Copyright 2003, SPE/IADC Drilling Conference This paper was prepared for presentation at the SPE/IADC Drilling Conference held in Amsterdam, The Netherlands, 1921 February 2003. This paper was selected for presentation by an SPE/IADC Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers or the International Association of Drilling Contractors and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the SPE, IADC, their officers, or members. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers or the International Association of Drilling Contractors is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract The measurement of continuous real-time inclination provides near instantaneous calculations of the build-up rate tendency of a bottom hole assembly in both rotary and slide drilling modes. The addition of an azimuthal measurement now allows for the calculation of wellbore position with this continuous data. The true nature of the wellbore curvature in slide/rotate directional drilling with steerable systems is lost when using the typical 90-foot survey interval. Continuous surveying shows this effect. When wellbore position is calculated with the continuous surveys, a significant positional discrepancy from the stationary surveys can occur. A study was conducted using both stationary and continuous survey data from over 20 wells in Nigeria, Angola, the Gulf of Mexico, the North Sea and Indonesia. The objective was to determine the magnitude and scope of TVD positional error caused by the different slide and rotate curvatures between stationary surveys on a wide range of wells. These curvatures are not reamed out as commonly thought. They can still be seen in continuous gyro surveys taken after drilling has finished. This positional effect is not a function of the sensor accuracy, but it is a result of the environment in which surveys are measured. We show that in a horizontal well the effect can accumulate up to plus/minus 25 ft TVD. The implications of these results are far reaching. Survey positions are used in creating structure and reservoir maps, which are used in determining reserves and recovery efficiencies, and in turn for making field management decisions. This paper highlights the results of the field studies. A review of rotary steerable system operations shows that the effect is much less than with steerable motors, but can still be of concern.

A low-cost solution for effectively determining when to slide and rotate with respect to the stationary survey is presented. This procedure results in a positional accuracy that can be maintained without changing survey data management practices. Introduction For more than 15 years the directional well surveying industry has settled on a standard method of calculating the position of a wellbore from inclination and azimuth measurements. This method, called minimum curvature, determines the smallest radius curvature between two survey stations1,2. The position coordinates for the second survey, in terms of easting (X), northing (Y) and true vertical depth (Z), can then be calculated. A basic assumption is that there is no appreciable change in the curvature between the surveys. Two things happened in the early 1990s that have altered this assumption. First, positive displacement motors (PDMs) with bent housings made it possible to drill directionally with a high curve rate (5-10 deg/100ft) when slide drilling and then switch to drilling in rotary mode with curve rates usually less than 1 deg/100ft. Second, top drives on offshore and some land rigs made it possible to drill three 30-ft joints of pipe (or a stand) without stopping to make connections. MWD tools usually take a directional survey when the mud pumps are cycled off and then on when a connection is made. This means that surveys gradually came to be taken every 90 feet instead of every 30 feet. These two developments meant that the probability of differing curve rates between survey points increased dramatically; the interpolation between the surveys did not reflect the actual trajectory of the wellbore. It became difficult to model and predict curve rates for various PDMs, and there was speculation that the location of the wellbore at any point may be incorrect. This positional difference would be in addition to the positional uncertainty that results from sensor accuracy and alignment specifications3,4. Directional drillers took extra surveys or check shots to help with trajectory tendency work, but little was done to determine the effect on wellbore position.

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Continuous Direction and Inclination Measurements Lead to an Improvement in Wellbore Positioning E.J. Stockhausen, SPE, ChevronTexaco and W.G. Lesso, Jr., SPE, Schlumberger

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MWD service companies have modified their downhole data streams to include sampling of accelerometer and magnetometer data during pumping operations, most notably drilling. This means that a simplified single-axis survey can be transmitted to the surface in the same way that gamma ray and resistivity data are transmitted. This is in contrast to stationary surveys, which are three-axis measurements that are taken when the drill pipe is held in a stationary position usually just after making a connection. These continuous direction and inclination measurements (cDNI) are made every 30-90 seconds which results in surveys that are two to four feet apart when drilling. The data is processed downhole to reduce the effects of vibration on the sensors during drilling and is routinely used by directional drillers for tendency work5. These surveys are of sufficient quality, and can be used in calculations of wellbore position. Work on error models for cDNI data is not complete so continuous surveys cannot yet reliably be used as definitive surveys. Figure 1 shows stationary and continuous survey data over 500 feet of a build section in a directional well. The stationary surveys are shown as yellow squares and triangles for inclination and azimuth respectively. The straight lines connecting the stationary surveys indicate a constant rate of curvature between these surveys. Continuous inclination data are shown as red circles while continuous azimuth is shown as light blue triangles. The vertical lines on this plot divide this drilling sequence into slide and rotate drilling modes. The pink data points near the bottom of the plot show the gravity tool face (GTF) data during the slide states. The changes in slope of the continuous inclination are indicative of the vertical build/drop rate achieved while slide versus rotary drilling. The PDM motor delivered about 13 deg/100ft building when sliding with these GTF settings. The BHA dropped at about 4 deg/100ft when rotated. This is a dramatic but not unusual occurrence resulting from a less than optimal choice of BHA. The curve rate between the stationary surveys is about 3.5 deg/100ft. It is fairly obvious that the minimum curvature method assumption of constant curvature between those stationary survey points is invalid. Positional Error from Non-Constant Curvature As mentioned above, the positional location of a survey point calculated with the minimum curvature method assumes a constant curvature between the survey points. Changes in three-dimensional curvature can be determined by analyzing cDNI data. Reviewing cDNI data has identified four sources of non-constant curvature between longer spaced stationary surveys. They are:

