Thin-walled liner equipment cuts costs on well deepening project

Jamie Sutherland
Shell Canada Ltd.
Calgary

Chris Weaver
Baker Oil Tools
Houston

Peter Aiello
Import Tool Corp. Ltd.
Calgary

Thin-walled, slim hole liner equipment can save $3-4 million per well in deep reentry applications by allowing existing wells to be deepened or sidetracked rather than drilling new wells from surface.

The design makes it possible to reenter existing wells, successfully isolate depleted zones, and deepen the well into virgin-pressured reservoirs.

The design includes thin-walled, close-tolerance liner hangers, liner top packers, tieback seal assemblies, and liner setting sleeves that provide reasonable burst and collapse resistance while maintaining an inside diameter to facilitate drilling a deep, deviated 43/4-in. hole with a tapered 27/8-in. 3 31/2-in. drillstring.

Shell Canada Ltd. is continually trying to lower its finding and producing costs, and one way to meet this challenge is through reentry and deepening projects. Reentering and deepening an existing well rather than drilling a new one eliminates a major new capital investment, resulting in drilling and construction costs potentially less than half of what they would be for a new well. Further benefits accrue if the project can be carried out with slim hole techniques.

These factors influenced Shell Canada's decision to undertake a reentry and deepening project in 1995 in its Waterton field in Western Canada.

In Shell Canada's Waterton field, gas-producing wells originally drilled in the 1950s, 1960s, and 1970s to depths of 14,760 ft were completed with perforations in 7-in. casing and open hole. These wells are now being reentered to tap new reserves. The reentries encounter particularly challenging sour gas, low temperature, diverse formation pressure conditions.

The objective of the reentry program is to seal off the depleted bottom zones of the wells and tap into the same fault-repeated formations at virgin pressure, at a deeper level.

Background

Waterton field production capability has recently declined to the point where production volumes are unable to use the Waterton plant fully, particularly as a result of the near depletion of the prolific Sheet III Rundle-Wabamun A pool. New reserves and additional deliverability are of utmost importance in keeping the plant at capacity to maximize revenue and maintain low unit operating costs.

The purpose of the reentry and deepening initiative was to determine whether commercially viable pools of hydrocarbons exist at the south end of the Waterton complex, beneath the Devonian Wabamun formation. Interpretation of regional seismic suggests the existence of as many as five prospective reservoirs beneath the productive Sheet III pool, each of those representing potential new reserves at virgin reservoir pressures.

The primary objective was the Sheet IV Mississippian Mounthead and Livingstone formations, which if hydrocarbon bearing, would represent a separate pool from the Sheet IV and IVc pools in North Waterton. Secondary objectives included the Sheet III Devonian Fairholme, Sheet IV Devonian Fairholme and Wabamun (Palliser), and Sheet V Mississippian Livingstone (Fig. 1 [30420 bytes]).

The Waterton 14 well was originally drilled in 1964. It was completed in 1969 with 31/2-in. tubing, perforations in the 7-in. casing, and open hole completion with a permanent production packer. Several workovers had been performed on the well, the last one in 1975.

Original pressure in the well was 4,641 psi; the pressure at the time of the deepening project had declined to 580 psi. Production was 4.2 MMcfd. The gas production included 18% H2S and 5% CO2 with no water.

Environmental considerations

The Waterton field presents particularly challenging sour gas, low temperature, diverse formation pressure conditions. The deepening was considered a critical sour gas well, with anticipated 17-33% H2S and the potential for very high deliverabilities. The field location is in an environmentally sensitive area with high wilderness value.

If new drilling were to occur, a joint public/government environmental hearing would be necessary, with no guarantee of subsequent drilling approval. No new wells have been drilled in the South Waterton area for more than 10 years. Three wells drilled in the North Waterton area in the past 10 years required a year or more for the environmental assessment process before approval was gained.

An additional consideration to be addressed in planning the deepening project was that lost circulation had previously been a serious problem in the field. Two wells (Waterton 20 and 35) had blowouts, and a third (Waterton 37) remained under control despite a gas kick while major lost circulation was being combated. Each of these three occurrences was either directly caused by or complicated by the exposed fractured, partially depleted but highly productive Livingstone B thief zone.

Using the existing Waterton 14 well bore rather than drilling a new well, and isolating the productive formation, would resolve both well control and environmental issues. Disturbances in Yarrow Canyon would be minimized, with only minor drilling pad enlargement and no new road construction required.

