The On-line Mud Logging Handbook by Alun Whittakery Alun Whittaker

The On-line Mud Logging Handbook

Alun Whittaker

The On-line Mud Logging Handbook by Alun Whittaker

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Down-hole Measurement & Logging Aegis Group 244 Ohio Street Vallejo, CA 94590-5051 USA This is Page 1 of Chapter 10: Down-hole Measurement & Logging

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Down-hole Measurement & Logging When the first edition of this book was published, measurement while drilling (MWD) was the hot, new thing. The need for a full-time manned receiving station/control center was ample reason for many contractors to attempt to shoehorn the MWD surface systems into the, already crowded, mud logging unit. With less space to perform their own work, mud loggers were often required to serve as laborers for their fellow logging technician crew members. The result was a degradation and devaluation of the mud logs being produced, without any of the hoped for synergy promised by the merging of mud logging, geo-pressure, and wire-line-like log data in near-real time. Today, the truth is that MWD logs, wire-line logs, and well testing can produce data that fit on the mud log for two purposes: ✔ First, synoptic reports of the bore-hole measurements belong on the mud log as part of it's day-to-day, grassroots-to-TD record. ✔ Next, some wire-line log data, from current or neighboring wells, can serve correlative, or predictive functions in interpreting or correlating mud log, and geo-pressure log data. Down-hole measurements and data discussed here include: ✔ Down-hole formation logging tool measurements and technologies ✔ Wire-line log correlation ✔ MWD - down-hole logging in the mud logging unit ✔ Down-hole measurements and drilling control ✔ Well testing, on a wire-line, in open hole, and through casing

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Table of Contents Real-time and Near Real-time Logging..........................................................................................................................................................8 Down-hole Logging (or Measurement) While Drilling...................................................................................................................................9 MWD and Mud Logging Chronology.............................................................................................................................................................9 Pre-emptive Data.....................................................................................................................................................................................9 True Real-time Data: .............................................................................................................................................................................10 Delayed Real-time Data.........................................................................................................................................................................10 Off-bottom Delayed Real-time Data........................................................................................................................................................10 Lagged Data...........................................................................................................................................................................................12 Down-hole Logging Transmission Methods.................................................................................................................................................13 Direct Hard Wire Connection..................................................................................................................................................................15 Electro-magnetic Transmission...............................................................................................................................................................17 Drill String Sonic Transmission...............................................................................................................................................................19 Mud Pulse Transmission........................................................................................................................................................................19 Down-hole Memory Systems..................................................................................................................................................................27 Down-hole Measurement Sensors..............................................................................................................................................................30 Directional-only Measurement................................................................................................................................................................30 Drilling Response Measurements...........................................................................................................................................................34 Bore Hole Environment Sensors............................................................................................................................................................37 Formation Evaluation Measurements.....................................................................................................................................................37 Tool Design........................................................................................................................................................................................38 Time of Measurement........................................................................................................................................................................38 Speed of Measurements....................................................................................................................................................................40 Averaging and Edge Effects..............................................................................................................................................................41 Formation Contact.............................................................................................................................................................................41 Electrical Measurements...................................................................................................................................................................42 Radio-activity Measurements............................................................................................................................................................44 Surface Receiving Systems........................................................................................................................................................................48

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MWD Service Configurations......................................................................................................................................................................50 Directional Survey Services....................................................................................................................................................................50 Enhanced Directional Services...............................................................................................................................................................53 Formation Evaluation Recording Services..............................................................................................................................................53 Real-time Formation Evaluation.............................................................................................................................................................54 The Future of MWD....................................................................................................................................................................................55 Next... In This Edition....................................................................................................................................................................................57 Next ... Time Around......................................................................................................................................................................................57

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Didn't find what you needed here? Sorry. Why not go back to the Chapter

Summaries, and fine a better place to start, or use the Index to search for the subject you need.

List of Figures & Tables Figure 1: Some measurement while drilling (MWD) data is truly real-time data, delayed only by transmission lags. other MWD data, particularly formation measurements are made some time later because of the location of the sensor some distance above bottom. ...........11 Figure 2: An MWD tool must package sensors, data processing, storage and transmission systems, power supply, distribution and other support systems within the dimensions of a conventional drill collar ...............................................................................................................14 Figure 3: The hard-wire MWD system uses a continuous direct connection between the down-hole sensors and the surface computers. In competing systems, this may be by (A) embedding an insulated electrical conductor in special drill pipe, or by (B) looping a cable down inside a conventional drill string. .....................................................................................................................................................................16 Figure 4: The electromagnetic MWD (EM) system transmits ultra-long wavelength radio waves from down-hole to surface. in high conductivity formations There is major signal attenuation requiring very high transmitting power, large sensitive antennæ or the use of boosters located in the drill string....................................................................................................................................................................18 Figure 5: Mud pulse transmission is the most widely used and successful method of data transmission used in commercial MWD services. the three variations are: (A) positive mud pulse, (B) negative mud pulse and, (C) the mud siren. ..................................................................20 Figure 6: The MWD sensor data is transmitted to surface as sequences of positive or negative mud pulses. at surface it is necessary to filter the mud pressure signal for systematic variations, for example: the mud pump cycle, and random noise. the MWD mud pulses may then be recognized and decoded back to the original sensor values (based on data courtesy of EXLOG, Inc.). .........................................................22 Figure 7: The conventional digital representation of data with associated error checking data is very slow. ...................................................23 Figure 8: Although less precise than conventional digital representation, the time analog method allows far more data to be transmitted using less pulses in less time. ..................................................................................................................................................................................24 Figure 9: Adding the mid-point check pulse to the the time analog data representation method prevents transmission errors and losses while requiring the minimum number of additional pulses. .......................................................................................................................................26

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Figure 10: In the memory-supported MWD system, data is processed down-hole and selectively transmitted to surface. when the tool is finally recovered to surface, the memory is down-loaded and its data with the transmitted data to fill-in gaps and correct errors. .................29 Figure 11: A portable, weatherized visual display unit of the type commonly used by directional MWD services. this unit can be set up in a mud logging unit or other well-site office but it may also be safely set up on the rig floor or elsewhere on the well location (illustration courtesy of EXLOG, Inc.) ............................................................................................................................................................................32 Figure 12: The MWD Weight on Bit and Rotary Torque on bit measurements show marked difference from the equivalent measurements made on surface. Differences may be used in drilling and safety monitoring and in formation evaluation to indicate rock strength, porosity or fracturing (illustration based on Lesso and Burgess, 1986, courtesy Society of Petroleum Engineers). .........................................................33 Figure 13: The Exploration Logging (EXLOG) Down-hole Vibration Monitor (DHVM) is a stand-alone sensor package that can be run in combination with any MWD transmission system, or run as an independent memory-only tool (illustration from Close, Owens and Macpherson, courtesy of Society of Petroleum Engineers). ...........................................................................................................................35 Figure 14: The Exploration Logging (EXLOG) Down-hole Vibration Monitor (DHVM) can supply data for Bottom-hole Assembly (or BHA -drill collars, stabilizers, subs, and so on) optimization, safety monitoring, drilling or equipment research (illustration based on Close, Owens and Macpherson, courtesy of Society of Petroleum Engineers). .....................................................................................................................36 Figure 15: A representation of the bore hole and adjacent formations. Over time, the depth and completeness of flushing increases, formation fluids are swept into the bore hole or flushed away from it, leaving the drilled formations filled with drilling fluid filtrate. .................40 Figure 16: MWD electrical measurements (upper scale and solid log trace) respond in a similar manner to the equivalent wire-line logs (lower scale and dashed log trace). however, due to the different logging environment there will be a qualitative difference in response between the two tools. ....................................................................................................................................................................................43 Figure 17: MWD gamma ray logs (upper scale and solid log trace) are similar in response to wire-line equivalents (the scale at the bottom, and the dashed log trace). However, there is a difference in response caused by the varying mud density and the blocking effect of the steel drill collar. .......................................................................................................................................................................................................45 Figure 18: Both the Thermal (or neutron-gamma) Neutron, and the Epithermal (or neutron-neutron) porosity tools use a high-energy neutron source. The Thermal tool detects the gamma rays emitted when thermal neutrons are captured. The Epithermal tool detects lower energy, epithermal neutrons that have lost almost all of their kinetic energy ...............................................................................................................47 Figure 19: Logging While Drilling requires measurement, processing and plotting of the measured data. on surface, after filtering and decoding, the data must be processed and displayed by a stand-alone micro-processor or in various sizes or configurations of mud logging unit. .................................................................................................................................................................................................................49

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Figure 20: If On-site well-planning or plan modification is undertaken a computer system will be needed to perform the complex calculations and plots needed to determine bottom-hole position and proximity to other wells or lease boundaries. .........................................................51 Figure 21: This small directional MWD tool can be hand-carried to the well site in its suitcase, go-deviled into a conventional drill string, and begin transmitting directional data within a matter of hours from call-out. .......................................................................................................52

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Down-hole Measurement & Logging Real-time and Near Real-time Logging We have defined mud logging as a real-time information service. In other places and occasions, it has even been referred to as logging while drilling. More recently, a new type of logging, MWD, has begun to claim both of those titles. In fact, it turns out that neither of them entirely fulfills the definition. Fortunately, the two are compatible and, together, they come close the meeting the target. In practice, mud logging and MWD fit well together (see Whittaker, et al, 1986). Although the measurements and sensor construction in MWD are similar to those used in wire-line logging, the mode of operation is very different. The wire-line logging unit and crew are activities for thirty to forty hours, two or three times during the well. The measurements are made of a short time period in a static bore hole with stabilized drilling fluid chemistry and density. Both MWD and wire-line log data (from this, or previously drilled offset wells) can be of interest to the mud logger, and the mud logger can provide useful information to the wire-line and MWD logging crews -- if not about formations penetrated – then, at least, about the drilling fluid, and bore hole condition. Mud logging and well-site geo-chemistry are also the standard, while-drilling tool for extracting, detecting and analyzing samples of hydrocarbons and formation water from the drilling fluid. Another method that may be available for extracting much larger and less contaminated samples of formation fluids is well-testing. Drill-stem testing is most commonly only performed after completion of the well, through casing, or a liner (see Chapter 4) and by this time, the mud logging service may have been terminated, and the crew sent off, or reduced to a one-man, safety service. In other cases, testing in open hole, either on using the drill-stem, or on a wire line, can be performed before completions, with the mud logging crew still on hand. In these cases, the mud logging unit may be of assistance by providing formation water and oil analyses, or running gas samples through the mud logging chromatograph. Geophysical surveying is usually performed well away from the drilling well site, both in distance and time. Mud loggers can rarely use geophysical, or contribute to a geophysical investigation. One circumstance where the two fields do coincide is in geo-pressure evaluation. Seismic velocities, and transit times from a geophysical investigation can be of assistance in developing a logging program for geo-pressure logging. Although you cannot really call it geo-pressure prediction, zones of abnormally high porosity, and possibly abnormally high pressure can be used to forecast intervals and depths at which special attention to geo-pressure indicators may be needed. So, there are aspects of each of these logging or measurement technologies, that should be of interest to the mud logger. We need to look at each of them here: ✔ (Down-hole) Measurement (or Logging) While Drilling – DLWD, DMWD, LWD, or MWD ✔ #Wire-line Logging Data ✔ Well Testing, and

