Cracking the carbonate code

Transcription

1 Cracking the carbonate code Carbonate reservoirs are the most complex reservoirs in existence, and the Middle East is the place to find them. The complexity and unpredictability of carbonates has frequently frustrated geologists, geophysicists, petrophysicists, reservoir engineers and drillers alike. In this article, Bernard Montaron looks at how advances in areas such as wireless telemetry and real-time, electronic imaging have contributed to the now formidable and versatile range of formation evaluationwhile-drilling tools.

2 What is the definition of carbonates? Carbonates mean different things to different people. Geologists have described them as often unpredictable, even when the depositional environment is well understood and with a good geology model and le caillou qui rend fou, which translates from the French as the rock that makes you nuts. For geophysicists, carbonate rocks are known to ring like a bell. In the Middle East, they present formidable challenges, such as the yet-to-be resolved issue of obtaining good seismic data for the deep Khuff gas reservoir in Saudi Arabia. Archie s Law applies very well to water-wet clastic formations all over the world, and petrophysicists would love to have such a universal law for predicting the oil saturation of carbonates, but there is no such thing. For reservoir engineers, carbonates certainly form the most complex reservoirs in existence. Carbonate reservoirs are very difficult to model because the behavior of permeability versus porosity is usually nonlinear, and the importance of fractures, vugs, and faults is amplified. Finally, drillers experience a very wide range of drilling conditions in carbonate formations. These vary from very soft formations to extremely hard rocks, and there are often massive and unpredictable drilling fluid losses. The common factor in all these observations about carbonates is that they are unpredictable the question is how to deal with this unpredictability. Like the weather forecast, one of the best lines of attack is to use a good model to combine the understanding of the physics with as much high-quality experimental data as can be obtained. Information gathered like this gradually improves predictability, and there is a need for new loggingwhile-drilling (LWD) technology to allow geologists, geophysicists, petrophysicists, reservoir engineers and drillers to improve control over carbonate reservoirs. Schlumberger Anadrill has made specific developments to address formation evaluation while drilling (FEWD) for carbonates: Enhancements to propagation resistivity tools to increase their measurement range to better fit carbonates High-quality wellbore images that can be acquired from resistivity, density and photoelectric factor measurements while drilling The GeoVISION* downhole MWD/LWD imaging services Improvements to the MWD telemetry system and data compression techniques that now allow images to be transmitted in real-time while drilling The introduction of seismic MWD services using the ISONIC* IDEAL sonic while drilling tool this could be used to acquire seismic data in deep Khuff wells and elsewhere The optimum way information can be used to help drill more efficiently through carbonates and other Middle Eastern formations, using NDS* No Drilling Surprises. VISION eyes downhole VISION* downhole MWD/LWD imaging services (Figure 5.1) utilize a large family of LWD tools to provide propagation resistivity (ARC* Array Resistivity Compensated tool), laterolog type resistivity (RAB* Resistivity-at-the-Bit tool and GeoVISION), density, photoelectric factor and porosity (ADN* Azimuthal Density neutron tool), and sonic while drilling (ISONIC tool). The tools can be used in any combination with no compromise on rate of penetration or data quality through the PowerPulse* MWD telemetry system and IMPulse* integrated MWD platform that use highdata-rate telemetry. For health, safety and environment reasons, the ADN tool is always placed at the top of the bottomhole assembly so that radioactive sources can be fished out in the event the tools are lost in the hole. A complete triple combo is available for FEWD in 6-in. holes, which represent a large proportion of the drains drilled in the Middle East /2in. hole PowerPulse DWOB ARC 12bits/sec Weight/torque Multidepth MWD telemetry resistivity and APWD PowerPak steerable motor GeoSteering 12 1 /4 and 8 1 /2in. holes ADN tool density/neutron/pe PowerPulse 12bits/sec DWOB Weight/torque ARC Multidepth MWD telemetry resistivity and APWD PowerPak steerable motor GeoSteering and AIM tool GeoDrilling ISONIC tool Wireless telemetry GeoVISION tool 6in. hole ADN tool density/neutron/p e IMPulse MWD telemetry, APWD and multidepth resistivity Wireless telemetry PowerPak steerable motor AIM tool Figure 5.1: The Schlumberger Drilling and Measurements VISION family of LWD tools 58

