Brod Sutcliffe
Teleco Oilfield Services Inc.
Aberdeen, Scotland
David Sim
Teleco Oilfield Services Inc.
Meriden, Conn.
By measuring the drilling performance of the bottom hole assembly (BHA) in real time, the probability of serious drilling problems can be reduced.
A new logging tool and service directly measures bottom hole assembly performance, thus allowing swifter and more accurate corrective measures when necessary. Drilling time savings are realized through improved rates of penetration (ROP), reduced off-bottom time, and increased life of drillstring components.
Improvements in oil field technology have led to the development of equipment with an increased capacity for drilling complex directional wells with large displacements.
Directional wells are designed to intersect targets while following the path of minimum torque and drag loss. Even in relatively lowangle wells, however, the amount of torque required to rotate the bit may be significantly less than that needed to overcome side-wall friction, resulting in inefficient drilling conditions that are not recognizable from surface torque measurements. Furthermore, hole drag can cause weight-on-bit (WOB) values obtained from hookload sensors to appear different from the weight actually applied to the bit.
In directional wells, surface parameters alone are not sufficient to monitor drilling conditions accurately, nor are they reliable enough to enable sound deductions regarding the cause of apparently anomalous events.
Applying the principle of conservation of energy, it can be broadly stated that: Energy required to rotate the drillstring at surface amount of work done by bit + energy lost through drillstring friction.
Measurements of surface WOB and rotary speed provide a good indication of the energy input to the drillstring. The resistance to drilling can be assessed from surface torque measurements and ROP. The main variables in drilling are hole conditions, bit condition, and formation properties. Using local experience and drilling knowledge, it is often possible to predict the effects of these factors fairly accurately. However, with a combination of unknowns, any unexpected drilling problem can be difficult to analyze, and a serious disruption of drilling operations may result.
Advances in measurement-while-drilling (MWD) technology have facilitated the inclusion of downhole drilling dynamics measurements into the package of MWD data transmitted in real time. Thus, the actual energy input to the bit and the resistance of the formation to drilling can be measured and compared to the surface data. This provides an extremely useful analytical tool for the drilling engineer.
DDG TOOL MEASUREMENTS
Teleco's drilling and dynamics with gamma ray (DDG) tool accurately measures downhole torque and WOB by using highly sensitive strain gauges bonded to the metal of the wall of the drilling dynamics sub. The sub is made of beryllium copper because this material has more elasticity than monel steel. The strain gauges are mounted in cylindrical recesses within the sub walls. Both the composition of the sub and the position of the strain gauges amplify the amount of strain per unit of loading, thereby increasing the resolution of measurements.
Each drilling dynamics measurement is made by four strain gauges connected in a Wheatstone bridge configuration. Precise positioning of the strain gauges compensates for sub distortion and eliminates errors associated with downhole changes in temperature and pressure across the sub wall. The readings from the weight and torque sensors are sampled simultaneously and then averaged before being transmitted to the surface. The strain data transmitted by the MWD DDG tool are converted into true downhole WOB and torque-on-bit readings by the data acquisition computer at the surface. This allows direct comparisons to be made between downhole WOB and torque.
To obtain accurate values, it is necessary to subtract a zero offset from the transmitted readings by a taring procedure. Taring corrects the data for the effects of drillstring weight and torque on the bottom hole assembly between the drilling dynamics sub and the bit. Further, gradual changes in background strain are caused by gradual increases in hydrostatic pressure and mud temperature as drilling proceeds. These effects are limited by routinely retaring every few hours.
Different taring procedures are used to correct drilling dynamics data during rotary drilling and steering. Taring for rotary drilling is carried out by rotating the drillstring off bottom at the rotary speed and flow rate used while drilling; the resulting transmitted values of torque and weight are used as the zero offset values. While steering, the tare is made with the bit off bottom, nonrotating.
In either case, the entire procedure takes about 2 min and can be carried out after taking an MWD directional survey.
The DDG sub body also acts as a mandrel, and a variety of sleeve stabilizers is available. This provides increased flexibility for BHA design and allows the tool to be positioned directly behind the bit to measure bit conditions efficiently.
SURFACE TO DDG
The difference between surface and downhole WOB is the component of the applied axial load used to overcome drag in the hole.
In practice, it is found that these drag losses are minimal under efficient rotary drilling conditions, even if hole angles are high. This is thought to occur because the rotation of the drillstring reduces the amount of contact between the drillstring and hole wall, thereby subjecting the string to less sliding friction.
In general, for rotary drilling, any weight loss indicates inefficient drilling.
During nonrotary drilling, the DDG tool provides measurements of downhole weight and reactive torque. There are two problems with surface measurements under these conditions: torque measurements are only available if the rotary drive is in use, and sliding friction of the drillstring masks the downhole WOB variations.
The difference between surface and downhole torque measurements is the torque required to overcome the rotating friction of the drillstring against the hole wall. This torque increases with depth at a rate related to the hole angle and the rate of change of hole angle and direction (dogleg severity).
DDG TO BIT
Downhole torque is directly related to ROP; for a steady downhole WOB and rotary speed, the bit torque generally increases with increasing ROP. Changes in penetration rate and associated changes in downhole torque are caused by differences in formation strength.