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✔ Geophysical Surveying

Down-hole Logging (or Measurement) While Drilling MWD activities, like mud logging, are carried out twenty four hours each day, every day, whenever drilling is underway, from the start of the well (or at least, very early in its progress) to completion. While this all goes on: ✔ The bore hole contains circulating drilling fluid of varying composition and density, well cuttings and gas content. ✔ The drill string is rotating, moving slowly downward, ✔ With occasionally upward movements during reaming, connections or down time. ✔ It is therefore practical to carry out MWD logging activities from the mud logging unit, and to bring to its interpretation the skills learned from mud logging evaluation. MWD and mud logging also fit well together in producing a compatible data set in the type of data they produce and in their timing, during and shortly after drilling. Each provides aspects that are missing from the other: ✔ MWD produces quantitative measurements of gross physical properties of the formation. ✔ Mud logging provides the direct geological and hydrocarbon observations that supply the context for understanding the MWD measurements.

MWD and Mud Logging Chronology In the time scale of logging, these real-time measurements can, in fact, be separated to form a definite chronology:

Pre-emptive Data These are data that is measured prior to the time at which it begins to have meaning (not until after the down lag time): ✔ Mud density (-in) ✔ Mud temperature (-in) ✔ Mud electrical conductivity (-in)

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✔ and so on

True Real-time Data: These are measurable at the same point in time as they occur (of course, human, electronic and software reactions times will delay actual reporting): ✔ Rate of penetration (ROP) ✔ Rotary table speed (RPM) ✔ Surface-measured rotary torque ✔ Hook Load, and surface-measured force (or weight) on bit

Delayed Real-time Data These are true bottom-hole data measured in real-time but delayed by processing and transmission: ✔ Down-hole force on bit ✔ Down-hole torque ✔ Down-hole drilling motor rotary speed ✔ Bottom-hole mud temperature, internal (or drill string) and external (or annular) ✔ Bottom-hole pressure, internal (or drill string) and external (or annular) ✔ Bottom-hole mud conductivity, internal (or drill string) and external (or annular) ✔ and so on

Off-bottom Delayed Real-time Data These are measured later than real-time, because of the location of the sensor above the bit (see Figure 1). ✔ Formation Electrical Properties ✔ Formation Natural Radioactivity

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Further delays may be induced by the nature or pre-requisites for the measurement in, for example: ✔ Formation induced radiation ✔ Bore-hole inclination and azimuth

Figure 1: Some measurement while drilling (MWD) data is truly real-time data, delayed only by transmission lags. other MWD data, particularly formation measurements are made some time later because of the location of the sensor some distance above bottom.

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Lagged Data These are data and observations not available until after the lag time after they are created at bottom: ✔ Gas analyses ✔ Mud density (-out) ✔ Mud temperature (-out) ✔ Mud electrical conductivity (-out) ✔ and so on Further delays may be induced by sample dispersion in the annulus, slow or mixed recovery: ✔ Cuttings, oil descriptions and tests ✔ Mud filtrate titrations Logging while drilling -- the measurement of in situ formation properties from a position in the drill string while the drill bit was making fresh bore hole -- has been attempted numerous times during the history of rotary drilling. Success as probably been claimed even more often. From a sixties literature search, logging while drilling ran a closed third of all claims in the Now it can be achieved stakes. Only since the early nineteen eighties has down-hole measurement while drilling (MWD) been offered as a truly reliable and genuine commercial service (see Arps, 1979 and Anonymous, 1983.) The essence of the technology is location of drilling and formation evaluation sensors within a special drill collar immediately above the drill bit, along with the necessary power, processing, and transmission hardware. Data from the sensors is pre-processed by a down-hole computer within the tool and transmitted to surface by various different physical mechanisms. Although a number of transmission schemes have been proposed and experimented with, only three methods are presently used commercially. These are: ✔ Hard-wire, or direct connection via an internal logging cable. ✔ Mud Pulse Telemetry, presently the most commercial method, involves the transmission via a series of pressure pulses through the drilling fluid to surface. ✔ Electromagnetic (EM) ultra-long wave length transmission from near the drill bit to an antennae array on surface. A method well suited to onshore production systems,with fresh water and a close proximity of wells, this is still under investigation as an exploration technique.

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measurement while drilling is providing a challenge to the previous supremacy of Wire-line Logs as the most significant (and most expensive) source of well-site data. Although expensive to obtain, MWD data is beginning to prove itself to be cost effective in the directional control and drilling optimization field. So far, MWD sensors have not yet shown themselves to be fully the equal of wire-line logging sensors. However, combination of MWD formation and drilling sensors with mud logging, and other surface measurements can yield the same completion decisions as wire-line logs. This does not necessarily render wire-line logs obsolete, but it can displace them into the position of being confirmation logs, for already established exploration decisions.

Down-hole Logging Transmission Methods All measurement while drilling systems suffer from a number of common problems (see Kamp, 1983, Honeybourne, 1985.) An important consequence of the measurement while drilling concept is that there is literally only one opportunity to make any of the measurements that are required, and that the measurement process must go on as drilling process takes place without disrupting it, and without being disrupted by it. The entire MWD assembly must fit within a conventional drill collar: ✔ Sensors, ✔ Data acquisition, processing and storage systems, ✔ Data transmission (and, in some cases, reception) system, ✔ Power generation, control, storage and distribution systems, ✔ Stabilization, shock absorbing, and other support structures. All of these elements must be included within the shape and size limitations of the standard drill collar which must still retain weight, strength, stiffness and mud flow characteristics within an acceptable range (Figure 2). Minimum requirements include that very MWD tool and all of its sensors must also remain functional for somewhat more than the lifetime of a typical drill bit: ✔ With only one chance to log, all sensors must keep operating throughout a bit run, even if measurements are required for only a portion of that depth interval. ✔ A MWD system that necessitates a trip to turn sensors on or off, or replace a failed sensor loses cost-effectiveness to the operator. ✔ An MWD system that survives only a single bit run, and then must be scrapped would be economic suicide to the service company.

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Figure 2: An MWD tool must package sensors, data processing, storage and transmission systems, power supply, distribution and other support systems within the dimensions of a conventional drill collar Some MWD systems (see below) accommodate two-way transmission thus allowing sensors to be turned on. off or supplied with operating parameters while drilling. In most other systems, however, all of the sensors must be turned on, making and transmitting measurements all of the time. In multiple sensor systems this can be a problem since, when compared with wire-line logging, MWD data transmission rates vary from slow to sub-U.S. Mail. At a fixed data rate, the larger the number of measurements made, the larger will be the time, and hence depth, interval between consecutive measurements.

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This problem is ameliorated somewhat by the relatively low logging speed of MWD systems: ✔ Wire-line logging speeds are always a compromise between the time necessary to make a valid measurement with reasonable depth resolution and the wish to reduce the rig time and cost taken up by logging. ✔ MWD logging speed, on the other hand, is governed by the rate of penetration and, in general, much lower. Even a relative high rate of penetration can be quite slow when compared to the running speed of some wire-line logs. ✔ Further improvement can be gained if data is processed by a down-hole computer, reducing the number of raw data items that must be transmitted. ✔ On the negative side, sending only computed results removes the ability to check the results for error in real time, perform crosschecks and re-calibrations. ✔ In some systems a further compromise is achieved by transmitting some data and results at different time intervals and storing others in a down-hole memory for recovery later. It is possible, therefore, even at much lower data rates, for MWD logs to sometimes provide equivalent or even better vertical resolution than wire-line logs from the same interval.

Direct Hard Wire Connection The oldest, simplest and most easily understood form of measurement while drilling is the hard-wire system (see Robinson, et al, 1980) in which there is a direct, physical link between the down-hole logging sensors and the surface receiving and display equipment. This may be by means of a cable hung down inside of a conventional drill string. Alternatively, a special drill string may be used which has an insulated electrical conductor embedded in it and special water-proof connectors in the tool joints (see Figure 3). First used in the thirties, the hard-wire system became prominent in the early seventies in conjunction with research projects involving electrically-powered down-hole drilling motors. Utilizing a multiple conductor system, it was possible to: ✔ Power the down-hole motor, ✔ Power the MWD sensors, and processors, and ✔ Provide two-way communication to logging tool, with the direct connection allowing very high data rates. The MWD sensors may be located below the down-hole motor, very close to the bit, or above the motor, in the non-rotating, more stable section of the bottom hole assembly, whichever is most appropriate to the measurement to be made.

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Figure 3: The hard-wire MWD system uses a continuous direct connection between the down-hole sensors and the surface computers. In competing systems, this may be by (A) embedding an insulated electrical conductor in special drill pipe, or by (B) looping a cable down inside a conventional drill string.