1) Pattern slide/rotate directional drilling during build/drop and/or turn sections of wells using PDM steerable systems

2) Systematic use of PDM steerable systems to compensate for build,drop, or walk tendencies when attempting to maintain or hold a constant

inclination and azimuth in a tangent section of a well

3) Changing modes with rotary steerable systems between stationary survey points

4) Lithology changes between stationary survey points such as tight streaks or changes in rock strength and changing bed dip angles that alter formation directional tendencies.

Currently, concerns about position concentrate on differences in true vertical depth (TVD). The positioning of a horizontal drainhole relative to fluid contacts and the construction of geological structure maps are based on TVD position. Changes in azimuthal location, while a valid concern, are, at this stage, of lesser importance. Continuous direction (or azimuth, as it is commonly called today) measurements have a wider fluctuation than the continuous inclination measurements. This can be seen in the character of these data in Figure 1. For these reasons and simplicity, this paper will focus on differences in TVD position, but the argument can be made for both TVD and azimuthal position. Figure 2 shows the assumption of constant curvature between two survey stations. Here a well path is building at a constant rate, and the position calculated for TVD for the next survey, x+1, would correctly model the actual location of the wellbore. If there were a non-constant curvature between these two survey points, the actual TVD location of survey x+1 could be shallower or deeper than the calculated position. Pattern Slide/Rotate Directional Drilling Figures 3 and 4 show how differing curve rates between surveys affect positional calculations. Figure 3a shows a modeled trajectory between two surveys. Here a rotate section with a zero curve rate follows a slide drilling section with a moderately high curve rate of 5 deg/100ft. Figure 3b shows a similar modeled section except this time the rotate section with no curve rate is performed first followed by the slide section. The surveys at the end points for both of these figures have the same inclination and will result in the same TVD when the minimum curvature calculation is made. Yet the figures show that the actual TVD for Figure 3b is deeper, and the actual TVD in Figure 3a is shallower than the TVD calculated using the end points or stationary surveys. Figure 3c shows a model of a slide section placed between two rotate sections. The actual TVD position for this section will be very close to the same as the TVD calculated from the stationary surveys. The changes in curvature shown in these models are examples of pattern slide rotate directional drilling. They could not be detected without taking additional stationary surveys or using continuous surveys. Figure 4a shows a model of what happens when the pattern of slide followed by rotary drilling relative to the stationary surveys, as shown in Figure 3a is repeated many times in the

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build section of a horizontal well. The difference between the TVD calculated using the stationary inclinations (taken at the endpoints of each pattern), and the continuous inclinations accumulates to where the TVD from the continuous inclination is about 25 feet shallow of the TVD from stationary inclination. This model shows a perfect slide/rotate pattern that generates the maximum TVD difference. Figure 4b shows the opposite extreme. Here the pattern is to rotate first then slide as shown in Figure 3b. When this pattern is carried out in the build of a horizontal well, the TVD from continuous inclination is 25 feet deeper than the TVD calculated from the stationary survey inclinations. Figure 4c shows the results for the pattern where the slide is placed in the middle as in Figure 3c. There is very little difference in TVD. These figures show that patterns in slide/rotate sequences can result in a positional difference in TVD between 25 ft shallow and 25 ft deep in a horizontal well. This TVD difference could be proportionally less if the build was to an inclination less than 90 degrees. It could also be greater if the contrast between the slide and rotate curvatures is larger. In practice, directional drillers do not execute the perfect patterns shown in these models, but systematic patterns do present themselves. TVD differences are also affected by the BHA configuration, the distance from the bit to the survey sensors, joint or stand lengths, and relative amount of slide and rotary footage in a sequence. PDM Steerable System Work in Tangent Sections A tangent section is the angle hold section in a standard slant or S trajectory or the lateral section of a horizontal well. Active directional drilling, that is performing slide sections when the objective is to hold angle in a tangent section is sometimes necessary. The tendency of a BHA can change with differing formations and operational parameters such as flow rate, weight-on-bit and rotation speed (RPMs). PDM steerable systems can be used to counter the effects of undesired rotary drilling tendencies. A slide section is added to the drilling sequence as discussed in the previous section. The difference is that the slides are usually much shorter. Figure 5 shows a model of what stationary and continuous survey data looks like when drilling a lateral section with a BHA that drops at 1 deg/100ft when rotary drilling. The objective is to maintain the wellbore at 90 degrees. This is accomplished by adding a slide section to each stand being drilled that, in this case delivers, 6 deg/100ft. A slide for 14 feet at building 6 deg/100ft will neutralize a rotary section of 86 feet dropping at 1 deg/100ft in a 100-foot drilling section. If the slide is performed immediately after the stationary survey depth, the stationary surveys will all read 90 degrees when this pattern is repeated. The continuous surveys will show the actual inclination for this pattern and will have values greater than 90 degrees (except at the stationary survey point). The wellbore TVD position calculated from the continuous surveys will drift shallow as compared to the

