the standard method in commercial MWD and LWD systems. Acoustic systems that transmit up the drillpipe suffer an attenuation of approximately 150 dB per 1000 m in drilling fluid.[1] Several attempts have been made to construct special drillpipe with an integral hardwire. Although it offers exceptionally high data rates, the integral hardwire telemetry method requires expensive special drillpipe, special handling, and hundreds of electrical connections that must all remain reliable in harsh conditions. The explosion of downhole measurements has stimulated new work in this area,[2] and data rates in excess of 2,000,000 bits/second have been demonstrated.

Low-frequency electromagnetic transmission is in limited commercial use in MWD and LWD systems. It is sometimes used when air or foam is used as drilling fluid. The depth from which electromagnetic telemetry can be transmitted is limited by the conductivity and thickness of the overlying formations. Repeaters or signal boosters positioned in the drillstring extend the depth from which electromagnetic systems can transmit reliably.

Three mud-pulse telemetry systems are available: positive-pulse, negative-pulse, and continuous-wave systems. These systems are named for the ways in which their pulses are propagated in the mud volume. Negative-pulse systems create a pressure pulse lower than that of the mud volume by venting a small amount of high-pressure drillstring mud from the drillpipe to the annulus. Positive-pulse systems create a momentary flow restriction (higher pressure than the drilling-mud volume) in the drillpipe. Continuous-wave systems create a carrier frequency that is transmitted through the mud, and they encode data using the phase shifts of the carrier. Many different data-coding systems are used, which are often designed to optimize the life and reliability of the pulser because it must survive direct contact with the abrasive, high-pressure mud flow.

Telemetry-signal detection is performed by one or more transducers located on the rig standpipe. Data are extracted from the signals by surface computer equipment housed either in a skid unit or on the drill floor. Successful data decoding is highly dependent on the signal-to-noise ratio.

A close correlation exists between the signal size and the telemetry data rate; the higher the data rate, the smaller the pulse size becomes. Most modern systems have the ability to reprogram the tool’ s telemetry parameters and slow down data-transmission speed without tripping out of the hole; however, slowing the data rate adversely affects log-data density.

The most notable sources of signal noise are the mud pumps, which often create a relatively high-frequency noise. Interference among pump frequencies leads to harmonics, but these background noises can be filtered out with analog techniques. Pump-speed sensors can be a very effective method of identifying and removing pump noise from the raw telemetry signal. Lower-frequency noise in the mud volume is often generated by drilling motors. Well depth and mud type also affect the received-signal amplitude and width. In general, oil-based muds (OBMs) and pseudo-oil-based muds are more compressible than water-based muds; therefore, they result in the greatest signal losses. Nevertheless, signals have been retrieved without significant problems from depths of almost 9144 m (30,000 ft) in compressible fluids.

Directional Sensors. The state of the art in directional-sensor technology is an array of three orthogonal fluxgate magnetometers and three accelerometers. Although in normal circumstances, standard directional sensors provide acceptable surveys, any application in which uncertainty in the bottomhole location exists can be troublesome. Recent trends to drill longer and more complex wells focused attention on the need for a standard error model.

Work carried out by the Industry Steering Committee on Wellbore Accuracy (ISCWA) aimed to provide a standard method of quantifying positional uncertainties with associated confidence levels. The key sources of error were classified as sensor errors, magnetic interference from the BHA, tool misalignment, and magnetic-field uncertainty.

Along with uncertainties in the measured depth, bottomhole survey uncertainties are one contributor to errors in the absolute depth. Note that all methods of real-time azimuth correction require raw data to be transmitted to the surface, which imposes load on the telemetry channel.

The development of gyroscope (gyro)-navigated MWD offers significant benefits over existing navigation sensors. In addition to greater accuracy, gyros are not susceptible to interference from magnetic fields. Current gyro technology centers upon incorporating mechanical robustness, minimizing external diameter, and overcoming temperature sensitivity. The main application of the technology is in saving the rig time used by wireline gyros when carrying out kickoffs from areas affected by magnetic interference.

MWD and LWD System Architecture. As MWD and LWD systems have evolved, the importance of customized measurement solutions has increased. The ability to add and remove measurement sections of the logging assembly as wellsite needs change is valuable, thus prompting the design of modular MWD/LWD systems. Operational issues, such as fault tolerance, power sharing, data sharing across tool joints, and memory management, have become increasingly important in LWD systems. The introduction of 3D rotary-steerable systems, which often use the same telemetry channel as the LWD systems, has reinforced the links between directional drilling and LWD.

A natural division in system architecture exists for drill-collar outside diameters (ODs) of 4¾ in. or less. Smaller-diameter tool systems tend to use positive-pulse telemetry systems and battery-power systems and are encased in a probe-type pressure housing. The pressure housing and internal components are centered on elastomer standoffs and mounted inside a drill collar. Some MWD/LWD systems are retrievable and replaceable, in case tool failure or tool sticking occurs. Retrievability from the drill collar while in the hole often compromises the system’

s mounting scheme; therefore, these types of systems are typically less reliable. Because the MWD string can be changed without tripping the entire drillstring, retrievable systems can be less-reliable, but still cost-effective, solutions.

For collar ODs greater than 6¾ in., LWD systems are often turbine-powered. When used with other modules, interchangeable power systems and measurement modules must supply power and transmit data across tool joints. Often, a central stinger assembly protrudes from the lower collar joint and mates with an upward-looking electrical connection as the collar-joint threads are made up on the drillfloor. These electrical and telemetry connections can be compromised by factors such as high build rates in the drillstring and electrically conductive muds. Recent MWD/LWD designs ensure that each module contains an independent battery and memory so that logging can continue even if central power and telemetry are interrupted. Battery power and memory also enable logging to be performed while tripping out of the hole. As the quantities of data gathered downhole increase, time spent dumping data on the rig floor becomes a significant factor affecting the economics of wireline replacement. Increasing efforts will be made to make the data-download process more rapid over the coming years.

Drilling Dynamics. 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.[3] 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.

The most frequently measured downhole drilling-mechanics parameters are downhole mud pressures (PWD), WOB, torque on bit, shock, temperature, and caliper. 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 two main causes of NPT are hole problems (addressed by hydraulics measurement and wellbore-integrity measurement) and drillstring and tool failure (addressed by drillstring-integrity measurement).

To have a positive effect on drilling efficiency, drilling dynamics must have a quick feedback loop to the driller. Recent advances have made it possible to observe the cyclic oscillations in WOB.[4] If the oscillations exceed a predetermined threshold, they can be diagnosed as bit bounce, and a warning is transmitted to the surface. The driller can then take corrective action (such as altering WOB) and observe whether the bit has stopped bouncing on the next data transmission. Other conditions, such as "stick-slip" (intermittent sticking of the bit and drillstring with rig torque applied, followed by damaging release or slip) and torsional shocks, also can be diagnosed and corrected.