Inefficient drilling is therefore indicated by a decrease in ROP for a constant WOB and formation strength. This may be accompanied by a change in downhole torque, depending on the type of drilling problem.
An increase in torque may indicate that the drillstring below the DDG sub is hanging up either on the bit gauge or on a stabilizer. A decrease in torque may indicate less resistance to rotation due to reduced penetration into the formation by the bit teeth or cutters, which may be the result of an increase in formation strength or a dulling of the teeth or cutters. A lithological change may be confirmed by the MWD gamma ray sensor, which is positioned 6.5 ft above the bottom of the MWD tool.
INTERPRETATION
DDG data provide valuable insight into the downhole drilling process. Proper interpretation of the results is a key element. Because of the number of variables involved, several different drilling problems may produce the same drilling dynamics symptoms.
Experienced drilling dynamics field engineers are necessary to provide a keen awareness of drilling operations and to constantly evaluate the available surface and MWD data to diagnose drilling problems promptly.
Table 1 shows the possible diagnoses of some typical drilling dynamics log responses. In addition to those parameters shown, gamma ray data are also available at a lagged depth (a result of the 6.5-ft distance between the two tools).
The MWD field engineer must use his experience and knowledge of the well's conditions to make the most probable interpretation for the operator. After discussing the implications of the drilling dynamics log with the MWD field engineer, the operator is much better suited to make a decision on what remedial action, if any, is required.
BENEFITS
The incremental cost of a drilling dynamics service is not excessive, particularly because directional MWD services in deviated wells are now the norm rather than the exception.
Drilling problems, such as poor weight transfer or turbine stalling, can be recognized from DDG data and immediately rectified. Increasing ROP and avoiding unnecessary trips are direct results of such corrective actions. This attention to downhole conditions improves drilling efficiency.
Another benefit of the DDG tool is the immediate detection of a failed BHA component. Rapid detection of a worn bit or detection of locked cones before a cone is lost may prevent costly fishing operations. Furthermore, increased downhole torque and drag can indicate conditions which, if not addressed, may lead to stuck pipe.
The information provided by a drilling dynamics service allows the operator to learn more quickly about inherent drilling difficulties on a project. Drilling dynamics may indicate that a certain bit type is better suited to a certain formation or that a particular hydraulic configuration may assist in drilling a hole section. Rapid identification and prompt modification of drilling practices can accelerate learning the peculiarities of a particular well or field.
APPLICATIONS
The following examples taken from early use of the DDG tool have been chosen to highlight some its applications. Unfortunately, results were not always interpreted to their full benefit at the time because field engineers and operators were themselves gaining experience. Some of the examples, therefore, depict events that a drilling dynamics service can assist in avoiding to permit proper analysis of similar events in the future.
POOR HOLE CONDITIONS
A knowledge of surface energy input and downhole drilling dynamics can be used to monitor and identify deteriorating hole conditions that may lead to inefficient drilling or stuck pipe (Fig. 1). This log of drilling dynamics data is from a section of hole where interbedded shales and silty sandstones were drilled at a decreasing hole angle with a soft-formation milled tooth bit.
The gamma ray log indicates the shale content of the formation. The measuring point is located about 45 ft behind the bit with a fullgauge stabilizer below the MWD tool.
Through Zone 1 there was a sudden decrease in weight transfer (i.e., the difference between surface and downhole WOB). The ROP also decreased accompanied by an increase in torque losses (increase in surface torque and decrease in downhole torque).
The lack of weight transfer indicated that the problem was above the measuring point and therefore not caused by the stabilizer immediately below the Teleco DDG sub. These symptoms were the result of one of the stabilizers above the MWD tool sticking or digging, thereby generating excess torque.
The problem partially corrected itself as the stabilizer passed through the zone, although weight transfer remained variable. This type of DDG data response may be a warning that conditions prevail which may lead to stuck pipe. It may prove necessary to ream the hole, make a wiper trip, or alter the mud properties, depending on the situation.
Through Zone 2, downhole weight readings dropped dramatically, but the surface weight remained constant. This was accompanied by a decrease in downhole torque and ROP, indicating that little of the input energy was reaching the bit (the surface torque varied about a mean value but showed no particular trend).
To interpret these data, the BHA must be studied. The second stabilizer is full gauge, located approximately 81 ft behind the bit, and passing through the sandy bed at the top of the log. In correlation with an increase in weight loss, torque losses increased much less than in Zone 1. The most likely explanation is that a ledge has developed at the shale/sand boundary, causing the stabilizer to hang up. Sticking is less probable since the torque losses were not excessive.
Zone 3 shows how lithology changes can mask a nonstandard response. Here the weight transfer was poor as a result of stabilizers hanging up above the MWD tool. However, the formation became more sandy and easier to drill.
The ROP increased with a corresponding initial increase in downhole torque. Even though the surface parameters indicated good drilling dynamics (increasing ROP and constant surface WOB and torque), the downhole data revealed poor weight transfer and associated inefficiency.