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In other words, hard-wire MWD provides, from an operating point of view, an almost ideal combination of operating and evaluation characteristics. Unfortunately, both of the implementations – the looped wire-line or conductive drill string -- involved expensive investment in new equipment or construction on the rig. The combination of function: drilling and evaluation, proved in practice not to be a benefit but a problem. It required the involvement the oil company exploration and drilling departments, the drilling contractor and one or more service contractors in designing, installing, operating and paying for the system. Even in the research phase, this caused budgetary and supervisory problems. In practice, with the need for the equipment to be installed on different rigs, then removed, and relocated to other rigs, hard-wire MWD could not overcome those jurisdictional problems in order to become a commercially viable service. Only in two special circumstances has hard-wire MWD been extensively used. It has been used for directional measurements on large development drilling programs where: ✔ A large number of wells are to be drilled from a single rig using a standard package of services and products, and ✔ The entire operation, both drilling and evaluation, is budgeted and controlled by a single organization. In the former Soviet Union, centralized control, and the need to find any alternative to rapidly failing, low quality steel drill pipe have combined to encourage wide use of electrically powered down-hole motors and, along with them, hard-wire MWD. First used in geological research and mining exploration drilling into very hard rocks, the techniques are now widely used in deep gas drilling. More recently, there have been several publications claiming great success for the IntelliServ system, from National Oilwell VARCO. This system uses conduction through special drill string components, with communication rates up to one megabit pre second. There have been suggestions made that developments of this system may be commercialized by Schlumberger or Baker-Hughes. We shall see.

Electro-magnetic Transmission Electromagnetic, or EM, transmission of MWD data has been used experimentally since the nineteen seventies (see De Gauque, and Grudzinski, 1987.) Sensor data is transmitted from down-hole to surface by ultra-long wavelength radio waves. In some systems, transmissions can also be made from surface to the logging tool, in order to turn sensors on and off, to change their measurement range, or to change other parameters while drilling was underway. Although successful in research efforts, EM transmission has achieved only limited success in practical exploration. The biggest problem in drilling petroleum basins is the massive signal attenuation by high conductivity formations: ones with high porosity, and content of saline pore waters. In order to overcome this problem necessitates the use of impractical levels of transmitting power or extensive surface antennæ which are too large for practical installation on an mobile or offshore exploration rig (Figure 4). .

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Figure 4: The electromagnetic MWD (EM) system transmits ultra-long wavelength radio waves from down-hole to surface. in high conductivity formations There is major signal attenuation requiring very high transmitting power, large sensitive antennæ or the use of boosters located in the drill string. Subsurface EM transmission has found an important oilfield application in the monitoring and control of subsurface control systems for

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producing oil and gas wells. In this type of operation a single, large, permanent antenna can be used to communicate with many down-hole transmitters installed in a large number of producing wells over a very large area. The installation cost of the system becomes acceptable when amortized over the number and lifetime of the producing wells Since the 19990's, Geoservice, the French mud logging company, has offered an EM-based exploration MWD logging service. Over the years, there have been regular technical publications and patents issued but, as yet, we have not seen much expansion as a successful commercial service of its type.

Drill String Sonic Transmission The transmission and detection of sonic disturbances through the drill string have been the subject of many experiments over the years. Many attempts have been made to detect, at surface, both natural and artificially induced acoustic transmissions from the bottom of the hole: bit vibrations, down-hole motor rotating speed and sonic signals from down-hole logging sensors. Again, despite regular publication of technical achievements developments and experimental success, no commercial service has been offered using sonic transmission and detection. There were unofficial reports of the use of acoustic MWD transmission of down-hole drilling parameters on ultra-deep research wells in the former Soviet Union. So far these have not been confirmed by any technical publication.

Mud Pulse Transmission Mud Pulse MWD transmission (see Gearhart, Ziemer, and Knight, 1981) was first used in the fifties for very simple directional systems. It has become, in several variations, the most important and common form of MWD transmission in commercial service. All of these methods use the column of drilling fluid column inside the drill string as the medium of transmission fluid pressure signals between the MWD tool and surface. In the first and simplest method (see Figure 5, A) an internal valve is used to close off the entire drill string bore. This valve is closed against the flow of circulating drilling fluid and, as quickly as possible, re-opened, and this generates a positive pressure pulse inside the drill string. This is recognized by a sensitive pressure gauge located in the stand pipe. Down-hole processors convert the MWD sensor data into a digital format so that it can be transmitted as a sequence of positive. mud pulses. Compared to hard-wire and EM methods, this is a very slow means of sending data. However, the pulses are quite large and easily recognized with unsophisticated detectors, even against the background noise of normal drilling fluid pressure variations.

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Figure 5: Mud pulse transmission is the most widely used and successful method of data transmission used in commercial MWD services. the three variations are: (A) positive mud pulse, (B) negative mud pulse and, (C) the mud siren.

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Positive mud pulsing was used in the first truly commercial MWD system, a bore hole inclination measuring device used in the 1960s by BJ Directional Services (later a division of Baker Hughes). The positive mud pulse method is simple and reliable but suffers from the limitation of low transmission rate. That limits the number sensors which can be monitored, or the vertical resolution possible for multi-sensor systems. The reason for this is that, in order to arrest the entire mud flow and to do so without massive valve erosion, a large amount of energy must be supplied to the system, and that can only take place over a relatively long time period. As can be seen in Figure 5, A, the pulse is extended and asymmetric. A secondary problem is that large pieces of debris in the mud stream may damage the valve or jam it in the open or closed position. Worse still, an accumulation of smaller debris may prevent the valve from completely closing. Leakage around the valve will decrease pulse size and, more importantly, lead to erosion of the valve and valve seat. A second method of mud pulse transmission, the negative mud pulse method (see Figure 5, B) , having some advantages was developed and commercialized by Gearhart Industries (later absorbed by Halliburton) in the 1970s. Several other companies (including Exploration Logging (EXLOG)) later licensed and further developed Gearhart’s negative mud pulse system. In the negative mud pulse method, a much smaller valve is opened between the drill string and the annulus allowing a small increment of drilling fluid to escape. This produces a small, and more rapid, fall in pressure inside the drill string, and this can be recognized at the stand pipe. Because only a small volume of mud is involved, the energy required to cycle the valve open and closed is much less than in the positive mud pulse system, and the valve may be opened and closed more rapidly and symmetrically. The pulse is also much smaller, of course, and so it can be more difficult to detect against background noise. Data may be encoded as digital pulses in the same manner as a positive mud pulse tool but at a higher data rate because of the more rapid valve cycling. Because of its low energy requirement and pulse symmetry (Figure 5, B), the negative mud pulse method allows a higher data rate than the positive mud pulse method but at the expense of much smaller pulse size. The mud pulser is, in effect stealing mud from the drill bit and negative mud pulse amplitude will obviously be related to: ✔ The depth of the pulser relative to the bit, and ✔ The relative nozzle area of the pulser and the bit jets. In order to optimize negative pulser performance, it is necessary to select appropriate nozzles for the bit and pulser in order to maximize data transmission pulse height without degrading bit hydraulics. The negative mud pulse system is less prone to being jammed open since it accommodates only a small fraction of the total mud flow, and in a direction perpendicular to it. However, the pulser valve can be plugged closed by even very fine debris. Particulate mud additives, such as LCM and plastic Lubri-Glide beads can totally plug a negative mud pulser very easily. Even the minor charcoal impurities in the calcium carbide lag time tracer have been accused of aborting a negative mud pulse MWD tool run. The tool is also even more susceptible to loss of pulse height due to valve leakage and erosion.

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Although simple and relatively cheap to implement Both mud pulse systems suffer from their extreme slow data transmission rates compared to the hard-wire and EM systems. In order to improve this, a lot of effort has been put into processing and filtering lower priority data as much as possible before transmission, to storing some of the data down-hole for later retrieval (see below), and to encoding the data in a more compact form for transmission. At surface, a continuous recording is made of the mud pressure at the rig stand pipe. This pressure will be effected by several systematic variations such as the cyclical variation induced by the rig pump operation. There will also be many other sources of purely random noise. Figure 6 shows that typical values of this noise can exceed the magnitude of the mud pulses to be detected. Very sophisticated filtering techniques must be used before it is even possible to recognize that pulses are present in the mud pressure signal.

Figure 6: The MWD sensor data is transmitted to surface as sequences of positive or negative mud pulses. at surface it is necessary to filter the mud pressure signal for systematic variations, for example: the mud pump cycle, and random noise. the MWD mud pulses may then be recognized and decoded back to the original sensor values (based on data courtesy of EXLOG, Inc.).

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In normal digital transmission, each sensor data item is converted to a binary coded number (as ones and zeros) and transmitted as a series of pulses at set time intervals (Figure 7, 8 and 9). Within each of the set reception time intervals, the presence of: ✔ A pulse that exceeds the detection threshold (see Figure 7) will represent the number one (1), and ✔ No pulse (or a pulse that does not reach the detection threshold) will represent zero (0). ✔ At the end of the data set time interval, the digits are concatenated (strung together) to make a digital number, like 0-0-0-0-1-1-1-1-0-1-1-1-0. ✔ The digital number can be converted to decimal (in this case, 494) and scaled with an appropriate decimal multiplier (4.94, or 49,400, and so on) With the high background noise levels, there is a high probability that some pulses will be missed, or that noise will be falsely recognized as a pulse. To avoid errors and to maintain data control, checksum and other error checking parameters will also need to be sent with each data set.

Figure 7: The conventional digital representation of data with associated error checking data is very slow.

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Obviously, when representing large numbers (such as 99,888,777), or large orders of precision in small numbers (like 0.001122345), this requires a large number of pulses to be sent for each set, or frame, of data. At a high rate of penetration, this means loss of vertical resolution. Even at lower drilling speeds, more pulses means a higher energy consumption and shorter lifetime for the MWD mud pulser. More pulses required for each data item also means more chances of data being scrambled by a missed pulse or a falsely detected noise pulse.

Figure 8: Although less precise than conventional digital representation, the time analog method allows far more data to be transmitted using less pulses in less time. The time analog encoding scheme (see Figure 8) is much less precise than straight digital transmission but it allows many less pulses to be used to represent the same quantity of data items. Put simply, the MWD tool sends a start pulse, signifying that a data frame is beginning, followed by a series of pulses at variable time intervals. The time between each pulse is an analog of the value of one of the MWD sensor data items.