Another application is the use of downhole shock sensors, which count the number of shocks that exceed a preset force threshold over a specific period. This number of occurrences is then transmitted to the surface. Downhole shock levels can be correlated with the design specification of the MWD tool. If the tool is operated above design thresholds for a period, the likelihood of tool failure increases proportionally. Of course, a strong correlation exists between continuous shocking of the BHA and the mechanical failure that causes the drillstring to part. In most cases, lateral-shock readings have been observed at significantly higher levels than axial (along the tool axis) shock.

Hydraulics management with PWD has proved a key enabling technology in extended-reach wells where long tangent sections may have been drilled. Studies performed on such wells have shown that hole cleaning can be difficult and that cuttings can build up on the lower side of the borehole. If this buildup is not identified early enough, loss of ROP and sticking problems can result. A downhole annulus-pressure measurement can monitor backpressure while circulating the mud volume, and, assuming that flow rates are unchanged, it can identify precisely if a wiper trip should be performed to clean the hole. Fig. 15.10 shows an example in which cuttings have fallen out of suspension in the annulus during a period of sliding. Once rotation is resumed, the cuttings are agitated and suspended once more in the mudstream with a consequent increase in equivalent circulating density (ECD).

In wells in which there is a narrow window between pore pressure and fracture gradient (e.g., deep water), the uncertainties can be reduced greatly through the use of PWD and FTWD technology. Downhole measurement and transmission of leakoff tests eliminate errors associated with surface measurements. Real-time ECD measurements pinpoint key pressure parameters frequently and accurately. Finally, real-time measurement of pore pressure identifies exactly the mud weight required.

Tool Operating Environment and Tool Reliability. MWD systems are used in the harshest operating environments. Obvious conditions such as high pressure and temperature are all too familiar to engineers and designers. The wireline industry has a long history of successfully overcoming these conditions.

Most MWD tools can operate continuously at temperatures up to 150°C, with some sensors available with ratings up to 175°C. MWD-tool temperatures may be 20°C lower than formation temperatures measured by wireline logs, owing to the cooling effect of mud circulation, so the highest temperatures encountered by MWD tools are those measured while running into a hole in which the drilling-fluid volume has not been circulated for an extended period. In such cases, it is advisable to break circulation periodically while running in the hole. Using a Dewar flask to protect sensors and electronics from high temperatures is common in wireline, where downhole exposure times are usually short, but using flasks for temperature protection is not practical in MWD because of the long exposure times at high temperatures that must be endured.

Downhole pressure is less a problem than temperature for MWD systems. Most tools are designed to withstand up to 20,000 psi, with specialist tools rated to 25,000 psi. The combination of hydrostatic pressure and system backpressure rarely approaches this limit.

However, it is downhole shock and vibration that present MWD systems with their most severe challenges. Contrary to expectation, early tests using instrumented downhole systems showed that the magnitudes of lateral (side-to-side) shocks are dramatically greater than axial shocks during normal drilling. Modem MWD tools are generally designed to withstand shocks of approximately 500 G for 0.5 ms over a life of 100,000 cycles. Torsional shock, produced by stick/slip torsional accelerations, may also be significant. If subjected to repeated stick/slip, tools can be expected to fail.

Early work done to standardize the measurement and reporting of MWD-tool reliability statistics focused on defining a failure and dividing the aggregate number of successful circulating hours by the aggregate number of failures. This work resulted in a mean-time-between-failure (MTBF) number. If the data were accumulated over a statistically significant period (typically 2,000 hours), meaningful failure-analysis trends could be derived. As downhole tools became more complex, however, the Intl. Assn. of Drilling Contractors (IADC) published recommendations on the acquisition and calculation of MTBF statistics.[5]

Logging While Drilling (LWD)

Electromagnetic Logging. The electromagnetic-wave resistivity (EWR) tool has become the standard of the LWD environment. The nature of the electromagnetic measurement requires that the tool typically be equipped with a loop antenna that fits around the OD of the drill collar and emits electromagnetic waves. The waves travel through the immediate wellbore environment and are detected by a pair of receivers. Two types of wave measurements are performed at the receivers. The attenuation of the wave amplitude as it arrives at the two receivers yields the attenuation ratio. The phase difference in the wave between the two receivers is measured, yielding the phase-difference measurement. Typically, these measurements are then converted back to resistivity values through the use of a conversion derived from computer-modeling or test-tank data.

The primary purpose of resistivity-measurement systems is to obtain a value of true formation resistivity (Rt) and to quantify the depth of invasion of the drilling-fluid filtrate into the formation. A critical parameter in MWD measurements is formation exposure time (FET), the time difference between the drillbit disturbing in-situ conditions and sensors measuring the formation. MWD systems have the advantage of measuring Rt after a relatively short FET, typically 30 to 300 minutes. Interpretation difficulties sometimes can be caused by variable FET, and logs should always contain at least one formation exposure curve.

Knowledge of FET does not, however, rule out other effects. Fig. 15.11 shows a comparison between phase and attenuation resistivity with an FET of less than 15 minutes and a wireline laterolog run several days later. Even the attenuation resistivity has been affected dramatically by invasion, reading about 10 Ω•m, whereas the true resistivity is in the region of 200 Ω•m.

Another example, shown in Fig. 15.12, illustrates invasion effects in the interval from 2995 to 3025 m. Very deep invasion by conductive muds in the reservoir has caused the 2-MHz tool to read less than 10 Ω•m in a 200-Ω•m zone. Between 3058 and 3070 m, the deep invasion has caused the hydrocarbon-bearing zone to be almost completely obscured. Only by comparison with the overlying, deeply invaded zone from 2995 to 3025 m was this productive interval identified.

Similarly, LWD data density is dependent upon ROP. Good-quality logs typically have graduations or "tick" marks in each track to give a quick-look indication of measurement-density variations with respect to depth.

Early resistivity systems emphasized the difference between the phase and attenuation curves and suggested that one curve was a "deep" (radius of investigation) curve and another was a "medium" curve. Difficulties with this interpretation in practice[6] led to the development of a generation of tools that derive their differences in investigation depth from additional physical spacings. Identification and presentation of invasion profiles, particularly in horizontal holes, can lead to a greater understanding of reservoir mechanisms. Many of the applications in which LWD logs have replaced wireline logs occur in high-angle wells. This trend leads to an emphasis on LWD for certain specialist-interpretation issues.

The depth of investigation of 2-MHz-wave resistivity devices is dependent on the resistivity of the formation being investigated. The measurement response of a device (both phase and attenuation) with four different receiver spacings is shown in Fig. 15.13. The region measured by the 25-in. sensor (R25P) is based on a 25-in. diameter of investigation in a formation known to have a resistivity of 1 Ω•m. The phase measurement looks deeper (away from the borehole) and loses vertical resolution as the charts progress to greater resistivities. In contrast, the amplitude ratio at first looks deeper than the phase measurement, and the expected penalty of poorer vertical resolution is paid. In the most resistive case, the attenuation measurement shows a 129-in. diameter of investigation. Many electromagnetic tools transmit at variable frequencies (2MHz, 1MHz, and 400kHz) to capture the benefit of variable depths of investigation and to minimize eccentering effects. Some systems can yield more than 20 resistivity measurements per data point, from which a greater understanding of reservoir characteristics can be derived.