A long and costly Alberta Energy & Utilities Board (AEUB-formerly the Energy Resources Conservation Board) hearing would be unnecessary, and confrontations with concerned environmental groups could be avoided.

Economics

The authority for expenditure (AFE) cost for the reentry/well deepening was $3.85 million, divided into three stages: well preparation ($550,000); drilling, evaluation, and completion ($2.85 million); and production testing ($450,000). The estimated cost for a new well was $8-10 million.

The decision to reenter the existing well was based not only on the 50% reduction in drilling and construction costs but also because potential problem costs associated with drilling through the Sheet III depleted reservoir section would be avoided, as would the cost of an AEUB hearing. Consideration was also given to the uncertainty of receiving government approval for a new well in this sensitive area.

The reentry/deepening project was planned to maintain the viability of the existing well bore, should the decision be made to plug back the new section. This strategy assured that the current 4.2 MMcfd production would not be lost, even if no new commercially viable pools were located.

Drilling strategy

To accomplish the program objectives, a six-step sequence was proposed for the Waterton 14 pilot well:

• Confirmation of the existing well bore

• Removal of existing well site facilities and well completion

• Isolation of the productive Sheet III intervals

• Deepening of the well from existing depth of 12,054 ft to planned total depth of 18,241 ft, followed by logging and selective coring to determine prospect potential of the five objective intervals

• Total or partial monobore completion with open hole or cased hole testing

• Suspension with possible future tie in or recompletion of the existing well in the Sheet III formation.

The well trajectory was chosen to intersect the five objectives.

Reentering the Waterton 14 presented certain limitations and challenges. To address potential lost circulation and uncontrolled flows, Shell Canada performed a comprehensive analysis on all offset well data (logs, daily drilling reports, core data, etc.) to establish exactly where any significant circulation losses had occurred (geologically) and what formations had been penetrated to total depth, taking into account local faulting.

Thorough scrutiny of all the data led to the conclusion that the Waterton 14 total depth lay near the base of the Wabamun formation below the deepest productive Sheet III unit, the Wabamun Crossfield member. Shell concluded that an anhydrite layer at the base of the Wabamun provided the likely pressure seal between it and deeper objectives.

Massive lost circulation in deeper objectives was considered unlikely because of the evidence of the anhydrite layer, normal pressured formations below, and less fracturing with associated negligible losses observed in the structurally deeper Sheet IV/IVc penetrated in the North Waterton area.

There remained significant uncertainties as to potential local faulting (fairly common in the area), hence, potential breaks in the pressure seal below. After performing a risk analysis, however, Shell chose to set a drilling liner in the anhydrite layer at the present total depth. This would eliminate the massive lost circulation problems during initial deepening by isolating the productive and fractured Sheet III formation prior to any new drilling.

To accomplish this isolation, it was decided that a service rig would snub in and cement a drilling liner, complete with liner top packer, before the drilling rig arrived on site.

Liner design philosophy

By setting the liner prior to drilling, the deepening project was to be undertaken with no contingency casing available to allow drilling to continue should hole problems, such as severe lost circulation or a high-pressured gas or water zone, be encountered.

This made the selection of the 51/2-in. drilling liner setting depth critical to the project's success. For example, if a porous zone encountered after setting the liner were in communication with the depleted Sheet III reservoir, drilling could not proceed deeper because of the risk of cross flow between the virgin and depleted zone. Conversely, if a high-pressure gas or water zone were encountered before setting the liner, the same unpredictable subsurface cross flow would develop, potentially requiring several months to control.

The 43/4-in hole was a requirement for several reasons:

• The expected, planned trajectory required a minimum 27/8-in. 3 31/2-in. S135 drillstring to allow drilling to total planned depth of 18,241 ft. (The 27/8-in. drill pipe with high-torque connectors was not feasible inside the 5-in. or 43/4-in. liners.)

• Logging tools were restricted for the 31/2-in. hole and not for the 43/4-in. hole.

• Other concerns included high pumping pressures, stiff bottom hole assemblies, and deviation control.

  With these issues in mind, the isolation liner and liner accessories were designed based on the following series of absolute design criteria:

• OD. As Waterton 14 was a reentry, all liner equipment had to fit into the existing 7-in. casing.

• ID. All newly installed equipment had to have sufficient inside diameter to permit drilling a 43/4-in. open hole.