position calculated from the stationary surveys. In this case the drift rate is 3.7 feet in every 500 feet drilled. Figure 6 shows how this drift can impact decisions in drilling a horizontal well. It sketches a typical geosteering objective. A 1500-foot lateral section is to be placed six feet below a formation pay top. The formation has 17 feet of pay before an oil water contact (OWC) is encountered. Figure 7a shows how geosteering progress would probably be interpreted if the slide/rotate pattern in figure 5 was used to drill this section. The stationary surveys would show that the wellbore was holding at 90 degrees and that there is no change in TVD. After about 810 feet of drilling the formation top is encountered. The most likely interpretation of the data is that the formation is dipping downward. A decision to stop drilling would be reasonable. Recoverable reserves estimates would also be lowered. Figure 7b is a sketch of the modeled trajectory where TVD is calculated from the continuous surveys. The well path drifts shallow at the 3.7 feet per 500 feet. The pay top, which remains flat, is encountered after 810 feet of drilling. The ultimate recovery for the project will be less than anticipated due to the shorter lateral section. By monitoring well position in real-time using the cDNI measurements these situations can be avoided. Figures 8 and 9 show actual cases of using slide sections to compensate for rotary dropping tendency during planned hold sections. Figure 8 shows a horizontal well where the situation developed in a similar fashion to the model in Figure 5. The slides are used to maintain 90 degrees when the rotary tendency is to drop. The TVD difference drifts shallow. Figure 9 shows a well where inclination is being held at about 47 degrees. The slide sections are placed at different positions relative to the stationary surveys. While there are large fluctuations in the TVD difference, the net effect over this 4000 foot interval is only about two feet. Positional Differences with Rotary Steerable Systems The introduction of rotary steerable systems eliminates the need for the large changes in curve rates between slide and rotary drilling sections resulting from the use of steerable motors. Rotary steerable systems produce curve rates based on the selection of a tool face angle and percentage of side force in the direction of the tool face angle. To increase angle and turn slightly to the right, a rotary steerable system would be set at a tool face of 20 degrees with 35% of total force available. The power setting could be changed to 100% in order to steer more aggressively. A neutral setting would be 0%, and the tool face angle would be irrelevant. This type of directional drilling produces longer, more consistent curve rates that are smooth and predictable. This, plus the ease of use of rotary steerable systems and higher rates of penetration are the major reasons that rotary steerable systems are rapidly changing the nature of directional drilling. But, a TVD difference can develop when settings are changed between survey points.

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Figure 10 shows an example of this. This well from the North Sea is in the final build to horizontal. A bit run using a steerable system motor finished at about 3100 feet. A rotary steerable system is used in the following run, and the figure shows four different tool settings applied over the interval from 3100 to 4000 feet. The continuous inclination shows the consistency in build angle for each set and clearly defines where a set ends and the next one starts. The stationary surveys are taken at the completion of drilling each stand of pipe. Note that in two cases the stationary surveys are not at the depths where the rotary steerable settings are changed. There is a rounding the corner effect between the continuous and stationary inclinations. These corners can cause up to a two-foot TVD difference for each occurrence. Lithology Effects on Non-Constant Curvature Lithology changes such as tight streaks, changes in rock strength, and changing bed dip angle can alter directional tendencies. When these are encountered between survey stations, a rounding the corner effect similar to what happens with rotary steerable systems can result in TVD positional differences. These events tend to be isolated incidences and they are difficult to detect with longer survey intervals. Tight streaks can result in a large dogleg over a short interval. This can cause drilling and completion problems in addition to TVD differences. By monitoring the cDNI data in real-time, these events can be identified and remedial action taken to minimize their effects. Figure 11 shows the reaction of a rotary steerable drilling assembly with a high density tight streak in a horizontal wellbore. The trajectory is decreasing from 95 to 82 degrees inclination. The bit hits the bottom of a hard streak at 5750 feet and bounces down as evidenced by the continuous inclination. BHA stiffness causes the inclination to recover and the bit hits the hard streak a second time before the general downward tendency in inclination continues. The stationary surveys do not see this event. In this case, the TVD positional differences cancel out. The density image log, by itself, indicates two tight streaks. The continuous surveys show that the wellbore approached one tight streak twice. Horizontal Well Position Study There is no standard set of procedures for incorporating the continuous directional data into survey calculations for dogleg severity or hole positioning. We wanted to determine the extent of this problem and methods for ameliorating it, at least for TVD positional error on present, future, and then past wells. A study was commissioned in August 2001 to determine the extent of wellbore TVD error resulting from pattern slide/rotate drilling practices. Three or more horizontal wells from Nigeria, Angola and Indonesia were selected for a total of thirteen wells. The survey data, both stationary and continuous, was captured and processed. Directional operations data, BHA reports, and slide sheets were also gathered together. The table shown in Figure 12 details the

