Ultra-HPHT conditions will be the next challenge

To assess the challenges in this arena, this article covers well completion issues and components. Table 1 shows well conditions for several typical HPHT wells. The time-to-acquire and degree of difficulty for each type of equipment have been estimated and are formatted by color, according to the key shown in Table 2.

Table 3 summarizes the gaps and expected lead times to develop equipment for shelf HPHT wells.

Casing materials, connections

Tieback casing design and sour service material qualification is the critical path issue for ultra-HPHT completions. Several authors covered this topic extensively in SPE’s May 2005 HPHT applied technology workshop. Issues include the need for qualifying high-strength carbon steels for the expected pressures, temperatures, and environment; and designing and testing appropriate connections.

Nickel-based corrosion-resistant alloys (CRAs) may be a solution but have never been made in the sizes required.

The tieback weight may be beyond capacity of most rigs. The tieback may have to be run in sections.

What casing test pressure is required on initial completion-shut-in tubing pressure? This requires that BOPs be rated to SITP, or operators would need to test the casing with the tree installed.

• Connections. During qualification of connections, should external gas testing be performed? During completion operations, connections will be exposed to large differential pressures with lightweight completion fluids.

If multiple productive zones are encountered, connections may be exposed to large differentials with lightweight packer fluids. Are heavy weight completion fluids the answer or do they just bring other problems? Are there appropriate facilities for external gas testing? A potential benefit of dual seal connections is that they keep the external pressure off the pin nose seal.

• Tieback systems and liner hangers. Current tieback systems and liner hanger packers are rated to maximum 20 ksi and 400° F.

Where temperature is concerned, the industry will need to build test fixtures rated higher than 500° F. In order to eliminate the use of elastomers, we will probably need metal-to-metal technology. Existing metal-to-metal technology, however, is not tested to 500° F. The metal properties may be altered and there are unknown issues related to expansion and contraction.

In terms of pressure, the tieback system needs to hold 30 ksi and not rely on cement. Such high pressure raises safety concerns and adequate test fixtures capable of 30 ksi need to be designed and built. Design and testing of the new tieback system and test facilities would take 12-18 months.

Cementing the tieback is critical to anchor the system to minimize movement.

• Cementing issues. Can we get good cement jobs?

The top of cement in a tieback may be critical to completion design and potentially limit the production rates. There may be isolation requirements and issues related to trapped annular pressure. There are also questions regarding the long-term stability of the cement and its ability to withstand multiple temperature and pressure cycles.

Tubing, connections

Nickel-based alloys have been used successfully in many HPHT applications. For ultra-HPHT wells, however, other concerns exist, including:

• Nickel-based alloys such as SM 2550, G50, and C276 will likely work but have not been tested above 450° F. Testing these alloys with constant-strain tests will require 6-10 months. Slow strain rate tests are shorter, but do they provide accurate results? Shell does not recommend this test for this application because it does not capture initiation effects, such as pitting, which is a concern with corrosion-resistant alloys (CRAs).

Have these alloys been tested in heavyweight brines at elevated temperatures (workover contingency)? How about pH effects? There are possible scale issues if the wells make water. Will the alloys stand up to remedial acids jobs to remove scale, etc. at these higher temperatures?

• Current lead-time for nickel-based alloys is 12-18 months. Both lead-time and costs are going up. Mills may not commit to orders until they test their product to confirm that it is suitable for these new environments; lead times may be longer for these extreme conditions.

• Titanium tubing is a possibility, but there could be issues with connections. There is no history of titanium tubing use in HPHT wells. Will acid compatibility be an issue?

• Tapered tubing strings may be required due to casing constraints, but there will be severe bending loads on smaller string sizes.

• Connection testing will be required for initial ultra-HPHT completions. Can sufficient amounts of material be obtained from the mills for connection tests prior to delivery of the order? If not, real tubing delivery time is the sum of the tubing delivery and test connection times. Standardization of sizes and connections would be a plus.

Packers

Although packers have been designed and tested for 15-ksi applications, sizes are limited. Only one packer has been designed for 20-ksi service.

Packers should be run with completion tubing and set either hydraulically or hydrostatically. This allows for a metal-to-metal backoff sub or metal-to-metal threaded connection to packer.