• Burst resistance. All liner components required sufficient burst resistance to enable the hole to be deepened to the projected total depth with normal drilling fluid and adequate kick margins.

• Setting depth. The liner had to be set at or near total depth to ensure Sheet III isolation.

• Cementing. Once at total depth, the liner would need to be cemented to ensure Sheet III isolation.

Under normal liner equipment sizing, a 5-in. or 41/2-in. liner would be run inside the 7-in., 29-lb/ft casing and 515/16-in. open hole. Neither of these sizes, even with the lightest possible weight, would allow for the drilling of a 41/2-in. hole, however.

With the above criteria, the liner size selection was simple: only a 51/2-in. liner would satisfy the requirement (Fig. 2 [27817 bytes]).

Casing design

Tight tolerances are an everyday reality in liner design; however, seldom does a well present the number of obstacles that had to be overcome in the Waterton 14 deepening.

Absolute design criteria for OD and ID dictated 51/2-in., 17 lb/ft L-80 to maintain the 43/4-in. open hole and retain the highest possible burst resistance. This casing met NACE specification MRO175-95 and AEUB specifications for sour service, normal, intermediate casing burst loading criteria.

AEUB now requests that all intermediate casing meet production loading criteria for anticipated reservoir pressure at total depth for all critical sour wells. Because actual Sheet IV and V reservoir pressures were unknown, the default gradient of 0.0486 psi/ft applied.

Neither the 7-in. casing nor the 51/2-in. liner would satisfy this requirement. In Shell's view, however, the liner was being run as a lost circulation string, not as an intermediate casing. Its primary objective was to isolate the Sheet III depleted reservoir, thereby allowing drilling to commence. Based on the view that the liner was not a conventional casing string, Shell was granted a waiver from the AEUB.

The 51/2-in. liner had sufficient collapse resistance and tensile strength to meet all requirements. In the event that the productive intervals were encountered in the lower well bore, a monobore completion [13862 bytes] using the 31/2-in. tubing would be run and cemented from total depth to above the top of the liner, isolating it from production. The monobore completion would have sufficient mechanical properties to meet or exceed all Shell and AEUB specifications.

As it was critical to successful isolation, the liner had to be placed in the anhydrite section at the bottom of the 57/8-in. cored open hole. Once in place, it had to allow cement to pass around the bottom of the liner and fill the annular space between the well bore and liner.

To satisfy setting depth and cementing criteria, connections with a flush OD and a swaged pin ID were selected for the liner casing. The 51/2-in. OD of the connection allowed for a reasonable chance of getting the liner to bottom and achieving good cement isolation at the liner shoe. However, the 51/2-in. liner inside 57/8-in. open hole ruled out the possibility of using isolation packers or cementing accessories to achieve zonal isolation in the open hole section because of the minimal clearance.

Liner hanger equipment

Getting the liner and associated equipment in the hole and then achieving successful isolation at both the bottom and top of the liner would require unique liner equipment and procedures specially designed to fit the very small clearance between the 7-in. production casing and the planned 51/2-in. drilling liner (Fig. 3 [21894 bytes]).

Prior to beginning the liner hanger equipment design phase, careful consideration was given to the cement isolation of the Sheet III formations, as cementing the liner could have significant impact on the liner hanger system design. Early in the discussions, it was determined that the probability of successful isolation of all Sheet III in a single-stage cementing operation was very low (Fig. 4 [16693 bytes]).

The two main reasons for this assessment were low pressure/highly fractured zones exposed in the interval and close tolerances between the 7-in. casing ID and 51/2-in. liner OD, resulting in a thin cement sheath between the wall and the casing.

Because of the hydrostatic head exerted by the cement column, it was believed that the formation would not support a sufficient column of cement to isolate the zones reliably and that significant cement losses would occur in the fractured formations, leaving upper zones uncemented.

Bottom isolation

Discussions turned to the possibility of using a liner top packer as the primary means of isolating the top of the Sheet III formation. However, this scenario was deemed unfeasible because no liner packers exist that could hold a full column of hydrostatic pressure at that depth (Fig. 5 [17289 bytes]).

After further analysis, it was determined that isolation of the top and bottom of the liner would have to be achieved in more than one stage. Because no existing stage cementing collars could meet the absolute deign criteria for OD and ID, it was determined that the best possible method of isolating the entire section would require first cementing the bottom of the liner. A second stub liner, with a tieback seal assembly on bottom, would be cemented then stung into the top of the primary liner.