Dielectric effects are responsible for some discrepancies between phase and attenuation resistivity measurements. Errors are greatest in the most resistive formations. Different approaches to this issue have been taken by vendors, with some opting to assume a set dielectric-constant value such as "10," whereas others have chosen to vary the dielectric constant as a function of formation resistivity.

Further discrepancies between phase and attenuation resistivity measurements also may be attributed to the effects of formation anisotropy. Anisotropy may also be responsible for the separation of measurements taken at different spacings or at different frequencies. This can be easily misinterpreted as an invasion effect. Anisotropy effects are caused by differences in the resistance of the formation when measured across bedding planes (Rv) or along bedding planes (Rh). An assumption is generally made that Rh is independent of orientation. As borehole inclination increases, the angle between the borehole and formation dip typically increases. When this relative angle exceeds approximately 40°, resultant effects become significant. Anisotropy has the effect of increasing the observed resistivity above Rh. Effects are greater on the phase measurements than the attenuation measurements and greater on longer receiver spacings than short ones. It is important to understand that separation between resistivity curves caused by conductive invasion will result in the deep-resistivity-curve reading less than or equal to the true formation resistivity, whereas resistivity-curve separation caused by anisotropy will lead to measured deep resistivities being greater than true formation resistivity. The importance of trying to resolve these effects has led to a substantial and ongoing effort by the industry to develop robust, fast resistivity-modeling packages.

Wave resistivity tools are run in most instances in which LWD systems are used, but toroidal resistivity measurements are desirable under some circumstances.[7] Toroidal resistivity tools typically consist of a transmitter that is excited by an AC, which induces a current in the BHA. Two receivers are placed below the transmitter, and the amount of current measured exiting the tool to the formation between the receivers is the lateral (or ring) resistivity. The amount of current passing through the lower measuring point is the bit resistivity (Fig. 15.14). Because of the large number of variables involved, bit resistivity measurements have been difficult to quantify, but measurements from current-generation tools now compare favorably with wireline laterolog measurements. In formations with high resistivities (greater than 100 Ω•m), measurements with a toroidal resistivity tool may be more appropriate than measurements with other tool types. An important side benefit of this technology is its insensitivity to anisotropic effects.

The log example in Fig. 15.15 shows a case in which 2-MHz measurements have saturated because of the high salinity of the mud. If the drilling fluid is conductive or if conductive invasion is expected, then toroidal resistivity measurement is preferred. If early identification of a coring or casing point is crucial, then bit resistivity measurements give a good first look. In geosteering applications, toroidal bit resistivity measurements are an immediate indicator of a fault crossing.

The first formation images while drilling were acquired through the use of toroidal resistivity tools. When a small-button electrode is placed on the OD of a stabilizer, the current flowing through that electrode can be monitored. The current is proportional to the formation resistivity in the immediate proximity. Effective measurements are best taken in salty muds with resistive formations. Vertical resolution is 2 to 3 in., and azimuthal resolution is less than 1 in. [8] With the tool rotating at least 30 RPM, internal magnetometer readings are taken, and resistivity values are scanned and stored appropriately. A sample of the data is pulsed to the surface in real time to provide a low-resolution measurement. At the surface, tool memory is dumped, and the data are related to the correct depth. Quality checks are made to ensure that poor microdepth measurements are not affecting the reading.

Imaging while drilling can provide a picture of formation structure, nonconformities, large fractures, and other visible formation features. Azimuthal-density devices may also be processed to provide dip information. Imaging is increasingly used as in geosteering applications. Real-time dip calculations can be carried out in structures with relatively high apparent dips.

Nuclear Logging. Gamma ray measurements have been made while drilling since the late 1970s. These measurements are relatively inexpensive, although they require a more sophisticated surface system than is needed for directional measurements. Log plotting requires a depth-tracking system and additional surface computer hardware.

Applications have been made in both reconnaissance mode, where qualitative readings are used to locate a casing or coring point, and evaluation mode. Verification of proper MWD gamma ray detector function is normally performed in the field with a thorium blanket or an annular calibrator.[9]

The main differences between MWD and wireline gamma ray curves are caused by spectral biasing of the formation gamma rays and logging speeds.[10]

Neutron porosity (Φ) and bulk-density (ρb) measurements in LWD tools are often combined in one sub or measurement module. Reproducing wireline-density accuracy has proven to be one of the most difficult challenges facing LWD tool designers. Tool geometry typically consists of a cesium gamma ray source (located in the drill collar) and two detectors, one at a short spacing from the source and one at a long spacing from the source. Gamma counts arriving at each of the detectors are measured. Count rates at the receivers depend upon the density of the media between them. Density measurements are severely affected by the presence of drilling mud between the detectors and the formation. If more than 1 in. of standoff exists, the tendency of the gamma rays to travel the (normally less dense) mud path and "short circuit" the formation-measurement path becomes overwhelming. The gamma ray short-circuit problem is solved by placing the gamma detectors behind a drilling stabilizer. With the detector mounted in the stabilizer, in gauge holes, the maximum mud thickness is 0.25 in., and the mean mud thickness is 0.125 in. Response of the tool is characterized for various standoffs in various mud weights, and various formations and corrections are applied.

Placing the gamma detector in the stabilizer does have some drawbacks. Detector placement can affect the directional tendency of the BHA. In horizontal and high-angle wells, in which the density measurement is most frequently run, the stabilizer can sometimes hang up and prevent weight from being properly transferred to the bit. It is important to note that in enlarged boreholes, gamma detectors deployed in the drilling stabilizer may not accurately measure density.

Assuming that an 8½-in. bit and an 8¼-in. density sleeve are used and the tool is rotating slowly in the hole, the average standoff is 0.125 in., and the maximum standoff is 0.25 in. If, however, the borehole enlarges to 10 in., the average standoff increases to 0.92 in., and the maximum standoff increases to 1.75 in. In big hole conditions, very large corrections are required to obtain an accurate density reading. An example of an erroneous gas effect using older-generation neutron density devices in an enlarged 9 7/8-in. hole is shown in Fig. 15.16.

Varying approaches have been developed to obtain accurate density measurements in enlarged boreholes. Most widely accepted are the azimuthal density method, the rapid-sampling method, and the constant-standoff method. Azimuthal density links the counts to an orientation of the borehole by taking regular readings from a magnetometer.[11] When this method is used, the wellbore (which is generally inclined) is divided into multiple segments (often 4, 8, or 16). Incoming gamma counts are placed into one of the bins. From this, the segment densities and an average density are obtained. A coarse image of the borehole can be obtained when beds of varying density arrive in one segment before another. Azimuthal density can be run without stabilization, but it relies on the assumption that standoff is minimal in the bottom quadrant of the wellbore.