What pressure rating is required? Should it be equal to the bottomhole pressure or expected differential across packer plus a safety factor to account for kill operations, acidizing, etc.

Is the ISO V0 test procedure enough? Should we also test with cyclic loads?

Test facilities are currently limited to 460° F.. and 20 ksi. Significant additional investment is required for establishing facilities capable of testing at higher temperatures and pressures.

HPHT packers have a limited setting range. This may require honed or extremely tight casing tolerances to get differential rating.

Casing stress caused by packer and tubing could be critical if casing is unsupportive.

Milling CRA packers is extremely difficult; losing the well is a possibility.

What are the temperature limits of Inconel 718/725 (nickel-chromium superalloys containing niobium, molybdenum)? At high temperatures, Inconel 718 /725 becomes susceptible to corrosion and environmental cracking when exposed to certain agents. Aging may be an issue. Testing needs to include exposure to heavyweight brines or cesium formates. What is the temperature effect on strength of the Inconel superalloys?

SCSSVs

Again, limited work has been done on HPHT surface-controlled subsurface safety valves (SCSSVs) but not at ultra-HPHT conditions.

Limited sizes are available for 20 ksi applications.

With API 14A requirement of a test pressure of 1.5 times the working pressure, maximum pressure rating is 20 ksi and 400° F. due to verification test limits at Southwest Research Institute, San Antonio. The standard is currently under review to reduce test pressure to 5 ksi above working pressure for SCSSVs of 10 ksi and greater. The MMS has not approved this change for wells under its jurisdiction. Is more than one SCSSV needed?

Does the slam test requirement in API 14 A provide a sufficient test? Rate is low in regulations (for instance, 17.3 MMcfd for a 31⁄2-in. valve) but what should be done for prudent operations (absolute open flow-AOF, maximum expected rate, etc.)?

Slam testing is done at atmospheric conditions. Would a low rate, high-pressure slam test better simulate what would happen in a real emergency? Test facilities do not currently exist for this type of testing.

SCSSVs require high-strength (140 ksi) Inconel 718/725, which is very hard to obtain. Typically, high-strength pieces must be hand-selected.

ID and OD constraints are critical; OD needs to be minimized to fit in tie back strings and potentially BOP bores. ID needs to be maximized to allow for electric line operations, especially pipe recovery and perforating.

What are the temperature effects on control line fluids and dynamic seals? Degradation of control line fluid and dynamic seals over time needs to be evaluated. Will dynamic seals be reliable at pressures greater than 25 ksi and at high temperatures?

Will control line connections be reliable long-term at pressures greater than 25 ksi with thermal changes? How about the control line itself? Engineers would have to take into account the maximum control-line pressure required in tree design for pass-through and outlet valves.

There is an alternate valve design that may alleviate some of the issues of high-pressure control lines, but this design is currently not available in pressure ratings required and has not been field proven to date.

Wellhead, tree

HPHT wellheads, 20 ksi and some 30 ksi, have been built. Most of the 30-ksi equipment was designed for land wells. These wells were mostly low rate, less than 20 MMcfd. The expected high rates, high surface flowing temperatures (>350° F.) and high pressures of ultra-HPHT wells will create new issues.

Even though 20 ksi, 350° F. clad trees and wellheads are available, 6 months to 1 year lead-time is required to fill orders.

New design or qualification testing is required if temperatures are higher than 350º F. and pressures greater than 20 ksi for tubing spools, back pressure valves, stem packing, gate valves and seats, and chokes.

A major qualification hurdle will be stem packing at temperatures hotter than 350° F. and pressures greater than 20 ksi. It is difficult to pass qualification test, which requires temperature, cycles from 0° F. to maximum temperature.

Reduction in material strength will also have to be determined for temperatures higher than 350° F.

What is the long-term reliability of gates, seats, and hard surfacing?

A positive and adjustable choke in series will be required to handle pressure drops.

Perforating, electric line

Three options exist for perforating. TCP guns can be installed below the permanent production packer and then detonated after the tree is installed. The well can be perforated through tubing either with multiple wireline runs, or guns can be hung off and fired hydraulically.

TCP systems

Guns, carriers, and firing heads for tubing-conveyed perforating (TCP) systems are currently rated to about 24 ksi and 450° F., but HNS (Hexanitrostilbene explosive) gun systems are good for only 107 hr at this temperature.

