Author Archives: Dr. Russell Hall Jr., PVI Consultant

Casing Wear Series - 5: What Have We Learned?

Posted on by

First of all, we realized that the data obtained from a casing wear test did not represent a single property of any one of the three elements (casing, tool joint, drilling fluid) of the casing wear system being tested.

The curve of ‘wear groove depth’ vs. ‘test time’, such as that shown in Figure 1, shows the performance of the entire casing wear system under the operating conditions of the test.

Wear Groove Depth VS Elapsed Test Time

Figure 1: Wear Groove Depth VS Elapsed Test Time

Next, we learned that casing grade, such as K-55, N-80, C-95, was not a good indicator of wear properties. Wear factors for various samples of N-80 casing were uncertain to ± 50%. Often there would be a significant difference in the wear factors obtained from casing samples cut from opposite ends of a 40 foot casing joint. Later tests showed a remarkable lack of correlation between wear factor and just about everything else associated with the composition of the casing alloy.

Every casing wear system should be regarded as unique and individual, and probably not related to any other casing wear system.

The Maurer ‘Wear Factor’, shown in Figure 2, has been shown to predict the performance of casing wear systems encountered in drilling operations with an uncertainty that is consistent with the uncertainty of the field measurements.

What is important in estimating casing wear to be expected during drilling operations is whether the casing wear factor will be 0.2 (oil based mud), 1.0 (some of the new hardbanding alloys), 5 to 8 (unprotected tool joints), or as high as 50 or 70 (X-80 as used in riser pipes).

Remember that we said that casing grade was no indicator of casing wear rate? I make an exception for X-80, a line pipe, often used as the basis for 21 inch riser pipes. At first, we didn’t believe our own results, but, yes, it was true. This explains the severity of riser wear adjacent to the flex joint at the wellhead.

Casing Wear Groove Volume VS Work Done by Tool Joint

Figure 2: Casing Wear Groove Volume VS Work Done by Tool Joint

The result of extremely high casing wear rate is shown in Figure 3. The tool joint was hardbanded with rough tungsten carbide, as shown in Figure 1 of Casing Wear Series – 1: How we got here?.

Extremely High Casing Wear Rate

Figure 3: Extremely High Casing Wear Rate

This is why rough, field applied Tungsten Carbide has largely been abandoned as a means to protect tool joints during drilling operations. It does protect the tool joints, but is a bit hard on the casing.

Casing Wear Series - 4: Interpreting Casing Wear Test Data

Posted on by

Casing wear test data consists of a series of wear groove depths and the elapsed test times at which they were obtained. A data set from one such test is pictured in Figure 1.

Wear groove depth VS Elapsed test time

Figure 1: Wear groove depth VS Elapsed test time

Since it is desired to use these test results to predict the performance of casing wear systems with dimensions other than those used in the laboratory test (Different casing ID and tool joint dimensions), a model which is independent of the casing and tool joint dimensions was needed. Such a model was proposed by Dr. W. C. Maurer. His model was: The casing wear groove volume per unit length of casing is proportional to the work done per unit length on the casing by the tool joint. The constant of proportionality, called `Wear Factor’, was to be evaluated at the end of the 8 hour casing wear test, as shown in Figure 2.

Casing Wear Groove Volume VS Work Done by Tool Joint

Figure 2: Casing wear groove volume VS Work done by tool joint

Here, the performance of the casing wear system is characterized by a single number - the wear factor. This describes the performance of the casing wear system (consisting of casing, tool joint, and drilling fluid ) as linear. Obviously, this is not the case.  But, the linear model greatly simplified the development of a mathematical procedure to predict the wear performance of a wear system in the field. This was the basis for several casing wear mathematical programs which are quite successful in predicting the casing wear to be expected in field drilling operations today. The difference between predictions based on the linear wear performance system and the real world non linear system is, in many cases, less than the uncertainty of wear data obtained in the field. Casing wear logs are costly and time consuming, and are not usually run on a routine basis.

CWPRO is a modern upgraded and improved descendent of these earlier casing wear programs.