BIT PERFORMANCE
Drilling dynamics measurements are very effective at determining bit failure, as shown in a log of the drop-off section of a directional well drilled with a diamond bit and turbine (Fig. 2). Through Zone 1, the ROP began to decrease, but the gamma ray response did not indicate any formation changes.
The marked decrease in downhole torque indicated that there was little resistance to the bit turning, suggesting little or no cutting by the bit. Because of the high drillstring torque in this directional well, these effects were not readily apparent in the surface torque curve. After pulling out of the hole, the bit was graded 100% worn.
Although expensive, polycrystalline diamond compact (PDC) bits have justified their cost by their extended lifetimes and high drilling efficiency. However, a PDC bit may fail very rapidly if run under unsuitable drilling conditions, such as excessive WOB (Fig. 3).
A new, extended-gauge, medium-formation parabolic PDC bit was run at X,812 m. Drilling proceeded through a sandstone containing very hard, well-cemented bands.
The drilling dynamics responses were excellent down to X,831 m. The ROP and downhole torque were consistent with the level of the WOB, weight losses were insignificant, and torque losses were normal for the hole trajectory.
At X,831 m, the bit entered one of the hard bands. The WOB was increased to improve the ROP, and downhole torque increased correspondingly. As the WOB was increased still further, the downhole torque suddenly decreased at X,832 m to approximately 500 Newton-meters (N-m). This decrease in downhole torque was identified by the Teleco field engineer as an indication of bit failure.
After attempting to drill ahead unsuccessfully, the bit was pulled after drilling just 21 m and found to be 1 00% worn. The bit failure was thought to be a result of the rapid increase in WOB.
TURBINE OPTIMIZATION
Very hard formations are often turbo-drilled to maximize diamond bit performance and minimize cost. This requires the services of a skilled turbo-drilling supervisor on the rig. However, in deep directional wells where surface parameters may not reflect downhole conditions accurately, even an experienced turbine supervisor may not be able to determine the optimum turbo-drilling parameters or detect whether the turbine has stalled (Fig. 4).
A turbine was used to drill the hard Carboniferous shale composing the final section of an extended reach, S-shaped, directional well. With an average ROP of only about 1.5 m/hr, approximately 15 min were required to detect turbine stalling by watching the ROP. High drillstring friction prevented any response in the surface torque measurements.
Downhole torque measurements, however, immediately registered a tremendous increase when the turbine stalled. By using the drilling dynamics data, up to 15 min of drilling time were saved during each stall.
It was also possible to determine the downhole stall weight and torque from the DDG data. By drilling with slightly less than this weight, the optimum turbo-drilling rate was achieved. On this 50-hr turbine run, approximately 15 hr of drilling time were saved.
TOP DRIVE FAILURE
Drilling dynamics measurements can assist in the diagnosis of more than just subsurface problems. Because the surface torque measurement point is between the rig power plant and the rotary drive, problems with the rotary drive itself can be identified (Fig. 5).
On a top-drive rig, drilling dynamics were measured for a hole section drilled through interbedded shales and evaporites. Through Zone 1 there was a rapid increase in surface torque, indicating a large increase in rotary friction. However, the weight transfer to the bit and the downhole torque both remained constant. ROPs were consistent with the gamma ray curve, indicating no lithology change. No anomalous trends were displayed in the downhole data. The efficient weight transfer suggested no drillstring hanging problems.
The driller initially suspected that the problem was related to the stabilizer below the MWD tool, but the constant, low downhole torque discounted this explanation. With problems below the MWD tool ruled out and excessive drillstring friction very unlikely, the top drive itself was inspected and found to have developed a cooling system problem.
TFA FACTOR
In one case, a sidetrack was drilled beside the original hole at a similar inclination, and it used the same BHA design, bit type, rotary speed, flow rate, and mud conditions. A medium-formation, heavy-set parabolic PDC bit of the same model was used for both sections. The formation consisted predominantly of claystone with anhydrite stringers. The only variation between the sections was the use of larger bit nozzles for the sidetrack to provide a total flow area (TFA) of 1.45 sq in. compared to 0.97 sq in. for the original hole.
A comparison of the two logs showed that for the same downhole WOB and rotary speed, the bit with the smaller TFA gave a 40% higher average ROP. The possibility of poor drilling dynamics causing the problem was ruled out by MWD drilling dynamics logs that showed excellent energy transfer to the bit.
The client had believed that the larger TFA would not adversely influence bit performance. Clearly, bit hydraulic horsepower played a larger part in the drilling efficiency of this bit type than was previously realized. As a result, a lower TFA was used with subsequent bits of this type, and the drilling time was reduced for this hole section.
This demonstrated how drilling dynamics measurements can be used to improve drilling efficiency through optimum matching of drilling tools to the hole conditions and formation types.
The various examples cited demonstrate some of the applications of downhole drilling measurements. Drilling time is optimized each time remedial action is taken more promptly as a result of a better understanding of downhole conditions. The cost benefits of increased longevity of drilling components and the reduced probability of serious drilling problems demonstrate a significant application for the DDG tool in horizontal or high-angle wells.
Copyright 1991 Oil & Gas Journal. All Rights Reserved.