But what if guns fail to fire? A contingency perforating plan will be required. Can guns be dropped off?

It is difficult to mill up CRA packers, and operators would be unlikely to be able to cut tubing to drop guns.

Quality assurance and quality control and testing of gun systems are critical to ensure performance.

If we drop the tubing string or if guns fall off while running in hole, will guns fire? Since it is likely completion fluid will not be kill weight, the risk is very high, even though the probability of occurrence is low.

Electric line perforating

It is difficult to obtain both pressure and temperature rating and high performance of through tubing perforating guns due to tubing and SCSSV restrictions.

Gamma-ray correlation tools and PIP tags will be required due to nickel-alloy production liners. The current rating is 25 ksi and 500° F. for 1 hr.

Lubricators, cables, plugs

There is limited availability of 20-ksi lubricators, and new 20-ksi equipment requires 6-month lead-time. Vendor safety standards, typically limit use to 80% of rated working pressure. The lead-time for developing 30-ksi equipment is even longer at 1-2 years.

Availability of MP35 N cables is also limited, with a long lead-time required for new cables. Cables are currently rated to 500° F.; minimal over pull available at depths greater than 22,000 ft.

Limited sizes of slick line plugs are available with ratings above 15 ksi and 400° F.

Tubing cutters

There are no cutters currently on the market that can reliably cut high-strength, thick-walled nickel alloy tubulars at ultra-HPHT conditions.

We cannot test cutters under well conditions due to test facility limitations. Tools are typically tested thermally first, then fired under pressure at ambient temperature.

Available test facilities include:

1. Navy gun: 30,000-psi working pressure (but ambient temperature only; does not have thermal capability).

2. HPHT chamber: 20,000-psi working pressure at 400° F.

Cutter types include radial cutting torches, jet cutters, and chemical cutters.

• Radial cutting torches are currently qualified to 500° F and 10 ksi. Successful cuts on nickel alloy tubulars have been made with 10-ksi rated tools.

Successful cuts can be achieved with smaller tool ODs of radial cutting torches than with other types of cutters. (i.e., 111⁄16-in. tool for 27⁄8-in.; 2-in. tool for 31⁄2-in.).

There have been instances, however, in which the tool or parts of the tool are lost in hole when used near the pressure rating. Performance has improved over the years.

There are radial cutters under development for pressures up to 15 ksi; some sizes are currently available. Plans are to develop 20-ksi tools in the future.

• Jet cutters can work at 400° F. for 1 hr with HMX (high melting explosive; octogen) at about 20 ksi. The industry can make jet cutters with higher temperature explosives but performance goes down.

The ID of safety valves limits the size of jet cutter that can be run. Tools near the ID of the tube are usually required for successful cuts.

• Chemical cutters are limited to 350° F. and 20 ksi with the same size limitations as jet cutters.

For HPHT applications, cutters have to be designed and tested based on actual temperatures and pressures and metallurgy of tubular goods. The need exists to test high-pressure cutters on nickel alloy tubing such as C276, 825, SM2250, etc.

Well control

Well control in the event of an infantile failure is a major gap in HPHT completion technology. The height and weight of BOPs, wellheads, choke manifolds, etc. will be larger than what is currently used and may require special handling equipment.

A limited number of 20-ksi BOP stacks and choke manifolds are available. Stacks have not been used in years and may need reconditioning. It will require 2 years to build new BOP stacks. No equipment is available for pressures greater than 20 ksi. Is it prudent to complete a well without having a BOP stack available that can handle maximum SITP?

Can the shear rams shear the heavy wall, high-strength tubulars that will be run?

Only a limited amount of 20 ksi well-kill equipment is available and there is nothing available for pressures greater than 20 ksi. Pumps, piping, chicksans, or flexible, high-pressure hoses would have to be developed; 1-2 year delivery lead-time. Is it prudent to complete a well without having equipment rated to the maximum SITP available in industry for an emergency kill?

There are assorted issues related to kill-weight completion fluids:

• Can heavy-weight brines be inhibited at these high temperatures? Corrosion inhibitors for ZnBr tend to degrade to H2S and zinc-sulfide scales. New fluids need to be tested with CRAs, elastomers, high-strength work strings, etc.

• Are cesium formates the answer?

