Martin Bethke
Conoco Inc.
Lafayette, La.
Bob Moe
Oil Technology Services Inc.
Houston
Steve Morey
Amoco Production Co.
Houston
Brian Schwind
Mobil Exploration & Producing U.S. Inc.
Dallas
Improvements in integral joint connections (IJC) for casing in the past decade have allowed operators to drill wells previously not feasible to drill for economic or technology reasons.
New integral joint connections can withstand greater loads, increasing their range of applications. The use of IJC casing can allow a slimmer well to be drilled, reducing total well costs.
Fig. 1 illustrates two deep well programs (for Latin America and the Gulf of Mexico) currently used by a major operator. Both of these well designs require multiple casing strings. With conventional coupled connections, both designs would require extremely large diameter surface boreholes to accommodate all of the required casing strings to reach total depth (TD) with a 7-in. hole.
IJC casing was run in the wells in Fig. 1, allowing the use of much smaller structural, conductor, and surface pipe and reducing drilling time and costs.
Fig. 2 shows two sample well plans used by another major operator for deepwater (5,000 ft) Gulf of Mexico wells. The design goal is to reach TD with a 7/8-in. cased hole. The primary design limitation is the outer diameter (OD) clearance through the wellhead equipment.
The programs use IJC extensively and have proven successful both economically and technically.
INTEGRAL JOINT CONNECTIONS
The term integral joint refers to a connection that does not use a coupling as a joining member; both mating parts of the connection are machined directly on the pipe. Integral connections have one of the following configurations:
- Hot-forged upset ends, with ODs typically 5-7% larger than the pipe OD
- Cold-formed (swaged) ends, with ODs typically 23% larger than the pipe OD
- Flush connections, with the connection OD equal to the pipe OD.
Hot-forged upset ends are the strongest connections; however, the technology required to upset the ends and subsequently heat treat the entire tube is expensive. Furthermore, this method offers little significant value in improved connection attributes compared to the less costly, coupled styles of connections.
Today, the most commonly used integral joint casing connections are cold-formed and flush OD. These connections have historically been used for their clearance attributes as a drilling finer or tieback string in contingency or emergency situations.
PHYSICAL TESTING
The performance properties of the integral joint connectors have significantly improved. A decade ago, tensile efficiency ratings (the ratio of amount of axial force causing connection failure to that causing pipe body failure) were in the 50-60% range for flush OD connections and 60-70% for swaged connections. Furthermore, many of these ratings were calculated values and not substantiated by physical testing.
Today, ratings of greater than 60% for flush OD and greater than 70% for swaged connections are not uncommon. Internal pressure ratings have also improved. More importantly, these ratings are generally substantiated by extensive testing programs.
Much of the improvement has resulted from connection design changes and enhancements prompted by a Drilling Engineering Association (DEA) joint-industry testing program, DEA-27. This program used a standardized test procedure designed to determine the performance limit of a connection under different combinations of loads. Each load combination simulated an actual downhole condition (Fig. 3).
The DEA-27 program was sponsored originally by Arco Oil & Gas, Exxon Co. USA, Amoco Production Co., Atlas Bradford Co., Baker-Hughes Tubular Services, Hydril Co., Seal-Tech, and VAM Premium Threading Services. Stress Engineering Services conducted the physical testing.1 DEA-27 has been the single most important factor driving improvements in performance attributes and operator confidence in this class of casing connection.
COMPUTER TECHNOLOGY
Improvements in other disciplines, particularly in personal computer (PC) technology, have enabled connection design changes yielding performance improvements. Computer programs which perform powerful analytical, computational, and graphic functions are now affordable and available on PC hardware platforms.
Engineers can use computer-aided drafting to speed and facilitate mechanical design. They can analyze designs by finite element analysis programs and other numerical techniques not practical without computer assistance. Computer analysis reduces physical testing required to confirm or repudiate a design, saving both time and money.
Stress data from strain gauge measurements during physical testing, gathered with a computer-driven system, and the subsequent computer-aided data reduction and analysis of these measurements give engineers immediate confirmation of design models.