3 34in. 28in. 22in. 16in. 10in. Figure 5.2: The ARC tool and its method of operation Propagation resistivity tools The ARC* Array Resistivity Compensated tool is a 2 MHz and 400 khz electromagnetic-wavepropagation tool that has two receivers and five transmitters (Figure 5.2 left). It provides 10 depths of investigation, allowing measurement of five phase-shift resistivities and five attenuation resistivities. It can also provide gammaray data. Like induction tools, ARC tools induce alternating currents (red loops) in the formation that are generated by a variable magnetic field (green). In turn, these currents looping around the tool generate a variable secondary magnetic field (red) that is detected by the receiver antennae (Figure 5.2 right). Another way to explain how these tools work, is to imagine an electromagnetic wave being emitted by the transmitter and propagating through the formation in all directions. This wave is detected by both receivers, which measure its phase and amplitude, and then provide a phase shift (the difference between the two phases) and an attenuation (the ratio between the two amplitudes). The phase shift and the attenuation are both affected in different ways by the dielectric and resistivity parameters of the formation. I F V R2 V R1 I T B T B F B F Formation magnetic field B T Transmitted magnetic field I F Formation current I T Transmitted current V R2 and V R1 Received voltages Unlike laterolog tools, no current actually leaves or returns to the ARC tool, which makes it ideal for operation in oil-based muds. Propagation tools were introduced more than ten years ago. The first generation tools (CDR* Compensated Dual Resistivity tool) provided two borehole-compensated measurements, one phase-shift resistivity and one attenuation resistivity. Extraction of the apparent resistivity from the phase-shift and attenuation measurements is made possible by the Resistivity, ohm-m Rps, ohm-m 20,000 10,000 1, HLLD good correlation between the dielectric constant and the resistivity of most rocks. However, the accuracy of these tools decreases with increasing resistivity (higher than 200ohm-m). Until recently, his was a serious limitation in the propagation resistivity tools for carbonates. Phase-shift resistivities generally provide better quality data for formation evaluation than attenuation resistivities, especially above 50 ohm-m. This is the value above which attenuation resistivities are considered meaningless. The ARC5 logs shown in Figure 5.3 are clipped at 1000 ohm-m, but should be considered quantitative only up to 200 ohm-m. Discrepancies between ARC5 and laterolog data increase as the resistivity increases. There is a very good match at around 2260 ft between the deep 34-in. phase shift resistivity (red curve), which is not affected by invasion, and the laterolog curve showing approximately 200 ohm-m. On the other hand, there is a large discrepancy at 2,050 ft for laterolog resistivities around 10,000 ohm-m. This clearly shows the limitation of conventional, phase-shift resistivity provided by propagation tools. Unlike the CDR, which provides only two measurements, the ARC tool features 10 different resistivity measurements enabling inversion for dielectric constant and for invasion (see Figure 5.4). The mud resistivity corrected for downhole conditions is also a known input. HLLS 20 2,000 2,100 2,200 2,300 2,400 2,500 2,600 20,000 10,000 10in. 16in. 1,000 22in. 28in in. 20 2,000 2,100 2,200 2,300 2,400 2,500 Depth,ft Figure 5.3: Comparison between a wireline laterolog tool and the ARC5 phase-shift resistivities in a vertical well and a Texas carbonate formation 2,600 59