• Oil-based mud will work, but there are issues. OBM can destabilize and the weighting agent will drop out over time, plugging the tubing and complicating future workovers.

Cleaning out the weighting agent with coiled tubing is difficult due to low pump rates. There is also potential for severe formation damage. Operators would be limited in their ability to clean up formation damage with stimulations due to the high pressures and temperatures.

The depth of potential relief wells is limited by the 350° F. temperature limit of magnetic proximity tools (used for detecting well string in a blowout). The deepest relief well to date is around 22,000 ft.

How do we want to configure the trees and wellheads for emergency kill operations? Topsides design and layout needs to address tree leaks, fires, and emergency-kill access.

Completion planning should include developing contingency kill plans and ensuring equipment availability prior to first production.

Remedial operations

Remedial operations are not normally planned as part of an initial completion. For ultra-HPHT wells, however, contingency planning will be required. Equipment gaps include:

• Snubbing units-maximum rated snubbing units are 20 ksi.

• Coiled tubing-maximum rating 15 ksi and 400° F.

• Work strings-heavy wall tiebacks and liners will limit work string sizes and torque ratings. May not be able to wash over tool joints due to limited clearances. High strength, S-135 work strings can be used in inhibited mud or completion brines before perforating (i.e., no H2S), but can heavyweight completion brines be inhibited sufficiently for use of S-135 for remedial operations?

Workstrings that are sour-gas compatible are in limited supply and may not have sufficient strength. A long lead-time is required for new strings.

• Connections-premium connections such as XTM40 or PH6 will be required. These connections are very susceptible to pitting on MTM seal face in heavyweight brines.

• Sand control-not likely any time soon. It is likely that formations will initially be competent. Remedial sand control may be possible after depletion but would have to be taken into consideration in initial completion. Small liners, CRA packers to mill up, temperatures, and poor cement jobs are all issues to be considered.

• Fracturing-not likely any time soon. There are issues with fluids, packer loads, surface pressures, etc. It may be possible to fracture stimulate after depletion, but it would have to be taken into consideration in initial completion.

Integration, production operations

Good communication between drilling, completion, facility, and production personnel is critical to ensure successful handoffs.

How many wells do you want on a platform? Should independent jackets be used if water is shallow enough?

Accurate modeling of wellhead growth is required for proper facility and flow line design. Shell has experienced growth below the mud line, especially if several wells clustered together. Consider whether casing growth will put unexpected loads on conductor casings.

The effect of trapped annular pressures due to trapped fluids between cement needs to be understood and managed:

• Annulus pressures can be reduced by putting in an N2 blanket. This reduces the need to bleed off annular fluid and reduces the risk of getting oxygen into the annulus during shutin. However, the N2 blanket reduces hydrostatic head, thus increasing external pressure differential on casing connections. Operations personnel need to have guidelines to maintain the desired backpressure on the annulus.

• Annulus pressures can be affected by thermal and communication with zones.

Mud degradation and thermal affects can cause microannuluses in cement. Shell has experienced this annulus pressure due to flow from tight noncommercial zones. Corrosion is a possibility.

• Must test casing hanger seals in both directions to prevent seal failure from outer to inner strings of casing.

The road ahead

New ultra-HPHT completions will tax our industry’s resources-people and infrastructure-to deliver safe completions in a timely fashion. We lack a strong industry focus on HPHT wells; many people who pioneered this effort are retiring and we’re at risk of losing industry knowledge if we don’t capture our past learnings. There is a stronger need than ever before to pool our efforts in preparing for the new HPHT future.

Acknowledgments

I thank the management of Shell Exploration and Producing Co. for the opportunity to publish this article. I also extend my appreciation for the input into this project by other Shell personnel and numerous equipment suppliers. ✦

Based on a presentation to SPE’s High Pressure/High Temperature Sour Well Design Applied Technology Workshop, The Woodlands, Tex., May 17-19, 2005.

The author

Ron Zeringue (ronald.zeringue @shell.com) is a staff completion engineer at Shell Exploration & Production Co. in New Orleans and primarily works on TLP and HPHT completions. Prior to joining Shell in 2000, he held production and completion engineering positions with Mobil in New Orleans and Houston. Zeringue holds a BS (1979) in chemical engineering from Louisiana State University and is a member of SPE.