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For example: ✔ Each data set is commenced with a start pulse, T01 for sample #1, T02 for sample #2, and so on. ✔ The receiver clock is set to zero by receipt of the start pulse, and ✔ The value of first data item in the data set is represented by the time interval before the arrival of the second pulse, T11 for sample #1, T12 for sample #2, and so on. ✔ The value of next data item in the data set is represented by the time interval before the arrival of the next pulse, T21 for the second data item in sample #1, T32 for the third data item in sample #2, and so on.. ✔ After the time necessary for all items in the data set has elapsed, there is a period of silence, followed by a new start pulse for the next frame. ✔ Figure 8 represents a simple case of three data samples, each containing only one data item. In each sample, the value of the data item is represented by the time difference between pulse T01 and pulse T1, T02 and pulse T2, and so on. ✔ Let us assume that a full scale value for the data item is defined as being equivalent to a time interval of two seconds. ✔ Then a full scale (100%) measurement would be represented by pulse T02 followed exactly 2 seconds later by pulse T2 ✔ If, pulse T03 and pulse T3 actually occur 1.2 seconds apart, then this means that the third data item value is 60 percent of full scale: 1.2 divided by 2.0 multiplied by 100 equals 60% The worst problem of the time analog scheme is that if a single pulse is missed (or a single extra false pulse detected) then, not only will that data item be incorrectly decoded, but all subsequent readings in the frame will be assigned to the wrong data type. This problem is greatly reduced by using the mid-point check pulse as a data validity test (see Figure 9): ✔ Exactly half way between each regular time analog pulse, a check pulse is transmitted. In other words, we can say that each data item is represented by the sum of two consecutive and identical time analog signals each equivalent to one half of the sensor response: ✔ The value of data item #1 is represented by the time interval: T10 -- to-- T11 , ✔ But only if the time intervals:

T10 -- to-- T1 is equal to T1 -- to-- T11 ,

✔ The value of data item #2 is represented by the time interval: T11 -- to-- T12 ,

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The On-line Mud Logging Handbook ✔ But only if the time intervals:

Alun Whittaker T11 -- to-- T2 is equal to T2 -- to-- T12 ,

✔ And so on. ✔ Missing and anomalous pulses can be easily identified by the loss of the mid-point symmetry, so that at worst only one or two data items will be lost, not the whole data set. ✔ Time analog encoding allows transmission at higher data rates than simple digital encoding with, in practice, comparable accuracy.

Figure 9: Adding the mid-point check pulse to the the time analog data representation method prevents transmission errors and losses while requiring the minimum number of additional pulses. The mud siren represents the third form of MWD data transmission by drilling fluid pressure changes. It was developed by Mobil in the 1960s, licensed and commercialized in the 1970s by Schlumberger and its mud logging subsidiary Anadrill. The mud siren is the most mechanically complex transmission method (see Figure 5, C) but also the one with the highest data rate (see Buchholz, 1981.)

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In this scheme a standing wave is generated in the drilling fluid column by the rotation of a bladed rotor over a stationary stator. Data is encoded by modulating the frequency of this standing wave. This modulation is produced by varying the rotational speed of the rotor. These rotational changes make little difference to the overall mud flow rate and volume, and so use very little energy. This allows changes to be made very quickly and repeatedly, allowing fast data transmission rates. Again detection is by means of a surface pressure sensor in the stand pipe. Just like an FM radio transmission, this method allows a large volume of information to be transmitted with very low error rates. It is however mechanically much more complex than the other two methods. It is necessary for the entire drilling fluid flow to pass by the transmission mechanism rendering it relatively vulnerable to erosion, impact damage, and to plugging. While the siren will allow fine debris to pass freely, coarse, soft material will be minced by rotors. Larger pieces of mechanical junk: nuts, bolts, lost wrenches, and so on, may smash into the rotor and destroy it. The mud siren also produces a much lower amplitude signal than either the positive or negative mud pulsing methods. Its success may be limited in very deep wells or when using oil-based drilling fluids, which very compressible, leading to serious signal attenuation.

Down-hole Memory Systems Most MWD logging tools are supplied with electrical power from a spinning generator driven by the circulating drilling fluid. Batteries are provided to maintain the sensors and down-hole computer when mud circulation is halted. With this battery support, it possible for the mud pulse MWD tool to make many more down-hole measurements than it is capable of transmitting. We have already discussed the situation of high rates of penetration and multi-sensor logging tools. In addition, there is the possibility of relogging sections of the hole when tripping in or out of the hole. This allows different sensors to be used on subsequent runs. If the same sensors are used, there is the possibility of time-lapse logging. Time-lapse logging of the same section several times with the same sensors, as mud filtrate invasion, and formation fluid migration proceeds, can give interesting new information about the original fluid content of the formation and it ability to flow, or be displaced from it. Time-lapse logging is rarely performed with wire-line logging tools because of the high cost of the rig time required but it can be performed by MWD logging tools during regular, or short trips at minimal extra cost see Fox, 1987, and Franz, 1981.) Unfortunately, although the battery-powered MWD sensors can make the necessary measurement, no mud pulses can be generated while tripping nor, if the could, would they be detectable at surface when the kelly is disconnected, and the mud is not circulating. Finally, we should also consider the possibility of pulser malfunction. The mud pulser or siren are subject to major stresses, strains, mud erosion, blockage or damage by falling debris. They are far more likely to be damaged or fail in operation than the sensors or other encapsulated and sealed electronic components of the system. If this happens, data may be gathered for hours but lost due to the failure to transmit them to surface. Even without complete sensor failure, the difficulties of mud pulse transmission, detection and decoding will allow

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much of the data to be lost or corrupted between the MWD tool and surface. There has been much technical and legal discussion as to the origins and development of down-hole memory systems. However, there now seems little doubt that it was Exploration Logging (EXLOG) which first patented and utilized the down-hole memory in an MWD tool. In the early days of EXLOG's DLWD (down-hole logging while drilling) this was primarily to support the unreliable and slow first generation mud pulser. As the pulser was improved, new MWD sensors were added, further increasing demand on the pulser, and so the down-hole memory remained an important part of the system (see Figure 10). In this system, the down-hole data acquisition system monitors all sensors on a regular basis and all of the raw data is retained in memory. The down-hole computer performs calculations, calibrations, averaging, and so on, on the data and prepares it for transmission. All of the most critical data is transmitted to surface. Data which is less necessary in real-time is transmitted less often. When the tool is removed to surface, it is connected by a wire line to the logging unit computer and its memory is down-loaded. A merge program fills in gaps in the log data, checks raw data to test the accuracy of previous down-hole calculations and corrects transmission errors and omissions in order to produce a final, more accurate log with the same vertical resolution for all data. It was, however, not Exploration Logging (EXLOG), but NL-Baroid who took the next step in producing a system which discarded the expensive and troublesome pulser and marketed the first memory-only MWD system. This system is, of course, unsuitable for directional and drilling data, which is required in real-time for optimization and control. However, formation and reservoir data is rarely needed for evaluation or decision-making, at the instant that it is drilled. If the measurement is made in real-time, it is reasonable to wait until the end of a bit run to be able to recover it and perform formation evaluation. Even with this few hours delay, we still have real-time data, from fresh, un-invaded formations and have access to it many days, or even weeks, earlier than conventional wire-line logging would provide it. The memory-only MWD tool provides this with considerably less complexity and at a much lower cost than any of the methods using real-time data transmission. The memory-only system does encounter problems when very long-lived diamond and PDC bits are used. The lifetime of these bits may exceed the memory capacity of the down-hole memory in the MWD tool. However, as we have all experienced in our personal purchases, memory continues to get larger, faster, and cheaper, so we can expect the capacity of memory-only MWD tools to regularly catch up, or surpass increased requirements. Less easily solved, is the problem of data being lost if the drill string becomes stuck in the bore hole and the MWD tool cannot be recovered from the hole. To overcome these problems a more recent version of the memory-only MWD tool contains a wire line retrievable memory module. A portion of the MWD tool can be detached and fished from out of the drill string on a wire line and, on long bit runs, replaced with a new memory module and fresh batteries.

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Figure 10: In the memory-supported MWD system, data is processed down-hole and selectively transmitted to surface. when the tool is finally recovered to surface, the memory is down-loaded and its data with the transmitted data to fill-in gaps and correct errors.

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Down-hole Measurement Sensors MWD logging is a rapidly evolving field. By the late 1980s, mud pressure systems (of all three kinds) had become established as the first truly commercial MWD operations. However, new service companies continued (and still continue) to enter the market, and radical design innovations arrive every day. During the first decade of MWD commercial development, the majority of research time and effort was put into improving the design of the transmission system. The first priority was reliability. In order to be commercial -- to be able to charge for the service -- it was necessary for the pulser to transmit data for a high proportion of its time on bottom. When this was achieved, improved total lifetime became the goal. Both sensors needed to be able to survive several bit runs, with only minimal well-site maintenance, before the contractors could start to see any return on their huge research and development investments. Early MWD systems were far from profitable: requiring large support crews, massive equipment backup and redundancy, followed by an entire re-manufacture operation after each trip into the hole. Like a space shuttle, they were reliable in operation only at the price of massive pre-flight preparation. For a short period, the customer was so impressed by a reliable stream of data while drilling that they were, for that short time, willing to accept, without complaint, the limited range and poor quality of the data being delivered. In this brief grace period the service companies put their investment into improving profitability by increasing the tools operating lifetime and reducing tool maintenance time and cost. Soon, however, geologists and log analysts became dissatisfied with the poor quality of the MWD formation logs which were little more than the equivalent of a thirty year old wire-line log suite. Soon, MWD sensor improvements were demanded, and research began in earnest in service company, and oil company laboratories, and in numerous other specialist companies. Given the time lag of publication, this book will inevitably be behind the state of your art. The following discussion therefore includes only the most ubiquitous sensors that are presently being utilized commercially. Beyond these, new possibilities are arriving every day.