results of this study. Figure 13 shows the positional calculation results of the study graphically. Eight of the wells have TVD differences greater than 5 feet. The largest difference was in the GBK a where the continuous inclination places the final true vertical depth 22 feet deeper than the TVD calculated from the stationary surveys. The three wells from Indonesia have the lowest positional errors. A review of the directional drilling procedures there showed that these rigs did not have top drives, and drilling was accomplished using a standard Kelly. Surveys were taken at every joint of pipe or roughly every 30 feet. A slide/rotate pattern developed with slides usually 15 feet in length. The shorter survey interval of 30 feet did not allow differences in inclination to develop into a significant TVD positional difference. For purposes of this study, surveys were eliminated from the 30-foot list to simulate a 90-foot survey spacing. A significant TVD difference still did not develop. This is due to the shorter slide lengths. Top drive use in the other countries allowed for longer slide sections between surveys. The delta TVD values presented reflect the well status only at final depth. Minor changes in procedures could cause the delta TVD to first drift shallower and then later drift deeper. Figure 14 shows the stationary and continuous inclination data for the GBK a well in Nigeria. The data covers the entire directional well from kick-off point through build and tangent sections and finally through the horizontal or lateral section to TD at 9033 feet. A comparison between the TVD calculated from the continuous inclination and the stationary inclination shows that the well would be 22 feet deeper at total depth based on the continuous inclination. The delta TVD curve on the plot shows how that error accumulated. The error both increased and decreased based on changing directional drilling practices. It reached a maximum at 7310 feet where the continuous surveys indicated that the well was 23.7 feet deeper. The section of borehole represented by the dashed box in Figure 14 is enlarged and shown in Figure 15. It shows a portion of the final build to horizontal from 6000 to 7000 feet. Here the true nature of pattern slide/rotate directional drilling can be seen. The continuous inclination shows that angle builds during the slide sections and simply holds angle during the rotary drilling sections. The stationary inclination survey points at approximately a 90-foot spacing do not see this effect. The line drawn between the stationary inclination points indicates the constant rate of curvature assumed by the minimum curvature method. When the non-constant curvature shown by the continuous surveys is below this line, the delta TVD accumulates indicating that the wellbore is increasingly deeper. Continuous surveys above the line result in delta TVD moving shallower. During this section, the continuous inclination is mostly below the stationary survey line. Thus, the delta TVD is accumulating from 14 to 23 feet deeper. There are a few points where the continuous inclination is above the stationary survey line, and the delta TVD decreases or moves shallower in these instances.

SPE/IADC 79917 5

It is important to note that in this well almost all of the TVD difference occurs as a result of attempting to build or drop angle. During the drilling of the hold sections (3600 5700 feet and 7100 9033 feet) the bottom hole assembly did a good job of holding angle when rotary drilling. The continuous inclination tended to directly overlay the line connecting the stationary surveys and little or no delta TVD developed. Only when correction slides were made (near 4700 and 7700 feet) did TVD differences occur. There are two conclusions from this study: first, a significant positional error is possible on 60% of horizontal wells studied; and second, that positional error can be greatly influenced by directional drilling procedures. The probability is high that horizontal wells drilled with PDM steerable systems on a top drive rig will have a TVD positional problem large enough to cause problems with the well placement. The obvious criticism of these conclusions is that 13 wells is not a large enough sample. Additional wells have been reviewed from the North Sea and Gulf of Mexico and also from the three countries of the original study. The process is on going, but the percentage seems to be holding. Landing Horizontal Wells The effect of TVD positional differences in horizontal wells can lead to poorly placed drainhole sections or even missing the target reservoir completely. Since both the operator personnel and service company directional drillers are not aware of this problem caused by non-constant curvature in surveys, the problem usually is attributed to an unexpected change in geological structure. Forty percent of gestured horizontal wells encounter a geological surprise6 was a statement made in 1996. These surprises were usually in the range of a 10 to 20 feet TVD shift. How many of these shifts were the result of non-constant curvature in the survey calculations as opposed to problems in structural mapping? During geosteering operations, marker beds above the target reservoir are used to help determine the relative position of the wellbore to the target. Adjustments are made to the trajectory to refine the landing point when correlations are made with these marker beds assuming the vertical thickness and dip angles of the intermediate beds remains constant. The modeling of petrophysical data and navigation techniques developed over the past ten years made it possible to deal with most of the unexpected changes that occur by making an evasive maneuver in landing a horizontal well. But additional TVD positional error can accumulate during the final approach to the landing resulting in an overshooting or undershooting of the desired landing location. This may result in the loss of some lateral section. Additionally, the projection of bed dips ahead of the bit may be misinterpreted leading to poor targeting further in the horizontal section or on subsequent wells. Gyro Comparisons It has long been assumed by many that these fluctuations in curvature caused by alternating between slide and rotary