4 With all these inputs, it is no longer necessary to assume a relationship between the dielectric constant and the resistivity. One can invert for the dielectric constant and calculate the apparent resistivity of the formation for the various depths of investigation (antennae spacings, denoted Rex). It is assumed that the invasion is limited, so that the deepest readings (34-in. phase shift and attenuation) are virtually unaffected. This is generally the case at drilling time. From there, one can also invert for invasion using the shallower readings and provide Rt, Rxo and Di. Rex (ohm m) R (ohm m) Rps - 10in. Rps - 16in. Rps - 22in. Rps - 28in. Rps - 34in. Rad - 10in. Rad - 16in. Rad - 22in. Rad - 28in. Rad - 34in. Rm 10, ,000 10, Assumption: limited WBM invasion Rex - 10in. Rex - 16in. Rex - 22in. Rex - 28in. Rex - 34in. E a Rxo Di Rt Figure 5.4: Inversion algorithm for the ARC tool Depth, (ft) Depth, (ft) Unlike for conventional, phase-shift resistivities, there is no need to clip the logs at 1000 ohm-m because the data remain meaningful over a much wider range of resistivity, well beyond 1000 ohm-m (Figure 5.5). The comparison between the deepest Rex reading (Figure 5.6: 34-in. spacing in red) and the laterolog logs shows an excellent match, even for resistivities as high as 10,000 ohm-m. Measurement uncertainties linked to the tool electronics and the air calibration, limit the range for quantitative FEWD for Rex with ARC tools to 1000 ohm-m. Qualitative evaluation remains possible up to 10,000 ohm-m, as shown in this example. Another interesting way to improve the resistivity readings in highly resistive formations such as carbonates, is to refine the dielectric approximation for resistivities above 100 ohm-m. The approximation can be improved by adding the asymptotic limit value for the dielectric constant to correspond with the dielectric constant of a rock with no porosity. Doing this does not change the curve much for resistivities of less than 100 ohm-m, but makes a big difference for resistivities higher than 10in. 16in. 22in. 28in. 34in. Rex_34 HLLD HLLS 28in. 34in. Figure 5.5: Dielectricindependent resistivities (Rex) for the five antennae spacings Figure 5.6: Comparison between dielectricindependent Rex reading (34 in. spacing) and laterolog 1000 ohm-m. Conventional processing of phase-shift resistivities is then carried out as before. Although it is not as good as the inversion technique, the advantages of this approach are that it can be adapted to older tools such as the CDR tool, and that it offers the same robustness as the well-proven conventional processing. Very good agreement exists between the deep (34-in.-spacing) phase-shift resistivity processed with the new dielectric approximation and the logs shown in Figure 5.6. Agreement is excellent up to 500ohm-m but degrades as the resistivity increases beyond 1000 ohm-m. In a horizontal well drilled several years ago in Abu Dhabi, a 4 3 /4-in. ARC tool was run, and the phase-shift resistivity data were processed to determine the invasion profile (bottom view Figure 5.7). The 6 1 /8-in. hole is in gauge (shown in black) and the invasion radius is plotted against depth (red curve). The dark-brown area corresponds to the invaded zone (Rxo). The color of the background is coded as a function of Rt. The darker zone between X2,075 ft and X2,100 ft corresponds to a lowresistivity zone that is a fault zone filled with salty water. The top log clearly shows this is a fault, i.e., a feature that is perpendicular to the well path, because all the resistivity curves, regardless of their depth of investigation, fall at the same time (at X2,075 ft) and rise at the same time (around X2,100 ft). To summarise, widening the resistivity range of propagation resistivity tools was carried out primarily to meet the requirements of FEWD in carbonate formations. Resistivity, ohm-m Invasion radius, in Phase resistivity R m ohm-m X1,950 X2,000 X2,050 X2,100 X2,150 X2,200 Depth, ft Phase resistivity Radial profile image X1,950 X2,000 X2,050 X2,100 X2,150 X2,200 Depth, ft Figure 5.7: Abu Dhabi example ARC invasion profile image 60