Another method is referred to as rapid sampling. In this method, statistical techniques are applied to rapid samples taken on incoming gamma counts. When the tool is rotating and there is a significant difference between mud weight and formation density, there will be an unexpectedly high standard deviation. This is used to create limits for a high- and low-count rate bin. The total counts arriving in the low-count rate bin are used to calculate a rapid sample density.

Another method of obtaining density in enlarged boreholes relies on the constant measurement of standoff using a series of ultrasonic calipers.[12] A standoff measurement is made at frequent intervals, and a weighted average is calculated. High weight is given to gamma rays arriving at the detector when the standoff is low, and low weight is given to those gamma rays that arrive when the standoff is high (Fig. 15.17). This method attempts to replicate the wireline technique of dragging a tool pad up the side of the borehole. The constant-standoff method can also be applied to neutron porosity tools.

All density measurements suffer if the drillstring is sliding in a high-angle or horizontal borehole with the gamma detectors pointing up (away from the bottom of the wellbore). To overcome this problem, orientation devices are often inserted in the toolstring. As the BHA is being made up, the offset between the density sleeve and the tool face is measured. Adjusting the location of the orientation device allows the density measurement to be set to the desired offset. While the drillstring is sliding to build angle, the density detectors can be oriented downward by setting the offset to 180°.

LWD porosity measurements use a source (typically americium beryllium) that emits neutrons into the formation. Neutrons arrive at the two detectors (near and far) in proportion to the amount they are moderated and captured by the media between the source and detectors. The best natural capture medium is hydrogen, generally found in the water, oil, and gas in the pore spaces of the formation. The ratio of neutron counts arriving at the detectors is calculated and stored in memory or transmitted to the surface. A high near/far ratio implies a high concentration of hydrogen in the formation and, hence, high porosity.

Neutron measurements are susceptible to a large number of environmental effects. Unlike wireline or LWD density measurements, the neutron measurement has minimal protection from mud effects. Neutron source/detector arrays are often built into a section of the tool that has a slightly larger OD than the rest of the string. The effect of centering the tool has been shown[13] to have a dramatic influence on corrections required compared to wireline (Fig. 15.18). Standoff between the tool and the formation requires corrections of approximately 5 to 7 porosity units (p.u.) per inch. Borehole-diameter corrections can range from 1 to 7 p.u./in. depending on tool design. Neutron porosity measurements are also affected by mud salinity, hydrogen index, formation salinity, temperature, and pressure. However, these effects are generally much smaller, requiring corrections of approximately 0.5 to 2.0 p.u.

Statistical effects on nuclear measurements are quite significant. Uncertainties increase as ROP increases. LWD nuclear measurements can be performed either while drilling or while tripping. LWD rates vary because of ROP changes, but they typically range from 15 to 200 ft/hr, whereas instantaneous logging rates can be significantly higher. Tripping rates can range from 1,500 to 3,000 ft/hr. Typical wireline rates are approximately 1,800 ft/hr and constant. Statistical uncertainty in LWD nuclear logging also varies with formation type. In general, log quality begins to suffer increased statistical uncertainties at logging rates above 100 ft/hr. This limits the value of logging while tripping to repeating formation intervals of particular interest.

Acoustic Logging. 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. Compared to the wireline mechanical caliper, the ultrasonic caliper provides readings with much higher resolution.

Acoustic-velocity data are important in many lithologies for correlation with seismic information. These data also can be a useful porosity indicator in certain areas. Shear-wave velocity also can be measured and used to calculate rock mechanical properties. Four main challenges in constructing an LWD acoustic tool are described as follows[14]:
  • Preventing the compressional wave from traveling down the drill collar and obscuring the formation arrival. Unlike wireline tools, the bodies of LWD tools must be rigid structural members that can withstand and transmit drilling forces down the BHA. Therefore, it is impractical to adopt the wireline solution of cutting intricate patterns into the body of the tool to delay the arrival of the compressional wave. Isolator design is crucial and is still implemented to enable successful signal processing in a wide variety of formations, particularly the slower ones[

those having a compressional delta time (ΔtC) slower than approximately 100 μsec ] .

  • Mounting transmitters and receivers on the OD of the drill collar without compromising their reliability.
  • Eliminating the effect of drilling noise from the measurement.
  • Processing the data so that they can be synthesized into a single ΔtC and that this data point can be transmitted by mud pulse. This is particularly challenging given the large quantity of raw data that must be acquired and processed.

In its most basic form, an acoustic-logging device consists of a transmitter with at least two receivers mounted several feet away. Additional receivers and transmitters enhance the measurement quality and reliability. The transmitters and receivers are piston-type piezoelectric stacks that operate at a higher frequency than typical drilling noise. Drilling noise has been shown to be concentrated in the lower frequencies (Fig. 15.19). A data-acquisition cycle is performed as the transmitter fires and the waveforms are measured and stored. Arrival time is measured from the time the transmitter fires until the wave arrives at each receiver. From this acoustic-velocity information, the tool ’

s downhole data-processing electronics, using digital signal-processing techniques, calculate the formation slowness or ΔtC. This value is the reciprocal of velocity and is expressed in units of μsec/ft. Waveforms also are stored in tool memory for later processing at the surface when the memory is dumped. Developments in acoustic LWD have focused on increasing the array of transmitters and receivers and operating with dual frequencies. These have shown much better ability to provide shear measurements when the shear velocity is greater than the mud velocity. When the converse condition exists, there is no shear-wave arrival, and corrections have to be applied to other modes to derive shear. The processing required both at surface and downhole has become ever more sophisticated.[15]

The log in Fig. 15.20 shows an example of a log processed at the surface from waveforms stored downhole. Here, the ΔtC values have been reprocessed from the stored waveforms. When compared with a wireline log, this log is clearly less affected by the washout below the shoe and in the shale at X235 measured depth. LWD acoustic devices, by nature of their size, fill a much larger portion of the borehole than wireline devices and are less susceptible to the effects of borehole washout. Synthetic seismograms can be produced when acoustic and density data are combined, which yield valuable correlations with seismic information. Nevertheless, synthetic seismograms derived from LWD suffer from the same frequency-dispersion issues as wireline when making comparisons with data acquired from surface seismic.

To deal with this issue, LWD-tool designers have made progress in developing seismic-while-drilling systems that can be used to provide seismic checkshots. In this system, sensitive instruments are placed in a downhole sub connected to the telemetry system. A surface gun is located on the surface. If the well is vertical or near vertical, this might be on the rig; otherwise, it will be on a boat located above the receivers. When the gun is fired, which is typically at a connection to ensure quiet conditions, the arriving waveform is detected by the instrumentation and stored in memory. Processing is carried out, and information is sent to the surface, from which the one-way seismic travel time can be derived. One of the key challenges in seismic while drilling is overcoming the lack of an electrical link between surface guns and downhole receivers.