After analyzing several cementing alternatives, it was determined that isolating the bottom end of the liner could best be achieved by the use of a balanced plug of cement, as formation pressures would not allow loading of the hole with fluid to perform a conventional circulating cement job.

The probability of success for this method was fairly high because of the location of the bottom of the liner in the competent anhydrite section. Having devised a reasonable plan for bottom isolation, thoughts returned to cementing the top, or stub, liner.

Top isolation

To ensure that slurry was displaced around the stub liner rather than being lost into the formation, a liner top packer was reintroduced on the top of the primary lower liner (Fig. 6 [16970 bytes]). In this scenario, the purpose of the packer seals would be two fold.

First, rather than having to hold the hydrostatic pressure of a full column of drilling fluid and kick margins, the seals would need only hold the hydrostatic head of the cement balanced plug used to cement the stub liner. Second, the liner top packer would allow the drill pipe to be removed from the well without the chance of well swabbing or control problems.

A weight-set liner top packer was chosen for the initial liner because of the OD restriction of 6.000 in. A hydraulic-set packer would not meet burst requirements in that OD while maintaining a 43/4-in. drift ID. The tieback system (primary liner seal bore and stub liner seal assembly) was designed with burst capabilities to withstand a full hydrostatic column of drilling fluid.

The two-stage cementing method required additional time and equipment, so by definition, was more complicated and expensive. By using this plan, however, the cementing operations were broken down into simple, manageable steps that ensured a reasonable probability of achieving overall success in isolating the Sheet III formations and ultimately deepening the well to projected total depth.

Equipment requirements

With a workable cementing plan developed, equipment requirements became more clear. Primary areas of concern during the liner-design phase were optimizing the tieback system for maximum burst resistance and ensuring that the liner was in tension when cemented and that cement of isolation of the Sheet III formations was successful.

In optimizing a tieback system, the initial considerations are the tieback receptacle OD, sealing system cross section, and tieback seal assembly ID. The OD of a tieback receptacle is generally larger than the OD of the liner, but it must fit inside the casing where the liner is being run.

A traditional rule of thumb is that the tieback receptacle should be at least 0.125-in. smaller on the OD than the drift of the casing in which it is run.

Hydraulic surging of the formation and the resulting loss of well bore fluid is of primary concern when running most liners. However, Waterton 14 would have little-to-no fluid in the well bore while the liner was being run. Therefore, normal rules did not apply. It was decided to make the OD of the tieback receptacle as large as was practical while still maintaining a high degree of certainty that it could be successfully run in the well.

Ultimately, 6-in. OD equip ment was chosen. Molyglass (80% Teflon, 15% glass fill, and 5% molybdenum disulfide) type seals in 0.188-in. cross section were chosen because of their field-proven durability, sealing capabilities, and suitability to sour environments.

The tieback seal assembly for Waterton 14 had to allow a 43/4-in. stiff drilling assembly to pass from the tieback into the liner. Therefore, not only the ID of the seal assembly, but also the eccentricity between the liner and tieback, had to be taken into account. For those reasons, 4.875 in. was determined as the seal assembly ID. With those factors decided, optimizing the wall thickness of both the tieback sleeve and the tieback stem was accomplished.

Once determined, calculations using NACE specification sour service carbon steel material (80,000 psi minimum yield strength, 22 Rc maximum) yielded unacceptable results for burst resistance.¹ To obtain acceptable burst resistance, it was necessary to increase yield strength to 125,000 psi. NACE specifications do not allow for the use of low-alloy material in this yield strength at temperatures below 225° F. Static bottom hole temperature (176° F.) at Waterton was well below that threshold.

Because the tieback receptacle on the liner top packer was considered a critical component for pressure containment in the drilling phase, it was necessary to use a proprietary nickel-chromium-molybdenum alloy in 125,000-psi minimum yield strength (mys).

Because of the considerable expense of the material, the minimum acceptable length extension of 6 ft was chosen. Based on Shell's risk analysis, the tieback extension and seal assembly on the stub liner were not deemed critical components, so in the interest of cost control, 125,000 psi mys low-alloy 41XX series steel was deemed acceptable for those components.

With the tight clearances between the liner/hanger system and the casing/open hole, there was a significant probability that the liner might become stuck once in the open hole section because of the sizing of the system or differential sticking at the low-pressure zones. Therefore, this scenario had to be considered.