sections using positive displacement motors would be reamed out by pipe rotation and tripping actions as the well progresses. It was thought that the tortuosity and positional difference were eliminated, and a smooth borehole was the end result. There has not been an easy way to check this assumption until recently when the continuous surveys made during drilling could be compared to continuous gyro surveys. Gyro surveys are generally taken after the completion of the drilling of the hole size section. Figure 16 shows the stationary and continuous MWD surveys along with a continuous gyro survey data set for 1000 feet of a North Sea well. Slide sections are plotted with gravity tool face data indicating a build section. The gyro survey was taken after this 12 hole section was drilled. It shows that while there was some reduction in the curve rates, a majority of it remains, and the two continuous data sets can be easily correlated. The Relationship between Positional Error from Non-constant Curvature and Survey Sensor Accuracy The positional difference found when computing the location from directional surveys with non-constant curvature is not to be confused with the positional accuracy calculated using the accepted error models in references 3 and 4. These computations are based on the design, capabilities, and packaging of the actual sensors. An ellipsoid of uncertainty is usually defined in terms of a major and minor axis and a vertical component. A confidence interval is defined and accuracy is stated such that there is a 95% or a 99% confidence that the wellbore at a survey point is within the ellipsoid. Since this accuracy is expressed in terms of the lengths of the ellipsoid axes, it is possible to compare the length of the vertical component of the ellipsoid to the TVD positional difference using minimum curvature with non-constant curvature. Such a comparison is misleading. One is an accuracy based on characteristics of the sensors, while the other is an effect based on the use of those sensors. Both of these attributes of survey analysis are real and independent of each other. There are distinct and separate methods for reducing both the effects of sensor accuracy and non-constant curvature. The survey accuracy issue affects every directional well. The non-constant curvature issue affects wells where curvature changes significantly, and survey spacing is greater than 45 feet. The population of wells with this positional problem is clearly a subset of wells where sensor accuracy is an issue. Possible Solutions The problem of positional difference resulting from non-constant curvature in wellbores has gradually crept into directional drilling practices. Several solutions are available based on modifying directional drilling methods, survey calculations and procedures in drilling measurements.

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Return to a Survey Interval of 30 Feet The obvious solution to this problem would be to go back to taking surveys every 30 feet. Analyses made during the studies presented in this paper indicate that the positional difference would be reduced by more than 90% by returning to 30-foot surveys. Figure 17 shows graphically how using 30-foot stationary surveys drastically reduces the TVD difference between continuous and stationary inclination. Since there is not yet a methodology for combining stationary and continuous survey data and maintain manageable sensor error models, returning to 30-ft survey stations is the simplest way to consistently minimize this problem. It would not require the introduction of new procedures to the directional drilling industry. However, it would greatly reduce a popular feature of top drive drilling by interrupting the drilling of 90-foot sections of hole. It also takes time and, therefore, costs money in drilling operations. It is estimated that the time required for adding back the two surveys in each stand would cost an additional $50,000 per well (offshore non-deepwater operations). Since data exists in the continuous survey measurements to resolve this problem, it is hard for these authors to accept that the best solution is to ignore this data and return to an older and less efficient procedure. Several alternatives exist. Balanced Slide Method A closer look at how this positional difference develops shows that it is the relationship between where the stationary surveys are taken and where the directional driller makes the slide section within each stand of drill pipe that causes the problem. Two things could be changed: first, the surveys could be taken at different depths; and second, the depths of the slide sections could be changed. The surveys are taken upon the completion of drilling the stand as close to the bottom of the hole as possible without increasing the risk of sticking the pipe. This procedure is nearly universal in directional drilling. The slide section planned for each stand of pipe is much more discretionary. The directional driller decides the footage needed for each slide section to achieve trajectory objectives. The slide is usually placed in the first part of the stand being drilled. Most of the remaining reasons for slide placement are based on hole cleaning procedures and the avoidance of hole sticking problems. These procedures are not universal and could be altered to include consideration of the positional problem. The location of a slide section within the drilling of a stand of pipe can be balanced to minimize the effect of non-continuous curvature on wellbore position. This would not eliminate the contrasting curvatures found with PDM drilling, but it would alter the locations of these curvatures so that they cancel out development of positional differences. Half of the difference between continuous and stationary survey data would be above the line drawn between stationary surveys, and half would be below. The net difference would be zero.

Several factors must be considered in balancing a slide section. These are: the length of the stand, the distance from the bit to the MWD survey sensor, the standard distance off-bottom where stationary surveys are taken, and the length of the intended slide section. Figure 18 shows how these factors come together to produce the desired result. This is a computation that the directional driller can make for each stand of pipe. The result is that he has a recommended footage to drill in rotary mode in the stand before starting the slide section. Hole cleaning, stability, or sticking problems can override this recommendation. In this case, the location of the stationary survey could be changed to balance the slide. The authors are testing operational procedures for implementing this solution. This includes real-time analysis of continuous and stationary survey data to minimize the delta TVD difference between the two survey sets. Other Alternatives A new method for calculating position from survey data that accounts for non-constant curvature can be devised. Several approaches are possible. These are usually based on previous knowledge of the curve rates for slide and rotary directional drilling. The location and tool face for slide sections, commonly found in the directional drillers slide sheets, could be used in this type of survey calculation. This may be the best solution for historical data where continuous survey data is not available but records of directional tactical operations are contained in well reports. Simulated surveys could be added to the stationary survey data based on continuous survey results. These simulated surveys would have the effect of altering the positional calculation in the stationary surveys so that it matches the position calculated from the continuous surveys alone. This approach achieves the desired result, but it has problems. One problem is that there are many ways to make the calculation. Another is the number of simulated surveys to be used between the stationary surveys. Continuous surveying will allow these solutions to be further developed and tested. Using this data in real-time to compare and contrast survey results as shown throughout this paper would help to significantly improve the placement of directional wells. Conclusions There is a positional difference that results from non-constant curvature between stationary surveys taken at spacings of 90 feet or greater. This error has crept into directional drilling with the wide use of PDM steerable motors and top drive systems. Both continuous MWD and continuous gyro survey data have quantified this effect. They show that survey frequency matters and that traditionally placed 90-foot surveys are inadequate when TVD position is important.