5 The new, dielectric-independent processing technique was developed for ARC tools. It provides five resistivities that are good for quantitative FEWD up to 1,000 ohm-m, and usable for qualitative evaluation up to 10,000 ohm-m. An improved dielectric approximation has also been developed that gives quantitative phase-shift resistivity readings up to 500 ohm-m and qualitative information up to 5000 ohm-m. This method can be used to reprocess the data from all tools, including the oldergeneration CDR tool. Depth, ft X0 X10 X20 X30 X40 R h R i R xo Shadow Radius, in. Resistivity, ohm-m R 1 Ring BD BM BS Rxo R t Figure 5.9: The new inversion algorithm (Di R t, R xo ) for the GeoVISION and RAB tools GeoVISION Resistivity-atthe-bit tool The RAB tool (see Figure 5.8) was introduced six years ago and has been used successfully since. However, its resistivity range is limited to 20,000 ohm-m, and, until recently, there Figure 5.8: GeoVision tool was no reliable inversion algorithm to derive Rt, Rxo and Di from the five measurements available. GeoVISION* downhole MWD/LWD imaging services are the new-generation RAB tools. The electronic hardware has been improved and the button electrodes redesigned to provide a focused resistivity measurement with a range up to 200,000 ohm-m, similar to wireline laterolog tools. They are the only focused resistivity laterolog type LWD tools available in the industry today, and are perfectly suited to FEWD in carbonate formations when drilled with water-based muds. The tools provide five resistivity measurements: Resistivity, using the bit as an electrode, which is an excellent tool for casing or coring point selection High-resolution, ring resistivity Three button resistivities: shallow, medium and deep Gamma ray Axial shock. As the tool rotates, the buttons scan the wellbore and resistivity values are recorded in the tool memory in 56 bins (angular sectors) around the wellbore, allowing the generation of three wellbore images. A new inversion algorithm was developed that can be applied for RAB and GeoVISION tools. This algorithm was shown to be accurate up to a diameter of invasion of the order of 25 in. The log shown (Figure 5.9), is the result of the inversion of data acquired in a carbonate formation drilled with a salt-saturated mud. Rt (red curve), Rxo (blue curve) and the invasion profile (track 2 Di in blue and the hole diameter in yellow) are shown. Note that the shallow button resistivity (in green) reads less than 1 ohm-m, i.e., lower than Rxo from X00 to X26 ft. This is due to the effect of the enlarged borehole in this interval. High-resolution borehole caliper An important feature of the new technique is that borehole and invasion effects are accounted for simultaneously. This eliminates the need for borehole corrections prior to inversion. This was difficult to achieve previously, due to the absence of a mechanical caliper while drilling. The new technique automatically solves the problem for borehole diameter and leads to accurate Rt values in overgauge and oval boreholes. The hole diameter is derived in all 56 azimuthal directions in order to provide a complete borehole cross section, which is extremely useful for geomechanical applications. Figure 5.10 shows the shape of the borehole at three logged depths. In effect, it is a 3D picture. The shallow (green), medium (blue), and deep (red) button resistivities in each of the 56 azimuthal bins are inverted in order to obtain the hole radius in 56 azimuthal sectors of the borehole. A hole breakout is clearly observed in the azimuth. As the GeoVISION tool rotates, the three buttons scan the wellbore at three depths of investigation: 1 in. for the 61

6 Figure 5.10: Derived borehole shape at three logged depths showing borehole breakout shallow button (green), 3 in. for the medium button (blue) and 5 in. for the deep button (red). The resistivity data are recorded in the tool s memory, from which images can be generated later on the surface computer. Figure 5.11: Shallow, medium and deep images for a 28-ft interval showing borehole breakout Figure 5.12: Comparison between drilling images, and washdown images acquired several hours later. Permeable zones invaded with conductive mud are seen at X084 and X104 ft, and breakout at X120 ft X690 X700 X710 Borehole breakcut GeoVISION wellbore images The three wellbore images (shallow, medium and deep) are shown in Figure 5.11 for a 28-ft interval. The black curve on the right is the gamma-ray log. The color curve in each image is the 360 -average button resistivity for the corresponding button. The black patches seen, for example at X694 ft and X700 ft, in the shallow image clearly correspond to hole breakouts at two opposite azimuths. Most breakout patches disappear in the deep