Casing wear groove geometry

Figure 3: Casing wear groove geometry

Conversion from casing wear test data, ‘groove depth vs. elapsed time’, to ‘groove volume vs. frictional work’ is a straightforward mathematical operation based on the wear groove geometry shown in Figure 3.

From ‘groove volume vs. frictional work’ back to a ‘casing wear groove depth vs. rotating time’ is similarly straightforward, regardless of the geometry in the field operations.

Knowing the value of the wear factor, and applying the concept that casing wear groove volume is a universal function of frictional work done by the tool joint on the casing, allows us to convert from wear groove volume to wear groove depth for any combination of casing internal diameter and tool joint outside diameter.  When applying the wear model to field drilling operations, the frictional work done by the tool joint on the casing is first determined. Applying the mathematical model to this information, allows the casing wear groove volume to be determined. Knowing the wear volume, and the inside diameter of the casing and the outside diameter of the tool joint (see Figure 3) we have all the information needed to determine the depth of the casing wear groove.

When the complete description of the wear system performance is needed, the differential wear factor shown in Figure 4 is used. The differential wear factor is the slope (derivative) of the wear groove volume vs. work function curve.

Differential wear factor

Figure 4: Differential wear factor

Casing Wear Series - 3: Developing an Experimental Technology

Posted on by

During the 15 years covered by these Drilling Engineering Association studies, more than 450 casing wear tests were run. Each test required an elapsed test operating time of 8 hours.  Each test would be interrupted after the first 15 minutes, then after elapsed time of 30 minutes, 2, 4, 6, and 8 hours to measure the width and depth of the casing wear groove. Such a casing wear groove is shown symbolically in Figure 2, and Figure 3 is a photograph of an actual casing wear groove. Tool joint wear was measured only after the conclusion of the 8 hour test time. Intermediate measures were not possible due to the very small amount of tool joint wear - usually 0.005 inches, or less, of diametrical wear. Measurement uncertainty was estimated to be ±0.0005 inches.

Casing and Tool Joint Samples

Figure 1: Casing and Tool Joint Samples

9 5/8 inch, 47 lb/ft. N-80 casing was chosen to be the baseline standard against which wear systems would be judged. At this time ( 1991 ), N-80 casing was the most commonly used tubular in oilfield operations. The standard tool joint was machined from AISI 4145 steel, and the baseline mud system was a 10 ppg, water-based mud carrying 7% by volume of Clemtex #5 sand.

All test operations were performed manually. Several attempts to automate test operations were unsuccessful. Satisfactory precision in the recorded data could not be achieved.

The original Drilco test machine was purchased by the National Oil company of China and a duplicate copy of the machine is now being operated by Ken Malloy of Mohr Engineering. Casing wear testing is available on a commercial basis from Mohr Engineering.

Casing and Tool joint Wear

Figure 2: Casing and Tool joint Wear

Casing Wear Groove

Figure 3: Casing Wear Groove

Casing Wear Series - 2: The Basics

Posted on by

When it became apparent that casing wear was going to be a matter to be reckoned with, several organizations initiated experimental studies of this phenomenon. Among these were (1) Shell Oil Company, (2) Exxon, (3) Texas A & M, and (4) Drilco. All these operators discovered that experimental casing wear studies were both time consuming and expensive.

All of the casings wear studies involved building a machine that would simulate field conditions as closely as possible in the laboratory. Figure 1 is a symbolic presentation of a casing wear test machine that incorporates all of the parameters needed to simulate casing wear as it would occur under field conditions.

Elements-of-a-casing-wear-test-machine

Figure 1: Elements-of-a-casing-wear-test-machine

As shown in the Figure 1, the rotating tool joint sample is pressed against the inner wall of the casing sample with a constant force. The intersection of the casing and the tool joint is flooded with drilling fluid, which contains sand to simulate the drill cuttings which the mud transports to the surface in field operations.