Directional-only Measurement The MWD sensors that found earliest commercial application were directional sensors for use on long-reach deviated wells being directed toward distance reservoir targets or around hazards (see Whittaker & Kashuba, 1987.) This remains the largest application of MWD because of the conspicuous savings obtained. Prior to MWD, it was necessary to halt drilling on deviated wells regularly, remove the drill string and run a wire-line tool into the hole to make detailed measurements of the well path. From the basis of these measurements, a new well steering plan was developed. If, as was often the case, it was a situation of you can’t get there from here, then it was necessary to plug back the well and re-drill a section of it. On

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an offshore production platform, with numerous wells drilled out from a central location, mis-direction might even result in two wells intersecting and a mutual well blowout occurring. MWD allows the directional measurements to be made while drilling continues to take place, thus saving a great deal of down time and allowing the wells to be drilled more quickly. In reality, the drill string must be held stationary while the actual directional measurement is made but, even so, it is possible to make a measurement quickly every time a connection is made and transmit it to surface immediately afterwards when circulation is re-started. In order to determine bottom hole inclination and azimuth accurately it is necessary to take several measurements using accelerometers, gravitometers and either a magnetic or gyro-compass. However, much of this data is condensed in down-hole calculations in order to transmit to surface: inclination, azimuth and the minimum extra data required to check measurement and calculation error ranges. If a directional drilling tool is being used, then the MWD tool will also transmit the tool face orientation so that the tool can be adjusted to follow the correct well path (see Arps, 1979.) MWD directional measurements involve a major saving of rig time in monitoring and controlling directional well paths in development drilling. The tool does not require the rig to be shut down for long periods and, being available while drilling, they help avoid other serious delays in modifying or re-drilling incorrectly deviated wells. Because measurement takes so little time, MWD also allows the measurements to be made over much smaller depth intervals than would be economical with conventional systems. This allows a more accurate calculation of well path and bottom hole position than has been possible. This allows more economical and optimized well plans to be made without such large safety factors as were previously required. Directional MWD does not require high data rates as the data set is small and is only transmitted at each connection -- every ten meters or so. It does, however, demand extremely high system reliability, since loss of real-time data, even if saved in memory would seriously reduce the value of the service. Directional MWD must also be relatively cheap and be compatible with the less sophisticated rigs, equipment and people sometimes used in development drilling. For this reason, the most successful directional MWD tools all use positive mud pulse transmission systems. This technology is relatively slow but reliable, and it produces large positive mud pulses which are easily detected using relatively simple detection systems against even very noisy older mud pumps. Instead of a sophisticated logging unit, equipped with computers and log plotters, the directional MWD service may require only a small service trailer or van with a weather-proofed optical display unit that can be mounted on the rig floor (see Figure 11). As another concession to low cost, some directional MWD systems dispense with power generation, system redundancy, and other extended lifetime features. Instead, they offer smaller, simpler tools which can be retrieved from the hole and replaced without removing the drill string (see Henderson and Cluchey, 1987.) If a pulser fails or the batteries are exhausted, a portion or even the whole MWD tool can be fished from the hole using a grapple on a wire line and replaced. The replacement assembly may be run back in on the wire line or for further time savings, the robust MWD system may be go-deviled (allowed to fall under the effect of its own weight, or be carried by mud flow) to reach bottom in time for the next required measurement.

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Figure 11: A portable, weatherized visual display unit of the type commonly used by directional MWD services. this unit can be set up in a mud logging unit or other well-site office but it may also be safely set up on the rig floor or elsewhere on the well location (illustration courtesy of EXLOG, Inc.)

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Figure 12: The MWD Weight on Bit and Rotary Torque on bit measurements show marked difference from the equivalent measurements made on surface. Differences may be used in drilling and safety monitoring and in formation evaluation to indicate rock strength, porosity or fracturing (illustration based on Lesso and Burgess, 1986, courtesy Society of Petroleum Engineers).

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Drilling Response Measurements While directional drilling measurements have alone served to prove the cost effectiveness (to the customer) and profit potential (to the contractor) of MWD, other drilling measurements have had a much lower impact on in marketing and application. The most obvious MWD drilling measurements are drilling torque and weight (or, more correctly, axial load) on the drill bit (see De Bruijn, Kemp, and van Dongen, 1986.) Both of these quantities are commonly measured at surface but are so effected by the drag and friction of the bore hole wall that the surface-measured value bears little relationship to the actual quantity being experienced by the drill bit. The surface-measured quantities are, of course, still valuable in monitoring and optimizing the drilling process: rate of penetration, bit cuttings structure and bearing lifetime are all effected. They may also be of value to the geologist, along with rate of penetration, in the interpretation of formation strength, induration, porosity and fracturing while drilling. The effects of these variables – as understood from surface measurements -- are well-studied and documented. Nevertheless, there is no doubt that measurement down hole will greatly improve the field by supplying more accurate and more representative measurements, and ones less susceptible to secondary effects and modifications. They are also relatively easy to measure by attaching solid-state strain gauges to (or even embedding them within) the steel of the MWD drill collar above the bit. Most multi-sensor MWD systems offer down-hole weight and drilling torque as part of their suite of sensors (see Figure 12). Logs showing the data from these sensors plotted alongside surface measurements demonstrate the major differences between and some work has been done toward developing methods of use and interpretation of the data (see Bates. and Martin, 1984.) Unfortunately, the work has not been widely accepted in the drilling community and the development of improved MWD drilling sensors and applications has consequently received lower priorities. A second type of MWD drilling sensor was developed as a consequence of the demands of MWD research itself. In the early stages of MWD development, it was found, under certain conditions of bottom assembly design, weight on bit and rotary speed, that longitudinal and torsional vibrations could occur that would literally shake the MWD tool to pieces. Of course, in other circumstances, they might, instead, do an equal amount of damage to the bearings in the drill bit, or cause the drill string to fail resulting in a lost bottom hole assembly, and a fishing job. In order to monitor this behavior and develop improved methods of predicting and avoiding it, Dave Close's group at EXLOG developed an MWD vibration monitoring add-on tool was developed (see Figure 13). This uses tri-axial accelerometers to measure three-dimensional Bottom-hole Assembly (the combination of drill collars, stabilizers, subs, and so on, run above the drill bit and below the regular drill pipe) movement and a single magnetometer to correlate these with the rotation of the drill string (see Allen, 1987, and Close, Owens and Macpherson, 1988). The tool measures and stores many thousands of accelerations for later analysis of major events and tool failure. Alternatively, it is possible to compute and transmit a real-time MWD log of average drill string tri-axial accelerations. These have been shown to be very useful in diagnosing bore hole condition, improved bottom hole assembly design and even in formation evaluation (see Figure 14). Unfortunately, this

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system seems to have gained more positive support in oil company research departments than it has so far achieved in the world of commerce.

Figure 13: The Exploration Logging (EXLOG) Down-hole Vibration Monitor (DHVM) is a stand-alone sensor package that can be run in combination with any MWD transmission system, or run as an independent memory-only tool (illustration from Close, Owens and Macpherson, courtesy of Society of Petroleum Engineers).

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Figure 14: The Exploration Logging (EXLOG) Down-hole Vibration Monitor (DHVM) can supply data for Bottom-hole Assembly (or BHA -- drill collars, stabilizers, subs, and so on) optimization, safety monitoring, drilling or equipment research (illustration based on Close, Owens and Macpherson, courtesy of Society of Petroleum Engineers).

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The one MWD drilling sensor that does seem to have gained wide support amongst drilling engineers is the down-hole tachometer. This is a device to measure and transmit the true rotating speed of a down-hole motor. Although there have been, in the past, methods to calculate hydraulic down-hole motor speed from mud flow rate, pressure loss, weight on bit and torque, none of these have been widely trusted. In this case, it seems that no driller is willing to trust the MWD sensor without any other established, and trusted value with which it can be compared, and with which it might disagree.

Bore Hole Environment Sensors The earliest MWD research tools contained sensors to measure temperature, pressure and electrical conductivity of the drilling fluid. This was simply a matter of find something easy to measure which could be transmitted to demonstrate functioning of the tool. In fact, these turned out to be very important measurements, and they can make important contributions to formation evaluation and drilling optimization. When formation electrical measurements, from either wire-line or MWD logs, are interpreted it is necessary to know formation temperature and the electrical conductivity of the mud in the bore hole and its filtrate. These are important benchmark values upon which much of the log analysis is to be based. For wire-line log analysis (see later in this chapter), a sample of mud is caught prior to the log run and analyzed with a simple, not particularly accurate, conductivity meter. Bottom hole temperature is taken from a maximum-reading thermometer in the logging tools, or estimated from the geothermal gradient. The mud temperature and conductivity measured continuously by the MWD multisensor logging tool provides more accurate and consistent values of the mud properties and a means of extrapolating formation properties. During the early MWD research runs, bottom-hole hydrostatic and circulating pressures were measured, and these were sometimes to drastically disagree from those calculated from conventional hydraulic models. It was obvious that neither theoretical nor empirical models were able to accurately represent the behavior of drilling fluid in drilling and pressure control. It was especially apparent that the new, more compressible oil-based drilling fluids behaved in highly unpredictable ways. As an earth scientist, I would not wish to malign the engineering disciplines by quoting the old slander that when an engineer finds disagreement between his theory and the data, he immediately solves the problem by discarding the data. However, it is certainly true, once again, that, after the measured pressures were found to disagree with the old tried and true calculation methods, there was a widely observed decline in the demand for MWD pressure measurements. Though bottom-hole pressure measurement can be provided by any commercial multi-sensor MWD tool, it is rarely requested.

Formation Evaluation Measurements MWD is a new field and much of the early development effort went into getting reliable and long-lived down-hole transmission, power, data processing and other support systems. First generation sensors were somewhat primitive compared to equivalent wire-line sensors. Indeed, they were closely related to the early ancestors of modern wire-line logging tools. Even the second and subsequent generations of MWD sensors suffered serious disadvantages compared to wire-line equivalents.

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Today, MWD logging tools are generally comparable to their wire-line logging cousins. Most differences result from the different environment and time scale of measurement. Some of the differences inevitably result in inferior MWD logging results, but others give the real-time logs a definite advantage:

Tool Design With the benefit of over 30 years of field experience, modern MWD logging tools have improved in sophistication and ruggedness, but the nature of their environment of operation still forces limits on tool design. The entire MWD logging tool: sensors, data processing, power supply and distribution and data transmission system must all fit within a conventional drill collar which must not deviate too greatly from the diameter, stiffness, strength and internal mud flow capacity of the collars above it (see Figure 2). This sets obvious limitations on the shape, size and positioning of MWD sensors. design and configuration of MWD sensors. Perhaps the greatest of these is a sever limitation of the number of penetrations and protrusions that can be made through the wall of the drill collar. These will substantially weaken the drill collar rendering it both more flexible, less able to control bore-hole deviation, and more prone to failure resulting in a twist-off and a fish lost in the hole. Sensors that cannot extend beyond the drill collar will be effected by the mass and thickness of steel between themselves, the outer annulus and the formation. Finally, the demands of formation evaluation must always take second place to the need for drill collar strength and rigidity. In addition, MWD logging tools must be designed to survive shock and vibration levels far in excess of anything experienced on a wire line.