image, as would be expected. The features remaining in the deep image are formation related. Several bedding planes are clearly distinguished, and correlate well with the gamma-ray and deep-resistivity logs. Note the layered formation at X692 ft with beds as thin as 2 in. High-quality images like this help to clear up a number of log interpretation issues. For example, some of the Shallow Medium Deep MD Drilling image Washdown image 1 : 140 ft U R B L U R B L X080 X090 X100 X110 X in. 6-in in. 2-in in Resistivity overlay 2 ( ohm-m) 200 features seen on the shallow resistivity log are clearly caused by breakout holes filled with conductive mud. GeoVISION can also be used to record images of the same formation at different times. In Figure 5.12, the image on the left was acquired at drilling time, while the image on the right was acquired several hours later during a washdown. The ring resistivity logs are overlain in track 3. The separations seen (blue-filled zones), are not all due to invasion and the image helps in making the correct interpretation. The zones at X084 ft and X104 ft correspond to permeable zones that have been invaded by conductive mud. On the other hand, the blue zone on the log at X120 ft clearly corresponds to a characteristic hole breakout, as evidenced by the two dark patches in two opposite azimuths. The GeoVISION tool provides geologists and drillers with eyes downhole. It can be used for real-time identification of formation dips, beddings, fractures, faults, and to help to geosteer the well. The FMI* Fullbore Formation MicroImager has a resolution of 0.2 in., and sensing electrodes located on four pads. The resolution of the GeoVISION tool is limited by the size of the buttons to about 2 in. The depth scale on Figure 5.13 has been expanded by a large factor (unusually large for a LWD log) and shows a 7-ft interval. Despite its lower resolution, the GeoVISION tool (right image) clearly identifies the main structural features in the formations, and accurate dips are obtained. Bedding surfaces as thin as 2 in. can be observed. Comparing FMI and GeoVISION images for fractures (Figure 5.14), the largeamplitude sine line in yellow seen on the GeoVISION image corresponds to a bedding surface that is intersected by the well trajectory at a very low angle of incidence (almost parallel to the bedding plane). The dark lines that are not horizontal are fractures invaded with conductive mud. Some of them are less than 2-in. wide but they are still detected. Figure 5.15 shows a fault plane imaged with reasonable agreement between the dips. The plane is interpreted as a fault because of its relationship with the bedding, 62

7 FMI Geovision Figure 5.13: Comparison of FMI with GeoVISION for dips and beddings 1ft FMI Geovision Figure 5.14: Comparison of FMI with GeoVISION for fractures 1ft Fractures Bedding FMI Geovision Figure 5.15: Comparison of FMI with GeoVISION for faults 1ft 63

8 Pressure Time Pressure Time Pressure Time Pressure Time Figure 5.16: The PowerPulse MWD (not shown here). The high true dip of about 80 makes this more likely to be a fault than bedding. The PowerPulse MWD telemetry system (see Figure 5.16) is the workhorse of Schlumberger s real-time MWD/LWD services. In the 10 years since its introduction it has become the industry s most reliable MWD tool. Recent improvements to the telemetry, or zero-gap modulator, have boosted the amplitude of the pressure pulses by 30%. These advances, in conjunction with recent improvements to modulation and demodulation techniques, have produced mud-pulse telemetry data rates of 12 bits/sec, making it, by far, the fastest telemetry-data-rate MWD tool in the industry. Such performance directly affects the quality of the data transmitted in real time. Data transmission requirements can be completely decoupled from the rate of penetration without compromising data quality. Real-time logs that are as good as memory logs can be produced if required. The tool s data transmission capabilities can be further enhanced using data-compression techniques. This is particularly useful when drilling long, extended-reach wells where it may be necessary to lower the MWD telemetry frequency to 1 Hz. Three factors contribute to the exceptional quality of real-time wellbore images, see Figure Firstly, drilling rates are generally fairly slow, typically 60 ft/hr. Secondly, mud-pulse telemetry rates are high, so, for example, at 6 bits per second a total of 360 bits is transmitted for each foot drilled. Thirdly, image resolution does not need to be much greater than tool resolution, which is limited to about 2 in. It therefore follows that an image of a 2-in. slice of formation in an 8 1 /2-in. wellbore using pixel resistivities coded with 16 colors, requires only 52 bits for real-time transmission. In practice, data compression techniques are based on complex algorithms similar to those used to transmit images from the space probes exploring our outer solar system. 64