These improved development tools have helped produce features such as reverse-angle load flanks (hooked) threads, trapped torque shoulders, multiple and variable lead threads, improved seal configurations, and maximized critical section areas. Perhaps most importantly, computer-aided manufacturing systems, computer numerically controlled machine tools, and statistical process control systems enable manufacturers to translate those improved designs into reliably reproduced products at reasonable cost.
These improvements in integral joint technology have occurred in sizes historically used as drilling liners (5-9 5/8 in.) as well as in larger OD casing (11 3/4 in., 13 3/8 in., 16 in., and greater). Casing strings with modern IJC now have the capability to be run to 60-70% the same depths as coupled connections, and most casing applications do not require full pipe-body axial load capacity.
DEEP WELLS
The most immediate and obvious impact of IJC technology improvements is in the application to larger OD casing. Deep wells, onshore or offshore, often require extremely large conductor and surface casing to have sufficient internal diameter (ID) for multiple, intermediate casing strings. By using integral flush or near-flush connections on structural, conductor, and surface casing, operators can start with 36-in. or 42-in. boreholes instead of 48-in. or 60-in. boreholes.
Continued use of IJC in the intermediate casing (16 in. to 9 5/8-in.) enables the operator to set multiple intermediate strings, to maintain the option of contingency strings, and still to set a 7-in. or 7 5/8-in. production liner.
The operator can tie back this liner or others as required to produce the well safely. The two well plans in Fig. 1 use this strategy. In both cases, the operator sets five casing strings below the 20-in. surface casing, reaching TD with 7 5/8 in. casing, and in one case, maintains the option of a contingency liner.
DEEPWATER WELLS
Deepwater wells (water depths of 5,000 ft) present several unique challenges:
- The effect of the fluid column is magnified by 5,000 ft of seawater, which increases burst requirements at both the wellhead and the casing shoe.
- In many areas (the Gulf of Mexico for example), pore pressure gradients and formation fracture gradients are relatively close, making six or seven casing strings necessary to reach TD.
- Commercially available risers limit the subsea wellhead size to 18 3/4 in. or 16 3/4 in.
Increased burst pressure requirements are a consideration but do not limit designs in water depths up to 5,000 ft. Increasing the weight or the grade of pipe will compensate. H2S service requirements will limit the grade, and water depths exceeding 5,000 ft will exacerbate the burst pressure requirement.
Currently, however, the requirement for multiple casing strings caused by the pore and fracture gradient characteristics coupled with the wellhead limitations poses the major challenge.
The preferred riser is a 21-in. OD system with an 18 5/8 in. wellhead. This configuration will accommodate a 16-in. protective casing string below the 20-in. surface casing using a weld-on buttress connector. The use of IJC below on 13 3/8 in., 11 3/4 in., 9 5/8 in., and 7 5/8 in. completes the casing.
If the available riser is an 18 5/8-in. system, then a 16 3/4-in. wellhead is used and will accommodate only 13 3/8-in. standard pipe size. The use of 13 3/8 in. casing as the first protective string would limit either the number of strings or the size of the production casing.
The alternative, shown in Fig. 2, is to use a special size tubular with an integral joint, flush-type connection. IJC on large and intermediate diameter casing makes these wells possible to be drilled safely and economically.
DRILLING COSTS
Drilling costs are proportional to the excavated hole volume, a function of the square of hole diameter. Engineers can reduce drilling costs throughout the entire drilling program by using integral joint connections to minimize hole size throughout the well.
Fig. 4 compares two casing programs which could be used for a high flow rate gas well completed with 5 1/2-in. tubing.
The first well used conventional threaded and coupled geometry, and the second used an alternative design with integral joint connections.
The IJC alternative required the removal of one-third the volume (36,000 cu ft) less than the conventional well. This design used 1,541 metric tons less steel as casing.
With a relatively conservative estimate of $700/metric ton for average casing delivered to the rig site, the IJC design resulted in a casing cost savings of $1.078 million . 2 The reduction in excavation volume would also reduce other drilling costs (time, bits, mud, cement, etc.).
These savings explain the attraction of slimmer well plans.
If an operator is purchasing casing from distributor stock for immediate delivery, integral joints often cost less than premium threaded-and-coupled connections (that is, connections with metal pressure seals and positive torque shoulders). This cost is a function of less steel (coupling stock not required), fewer threads, less processing, and less inspection.