Time of Measurement Fortunately, there is some good news: the MWD sensors are located at, or at worst a few feet above, the drill bit. Measurements are made when the formations are freshly cut. There will be minimal fluid invasion, mud filter cake formation, fracturing, caving or other damage to the bore hole wall. Hopefully, less than perfect sensors can still achieve good results on such a near-perfect sample. Interpretation of many formation evaluation measurements require knowledge, or assumptions about, the extent and type of drilling fluid filtrate invasion of the bore hole wall. We need to know, or guess, what proportion of which formation fluids have been flushed away from the bore hole, and how far radially that invasion extends. We also need to make estimates of the salinity and chemistry of that mud filtrate, and the thickness, composition, and consistency of the mud filter cake remaining on the bore hole wall.

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For wire-line log analysis, after days or weeks of filtration have taken place since drilling occurred, we assume that: ✔ Filtration, invasion, and filter cake formation has proceeded to a maximum or at least stable, steady state extent. ✔ The chemistry of mud being circulated in the bore hole when drilling ended is indicative of the properties of filtrate and filter cake to be found down hole.

Good neighborliness hint: the wire-line logging crew may not arrive at the well site until after drilling and circulating (to clean out, and co nd itio n the hole) has finished and the trip out is under way. A good neighbor mud logger will catch a liter sample cup of mud and keep it, covered, to serve as welcome gift for the wire-line loggers. That way, they can get a trustworthy mud conductivity measurement for their log headings.

MWD formation evaluation sensors are located just a few meters, above the drill bit. This gives them one obvious advantage; their measurements are, by a long shot, the first available, and they add an important new dimension to well-site decision making in both formation evaluation and drilling efficiency. But, there is another advantage, one effecting the both the quality and quantity of data available from MWD formation evaluation. This is that MWD log measurements are made only minutes, or less, after the formation has been penetrated, and when mud filtration and invasion have barely started. We may not know the chemistry of the formation fluids, but we can be certain that, at the time of the first MWD measurements, the measured formation was close to 100% filled with virgin formation fluids. We can also, only one lag time after measurement, sample and analyze the actual drilling fluid that was filling the bore hole at the time of that first measurement. Finally, on subsequent trips in and out of the bore hole we can make the same measurements again and again (and store them in down-hole memory) and merge them with earlier measurements to study the progressive changes brought about by changes in fluid content (or oil, gas, and water saturations), as invasion, flushing, and filter cake formation proceed (see Figure 15). Time-lapse logging of this kind was previously unknown (or very rarely so, given the prohibitive expense involved in multiple log runs, and associated down time) in wire-line logging and adds yet another new dimension to formation evaluation. From several generations of MWD logs or from MWD-plus-Wire-line combinations it is possible to observe the results of progressive formation invasion (see Chin, 1986, and Cobern, and Nuckols, 1985.)

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Figure 15: A representation of the bore hole and adjacent formations. Over time, the depth and completeness of flushing increases, formation fluids are swept into the bore hole or flushed away from it, leaving the drilled formations filled with drilling fluid filtrate.

Speed of Measurements Wire-line logs are run at several hundreds or thousands of meters per hour. The logging speed of a MWD logs is, of course, no more nor less than the rate of penetration: at best tens of meters per hour, very low one compared to wire-line logs. This can result,

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for some logs, in extremely good vertical definition. For others, for example: radioactivity logs, where the thick, steel drill collar acts as a massive filter, the extra time available allows a statistically valid count to be made and a comparable log to be produced.

Averaging and Edge Effects The MWD sensors operate during drilling. This means that the measurements must be taken with the drill collars rotating rapidly. If we could be certain that the collar was always perfectly centralized this would produced a rotationally averaged response. Unfortunately, we cannot guarantee this to be the case. The collar may precess in the hole, following a helical path. In deviated wells, the weight of the drill collar will cause it the be positioned closer to the low side of the bore hole. Depending upon the sensor position and whether the measurement is a directional one, this eccentricity may seriously bias the measured data. On the good side, the slow speed of MWD logging make the results less susceptible to edge effects. On wire-line logs, rapidly crossing sharp formation boundaries with sharp changes in properties, can cause the logging tool to produce transitional or Of course, drag on wire-line logging tools, particularly with long anomalous at that depth (and immediately above and below). combination tools, centralized, or pad tools, can result in The worst result of these edge affects can be inaccuracies in variable wire-line stretch and small depth measurement errors. defining the exact depth of formation boundaries. MWD logs The first job of any log analyst is the adjust all log traces: mud, are less susceptible to this.

MWD, or wire-line, to a common depth reference.

Formation Contact Rotation of the drill collar also preclude the possibility of any form of pad tool. The concept of an MWD logging sensor pressing against or even penetrating the bore hole wall is quite unachievable with present day materials and techniques. This means that MWD sensors and MWD log analysis must always cope with the presence of a mud annulus effecting the measurements. The fact that this annulus contains both mud and variable amounts of well cutting -- fragments of formation – and formation fluids is yet another complicating factor. Eccentric rotation, lack of pad contact, and filtering by thick steel collars, at first considered to be serious draw-backs, have over the years led to improved stabilizer (or centralizer) design, and to the development of sophisticated Despite the digitization and computer pre-processing of modern MWD, and new mathematical and statistical techniques for wire-line logs, log analysts in the field seem to require just as many thick correcting measured quantities.

volumes of correction charts and nomograms as they ever did before.

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Electrical Measurements The MWD electrical sensors are similar in design to wire-line log sensors (see Electro-magnetic Properties, later in this chapter). The Short Normal Electric Log is the simplest measurement of the electrical resistivity of the formation. The tool transmits an electric current between two electrodes, and the potential difference measured between two more electrodes is responsive to temperature, and to the electrical resistivity of the drilling mud, to the mud filtrate, and formation fluid in the formation. The measurement relies upon the presence of a conductive fluid, and: ✔ It works best with saline formation water and water-based drilling fluid. ✔ It becomes unresponsive to formation resistivity with a highly conductive salt-saturated drilling fluid, and ✔ It does not work at all in a non-conductive, (invert-emulsion) oil-based mud. Historically, resistivity logging tools came with a range of electrode spacings from the 16-inch (or Short) Normal, up to the 16-feet, 6-inch Lateral. With a longer electrode spacing, the current penetrated further out into the formation, and the measurement was more responsive to formation fluid resistivity, and less to the drilling fluid. Unfortunately, the vertical resolution of the tool was limited by longer electrode spacing. In MWD logging, the Short Normal is the most common tool (see Coope, 1985). The shorter spacing tool gives good bed resolution and clearly delineates: ✔ Higher resistivity from low porosity, impermeable formation, where the current only flows through the less conductive drilling fluid, and ✔ Lower resistivity from high porosity, and permeable formations, where more current flows through the formation water, or filtrate filled pore spaces. The measurements therefore correlate well with Rate of Penetration on the mud log. Induction logging also measures the electrical conductivity of the formation. In this tool, an electric current flows through induction coils and induces eddy currents to flow in the formation water, or mud filtrate-filled formation pore space. These in turn, induce current to flow in a second set of receiver coils in the tool. The measurement is again responsive to temperature, and to the electrical resistivity of the drilling mud, to the mud filtrate, and formation fluid in the formation. In this case, there is no current flow between the tool and the formation and no need for a conductive drilling fluid. In fact, induction logging works best when: ✔ Mud filtrate in much higher than formation resistivity, for example when using a fresh water mud to drill saline formation, and ✔ An (invert-emulsion), non-conductive, oil-based mud is used, and the induced eddy currents are only in the formation, not in the

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drilling fluid.

Figure 16: MWD electrical measurements (upper scale and solid log trace) respond in a similar manner to the equivalent wire-line logs (lower scale and dashed log trace). however, due to the different logging environment there will be a qualitative difference in response between the two tools. By convention, induction logs are scaled in units of Conductivity (the reciprocal of resistivity), but the Induction log respond in similar manner to the Electric Log, and showing: ✔ Lower conductivity from low porosity, impermeable formation, where the current only flows through the less conductive drilling fluid, and

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✔ Higher conductivity from high porosity, and permeable formations, where more current flows through the formation water, or filtrate filled pore spaces. Focused Formation Resistivity (see Evans, Brooks, Meisner and Squire, 1987) logging tools (commonly, in wire-line logging, referred to as Laterologs, or Spherically-focused logs) use a more sophisticated arrangement of electrodes to control the path of the electric current from the tool, out into the formation, and back to the tool, in order to obtain deeper penetration into the formation and better depth resolution. All of these tools respond in a similar manner to the equivalent wire-line tools. However, remember that the MWD logging environment is very different, fresher, less invaded and with closer to in-gauge bore hole than that which will be seen later by the wire-line logs. There will be qualitative differences between the response of MWD and wire-line logs reflecting this difference. In general, we find that each MWD log has the appearance of an equivalent -- but more deeply investigating -- wireline log (see Figure 15). In wire-line logging, micro-resistivity or proximity logging tools, have a very limited depth of measurement and respond almost entirely to the resistivity of formations near to the bore hole, flushed almost entirely with drilling fluid filtrate. By comparing the resistivity and induction log measurements from deep and shallow investigating tools, it is possible to compute the difference in Water Saturation and hence the mobility of the non-water components in the formation fluid. In MWD logging, these micro-tools are obviated by time-lapse logging: fluid mobility measurements can be better determined by making the same resistivity measurement, several times, and monitoring the progressive changes as filtrate invasion proceeds, and oil and gas are displaced. Electromagnetic Wave Propagation logging measures the travel time and attenuation of an electromagnetic wave through the bore hole and adjacent formation. This measurement is little affected by water salinity, but is markedly different in water, oil and gas. It provides a very reliable measurement of water saturation, and progressive flushing.

Radio-activity Measurements The MWD radiometric sensors are similar in design to wire-line log sensors (see Radiometric Properties, later in this chapter). Formation lithology and porosity can be investigated using natural and induced radioactivity. In the simplest tools a scintillation counter within the drill collar monitors formation background (gamma ray) radioactivity (see Figure 17 and Coope, D. F., 1985). Once again, the general response is similar to a wire-line logging tool in a fresher, less damaged bore hole. Detailed examination, however, reveals other problems. For example, the MWD gamma ray log must be corrected for bore hole diameter and mud density on a foot-by-foot basis as the data is gathered. Unlike the wire-line log, we are not gathering data from a static bore hole filled with uniform mud. The Gamma Ray logging tool responds to natural radio-activity in the formation, and this is mostly from Potassium, Uranium and Thorium isotopes present in clay minerals. The log shows a high gamma ray background through long claystone and shale sections, with lower values when clean, clastic, and possibly productive intervals are penetrated.

