Kirk Huber, Baker Oil Tools
The completion of high-pressure/high-temperature (HP/HT) wells involves high-risk and high-cost operations with exposure levels among the highest in the completion sector. Many challenges exist when drilling these new super wells and infinding the materials to complete and produce them. Most available lab equipment is suitable for testing HP/HT systems designed for pressures up to 15,000 psi (1,034 bar) and 400°F (204ºC). However, recent industry needs are demanding technologies and equipment qualification capabilities for much more extreme HP/HT conditions.
HP/HT terminology
To help identify HP/HT operating environments, safe operating envelopes, and technology gaps, a common terminology is presented. This terminology segments HP/HT operations into three tiers. Tier I or “HP/HT” refers to wells with reservoir pressures greater than 10,000 psi to 15,000 psi (689 bar to 1,034 bar), and with temperatures up to 350ºF (177ºC). Most HP/HT operations to date have taken place under Tier I conditions. Tier II are the “Extreme HP/HT” wells, which are characterized by reservoir pressures greater than 15,000 psi to 20,000 psi (1,379 bar), and with temperatures up to 400ºF (204ºC). Many upcoming HP/HT deepwater gas/oil wells, particularly in the Gulf of Mexico, fall into the Tier II category. Tier III encompasses “Ultra HP/HT” wells, with reservoir pressures greater than 20,000 psi to 30,000 psi (2,068 bar), and with temperatures up to 500ºF (260ºC). Tier III is the HP/HT segment with the most significant technology gaps. Several deep gas reservoirs in North America and the GoM shelf fall into this category. Also, some of the lower tertiary plays currently targeted by various operators in the GoM are approaching Ultra HP/HT pressures.
Completion equipment exists today that can meet either the pressure or temperature requirements for Ultra HP/HT Tier III. However, the combination of the higher temperatures and pressures will dictate the suitability of a given technology, tool, or kit.
Risks require unique approach
The risks and demanding performance requirements for HP/HT completions dictate special considerations and investments. Most completions are designed based on the casing and tubing programs selected for the well. For most Tier II and Tier III HP/HT completions, however, the completion design is identified first (such as the ODs/IDs of the SCSSV), which will dictate the casing and tubing design. Other considerations include a strategy to address the potentially damaging effects of HP/HT conditions on downhole components.
Most HP/HT projects to date have been Tier I, but industry growth areas (i.e., deepwater gas/oil and deepshelf gas) are in Tiers II and III.
High temperatures can cause:
- Significant pipe movement or high compression loads at the packer, particularly when the high temperatures are combined with high operating pressures
- Increased mechanical and fluid friction as well as depth increases and/or deviates from vertical
- Thermal cycling and resulting tubing stresses, requiring careful consideration of the use of tubing to packer connections (floating seals vs. static or no seals at all)
- Shorter elastomer performance life and derated yield strength of metals used in packers and seals.
High-pressure regimes require:
- Much thicker cross-sections in all tubulars and downhole equipment
- High-yield-strength materials to handle excessive burst and collapse pressures
- Corrosion-resistant alloys (CRAs) where needed to protect from wellbore fluids that can corrode high-yield steel.
Critical success factors
To ensure that completion equipment will perform safely and productively in specific HP/HT environments, it is important to:
- Accurately define a set of operational parameters and performance rating requirements for any new equipment
- Set approved design specifications “in stone” as soon as possible
- Ensure that engineering feasibility work is accurate so equipment can be delivered as designed<
- Ensure adequate testing facilities.
Completion engineering and well test design should begin during initial well planning. The overall completion philosophy will have significant impact on subsequent equipment selection. Detailed contingency planning is crucial for situations that require lead times for alternate equipment or services.
Project management
No process has proven to be more critical to successful HP/HT completions than quality assurance and quality control (QA/QC). Equally important, the success of the QA/QC process depends on extensive operator involvement and clear, ongoing, and accurate communication between the operator, the completion supplier, and project team members. Both the operator and service provider must establish a project management structure customized to meet the specific product challenges.