Seismic while drilling has the potential to reduce the positional uncertainty in the earth model. The main applications are in exploration wells or where there is limited confidence in the velocity model. Data can be acquired at connections either while drilling or while pulling out the hole. The cost of locating a boat on a station with guns for the duration of drilling may be an impediment to routine operations of this sort in deviated wells. Data quality is not currently thought to be adequate for processing for vertical-seismic-profile purposes.

Magnetic-Resonance-Image (MRI) Logging. Another measurement that is in the process of making the transition to a while-drilling environment is magnetic resonance. The use of chemical nuclear sources downhole has been a logistical and management headache. MRI, by measuring in real time the free-fluid, capillary-bound-water, and clay-based-water volumes, offers an alternative, lithology-independent porosity measurement in complex lithologies. It can be used for geosteering and geostopping when sufficient productive formation has been exposed to the wellbore.

Like most measurements, at an initial phase there are specialist applications that are more susceptible to realizing the value of magnetic-resonance logging. In this case, applications of interest are the evaluation of shaly sands and low-resistivity pays, particularly in deepwater and exploration wells.

Tool designers have had to meet a number of challenges in converting the measurement to a drilling environment. Shock, vibration, rotation, and general tool movement mitigate against the use of the T2 measurement, which is sensitive to excessive motion while drilling. As a result, the T1 measurement has been adopted as a de facto standard in real-time (reconnaissance) applications. This is supplemented by T2 measurements when a more-detailed characterization of the formation is required. Devices in use investigate a rotationally symmetric volume with a diameter of 14 in. They benefit from the generally lower ROP experienced in the drilling environment. Some care needs to be taken in the relative position of the large permanent magnets in the magnetic-resonance device and the magnetometers in the directional module, although correction algorithms can be used to eliminate interference.

Formation Testing While Drilling

FTWD has a broad interest in all the different disciplines involved in drilling and evaluating the well. For the drilling engineer and the geologist, a number of different approaches to the problem of acquiring formation-pressure data while drilling have been tried. A sophisticated subindustry has evolved aimed at pore-pressure prediction using proven methods such as "D exponent" (see the chapter on Drilling Geology in this section of the Handbook), connection gas, and cuttings analysis. Real-time formation-pressure data will, at a minimum, allow more-frequent calibration of pressure models. For the reservoir engineer, it opens the possibility of "barosteering"; where there is doubt in mature fields about whether a compartment has been drained, immediate measurements can be taken and a decision reached about whether to geostop or geosteer for a more-promising compartment. It allows immediate testing to verify whether geological barriers are sealing, and it opens the possibility of pressure profiling to identify (from gradient information) types of fluids present and contact points. For the drilling engineer, the precise identification of mud weight needed offers potential for improvements in ROP. For all, particularly in high-angle wells, it offers the prospect of eliminating the need to acquire costly pressure measurements by pipe-conveyed wireline techniques. All will have concerns about the time required to take a test, especially if no circulation is permitted because those conditions increase the likelihood of tool sticking.

Two different approaches have been taken to the problem of acquiring the data. The first adopts the traditional testing approach associated with drillstem tests (DSTs). In this manifestation, dual inflatable packers are mounted on the outside of the tester. When a zone of interest is reached, a command is issued from the surface, and the packers are inflated to isolate the zone of interest. The drawdown pump is activated to remove a controlled volume of fluid from the annulus between the packers. Circulation above the tool can be maintained with a diverter sub, and pressure data continue to be pumped to the surface until sufficient data are acquired. One advantage of an approach of this sort is that it investigates a greater depth in the formation and is not susceptible to seating problems in laminated formations in which there may be a chance of landing a probe on a hard streak. Conversely, the exposure of relatively large areas of inflatable packers to the wellbore environment calls for careful design and handling to avoid damage.

An alternative approach to acquiring data follows the traditional wireline approach.[16] In this, a small extendable probe with an elastomeric seal is applied to the formation on command from the surface. An internal piston is then actuated to draw down the pressure by as much as 8,000 psi below hydrostatic pressure. Formation fluids then flow into the probe and build up the pressure in the probe to the formation pore pressure. Pressure measurements are taken both with fast-acting strain gauges and high-accuracy quartz gauges. Tests can be acquired either with the pumps on or off. The drawdown and buildup profiles also provide information used in the determination of formation permeability. The reduced area associated with the probe should reduce the chances of drilling damage, and the smaller volumes involved in the test should provide reasonable data in a shorter time period (although from a shallower depth) than the DST-type design.

Early indications are that FTWD tools will be adopted quite rapidly by the industry provided that they can be shown to provide high-quality, reliable measurements without significantly increasing loss-in-hole risks.

Depth Measurement. Good, consistent knowledge of the absolute depth of critical bed boundaries is important for geological models. Knowledge of the relative depth from the top of a reservoir to the oil/water contact is vital for reserves estimates. Nevertheless, of all the measurements made by wireline and LWD, depth is the one most taken for granted (despite being one of the most critical). Depth discrepancies between LWD and wireline have plagued the industry.

LWD depth measurements have evolved from mud-logging methods. Depth readings are tied, on a daily basis, to the driller ’ s depth. Driller’ s depths are based on measurements of the length of drillpipe going in the hole and are referenced to a device for measuring the height of the kelly or top drive with respect to a fixed point. These instantaneous measurements of depth are stored with respect to time for later merging with LWD downhole-memory data. The final log is constructed from this depth merge. On fixed installations, such as land rigs or jackup rigs, a number of well-documented sources exist that describe environmental error being introduced in the driller’ s depth method. Floating rigs can introduce additional errors. One study suggested that the following environmental errors would be introduced in a 3000-m well[17]:

  • Drillpipe stretch: 5- to 6-m increase.
  • Thermal expansion: 3- to 4-m increase.
  • Pressure effects: 1- to 2-m increase.

Floating rigs have special problems associated with depth measurements. Errors are caused principally by rig heave and tidal action. In LWD, these effects are sufficiently overcome by the placement of compensation transducers in locations fixed with respect to the seabed.

Wireline measurements are also significantly affected by depth errors, as shown by the amount of depth shifting required between logging runs, which are often performed only hours apart. Given the errors inherent to depth measurement, if wireline and LWD ever tagged a marker bed at the same depth, it would be sheer coincidence.

Environmentally corrected depth would be a relatively simple measure to implement in LWD. Although this measure would certainly reduce depth errors, it probably would not eliminate them. The "cost" of corrected depth is an additional depth measurement that must be monitored. Driven by the increasing availability of wireline-quality measurements while drilling, the industry is beginning to realize the need to adopt a new process for measuring depth accurately. Running a cased-hole gamma ray during completion operations is a practice adopted by many operators as a check against LWD depth errors and lost-data zones.