9 Depth, ft Depth, ft Recorded image X050 X100 X150 X200 Real-time image, compression factor 64 X050 X100 X150 X200 Figure 5.17: Comparison of real-time and stored wellbore images Neutron detectors LINC coils Neutron source Electronic source Density source X250 X300 X350 X400 X250 X300 X350 X400 ADN Azimuthal Density Neutron tool Some carbonate reservoirs display a fairly flat, high-value resistivity log. In these cases, porosity becomes the most useful measurement for placing the drain in the sweet spots of the reservoir. Porosity measurements are made with the ADN* Azimuthal Density Neutron tool (Figure 5.18). The ADN tool has neutron and gamma-ray sources that are attached with a titanium rod to a fishing head. It makes four azimuthal density and photoelectric factor measurements (up, down, left and right). This is possible because gamma rays can be detected through a fairly narrow, angular window and the formation is scanned for gamma rays as the tool rotates. Not only can the ADN make measurements in the four quadrants, but it can also record wellbore density and photoelectric factor images with 16 angular sectors around the wellbore. The ADN tool also measures neutron porosity. Neutrons have a life of their own: they tend to scatter widely in the formation through multiple interactions, and they can also pass through the steel body of the tool. Because of this, only one average porosity measurement is made. The 16 sectors are clearly visible in Figure The limitation to 16 sectors comes from the requirement to obtain acceptable statistics for the gamma-ray counts in each sector. X200 Density detectors Ultasonic sensor X250 X300 Batteries X350 Tool bus Figure 5.18: The ADN tool Figure 5.19: Example of a density image showing sand shale layering 65

10 X000 PeF U/D PeF L/R RHOB U/D RHOB L/R PeF image Top of porosity Sliding mode Density image 14ft = 2.5 The left-hand image is a true representation of density, and the other image is a representation with the color scale optimized to enhance contrast. In the X250 X300-ft interval, azimuthal density was the only measurement that identified the sand shale layering. Gamma-ray, resistivity, neutron and average density measurements all indicate that the zone is homogeneous. It can be seen from this example that displaying or utilizing maximum density would not be correct and would greatly underestimate the porosity. X100 Figure 5.20: Density and PeF images Middle East well log examples PeF image Density image X500 Bedded pyrite layer Figure 5.21: Pyrite bed from PeF image PeF image Density image Fault plane Figure 5.22: Density image fault detection 10ft The ADN logs on this page were obtained from a 6 1 /8-in. horizontal well in the United Arab Emirates. Despite the modest resolution, formation dips are easily determined from these images. Since there is no GeoVISION tool currently available in 4 3 /4-in. size, the ADN 4 3 /4-in. images are even more valuable. The four photoelectric factor (PeF) quadrant logs (up, down, left, right) and the corresponding PeF image are shown on the left side of Figure The density image and quadrant logs are shown on the right side. As with GeoVISION resistivity images, the green bar corresponds to a sliding interval (no rotation no wellbore scanning). In this interval, only the porosity, and the bottom density and PeF are used. In this 130-ft interval the PeF does not show any character. However, interesting structures can be seen on the density image and logs. The dip of the bedding at X020 ft can be directly determined in real time from the up and down density logs. The up and down logs are shifted by 14 ft, and the left and right logs are on top of each other. The well trajectory intersects the bedding plane at an angle of 2.5, which is directly calculated from the 14-ft shift and the hole diameter. The same well over another depth interval is shown in Figure Here, the PeF image and logs correspond well to a thin pyrite layer that can also be observed on the density log. The shift between the up and down logs is observed again, this time with a lower value, indicating a slightly higher 66