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Figure 17: MWD gamma ray logs (upper scale and solid log trace) are similar in response to wire-line equivalents (the scale at the bottom, and the dashed log trace). However, there is a difference in response caused by the varying mud density and the blocking effect of the steel drill collar. The greatest difference between MWD and wire-line gamma ray logs will be seen in logs from long shale sections with variations in the proportions of the radioactive elements Potassium, Uranium and Thorium. ✔ Potassium is the dominant radioactive component, but

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✔ Uranium and Thorium produce significant amounts of lower energy gamma rays the effects of which are seen in wire-line gamma ray logs. ✔ The lower energy gamma rays produced from Uranium and Thorium are absorbed by the steel of a drill collar, and so they are less well detected by the MWD gamma-ray sensor. Figure 17 shows the similarities and difference of the two sensors when drilling a uniform shale of varying spectral response. In the more sophisticated radioactivity measuring tools used for porosity determination there are more serious problems (see Paske, 1987, Howes, 1986, and Howes, 1987). These are the: The Formation Density (gamma-gamma) tool contains a high energy gamma ray source. Gamma rays collide with electrons in the formation, and lose energy (Compton Scattering). The lower energy gamma rays, continue to bounce around until they are either captured by dense formation materials, or find their way back to a detector in the logging tool. Capture rate is linearly related to the formation mass absorption coefficient, which for most common rock materials is closely related to bulk density, so that the detector gamma ray count rate decreases with increasing bulk density. If formation matrix density is known, then the log output can be scaled in porosity. Neutron logging tools contain a source of fast neutrons: ✔ These neutrons collide with nuclei in the formation, and fluids (mostly in the near, flushed zone). ✔ At each collision, a neutron loses energy, and eventually becomes a thermal neutron, drifting randomly ✔ Eventually, every thermal neutron is captured by a nucleus, and a gamma ray is emitted. Collisions with smaller, lighter nuclei cause the neutrons to lose energy more quickly, and so the rate of energy loss is greatest when the formation contains more light elements: mostly Hydrogen atoms, in water, oil and gas. There are two types of Neutron porosity tool. ✔ The Thermal (or neutron-gamma) Neutron porosity tool uses a gamma ray detector to measure the gamma rays emitted when neutrons are captured. ✔ The Epithermal (or neutron-neutron) porosity tool uses a detector of low energy neutrons. It only responds to neutrons that have lost almost all of their kinetic energy, and are almost thermal, or epithermal. In either case, the detector output increases with the amount of fluid-filled porosity in the rock, and the log can be scaled in Neutron Porosity Units.

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Figure 18: Both the Thermal (or neutron-gamma) Neutron, and the Epithermal (or neutron-neutron) porosity tools use a high-energy neutron source. The Thermal tool detects the gamma rays emitted when thermal neutrons are captured. The Epithermal tool detects lower energy, epithermal neutrons that have lost almost all of their kinetic energy . In addition to porosity, the measurement is also affected by salinity (chlorine is another light element, present in the formation and drilling fluid). Corrections are also required for bore-hole size, drilling fluid type, and density. Each type of measurement has certain advantages and disadvantages, and both continue to be used in wire-line and in MWD logging. All three of these devices must detect lower energy particles, either gamma rays or epithermal neutrons. The wire-line log equivalents are pad tools in which the sensor window makes direct contact with the bore hole wall.

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In MWD tools this is, of course, not possible, but with a fresh, undamaged, almost perfectly circular bore hole it is still possible to obtain a valid response. However, the existence of a single window means that the device is strictly directional. This is a problem because the count rates in many formations are so low that, in order to achieve a valid measurement, the count must be accumulated over a significant length of time, that would be over a fraction of one or more rotations of the drill collar. Unfortunately, as I mentioned above, this rotation is unlikely to be perfectly centralized in the bore hole. Combining a timed measurement with eccentric rotation produces a result that is not a true average of the actual formation and bore-hole effects. At the present time, this effect introduces unpredictable and un-correctable errors in all measurements of this type. Until such time as a means is found of stabilizing and centralizing the drill string, it will not be possible to obtain an MWD porosity measurement with the same degree of accuracy obtained from an equivalent wire-line tool. However, once again, the MWD neutron logs obtained from freshly cut formation, and delivered within hours of the formation being drilled, and using regularly improved computation methods, are still considered worthwhile. This has been a necessarily very brief review of MWD formation logging sensors. A more detailed discussion of the principals behind the measurements, and methods of interpretation and analysis are included in the Wire-line Logging Data section, later in this chapter.

Surface Receiving Systems The essential components of the MWD surface receiving system are a sensitive mud pressure gauge, a computer to perform the filtering and decoding of the signals and, finally, a means of displaying the results. In a simple directional MWD service, this may consist of a small automatic logging unit or a stand-alone box with keypad and visual display Martin, C. A., 1986 on page 14 which can be located on the rig floor or any other convenient location. For multi-sensor, formation evaluation and drilling control services, a surface system with more capabilities must be provided and this, in most cases is a mud logging unit. Raw MWD data, even after filtering and decoding is not immediately usable. The data must be normalized by applying bore hole diameter, mud density and other corrections. Other calculations, corrections and automatic plotting are also required if the logs are to available in a timely manner. Making extra effort to perform real-time logging serves no purpose, if the logs are not available until hours later. The mud logging is also a source of the background and correlative data needed to complete the MWD log data and provide a full suite of formation evaluation services. Some of the larger mud logging contractors, for example Schlumberger-Anadrill and Exploration Logging (EXLOG) can supply this entire service: multi-sensor MWD, enhanced mud logging and data evaluation services in a single large mainframe mud logging units (Figure 89 on page 431). However, this does not mean that using MWD must reduce the available choice of mud logging services. Each of the MWD companies, including the full-service ones should be able to supply their MWD data in an electronic format which can be read, processed and displayed by other information management services. Similarly, many of the smaller, though not unsophisticated mud logging

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companies should be able to interface with this data source, store the data in their on-line database and incorporate it with plots of drilling and geological data. As with all computer hook-ups, first efforts will require some hardware and software adjustment (we all know about nonstandard computer standards) but it is worthwhile to take the trouble if it yields greater flexibility in the best logging and geological services for the well.

Figure 19: Logging While Drilling requires measurement, processing and plotting of the measured data. on surface, after filtering and decoding, the data must be processed and displayed by a stand-alone micro-processor or in various sizes or configurations of mud logging unit.

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MWD Service Configurations From the available down-hole measurements, transmission schemes and surface systems it is possible to assemble a multitude of MWD systems. Not all of these are, in fact, commercially viable. The following list contains the configurations most commonly encountered in industry.

Directional Survey Services The minimal level of MWD service requires only measurement of drill string inclination, azimuth and the tool face direction of directional steering tools, when used. The service equipment must readily portable and easy to install and remove since, in low cost production drilling, the service may be used only for complicated steering jobs and then replaced with a cheaper, conventional wire-line directional service for the remainder of the well. It must be compatible with low-tech rigs and, most important of all, either monumentally reliable or capable of being replaced in the drill string without tripping. Since the service provides only single measurements, not a continuous log, there is little need for any sophisticated data processing, storage or plotting functions. A simple, weather-proofed gauge or liquid-crystal visual display unit is commonly sufficient (see Figure 11 and Figure 19). This is, most often, used to monitor that the well is correctly following a pre-planned well path. If, on the other hand, the data is to be used, for well planning or course correction, it will be necessary to provided a computer and software to perform the complicated calculations in three-dimensional geometry required for well planning. This software, which may be provided by then MWD contractor, the operator or separate directional drilling contractor will normally run on a networked personal computer, either at the well site, or accessible via the Internet. Alternatively, off-line analyses may use manually entered directional data (there is not so much as to require automatic data acquisition). Reports will be generated as two- or three-dimensional well plots rather than depth-scaled continuous logs (see Figure 20). Several companies provide this level of service; the majority of them using positive mud pulsing systems. Amongst them are pure MWD service companies and others who combine directional MWD with mud logging or with other services, such as directional well planning, drilling management, wire-line directional measurement and steering tool rental. Obviously, this gives a wide choice in service combinations and competitive pricing. As I mentioned above, all use positive mud pulsing with similar sensor equipment and performance. Most MWD companies purchase identical directional sensor from the same manufacturer, and offer a very limited form of two-way communication in which the down-hole computer can be turned-off, reset, or switched between various computational modes by applying instructions signaled by drill string movements, or turning the mud pump on and off in a particular sequence. The major variations in tool design, centering around the reliability question. At on extreme are large, powerful, multiply redundant system which offer very high reliability but they are, of course, as large, and as expensive to use and as cumbersome to rig-up and tear-out as the

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multi-sensor MWD tools used in exploration drilling (see below). At the other extreme are systems almost, but not quite, to the point of being expendable. These small light systems are not only easily installed or removed from the drill string, without tripping in a special drill collar, they also light weight enough to be carried easily to and from the well site in a van or helicopter (see Figure 21).

Figure 20: If On-site well-planning or plan modification is undertaken a computer system will be needed to perform the complex calculations and plots needed to determine bottom-hole position and proximity to other wells or lease boundaries.

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Figure 21: This small directional MWD tool can be hand-carried to the well site in its suitcase, go-deviled into a conventional drill string, and begin transmitting directional data within a matter of hours from call-out.

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Enhanced Directional Services Directional logging is useful in monitoring a well plan on production wells where a detailed well plan has been designed from good knowledge of the geological structure and target depths. However, on early stage development wells drilled from offshore production platforms and the rare directional exploration well, knowledge of the section may not be so conclusive. In these cases, there can be need for a directional MWD service with some limited formation logging capability for correlation purposes. While the simplest directional MWD systems are limited to low end capabilities, the larger systems can be enhanced with natural gamma ray or simple short normal electric log and a surface logging unit capable of producing a rudimentary real-time log, sometimes in conjunction with mud logging. To add this capability requires greater internal complexity: power supply and distribution, processing power and, of course, the ability to operate continuously at higher data rates. It is also necessary, on surface, to have equipment to automatically acquire, process, store and plot the data. These logs are insufficient for complete formation evaluation but they can be used to maintain real-time well path control relative to both the original drilling plan and to the actual formation tops encountered while drilling. They may particularly effective as in-bed steering tools in long reach,directional wells. When the well path is approximately horizontal following a single, relative thin horizon then, more important than the actual, quantitative bore-hole inclination measurement, is determining whether the well path is within the target horizon, or whether it has transgressed upward, or downward, beyond that horizon. In this circumstance, a real-time Short Normal, or Gamma Ray log may be the most useful directional tool available.