Drilling-Data Management and Reporting


From the late 1960s and early 1970s to the present, oilfield drilling and well-services rigs and work units have seen an increase in electronic data-recording, monitoring, engineering, and reporting systems that have replaced manual or mechanical recording systems and hard-copy paper reports completed by rigsite personnel. Implementation of service-company, operator, and rig-contractor software systems has enabled the electronic capture of drilling and well-services operations and equipment data that provide significant value to engineers involved in operations monitoring, data analysis, well planning, and external reporting. Live capture of real-time data fed into engineering and geoscience systems has enabled asset-team members to make more-informed 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.

Rigsite Software Systems

Service Company. The most comprehensive data-acquisition systems present at the rigsite are provided by service companies such as mud-logging, MWD/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. In addition to collating sensor readings, service-company software systems also enable various interpretative reports to be entered into the system depending on the service provided, such as mud logs, drilling-data logs, pressure logs, wellsite geology, mud, and cementing. 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. Rig-contractor personnel may use any number of commercially available electronic tour-sheet applications that enable them to complete their Intl. Assn. of Drilling Contractors (IADC)/Canadian Assn. of Oilwell Drilling Contractors (CAODC) report electronically on a PC rather than fill in traditional paper-based forms. These electronic tour-sheet applications may be hooked up to the rig’ s own data-acquisition system, which records surface-sensor readings from all rig equipment, such as hookload, WOB, ROP, kelly or stand height, surface torque and RPM, pump pressure, pump flow rate, pump speed, and pit volumes, all in an electronic drilling recorder (EDR) system.

Increasingly, data from rig-contractor EDR systems and service-company systems are being supplied live back to the beach or office and made available as a service to operators through commercial Website offerings that provide online or offline logs of drilling and well-services data.

Operator. From an operator’ s perspective, rigsite data acquisition typically consists of daily operations morning reporting systems, survey-data management, and well-engineering software systems.

Operations Reporting. The daily operations report is the operator’ s record of the construction, completion, workover, or abandonment operation occurring on the well. The daily operations report is a comprehensive record of all daily activity and equipment operations that occur over a reporting interval. Current operations status, progress and current formation/lithology information, time summary information, and daily cost, survey, drilling fluids, bit, BHA, mud-cleaning-equipment, safety, personnel, support-craft, and weather information are typically entered. Rigsite supervisors or field engineers enter a number of associated reports depending on the type of well operation, rig equipment used, or operator and regional government reporting requirements.

For the drilling process, reports are typically entered for daily operations, pipe tallies, casing, cementing, wellsite geology, coring, logging, and DSTs when these operations occur. For completion and workover operations, engineers enter reports for downhole wellbore equipment, wellhead installations, perforation, stimulation, remedial cementing, production tests, and pressure surveys. For artificial-lift completions, engineers will enter detailed report information for conventional pumps, gas lift, electrical submersible pumps, progressing-cavity pumps, and hydraulic-lift completions. For all types of operations, performance is measured through detailed, planned (vs. actual) activity tracking, NPT analysis, and equipment-failure analysis. Operational learnings are recorded and collated in lessons-learned systems associated with key data parameters so that this information may be shared across an organization and used for future well-performance assessments or well-planning operations. Health, safety, and environmental assessment and monitoring of the well operation and fluids/chemicals used are an increasingly important part of the well-operations reporting process.

Survey-Data Management. Correct placement of the wellbore to meet geological and production requirements is the primary goal of any drilling operation. In the office, directional-well planners will use a survey-data-management solution to design the well trajectory to intersect one or more drilling targets, avoid adjacent wellbores within safe collision-avoidance tolerances, and not exceed other well-design criteria. At the rigsite, the system is used to record survey-station data for specific survey-tool runs. Survey-tool error models are used to calculate positional uncertainty down the wellbore. The definitive wellpath is updated continuously to calculate the most accurate well trajectory, compare planned vs. actual well trajectory, and perform anticollision risk assessment for any nearby wellbores. Tools are also available to quality assess the survey data to ensure that survey-station data are within acceptable tolerances.

Well Planning/Drilling Engineering. Many commercial software vendors provide a suite of drilling-engineering applications that enable casing/tubing design, torque/drag, hydraulics, hole cleaning, swab/surge, well control, cementing, drillstring-vibration/directional-performance, and wellbore-stability analysis to be performed. These engineering systems enable well planners to design the well within concise engineering constraints. These planned models are updated during the drilling process to monitor the well and to ensure that design constraints are not exceeded.

Drilling/Rigsite Simulators. The electronic capture of real-time rig-operations information into rig or drilling simulations or modeling systems enables the users of these systems to "play back" the well operation so that detailed research or analysis may be performed. This enables researchers to simulate the use of new technologies or monitoring systems before their actual use at the rigsite. The increased availability of usable data sets provided by various rigsite data-acquisition vendors in WITS or Wellsite Information Transfer Standard Markup Language (WITSML) format is enabling operators to store this information consistently within their own data stores. Previously, service companies could provide real-time information only in proprietary or other nonstandard formats, making consistent storage of this data for reuse much more difficult.

Other Software Systems. Associated rigsite systems used by operators include site construction and reclamation software and environmental-assessment and -monitoring systems. The rig contractor and/or the operator may also be using human resources systems and materials/inventory-tracking software systems to manage the flow of personnel and materials to and from the rigsite. A new software area at the rigsite and in the office is e-invoicing, where service-company and materials/equipment vendors invoice the operator electronically using Extensible Markup Language (XML) -based systems instead of traditional paper invoices or field tickets.

Enter It Once! The Value of Integration

Historically, all these types of rigsite software systems have been separate applications or application suites hosted on separate data stores and IT infrastructures with little to no connectivity between them. These software systems did not integrate because they were used by different companies, teams of users, or single users who did not expect integration because they were using their software to perform specific tasks. With increasingly complex and costly drilling and well-services operations and technologies, all office rigsite personnel who use well-information management systems today expect to use innovative suites of applications that integrate across the geoscience, well-engineering, and rigsite-management disciplines.

The current trend in oilfield software development is to provide integrated systems used by multiple well-engineering disciplines that support numerous engineering workflows that meet rigsite monitoring requirements. These systems use a single common repository of well data that covers an ever-increasing extent of the well life cycle from initial wellsite environmental surveys, initial well construction, and completion to production field-data capture, accounting, economics, workover, abandonment, site reclamation, and follow-up environmental monitoring. Engineers expect to see efficiencies resulting from shared use of a common data store that enables them to more efficiently perform their specific tasks or perform analysis without having to duplicate or transfer information entered elsewhere.

Where systems do not share the same data store, field users expect to be able to import or exchange data between systems with no loss of content or data quality. To meet this requirement, electronic data-exchange systems have evolved from the 1980s WITS standard and various system-specific methods to modern XML-based systems. Additionally, standardization of software systems on the Windows operating system enables rigsite systems to exchange information through Microsoft OLE and ODBC standard methods.