Extensive operator involvement in equipment design and manufacture is not typical for standard wells, but it is crucial to successful HP/HT completions. Operator involvement in equipment detail design reviews ensures that the operational requirements are addressed before the design is released for prototype manufacture. Similarly, the operator’s participation in identifying safety-critical elements and components is vital to subsequent processes of engineering, qualification testing, manufacturing, assembly, subassembly make-up, testing, and installation.
Information transfer
Safeguards and processes from earlier stages of the project are wasted if the HP/HT equipment is not deployed flawlessly at the well site. To ensure that knowledge and information are transferred and that the equipment is properly installed, the operator and completion supplier project management teams should continue their involvement through the drilling and completion phases.
Service center personnel and field service technicians should be members of the team that develops the completion procedure. Detailed knowledge of how the equipment was designed, tested and assembled can prevent installation mishaps. A complete run-through of the completion procedures and “stack-up” testing with the entire team of service technicians, rig personnel, and the operator team is essential.
Closing technology gaps
Deep gas plays and the search for hydrocarbons in deeper formations are drivers for the development of Tier III HP/HT cased-hole completion systems. At the same time, these systems must satisfy the need for reductions in risk, rig time, and cost. Meeting these needs depends upon closing technology gaps in three key areas: testing facilities, seals, and polymers and metallurgy.
A key factor in the success of HP/HT projects is the physical qualification and testing of the proposed equipment. The Baker Oil Tools Center for Technology and Innovation (CTI) in Houston, can recreate downhole HP/HT environments. Four of the eight test cells at CTI are 75-ft (22-m) towers for easy accommodation of 40-ft (12-m) joints of large OD casing, with testing capabilities up to 40,000 psi (2,758 bar) and 700ºF (371ºC). The industry will need to continue to invest in equipment and materials to generate the technologies, and to qualify the equipment for Ultra HP/HT Tier III conditions.
Issues to address
- The industry currently is developing, though perhaps not fast enough, polymers and seals that can withstand these Ultra HP/HT well conditions up to 30,000 psi (2,068 bar) and 500ºF (260ºC) while retaining mechanical properties, chemical performance, and well fluid compatibility. Reliability prediction and HS&E issues must be addressed, and further seal research must be conducted. In some cases, metal-to-metal seals may replace elastomers.
- Metallurgy, first and foremost, must be available. Sourcing metals such as nickel alloys, Hastelloy (C-276), and titanium will be a challenge. Careful planning must consider lead times and availability of metallurgies in the equipment’s overall procurement and manufacturing schedule. Additionally, heat-treated nickel alloys are not NACE-approved above 450ºF (232ºC), which may present regulatory challenges. Well fluid compatibility (sour vs. sweet service) is another key issue, as are temperature de-rating effects on minimum yield strength. A finite understanding of material properties is essential, especially for large cross-sections.
- Industry standards for all HP/HT tiers need to be established. For example, the current API 14A, Edition 11 standard for Surface-Controlled Subsurface Safety Valves (SCSSVs) requires that SCSSVs with a working pressure >10,000 psi (689 bar) be tested to 5,000 psi (345 bar) above working pressure, rather than the 1.5 times working pressure requirement of API 14A, Edition 10. However, the Minerals Management Service has not adopted Edition 11 and still requires operators to have their equipment tested to 1.5 times working pressure. Under Edition 10, a SCSSV needed for a working pressure of 20,000 psi (1,379 bar) had to be tested to 30,000 psi (2,068 bar), but under Edition 11 it would only have to be tested to 25,000 psi (1,724 bar). Manufacturers of SCSSVs are required to follow the latest edition (Edition 11) in order to receive the API monogram. Operators are thereby relegated to seek waivers from the Minerals Management Service to run a valve tested under the API 14A, Edition 11 standard, or to request additional testing.
With commitment from exploration and production operators and service providers, the industry will advance the technologies necessary to meet the world’s growing demand for energy. The HP/HT market will play a key role in this challenge.