Formation Evaluation Recording Services Not all exploration data is required instantly as drilling takes place. While gathering data in real-time may have value, there still may not be any value to using the data in real-time. In many cases, the complexity, cost and failure-probability of a transmission system is simply superfluous to an MWD system (see Coope, and Hendricks, 1984.) In these circumstances, reliability can be improved and costs substantially reduced by dispensing with the transmission system and using a memory-only system. Where formation evaluation demands can wait a few hours until the end of the bit run, a memory-only MWD system can allow reduced logging costs, or addition of more and better sensors to the system without adding cost. Yet another use for a memory-only system is for specialized applications requiring either very large volumes of data, or where data processing demands are complex, variable or subject to operator skill. In these cases, down-hole processing may not be practical and MWD data transmission rates cannot accommodate the data volume in real-time. An obvious example of this type of applications is the detailed analysis of drill string vibration, discussed above. Geophysical applications such as VSP similarly require the gathering of large volumes of data in a short time interval and subjective processing. These types of MWD applications are not compatible with real-time transmission but lose little value when used with a memory-only system.

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There are other variations on the theme of a recording (or strictly speaking a no n-transm itting ) MWD system. Long, long ago, Anadrill had its origins when Schlumberger purchased a small Gulf Coast mud logger in order to have well-site labs in which they could test the so-called SNAP Log. Log. This was a continuous, very high resolution surface measurement of drill string vibration and torque. It was hoped, that this could yield useful information about rock strength, porosity or permeability. More recently International Logging offered the SEISBIT service, in which drill bit noise (or vibration) served as the energy source of seismic signals that were reflected and refracted underground and, inevitably detected by sensors on the rig and and surface-located geo-phones some distance around the rig. DataLog (now merged with International Logging into the Surface Logging Division of Weatherford International) offered another SNAP Log-like service in which high resolution drill drill string torsional vibrations are measured and analyzed for drill bit optimization, and drill string wear protection. It would be interesting to see these technologies (or something like them) combined with a memory-only directional MWD tool, or with a a memory-only drill bit diagnostics tool, such as EXLOG's DHVM tool (see Figure 13). 13). Even more interesting, if you were planning to bury geo-phones and run cables around the rig, then why not combine them with the ground antennæ for an EM MWD transmission system (see Figure 4). 4). Maybe someone is working on that in a back room somewhere, and we can look forward to seeing it when oil gets back up to $150/barrel. Real-time Formation Evaluation The top-of-the-line, gold-plated Cadillacs of MWD services are the multi-sensor tools providing a complete suite of drilling, bore-hole and formation sensors (see Teige, Undersrud and Rees, 1984) combined with a powerful system for data acquisition, data analysis and log evaluation. MWD sensor development is not so far developed that these systems are able to offer a choice of sensor combinations. Most systems provide all available sensors in a single, standard MWD tool. The few choices presently provided are: ✔ The type of formation electrical measurement made. Short normal or focused resistivity measurements may be replaced with induction or electromagnetic propagation measurements. As with wire-line logging, the choice is made on the basis of the anticipated

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difference in resistivities of the formation pore water and mud filtrate, and ✔ The type of porosity logging tool: Density, Thermal, Epithermal Neutron In order to accommodate the full suite of sensors, a high data rate MWD transmission system is required, negative mud pulse and mud siren systems are most common. It is also necessary to have a high capacity surface system for data acquisition, processing and plotting of realtime logs. This requires all of the capabilities of an advanced, computerized mud logging unit.

The Future of MWD Today, full-service MWD is very much a niche business, with two major markets: ✔ Long-reach, directional drilling where MWD offers a level of real-time formation evaluation, and directional monitoring unavailable from any other technology, and ✔ Those high budget, high profile exploration programs, on which success makes and breaks both companies and careers. Although less common than in the high-rolling eighties, such programs still exist and no innovation is too expensive, nor too speculative to be left out of the program. In more practical operations, real-time, multi-sensor MWD can provide a revolution in formation evaluation and drilling optimization. Its contribution is threefold: ✔ Data is provided which is unavailable from any other source, such as true axial force and torque on the bit. ✔ Data is provided in a better or different form than any other source, such as formation resistivity from recently drilled and barely invaded formations. ✔ Data is provided in real-time, near-real-time or (at worst) much more quickly than any other source. The importance of these improvements is unquestionable (see Nuckols, Cobern, and Couillard, 1985). Yet, in order to gain any effective value from and MWD service, it is important to select sensors, transmission system, surface receiving and evaluation systems that are compatible with each other, with the needs of the exploration program and with people and methods to be utilized at the well site (or in realtime communication with it). Any type of MWD operation adds costs to the exploration program: both its own day rate and other rig and logistic costs incurred in supporting MWD. If the type or timing of MWD data gathering is not matched by the needs or capabilities of the program the service, no matter how well performed, becomes an expensive waste of rig time and people. In selecting an MWD service, the first consideration should, of course, be to match the data requirements and sensors. If data is needed in real-time it should be gathered by MWD. If it is not needed until later then it can wait for later, cheaper or better measurement techniques. In addition to the theoretical need there is also the practical capability to handle the data. Having data that is available is only part of the

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solution. Unless skilled people are available with adequate time and suitable tools, the data will go to waste. Finally, there are considerations of flexibility of the drilling and evaluation procedures for the well. If the well program cannot accommodate changes dictated by real-time evaluation, then much of the value of real-time data is lost. This should be considered on the basis of two worst cases: ✔ If data gathered in real-time dictates major changes in drilling or evaluation, does the well plan have sufficient flexibility to accommodate these changes without major loss or delays -- or will the real-time data fail to have impact on the current well? ✔ If all or a section of the MWD data is lost due to equipment malfunction, is there a means to make up the data from conventional means without extra expense, delays or re-drilling? The final question is one of trust. MWD measurements are made in a unique environment. The results of these measurements are inevitably different from those of other, more familiar measurements made at different locations or times. If the people involved in the well can accept this fact, then the MWD data can form part of a complete and integrated log suite. For example, MWD formation logs should not replace wire-line logging. Instead, the data gathered from MWD should assist in optimizing the selection of tools, parameters and intervals for wireline logging. Unfortunately, to many people different and inferior are synonymous! ✔ To these people, much MWD data is too different to be usable. ✔ Other MWD data may be used in real-time when it is all that is available. ✔ Later when better, or more familiar (which can – sometimes, but not always – mean the same thing), data becomes available, the MWD data is discarded. This is a waste in two ways. Money is wasted in repetitive measurement. Evaluation potential is wasted by failing to investigate and learn from the differences and similarities between the data from different measurements and times. Both of these act to reduce the value of MWD. While we can work to improve the understanding and use of new data sources, we are not on running an academic research program, nor a religious crusade. We must be pragmatic about the reality of well-site activity. The tools available must be those most used and favored by the people who will be drilling the well. If the won't be used, supplying them is a waste of money and an unnecessary complication at the well site.

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Next... In This Edition OK, we've finished talking about all the how-its-done stuff. From here on, it doesn't matter whether you're ever going out to a rig, or if you've ever even seen one. We're going to talk about what's on a mud log and how you can read it and use it, along with other logs. Chapter 11 is all about the basic mud log. That the five, or ten, or fifty year-old standard mud log you pull from the log library, or the log you got at the well site last week from Billy Bob's Modern Storm Drain, Septic Tank, and Mud Logging Company. Chapter 12 is about geo-pressure logs, how the various data gathered from mud logging, drill rig sensors, and other places, is processed and plotted, and can be used to anticipate, plan for, and work through formations with abnormally high (or low) formation pressures. Finally, Chapter 13, looks at that final question: how can someone, without fifty years experience and a magic eight-ball, draw meaningful (that is reproducible) conclusions from a mud log. We'll try to give you some voodoo-free tools you can use to estimate formation productivity – the type and mobility of hydrocarbons – from a modern mud log. But first...

Next ... Time Around OK, it's let down time again. Once again you get to see the flimsy scaffolding behind this fancy facade. What follows is an outline of what we used to cover in the Modern Mud Logging class about some of the data that might be available in the mud logging unit, what it means, and how we may be able to use it to help us get more out of (or into) the mud log. But for now, that's all it is – an outline. Maybe next time through the mill, it will be fleshed out with some content. Until then, you can start filling the gaps yourself, or just treat it as an advertisement, a promise of things to come, if you buy enough copies, and I live ling enough... At least, in an electronic book it isn't wasting any paper – just a few electrons.

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Wire-line Logging Data Wire-line Logging Unit Wire-line Logging Tools and Measurements Electro-magnetic Properties Spontaneous Potential Resistivity Focused Resistivity Induction Micro-resistivity & Proximity Logs Nuclear Magnetic Resonance Remember from Chapter 7 that NMR is not a nuclear property but an electro-magnetic one.

Electromagnetic Propagation Tool Free-point Indicator Radiometric Properties Natural Gamma Ray Formation Density Thermal Neutron Epi-thermal Neutron Thermal Neutron Decay Time Induced Gamma Ray Spectrometry This is Page 58 of Chapter 10: Down-hole Measurement & Logging

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Sonic Interval Transit Time Cement Bond Log Mechanical Caliper Bore-hole Geometry Tool Dip meter Wire-line Log Data & Mud Logging Wire-line and Mud Log Correlation SP and Rate of Penetration Gamma Ray & Rate of Penetration Geo-pressure Logging Resistivity Pressure Evaluations Porosity Logs and Geo-pressure Density Log Overburden Pressure

Well Testing Data Drill Stem Testing Open-hole Testing Production Testing

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The On-line Mud Logging Handbook

Alun Whittaker

Wire-line Formation Testing Formation Test Tool Repeat Formation Tester Well Testing & Mud Logging Fluid Sampling Water Analyses Oil Evaluations Gas Chromatography

Geophysical Data Wire-line Velocity Survey Geophysical Data & Mud Logging Seismic Velocity Geo-pressure “Forecasting”

This is Page 60 of Chapter 10: Down-hole Measurement & Logging

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