11 incidence angle. However, the down curve reacts before the up curve, showing that the bedding plane is intersected from above. Other interesting images in the same well are shown in Figure These indicate a fault plane on both density and PeF images and logs. The transition is interpreted as a fault, because up/down and left/right logs react at exactly the same time, indicating that the feature is perpendicular to the well trajectory (or at a very high angle of incidence compared to the formation dips in the same zone). The ISONIC tool The ISONIC tool produces real-time t measurement to enable drilling with look ahead in thick carbonate reservoirs (Figure 5.23). One objective for every geophysicist is to correlate time-based surface seismic data with depth. Using the sonic data provided by wireline or LWD tools, the geophysicist can tie the prospect found on the seismic map to the formations that are actually drilled. First, the compressional slowness is incorporated with density data to compute an acoustic-impedance curve. The acoustic-impedance curve is then converted to a synthetic seismogram that is used to correlate with the surface seismic trace extracted along the wellbore trajectory. Once these are correlated, the geophysicist has a depth tie for the surface seismic. The ISONIC tool produces t in real time, so the seismic tie can be done in real time. This provides a unique opportunity to tie surface seismic to depth before the well reaches total depth. The ISONIC tool (Figure 5.23) consists of a monopole sonic transmitter and a 2-ft array of four receivers embedded in a drill collar. The tool has two different applications: real time and recorded mode. During the drilling process, the transmitter is fired and acoustic waves are propagated through the mud and formation to the four receivers. Four waveforms (one from each receiver) are recorded and stored in downhole memory. The compressional transit time of the formation is extracted by downhole waveform processing and is then sent to the surface via MWD mudpulse telemetry. Although the ISONIC tool has been optimized to measure compressional waves, it can also measure the velocity of shear waves in fast rocks, as is often the case in carbonate formations. Figure 5.23: The ISONIC tool Figure 5.24: Looking ahead at the bit. M-Base D10 expected at 9800 ft, ISONIC showed 9860 ft RAD CDR RPS CDR GR CDR Velocity v(dt ISONIC) Reflectivity Impedance Impedance Synthetics Synthetics Seis along I Seis along I Reference section Depth, ft M-Top D1 M-Base D8 M-Top D1 M-Base D M-Base D10 M-Base D ,000 10,500 10,000 10,500 67

12 A synthetic seismogram can be generated on the surface computer in real time from the t transmitted through the MWD telemetry. Once the surface seismic is tied to depth, seismic bright spots and other significant features can be defined relative to driller s depth. This provides a look ahead of the bit, which can be used to make better decisions on casing point and total depth (see Figure 5.24). The look ahead relies on the availability of a seismic vertical slice. But there are cases where such seismic data are not available. Seismic data can be acquired while drilling, either by drill-bit seismics (also called seismic while drilling (SWD)), or by seismic MWD. Drill-bit seismics use the rock bit as the source of compressional seismic energy. The seismic waves and the reflected waves propagate through the formation back to surface where they are detected by an array of geophones. The drill-bit vibrations also propagate through the steel drillpipe back to surface where they are detected by an accelerometer installed on the standpipe. This can be done offshore (Figure 5.25), but it is actually easier to do on land. Cross correlation of the accelerometer signal with the geophone signals, and a lot of stacking produce a seismic image that takes the form of a vertical cone of about 30 looking down the bit. Sensor Drill bit Drill bit seismic Sensor weights Sea floor Seismic