Value from Data

The shared use of information at the rigsite or data transmitted in real time or offline to the office is used for a variety of purposes that provide real value to the operator. Operators implement corporate stores of this information to realize several goals:

  • Enabling an open database to reliably store historical drilling, completion, and well-services information in a common data store.
  • Providing instant access to data across the organization.
  • Supporting consistent rigsite data capture and reporting across all operations.
  • Supporting the implementation of consistent data-quality methods and procedures.
  • Providing consistent output reports and electronic output formats.
  • Supporting multiple units of measure.
  • Enabling operations engineers to remotely oversee drilling and well-services operations.
  • Enabling operations statistics and performance benchmarks to be performed so that procedures requiring improvement can be identified.
  • Providing well planners with accurate historical operations-performance data with which to perform statistical risk analysis for future well operations.
  • Making informed decisions with greater effectiveness at the time they have to be taken.

Output Reporting. From an operator ’ s perspective, the most immediate benefit of rigsite software systems that collate information is to enable consistent output reporting through all types of well operations and across all geographic areas. Daily well-operations information is required by operations engineers supervising well progress, fellow asset-team members, senior managers, and members of associated disciplines such as materials management, accountancy, and health, safety, and environment. Traditionally, operations reports have been faxed in from the rig or completed in the office using information provided from the rig by telephone. Increasingly, information-management systems enable operations-report data sets to be sent electronically from the rig to the office so that the data may be used in town. Hard-copy reports can then be distributed from the office, often generated through automated systems that filter data. Increasingly, electronic output report formats such as Adobe Acrobat Reader (PDF) and dynamically populated Websites are used to disseminate well-operations information across the various disciplines.

In many regions, local or federal government agencies require well-operations and equipment information to be submitted as hard-copy or electronic reports so that the government has an accurate record of the well operation and completion. Hard-copy reports in government-required formats are easily generated from electronic information systems. Digital data-submission files also can be extracted from electronic data stores and formatted to the government requirement so that they may be uploaded directly into government master data stores. Examples of digital data submissions include the Norwegian Petroleum Directorate DDRS system for daily operations data and the Alberta Energy & Utilities Board Guide 59 Standard for event-summary data for each phase of well operations.

Wellbore Schematics. Historical wellbore-equipment visualization based on field-entered data is a key requirement for many operators, who demand accurate wellbore-equipment schematic diagrams and reports to be automatically drawn from well-operations data. Some systems enable wellbore drawings to be generated directly from the operations reporting system data store for any phase of the wellbore life history. Other products enable detailed wellbore-equipment schematic diagrams to be constructed manually and associated to planned or actual equipment parameters. A completion manager enables slick wellbore drawings to be manually constructed. Well-services engineers in the office and in the field about to go on a job require the ability to quickly generate an up-to-date wellbore drawing that enables them to plan their next job.

Data Analysis. The primary function of a well-operations database is to enable analysis of the captured data so that they may be used to improve future well operations. This enables the operator to use the information as a real asset that provides value. A well-organized well-operations data model should easily facilitate analysis through use of simple Structured Query Language (SQL) queries, summary output reports, and sophisticated data-analysis tools. This enables operator engineers to perform any kind of structured query for a variety of analyses, performance benchmarking, research, or collation of statistical information for corporate or government reporting. Typically, commercial software systems now provide data-analysis tools with which queries and analyses can be shared across the network. These systems store queries with the data so that they can be reused at any time.

Performance Benchmarking. Well planners and operations engineers are often required to analyze the cost or operations performance of their drilling and/or well-services operations. These analyses may be performed to identify areas for improvement, as well as to identify operators or operations that are performing above or below standard, or they may be performed to compare various operator or contractor performances. Analyses also may be performed to compare different well-construction methods or technologies to evaluate their effectiveness. The electronic capture of data at the rigsite integrated into corporate reporting systems or data stores enables the operator to perform these types of analysis.

Technical-Limit Well Planning and Operations. A high-profile well-planning and operations-monitoring method used by an increasing number of operators is technical-limit drilling (TLD) or well services. The technical limit is defined as the most optimal well-construction process that enables the well to be drilled or serviced safely in as short a time as possible. The method is used to challenge well-construction teams to reach their objective safely while identifying performance bottlenecks or procedures that may be performed more quickly with other methods or technologies while achieving the same result. Many operators have formal technical-limit initiatives in place that enable the entire well-construction team to improve operational performance. A significant part of the TLD process is the historical analysis of comparable offset-well data, which enables the well-planning team to identify the most efficient procedures and best performance for each phase of the well operation. This analysis of historical data is enabled through the capture of operations or activity information at the rigsite. Without offset-well data, identification of the desired "gold medal" performance is difficult if not impossible.

With a technical-limit operation plan defined for the new well operation, the actual execution of the well program may be compared to the technical-limit performance identified for each phase of the well operation. Deviations of actual performance from the technical-limit plan may be recorded for both improved or degraded performance to identify more-efficient procedures or technologies, as well as reasons why targeted performance was not achieved. Recording this information enables future well-planning teams to incorporate these findings into future well designs.

Knowledge Management. With historically inadequate replacement of employees leaving the industry, the oil field is currently witnessing decreased availability of experienced knowledge workers. The result is that fewer people are available to perform the same level of activity that has been performed previously. Additionally, other factors, such as a reduced occurrence of easy-to-find, accessible hydrocarbon reservoirs and an increased demand for hydrocarbons caused by an increasing population and more energy-demanding industries and technologies, have forced the industry to use increasingly more-complex operations methods, equipment, and technologies to replace existing hydrocarbon reserves. With the reduced availability of experienced knowledge workers, operators are looking at various technologies to enable their workforce to more effectively leverage the knowledge and experience retained within the corporation so that new or existing technologies, methods, and equipment may be used more efficiently.

Many operators and service companies are looking at knowledge-management best practices as a framework for capturing engineering experience, lessons-learned information, and results for various procedures and technologies. Storing this knowledge in an information-management system enables operators to distribute it more effectively across the organization to maximize its value. Different types of knowledge-capture systems are being implemented across the industry, including the rigsite, where immediate operational knowledge or experience may be recorded or referenced to improve operations. This enables service companies to more easily disseminate operations experience across the organization for their various product service lines and equipment. Operators are able to more easily share well-construction and well-planning experience across various operating regions. Information systems and other information technologies increasingly are being used to bring together experts of the same domain or discipline to form "networks of excellence" in which experience or other knowledge may be shared.

Data-Management Systems

Overview. "E&P project data-management" systems are database-management systems designed to support integrated suites of exploration and production applications. Applications share data through a single common data store. Data are administered with a single set of tools for importing, exporting, viewing, and editing and for performing database administration. By centralizing all data available for an E&P asset in a single integrated data store, project data-management systems greatly reduce the amount of time spent moving data between applications. Data-management systems serve as readily accessible repositories for the knowledge about an asset. This knowledge comes from a variety of studies and continues to grow over the life of the asset.