The use of an hydraulic-set hanger was not considered because of the tight clearances and burst requirements. Traditional mechanical-set liner hangers require that the hanger be raised then rotated to unjay the setting cage. In the event that a liner becomes stuck, it is often impossible to overpull the liner enough to unjay the assembly.

The liner hanger chosen for the reentry was a new generation mechanical-set hanger with a unique releasing feature that allowed the hanger to be actuated by rotation alone, thereby increasing the chances of a successful set should the liner become stuck (Fig. 7 [114195 bytes]). With this new hanger, upward motion is not required to release the hanger. Instead, right-hand rotation releases a collet mechanism that allows the hanger to be actuated when the liner is lowered. The landing collar, float equipment, and wiper plugs were all conventional.

The stub liner was not of sufficient length to require a liner hanger; therefore, it consisted of a liner setting sleeve with 6-ft extension, dimensionally matching the tieback on the initial liner, an orifice float collar, and tieback seal assembly.

This assembly would be lowered in the well on a rotational release liner setting tool on drill pipe. Cementing would be achieved by the balanced plug method as had been used on the initial liner, thereby isolating the Sheet III formations behind steel and cement and allowing deepening to continue.

Liner operations

To run the liner it was necessary to kill the well, which was accomplished conventionally with water. Because of the necessity of achieving a successful cement isolation at the bottom of the primary liner, it was deemed critical to displace, and keep, the maximum possible amount of cement in the casing below the landing collar and around the outside of the liner.

With this in mind, the lower end of the liner string included a double-valve float shoe and float collar along with a conventional liner landing collar to catch and retain the liner cementing plugs (Fig. 8 [90991 bytes]).

At the top of the liner-running assembly, a premium cementing packoff provided a pressure-tight seal between the liner and the running string. The Molyglass packoff was deployed at the bottom of the liner running tool and sealed in the honed body of the liner hanger. This ensured that all fluids pumped in the well would go through both the workstring and liner and exit out the shoe as desired.

The entire liner running tool/hanger assembly had been preassembled and pressure tested prior to being shipped to the well site. The liner was made up and tripped in the well conventionally.

As the liner shoe reached the perforated section of the 7-in. casing, tripping operations were suspended, and a meeting was held to ensure that all further operations were completed successfully and safely. Prior to recommencing running operations, water was pumped into the well to prevent packoff and ensure that the well would take fluid.

Immediately after the liner reached total depth, it was raised off bottom and hung in tension according to plan. The liner running tool was then released and the liner top packer set. The cementing program called for a 410-ft high water preflush to be placed on top of a 312-ft column of cement in the annulus. It also allowed for the entire four-joint shoe track to be filled with cement with an additional 69 ft of cement on top of the cementing plugs. The balance of the pumping program consisted of 14.2 bbl (or 610 ft) of water inside the liner to displace the cement and latch the cementing plugs (Fig. 9 [13880 bytes]).

Careful planning resulted in the liner being run in the hole and cemented without incident.

Stub liner

Under normal operating conditions, a tandem mill run is recommended to clean out the liner top prior to running a seal assembly. Because there was no cement on top of the liner in Waterton 14 and no operations had been conducted inside the liner, this step was deemed unnecessary and omitted.

While waiting on cement to harden, a wire line was run to determine the water level in the liner. The results indicated that the cementing procedure had indeed gone per plan, that all production was isolated, and that the well was dead. After these findings were confirmed, a sufficient quantity of water was pumped down the drill pipe to fill the inside of the primary liner, and the workstring was pulled conventionally. The well could not be filled at this point, however, because of pressure limitations of the liner top packer.

When the liner running tool was removed from the well, it was inspected and redressed in preparation for running the stub liner. The liner tieback seal assembly was made up to the bottom of the stub liner casing, followed by the four-joint shoe track. An orifice collar was placed at the top of the four shoe joints to allow the cementing plugs to bump after displacement.

An additional 11 joints of 51/2-in. casing were added to the string, and the liner setting sleeve/extension and redressed liner running tool were placed at the top of the stub liner (Fig. 10 [86776 bytes]). This assembly was then lowered in the hole conventionally. Once at the top of the liner, the seal assembly was lowered into the tieback extension, and 45,000-lb weight was applied to the locator.