Although not always true with large orders directly from integrated steel mills an operator can often realize a direct savings by purchasing integral joint connections rather than threaded-and-coupled ones.
An indirect cost savings can result from reduced inventory requirements. Most drilling operations require contingency strings to be available. The full string capability of modern integral joint connections increases their flexibility.
The ability to use integral joint casing as contingency liner, tie back, or full casing string allows an operator to reduce the casing tonnage in inventory.
DRAWBACKS
Operators could thus save considerable money by wider use of integral joint connections. Because the use of internal joint connections is not more widespread, there must be several valid drawbacks.
The original purpose of high-clearance connections as contingency liners must still be considered in overall well planning. If any contingency occurs, the drilling engineer may well want more annular space available in which to run a contingency liner. This space is the very annulus which must be reduced to save drilling costs.
The following are the two principal circumstances that historically required the use of high-clearance, integral joint connections:
- Not being able to run a casing string to bottom (because of obstructions in the borehole path)
- Not achieving a good cement job.
The inability to run a casing string to bottom, no matter what the cause, requires the operator to rework the hole and then set a drilling liner.
This situation is expensive and should be avoided if possible. If a casing string sticks during running, operators will try to work the pipe, that is, reciprocate or rotate it past tight spots and force it down to the planned setting depth. Working the pipe may also involve the use of jars, tools which apply axial shock loads to the casing string to work it downhole.
These operations require the pipe and connection to withstand forces greater than those normally encountered.
Existing integral joint connections do not have tensile, compressive, or torsion capacities equivalent to coupled connections. The reduced tensile ratings of existing IJC limit their overpull capacity. The reduced compression ratings of existing IJC prohibit jarring down on them.
The lower torsion capacities make rotating dangerous.
Therefore, if a casing string sticks during running, the operator has fewer options to free the pipe and complete the casing job.
Cementing operations are more difficult in boreholes with reduced annular clearances because the cement does not flow as easily in the smaller annular cavity. Cementing operations can be enhanced by working pipe during cementing, either by reciprocation or rotation, to better distribute the cement throughout the annulus. As noted, integral joints limit the engineer's ability to work the pipe, reducing the effectiveness of cementing.
Thus, the characteristics of integral joint connections which make them attractive with the promise of cost savings also limit their operational usefulness.
Additionally, some operators resist using integral joint connections because of poor past experience. Human tendency is to repeat what has proven successful in the past, particularly when dealing with potentially dangerous, expensive, and highly visible operations.
Past failures attributed to integral, flush-type connections discourage subsequent use of them even though technological improvements may have eliminated or greatly reduced the probability of problem recurrence.
Additionally, there is a high cost to test prove connections to demonstrate improvements and application suitability.
OUTLOOK
Future development of integral joint technology to expand its application will require the manufacturers of these products to address field problems and substantiate improvements with further testing and computer modeling (finite element analysis).
Specific areas to consider include the following:
- Improved compression and torsion capacity
- Shock resistance (jarring in both tension and compression)
- External pressure capability
- Bending (particularly important in extended reach applications)
- Shear loading (formation shifts which cause shear loading)
- Effect of bit wear (particularly on cold formed pins)
- Cyclic loading (fatigue resistance).
The DEA-27 program has added a second strain gauge/combined load cycle at elevated temperature and a sixth sample to test external pressure and compression capacity.
More work is needed, however.
REFERENCES
1. Payne, M.L., Asbill, W.T., Davis, H.L., and Pattillo, P.D., "Joint Industry Qualification Test Program for High-Clearance Casing Connections," Paper 21908, presented at the Society of Petroleum Engineers/International Association of Drilling Contractors Annual Drilling Conference, Mar. 11-14, 1991, Amsterdam.
2. Klementich, E.F., Morey, S.C., Payne, M.L., Asbill, W.T., Banker, E.O., and Bouche, J.K., "Development and Acceptance Testing of a Flush Joint Casing Connection with Improved Performance Properties," Paper 26320, presented at the SPE Annual Technical Conference and Exhibition, Oct. 3-6, 1993, Houston.
Copyright 1994 Oil & Gas Journal. All Rights Reserved.
Issue date: 11/07/94