Before integrated project data-management systems, each fit-for-purpose E&P application had its own private, proprietary data store. Each individual data store supported different data-exchange formats and procedures. Moving data between applications involved exporting files, reformatting them manually, and importing them into the target application. This process was often so cumbersome that data were not exchanged at all, or they could be exchanged only by manually retyping the data into each application. Project data-management systems allow applications to share data without moving them from application to application. Outputs created by one application are automatically available in all applications connected to the project data-management system.

Key Features and Functions of Project Data-Management Systems

Broad Application Support. Project data-management systems should support a rich set of E&P applications that solve a broad range of technical problems. Key workflows should be completed entirely within a system, without the use of external tools for data manipulation.

Open Extensible Environment. Given the diversity of the oil and gas industry, no software vendor can offer a solution to all problems. Instead, project-management systems should provide an open-development environment, allowing niche application vendors to plug in "best of breed" applications.

Technology Based on a Standard Database. Many requirements of an E&P project data-management system are similar to those of database systems in other industries. Systems based on common horizontal-market technologies allow the use of relatively cheap and powerful horizontal-market database tools.

The most mature database-management systems are "relational databases." Relational databases have been used by many industries to store mission-critical data for more than 25 years. Researchers at IBM performed much of the early research on the relational model in the late 1960s and early 1970s.[18] A relational model views data logically as a series of tables and columns, with a mathematical model for operations on these structures. The physical arrangement of data is hidden; instead, one depends only on a simple, logical view of tabular data. All data are reduced to the simple "flat" tabular form. Relational databases support SQL, which allows users to build queries that filter the rows of a single table. SQL queries can also combine data from one table with data from another on the basis of shared foreign key fields. This allows SQL statements to join data from multiple tables and build powerful ad hoc reports.

Relational database-management systems range from desktop databases to enterprise data-management systems. Robust database systems typically provide:

  • Network access to data; flexible and powerful data security; tools for "hot backups," allowing a system to be backed up without shutting down; and recovery tools in case of a system crash.
  • A rich set of utilities that allow administrators to configure, control, and monitor the system.

Several very powerful tools have been developed for working with relational databases. These include systems that generate flexible ad hoc reports with rich format control and systems to build queries graphically without the use of SQL. Many tools that were originally designed for the horizontal market can be used when working with E&P data. These tools expose the data model of the underlying database. For a project database to be readily accessible by these generic tools, it must use relational technology and have a relatively simple and well-documented data model.

Object-oriented databases are a newer trend in database-management systems. They have the flexibility to store complex, structured data and to associate software logic with that data. Object databases allow data to be stored in the form needed by today ’ s object-oriented applications. This can create a performance advantage, but the flexibility offered by object databases makes it difficult to write generic tools or evaluate arbitrary user-defined queries against object databases. Many large database vendors are moving toward a "hybrid database." Hybrid databases contain most features of relational databases, but they extend the table/column view of a relational database to allow a column to contain rich, complex user-defined data types. If used carefully, this allows developers the best of both worlds. Most data are modeled relationally for flexibility and ease of query. When performance becomes critical, however, certain columns are modeled with optimized object structures. This is particularly important for E&P data because this flexibility is important for managing certain E&P data types.

Efficient Handling of Bulk Data. Many E&P data types lend themselves readily to representation as relational rows and columns. However, a few critically important data types in the petroleum industry have special performance concerns because of their size. Well logs, seismic surveys, and continuous sensor readings are examples of data types that can produce very large amounts of data. Large data items cannot be stored efficiently using the row/column abstraction of relational databases. These data are stored more efficiently in unstructured "blob" data types, either within the database or within operating-system files outside of the database. An E&P project-management system should blend these specialized data types seamlessly with more traditional relational data in integrated user presentations and displays. The location of data should be irrelevant to the user.

Rich Suite of Project Data-Management Tools. Although many key data-management functions are provided by generic database-management systems, it is the responsibility of the E&P project-management system software to provide both data-type and domain-specific functionality to manage E&P technical data. Project-management systems provide rich data-management utility applications that allow:

  • Flexible importing/exporting of data.
  • Data browsing/querying/editing.
  • Simple project database administration.

Project data-management tools should isolate end users from the complexity of working directly with the database when performing common data-management tasks.

Data import/export routines support a wide variety of common data-exchange formats. They should provide management for units of measure and unit conversion, if necessary. They also should convert surface locations between different map-projection systems. Other domain-specific functionality is provided when importing particular data types (e.g., the computation of wellbore paths from directional survey information).

Data browsing, querying, and editing tools should fill in the gaps left by horizontal-market query and browse tools, offering industry-specific displays for key data types such as well logs, production plots, and seismic displays. These tools should allow the updating and editing of project data and should enforce standard business rules and data integrity.

Project-administration tools should allow users with relatively little database knowledge to perform the following:

  • Project database creation.
  • Control of user access to a project database.
  • Backup and restoration of a project database.
  • Allocation of disk space and other database resources to a project database.

Support Industrywide Standards. Several industry consortia, including the Petrotechnical Open Software Corp. (POSC; and the Public Petroleum Data Model Assn. (PPDM; offer standard data models for many common E&P data types. As vendors move to support these standards, it should become easier to integrate data between project data-management systems from different vendors.

Integrate User Experience Across Applications. Project data-management systems should provide a framework for applications to work together seamlessly using the same data. This requires more than sharing the same database. Applications should be notified when another application changes data in the shared database, allowing them to refresh their display to reflect changes made in other applications. In addition, a data selection made in one application should be available in another application. Consider selecting a well in map view to view in a utility that provides cross-sectional views of downhole well equipment. It is more efficient for a user to select a well in map view and send it to the utility than for a user to type in the name of the well in each utility.

This integrated functionality typically requires an interprocess communication scheme, allowing different applications in a user session to communicate. In addition, "session management" is needed so that users may select parameters that apply to all applications in a session (e.g., the active project or units of measure for display).


Rh = formation resistivity along bedding planes
Rt = true formation resistivity
Rv = formation resistivity across bedding planes
T1 = longitudinal, or spin-lattice, relaxation time; this time constant characterizes the alignment of spins with the external static magnetic field. Refer to the chapter on Logging in this section of the Handbook for more information.
T2 = transverse, or spin-spin, relaxation time; this time constant characterizes the loss of phase coherence that occurs among spins oriented at an angle to the main magnetic field, caused by interactions between spins
Δtc = formation slowness (reciprocal velocity), μsec/ft
Φ = neutron porosity
ρ = density
ρb = bulk density


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SI Metric Conversion Factors

cycles/sec × 1.0* E + 00 = Hz
ft × 3.048* E – 01 = m
°F   (°F – 32)/1.8   = °C
in. × 2.54* E + 00 = cm
in.3 × 1.638 706 E + 01 = cm3
psi × 6.894 757 E + 00 = kPa


Conversion factor is exact.