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A study of 13 horizontal wells shows that 60% of those wells were significantly affected. Returning to taking stationary surveys every 30 feet can solve this problem, but this is a costly and reactionary approach. The data exists to get better positional results without returning to older methods. Positional differences result from the relationship between the location of stationary surveys and the nature of pattern slide/rotate directional drilling. Balancing the location of the slide sections is a non-intrusive, low-cost method of greatly reducing these differences. Rotary steerable systems produce wellbores with a more constant curvature. Thus positional differences are greatly reduced. Care must be taken to obtain survey data at points where the settings are changed. Monitoring positional differences between continuous and stationary measurements in real-time and taking additional stationary surveys when necessary is an effective means of minimizing the four sources of TVD positional differences discussed in this paper. New methods of calculating the position of a wellbore from stationary survey data are possible and numerous. This presents a problem for the directional drilling industry, which has for more than 15 years enjoyed the effective use of the minimum curvature method as the standard. Longer term, it is the view of the authors that improvements in the accuracy of continuous survey data and the development of an appropriate error model will allow it to be combined with normal stationary surveys taken every stand, so that it can indeed be used for definitive survey purposes. Acknowledgements The authors would like to thank Stan Franklin (ChevronTexaco), Stan Ingham (Schlumberger), and Mike Sullivan (ChevronTexaco) for bringing this issue to our attention and supporting our efforts by providing many of the data sets used in our analysis. We would also like to thank Connor OKelly (Schlumberger) for the work he did on organizing and analyzing the data in the horizontal well study. The table in Figure 12 reflects a large concentration his of effort. Additionally we would like to recognize John Potter and John Lofton (ChevronTexaco) for their support in data analysis and recommendations on procedures.

References

1 Bourgoyne, Jr, A.T., Millheim, K.K, Chenevert, M.E., Young, Jr, F.S.: Applied Drilling Engineering, SPE, 1986, pgs 364-366.

2. American Petroleum Institute, API Bulletin D20:

Directional Drilling Survey Calculation Methods and Terminology, First Edition, Dec 31, 1985.

3. Wolff, C.J.M and de Wardt, J.P.: Borehole Position Uncertainty Analysis of Measurement Methods Error, SPE 9223, Journal of Petroleum Technology, Dec 1981.

4. Williamson, H.S.: Accuracy Prediction for Directional

Measurement While Drilling, SPE 67616, SPE Drilling and Completions, Dec 2000.

5. Lesso, W.G., Cooper, I.M. and Chau, M.: Continuous

Direction and Inclination Measurements Revolutionize Real-Time Directional Drilling Decision-Making, paper IADC/SPE 67752 presented at the IADC/SPE Drilling Conference, Amsterdam, The Netherlands, 27 Feb 1 Mar 2001.

6. Lesso, Jr, W.G. and Kashikar, S.V.: The Principles and

Procedures of Geosteering, paper IADC/SPE 35051 presented at the IADC/SPE Drilling Conference, New Orleans, Louisiana, 12-15 Mar 1996.

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Figure 1. Continuous direction and inclination measurements versus standard stationary survey measurements during a build section using pattern slide/rotary drilling practices with a PDM steerable system. The gravity tool face angle (GTF) data indicates where the slide sections were drilled. GTF is nearly zero for these slides indicating mostly building action with very little turn or change in azimuth.

Figure 2. The minimum radius of curvature method for calculating the position of a wellbore between surveys assumes a constant radius of curvature between the survey points

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Figure 3a. A rotate section with no curvature follows a slide drilling section with a moderately high curve rate or shorter radius of curvature. The actual position will be shallower than what would be calculated assuming a constant curvature between the survey points. Figure 3b. The rotate drilling section happens first followed by the slide section with a shorter radius of curvature. The actual position will be deeper than what would be calculated assuming a constant curvature between the survey points. Figure 3c. The slide drilling section is balanced between the rotate sections that have been cut in half. There remain different curvatures between the survey points but the actual and calculated positions remain approximately the same.

Figure 4a. The slide then rotate pattern of Figure 3a is repeated for an entire build to horizontal section where the slide curve rate is 10 deg/100ft and the rotate rate is zero. The well position will be 25 ft shallower than what would be calculated using stationary surveys.

Figure 4b. Here the rotate then slide pattern of Figure 3b is repeated with the same curve rates. The well position will be 25 ft deeper than what would be calculated using the stationary surveys and a constant curvature.