In addition, the tool joint ( or the casing sample ) should be slowly reciprocated during the wear test to simulate drilling progress. Failure to include this reciprocation results in a significant reduction in the observed casing wear. It is believed that without reciprocation, the casing sample and the tool joint sample will `mate’ to each other, and the drilling fluid will then form a hydrodynamic lubricating layer between the two surfaces. This will greatly reduce the grinding effectiveness of the sand that is transported by the drilling fluid. Non-reciprocating wear tests may result in as little as 10% of the wear observed in tests where reciprocation is employed.

Such a casing wear test machine is pictured in Figure 2. This machine was built by Steve Williamson ( Drilco ) in the early 1980s, and was later purchased by Maurer Engineering for use in the Drilling Engineering Association ( DEA ) projects ( DEA – 8, DEA – 42, and DEA – 137 ). These projects covered the period from 1990 through 2002.

Drilco casing wear test machine

Figure 2: Drilco casing wear test machine

Most of the material presented in these articles was developed as a result of the work done using this machine.

Casing Wear Series - 1: How we got here?

Posted on by

Prologue

Mr. Gefei Liu, president of Pegasus Vertex, Inc. (PVI), suggested that I write a series of short articles to discuss the empirical science of casing and riser wear. PVI incorporates this technology in their computer program – ‘CWPRO’. This program applies wear technology to predict casing and riser wear to be expected during drilling operations.

The observations and opinions expressed in these articles are based on my 20-year association with the subject of casing and riser wear. Much of this time was spent at Maurer Engineering, under the direction of Dr. W. C. Maurer. Much of the advances in the subject were the direct result of Dr. Maurer’s phenomenal knowledge of and insight into the technical challenges that were encountered during the development and application of casing and riser wear technology.

In the beginning

Casing wear was not recognized as a problem until the early 1960s. Vertical wells were being drilled deeper, and directional wells were being pushed out further. This required longer drilling times, and resulted in much greater exposure of the inner wall of the intermediate casing to the rotating tool joints of the drill string. Wear grooves appeared in the intermediate casing and progressed from noticeable to serious.

Up to this time, tool joint wear was the only wear problem being treated.

The universally accepted treatment to prevent tool joint wear was to coat the tool joints with an alloy containing tungsten carbide particles. This protected the tool joints, but was proving to be a bit hard on the intermediate casings.

Tungsten carbide coated tool joint (Field Applied)

Figure 1: Tungsten carbide coated tool joint (Field Applied)

The tungsten carbide coated tool joints were efficiently machining wear grooves into the inner walls of the intermediate casings. As these wear grooves deepened, they would seriously reduce the pressure capacities (burst & collapse), sometimes resulting in catastrophic failure.

Pressure test of worn casing

Figure 2: Pressure test of worn casing

These early findings resulted in the establishment of two distinct, but related, developments.

1. Experimental studies of casing wear; and

2. The development of casing-friendly tool joint coatings that would also protect the tool joints.

First of all, what are the basic elements of casing wear?

If boreholes were straight, casing wear would be much less of a problem. But, boreholes are not straight. As shown in Figure 3, tension in the drillstring pulls the rotating tool joints into the convex sides of the curved borehole. Since the tension in the drillstring may be several hundred thousand pounds force, the lateral loads forcing the tool joints into the convex wall of the intermediate casing may be several thousands of pounds force. The greater the curvature of the borehole, measured as `dogleg severity’, the greater will be the lateral load pushing the drill string into the intermediate casing wall. ‘Dogleg Severity (DLS)’, which is measured in degrees per 100 feet, can run as high as 5 deg/100 ft. or worse.

Drilling fluid which transports drill cuttings to the surface, flows past the tool joint/casing contact, and provides the abrasive needed to grind a wear groove into the inner wall of the intermediate casing.

Casing wear at a dogleg is shown in Figure 3, and a schematic of the resulting casing wear groove is shown in Figure 4.

The existence of the casing wear grooves indicates that there are many locations where epicyclic drillstring vibrations do not occur.

Elements of casing wear

Figure 3: Elements of casing wear

Casing wear groove

Figure 4: Casing wear groove