Traditional tieback operations dictate pressure testing the seal assembly. Again, because of pressure limitations of the packer, this testing was not possible. Therefore, the seal assembly was simply picked up out of the tieback extension, and cement was pumped into the dry workstring. Because of the critical nature of the cement isolation at the liner top, cement volumes pumped totaled 250% excess, bringing the top of cement well past the top of the liner.

After the plugs were dropped from surface, cement was displaced with water to create a 100-psi positive differential across the plugs. Once the free fall of fluid stopped and the plugs bumped against the orifice collar, the seal assembly was lowered back into the tieback extension.

A conventional landing collar was not used for bumping the plugs. In the event one had been used, when the cementing plugs latched into place, a check would have been introduced into the liner. At that point, it would have been impossible for the tieback seal assembly to be lowered into the tieback extension past the first set of seals, because of the noncompressibility of the fluid in the liner top. Conversely, with the use of an orifice collar, after the plugs bumped and the seal assembly was lowered into the tieback extension, the plugs were forced back up the casing as the fluid was displaced.

The entire stub liner weight plus 5,000 lb of workstring weight was placed on top of the stub liner, and the setting tool was released with right-hand rotation and pulled from the well. Operations were suspended while the cement cured.

After the setting time had expired, the hole was slowly filled with water and monitored for losses. Once filled, the hole was tested with 145 psi surface pressure for 1 hr to establish well bore integrity.

This completed the liner running operations and successful isolation of the Sheet III productive intervals. The workover rig was removed from location, and the drilling rig was moved on. Ultimately, the Waterton 14 well was deepened to the target depth of 18,000 ft, and the deeper Sheet IV and V intervals were evaluated (Fig. 11 [19995 bytes]).

Second well deepened

Subsequent to the Waterton 14 project, a second well in the Waterton field, Carbondale 06-12-06-3W5M, was deepened to evaluate the lower Sheet IV and V formations. For this project, the above methodology was further refined to include an open hole liner and tieback, with a second stub tieback.

Although actual operations were somewhat different, the overall objectives and results were very similar, further proving the techniques.

Results

• All five absolute design criteria were met. All liner equipment had sufficient ID to permit drilling a 43/4-in. open hole and had sufficient burst resistance to enable the hole to be deepened. All fit into the 7-in. casing, were set at total depth, and were cemented to isolate the Sheet III.

• Both liners were run and cemented according to plan, with no problems. The liner top cement integrity proved adequate for purpose, proving the two stage/balanced plug meth od.

• While not accepted as standard tolerance criteria, the actual radial clearances successfully used on 51/2-in. liners in Waterton 14 should be used as a guideline to identify a new upper boundary for liner/casing running tolerances.

• There are many advantages of a 4.750-in. open hole instead of a 3.875-in. open hole for this type of well (that is, very deep, long, slim, deviated open hole section with medium-to-high torque and drag). For example, the 43/4-in. open hole allowed a larger completion (31/2-in. monobore) with corresponding higher deliverability, larger drillstring design, and lower pumping pressures. This well could not have been deepened to the planned depth of 18,000 ft had the hole size been restricted to 3.875 in.

• Successfully placing the 51/2-in. liner was critical to the project.

• After a thorough cost analysis, the higher cost of the corrosion-resistant alloy (CRA) liner equipment was not an overriding issue. However, there may well be applications where the higher cost may outweigh the benefits of the larger hole size. These issues must be considered case-by-case. Risk analysis and regulatory specifications should be applied in deciding on the application of NACE specifications, particularly for high-cost, high-strength CRA materials.

• Similar methodology can be used to identify potential issues and solutions for isolating fractured/depleted formations. While this liner technology is one method of achieving these ends, it may not be the only way to overcome these types of solutions.

• When casing strings that are fixed on both ends and unsupported in the middle are subjected to increased internal pressure loads subsequent to being cemented, the risk of buckling must be considered. Commercially available computer programs allow these forces to be identified and quantified.

Acknowledgment

The authors thank Shell Canada Ltd., Baker Hughes Inc., and Import Tool Corp. Ltd. for permission to publish this article.

Reference

1. American Petroleum Institute Bulletin 5C3, Bulletin on Formulas and Calculations for Casing, Tubing, Drill Pipe, and Line Pipe Properties, sixth edition, October 1994.

Based on a paper presented at the 28th annual Offshore Technology Conference, Houston, May 6-9.

Copyright 1996 Oil & Gas Journal. All Rights Reserved.