Figure 4c. The balanced slide/rotate pattern of Figure 3c is repeated here for a build to horizontal. Small variations in the well position occur but the difference between actual and calculated remains small at TD.

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Design Model/Continuous Stationary Measurements dTVD

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Measured Depth

Incl

inat

ion

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-5

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5

delta

TVD

(ft)

shal

low

er --

>

Design Model/Continuous Stationary Measurements dTVD

slide

rotate slide

radius o

f curvat

ure

rotate

calculatedand actual

position

calculatedposition

slide

rotate

actual position

slide ra

dius of c

urvature

calculatedposition

sliderotate actualposition

slide rad

ius of cu

rvature

10 SPE/IADC 79917

Figure 5. A simulation of PDM steerable directional drilling in a horizontal section. The motor delivers a 6 deg/100ft build when sliding that counters the rotary drop tendency of 1 deg/100ft. The steering is section is performed immediately following the stationary survey. In this situation all the stationary surveys will return a value of 90 degrees.

Figure 6. A sketch of a typical geosteering objective in a horizontal well. The lateral section is to be placed 6 feet below the top of the pay zone, which is 17 feet in TVD thickness before an oil water contact (OWC).

Figures 7a & 7b. 7a shows the TVD calculation for the horizontal well using the stationary surveys if the well was drilled as in Figure 5. The horizontal section is at 90 degrees and in the geosteering process, the pay top is encountered. This can be interpreted as the top is dipping down or the zone is pinching out. Figure 7b shows what the drilled well path (in red) would look like if the TVD position accounted for the slide/rotate pattern in Figure 5. The well position is actually drifting shallow at a rate of 3.7 feet/500ft and thus the well will progress the six feet to the pay top in just over 800 feet.

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3800 3850 3900 3950 4000 4050 4100 4150 4200 4250 4300MD (ft)

INC

L (d

eg)

plan curve rate = 0.0 deg/100ftPDM rate = 6.0ROT rate = -1.0slide offset = 0 ft

Continuous INCL svy calc is 2.0 ft TVD shallow after 500 ft

All stationary surveys show 90.0 deg

Continuous INCLINATION

Stationary INCLINATION

3930

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3950

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3970

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VSEC (ft)

TVD

(ft) Pay Top

OWC

Target is 6 feet below pay top

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VSEC (ft)

TVD

(ft)

OWC

trajectory calculated withstationary surveys, all

at 90 degrees inclination

pay top encounteredafter 810 feet

interpretation: top is dipping down

decision: drilling stopsnot worth chasingformation down

7a 3930

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500 1000 1500 2000VSEC (ft)

TVD

(ft)

trajectory calculated withcontinuous surveyswell drifts shallow

pay top encounteredafter 810 feet

interpretation: top is flatneed to steer down

OWC

(planned trajectory)

7b

2500

SPE/IADC 79917 11

Figure 8. Artificially maintaining a constant inclination in a horizontal section. Slide sections with curve rates between 5 and 15 deg/100ft push the inclination above 90 degrees while during the rotary sections the wellbore drops inclination. The TVD positional difference between the continuous and stationary inclination (delta TVD) increases from about 7 to 15 feet shallow. Figure 9. Active directional drilling during a tangent section where the inclination is held to about 45 degrees. The continuous inclination shows pattern slide/rotate sections that are confirmed by the continuous gyro data. The TVD position from this continuous data varies between 4 and 7 ft shallow of the stationary survey position.

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7000 7100 7200 7300 7400 7500 7600 7700 7800 7900 8000

MD (ft)

INC

L (d

eg)

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-5

0

delta

TVD

(ft)

sha

llow

-->

delta TVD

continuous INCLINATION

stationary INCLINATION

+180

0 GTF

-180

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INC

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eg)

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delta

TVD

(ft)

sha

llow

-->

delta TVD(cont MWD stationary INCL)

stationaryINCLINATION

continuous MWDINCLINATION

continuous gyroINCLINATION

12 SPE/IADC 79917

Figure 10. Survey data from a North Sea well using a rotary steerable system in the final build to horizontal. There is a difference between the continuous and stationary inclinations where the rotary steerable system sets are changed. The delta TVD curve shows that this can result in an up to two foot TVD difference for each occurrence. Figure 11. LWD Density, directional survey data and geosteering sketch over 500 ft of a horizontal well in Angola. The density image shows an improbable double formation fold within 200 feet. The continuous inclination (red) shows that the wellbore bounced off of a hard streak and that the image anomaly is actually a double inflection point in the well path.

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MD (ft)

INC

L&A

ZI (

deg)

-15

-14

-13

-12

-11

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-9

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-5

delta

TVD

(ft)

shal

low

er --

>

motor >>drilling

rotary

SPE/IADC 79917 13

Horizontal Well Position Study Results

Figure 12. 13 horizontal wells drilled in 2000-01 were analyzed to determine the extent of TVD positional difference between stationary and continuous inclination data. The eight highlighted wells had TVD differences greater than five feet (either shallower or deeper). Figure 13. The true vertical depth differences for the 13 wells in the study. Stationary inclination is subtracted from continuous inclination. The left hand column (blue) is the maximum difference seen in the wellbore while the right hand column shows the difference seen at total depth of the well.