reflector Surface system MWD telemetry LWD tool Figure 5.25: Borehole seismic while drilling. Left, drill-bit seismic, middle, seismic MWD, right, a seismic cone Seismic MWD Sea floor Seismic reflector Figure 5.26: Vertical geosteering is conceivable to intersect as many bright spots as possible Geosteering with borehole seismic Drilling a vertical well without seismic data in a thick reservoir with a heterogeneous distribution of porous zones is largely a matter of chance. But if borehole seismics could be used in real time, a new kind of geosteering is conceivable vertical geosteering to try to intersect as many bright spots as possible on the way down to total depth (Figure 5.26). Hydraulic fracturing could then be used to further increase productivity. This technique, which would associate SWD or seismic MWD services with directional drilling and hydraulic fracturing services, could provide a solution for optimizing the productivity of gas wells in thick carbonate reservoirs, such as the deep Khuff in Saudi Arabia. Drilling with information Drillers have been using roller cone bits and PDC bits for a long time, and, although the technology of bits is constantly progressing, this is considered a well-proven and mature technique. On the other hand, drilling with bits of information is a domain that is still young and has a tremendous potential to contribute to drilling efficiency. One of the challenges is to capture the large volumes of information from measurements, directional drilling experience and drilling monitoring from a company s DD, MWD and LWD engineers, and to transform it into knowledge that is easily accessible as input to the development of new wells. This is the aim of the PERFORM* Performance Through Risk Management Process package with its DrillBase, DrillMAP, DrillCAST and DrillTrak applications and database, and the No Drilling Surprises initiative at Schlumberger Drilling and Measurements (Figure 5.27). The PERFORM engineer analyses all the data and events recorded in real time and compares them with past experience, recent or distant, local or global. The driller and the operating company can then be advised on ways to avoid drilling problems, to increase the rate of penetration or to minimise drilling costs. 68

13 First well Second well Subsequent wells Offset data Knowledge hub Best practices Events, near misses, solutions DrillBase Drilling events database Road map of potential hazards with contingencies DrillMap Forecast of hazards Best practices Contingencies DrillCAST Record of events versus plan DrillTrak DrillMAP DrillCAST DrillTrak DrillMap DrillCAST DrillTrak Figure 5.27: PERFORM process for drilling knowledge management. The aim is to reduce costs and nonproductive time by integrating planning and real-time drilling solutions The PERFORM service was introduced in the Middle East in 2000 and, as a direct result, Schlumberger broke several drilling records in Saudi Arabia and in Abu Dhabi. In Abu Dhabi, the PERFORM engineer, analyzed the data and recommended the use of new BHA designs that represented a significant change to local drilling and directional drilling habits. This resulted in dramatic rig-time reductions, with wells drilled in less than 20 days compared to more than 30 days prior to these changes. This meant total savings of the order of half a million dollars per well. Conclusions Most reservoirs in the Middle East have carbonate formations, and long ago Schlumberger Drilling and Measurements recognized the need to address their problems with specific solutions developed for FEWD and drilling of carbonates. The main advances made as a result of these efforts are: A new processing algorithm for propagation resistivity tools that expands their resistivity range well beyond 1000 ohm-m The introduction of a new-generation, focused laterolog LWD tool, GeoVISION, with a measurement range exceeding 20,000 ohm-m, and that provides wellbore resistivity images useful in visualizing beddings, fractures and faults Full VISION triple-combo LWD services in 6-in. holes Real-time wellbore images using resistivity, density and PeF scans PERFORM service for drilling faster and improved wells. These advances are bringing higher quality data and drilling knowledge that are helping to turn the unpredictable nature of carbonates into predictable wells throughout the Middle East. 69