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30GBK"a" GBK"b" GBK"c" MRN st1 MRN st2 MRN st3 AMP "a" BKP org BKP st1 KGL lat0 KGL lat1 BZL lat1 BZL lat2

delta

TVD

ft

(cD

NI-S

svy)

MAX

at TD

continuous inclination shows well shallower

continuous inclination shows well deeper

Well GBK"a" GBK"b" GBK"c" MRN st1 MRN st2 MRN st3 AMP "a" BKP org BKP st1 KGL lat0 KGL lat1 BZL lat1 BZL lat2Country Nigeria Nigeria Nigeria Nigeria Nigeria Nigeria Indonesia Indonesia Indonesia Angola Angola Angola Angola

TD Date 13-Apr-01 26-Apr-01 13-May-01 17-Dec-00 27-Dec-00 31-Dec-00 04-May-01 17-May-01 27-May-01 23-Apr-01 01-May-01 25-Apr-01 09-May-01Final MD 9076 9020 9428 8393 9050 8785 7250 3067 3953 8156 8700 7705 7540Final TVD 4824 4272 4921 6508 6482 6458 5186 2268 2281 2977 2931 1964 1887

continuous surveys depth interval (feet)beg depth 330 238 496 3292 4774 6916 3938 987 2650 445 3664 1300 3400end depth 9034 8977 7859 8278 8972 8706 7175 2987 3874 8108 8653 7648 7492interval 8704 8739 7363 4986 4198 1790 3237 2000 1224 7663 4989 6348 4092svy spacing 5.2 3.8 3.6 4.1 2.5 2.0 1.3 2.2 1.4 2.0 1.7 2.6 2.1

number of surveysstationary 94 95 97 56 44 18 105 61 87 88 56 71 46continuous 1687 2328 2031 1220 1688 911 2503 923 859 3783 2897 2407 1941

max dTVD 23.7 17.0 13.4 9.8 2.4 2.1 3.0 1.9 2.1 11.0 11.3 5.3 6.4s/d deeper deeper deeper shallower shallower deeper deeper shallower shallower deeper deeper deeper shallower

depth 7300 8970 7800 8100 6945 7400 6400 2950 3850 6000 5066 3350 7492dTVD at TDdelta TVD 22.0 17.0 12.9 9.6 2.3 1.3 1.0 1.9 1.8 5.7 6.2 1.1 6.4

s/d deeper deeper deeper shallower deeper deeper deeper shallower shallower deeper deeper shallower shallower

14 SPE/IADC 79917

Figure 14. Delta TVD plot for GBK a well in Nigeria. Continuous surveys were available for the entire well from kick-off point to horizontal and including the drainhole section. The maximum TVD difference occurs at 7310 ft with the continuous surveys indicating that the well is 23.7 ft deeper than the stationary surveys. The well at TD was 22.0 ft deeper based on the continuous data. The dashed square indicates the data for the next figure. Figure 15. A section of the Delta TVD plot for GBK a from 6000 to 7000 ft measured depth. This is in the build section to horizontal. The slide sections with tool face data have been added. Note that the black delta TVD curve moves with the nature of the continuous inclination.

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SPE/IADC 79917 15

Figure 16. Stationary inclination, continuous drilling and continuous gyro inclination data for a build section of a North Sea horizontal well. The build was accomplished using a PDM motor and the tool face data for the slide sections is also shown. Note that the continuous gyro inclination taken after the entire build was finished still reflects the slide/rotate nature seen in the drilling continuous inclination. This indicates that this tortuosity is not reamed out and that the positional differences will still exist. Figure 17. This is inclination data for part of the build section for a well in Nigeria. Surveys were taken every joint of pipe or 30 feet. A second grouping of the surveys every stand of pipe or 90 feet was made. The 30-ft surveys closely track the continuous and the TVD positional difference remains nearly constant about 2 ft shallow. The 90 ft surveys do not track the continuous and delta TVD drifts six feet deeper in this 1000 foot section of data.

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MD (ft)

INC

L (d

eg)

+180

GTF

-180

ContinuousMWD

INCLINATION(red)

ContinuousGYRO

INCLINATION(green)

StationaryINCLINATION

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TVD

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llow

er --

>

INCLINATION90-ft surveys (blue line/yellow boxes)

30-ft surveys (green diamonds)continuous surveys (red circles)

delta TVD cINCL - 30ft S INCL

delta TVDcINCL - 90ft S INCL

16 SPE/IADC 79917

Figure 18. The balanced slide approach to reducing positional error. The directional driller delays the start of a slide section in a stand of pipe by rotary drilling. This rotary footage is calculated using: a) distance from the bit to the survey sensor, b) off bottom survey distance and c) the length of the stand to be drilled are used along with the d) directional drillers intended slide length. The footage that should be rotary drilled before starting the slide e) is calculated as c-(a + b) + (c d)/2. The differing curve rates remain (red line) but the area (orange shading) will be equally above and below the constant curvature line between the two surveys (X and X+1).

one stand

svyX

svyX+1

a) dist bit to svy sensor b) off bottom dist

d) length of intended slide

e) footage to drill rotary before slide

c) length of stand

joint 1 joint 2 joint 3