HPHT research heats up

BP’s Project 20K among industry initiatives to push technologies beyond 20,000 psi, 400°F

By Katie Mazerov, contributing editor

What will production in subsea, ultra-deepwater fields look like in 10 years? That’s the multi-billion-dollar question as industry attempts to chart a course for those high stakes-arenas. But as operators continue to move into deep resource-rich regions, they know that today’s technological advances won’t be enough to sustain long-term production in fields where ever-rising pressures and temperatures characterize virtually every reservoir.

That realization has spawned a push from both inside and outside the industry to revitalize research and development that are taking the long view in developing tools and technologies and standardizing equipment design and methods for pressures and temperatures well above 15,000 psi and 300°F. The efforts are aimed at not just providing solutions for today’s needs but to meet the anticipated challenges for the next decade and beyond.

High-pressure, high-temperature (HPHT) conditions are pervasive in deepwater environments and impact virtually every aspect of the production process, from drilling risers to sensors to safety control valves to blowout preventer (BOP) control systems. HPHT conditions have been a reality in shallow-water regions such as the Gulf of Mexico (GOM) shelf for years. In deeper areas, where high pressures and temperatures don’t often exist simultaneously, pressure is driving innovation.

However, high temperatures also pose significant obstacles, and many believe a futuristic approach is critical.

“Historically in the oil and gas industry, it has taken upwards of 25 years to develop new technologies,” said James Pappas, vice president of the Ultra-Deepwater Program for the Research Partnership to Secure Energy for America (RPSEA). “There has been a pervasive attitude that we can live off just-in-time technology and not push the envelope until it’s absolutely necessary. But with high oil prices and a more active public demeanor towards the industry, we are looking in our crystal ball in two-year, five-year and 10-year time frames to determine what will be necessary to improve the business in a safe and environmentally friendly manner.”

Sharing that philosophy are a number of major operators eyeing ultra-deepwater regions, like the GOM, to meet global energy demand.

In February, BP launched Project 20K, an effort aimed at developing technology and equipment that will enable the industry to drill, complete, produce, intervene and contain deepwater reservoirs with 20,000 psi and 350°F at the mudline, explained Kevin J. Kennelley, vice president of technology for BP’s Global Projects Organization.

“Today, we have equipment rated up to 15,000 psi for deepwater service, so this is the next evolution,” he said. “Because this effort is new, it provides an opportunity to take the lessons we’ve learned and incorporate them into developing technologies for the future. We believe these technologies will be developed and used before the end of the decade, and we foresee them helping to meet the world’s increasing demand for energy.”

Project 20K has four key focus areas: well design and completion; rig, riser and BOP equipment; subsea production systems; and well intervention and containment. Although BP is leading the effort, the company will work with manufacturers and service companies, with other operating companies when practical, and with regulatory agencies to achieve project goals. “A comprehensive suite of applicable codes for 20,000-psi equipment in deepwater will also need to be developed,” Mr Kennelley noted.

The project is targeting three global offshore regions for the initial application of these technologies: the GOM, Azerbaijan and Egypt. With a team of 60 experts, Project 20K has just completed a concept appraisal phase and is entering an 18-month period where requirements and equipment specifications will be identified.

“This is one of the biggest technological challenges to hit the industry in the last decade,” Mr Kennelley said. “We have discovered deepwater fields that require this equipment. Until we get this technology developed, the reserves in these fields cannot be produced.”

Identifying gaps

Another operator-driven technology development project, DeepStar, managed by Chevron, provides a forum and funding for advancing deepwater technologies required to successfully tackle future development and production challenges, explained DeepStar director Dr Greg Kusinski.

Launched 21 years ago and now in the 11th phase of research projects, DeepStarXI is supported and funded by 11 major operators – Anadarko, BP, ConocoPhillips, Maersk Oil,  Marathon Oil, Nexum, Petrobras, Statoil, TOTAL and Woodside, in addition to Chevron. A contributor tier of membership includes manufacturing, engineering-design and service companies that participate on technical committees addressing a variety of areas, including drilling and completions, intervention, reservoir management, geosciences, flow assurance, metocean and subsea processing.

“Our projects are geared to early stages of technological development, or immature technologies that we expect to see commercialized five years down the road, as well as to identification and assessment of technology gaps,” Dr Kusinski said. Among 26 other projects, DeepStar is funding a project focused on developing high-pressure 4-in. flow lines for the ultra-deepwater that would have applications for intervention, service lines and jumpers.

Industry looks to standards to drive HPHT to next level

By Katie Mazerov, contributing editor

Tackling the challenges of high pressures and temperatures in ultra-deep subsea environments involves more than advancing new technologies. A critical aspect of that process is developing uniform standards in design methods for equipment to take the industry to the next level – 25,000-psi working pressure. Now that operators are stretching beyond where the standards have been traditionally based, an effort is under way to align American Petroleum Institute (API) design methods with American Society of Mechanical Engineers (ASME) methods.

“Standardization is what drives consistency across the industry,” said Chris Kocurek, subsea tree production manager for Cameron, a global provider of pressure control, processing, flow control and compression, and aftermarket services. “For the subsea oilfield, high pressure is a factor for driving change,” he said.

Mr Kocurek and others from Cameron presented a paper, “Merging ASME and API Design Methods for Subsea Equipment Up to 25,000 PSI Working Pressure,” at the 2012 OTC. “The problem from an industry standpoint is that operators have to select completion systems, wellheads, trees, blowout preventers (BOP) and high-integrity pressure protection (HIPP) systems. When an operator buys a piece of 20,000-psi equipment, they need to know they can bolt the next piece of 20,000-psi equipment on top.”

Work in progress

Historically, API and ASME codes have been aligned. Now that the bar has been raised for conditions above 15,000-psi working pressures and 350°F, the two agencies are no longer in sync – but they are close. In particular, they differ in the material, hydrostatic test and nondestructive examination requirements. ASME, which must compete with European pressure vessel codes, has been more progressive in pushing advanced design methods while API has maintained a more conservative stance, he explained.

A key technical difference in the design of pressure vessels has emerged with ASME’s allowance of a plastic collapse limit (e.g., burst pressures) with a large safety factor, rather than the traditional yield stress threshold, Mr Kocurek said. “If we design around plastic collapse, we also have to design and manufacture equipment around fatigue and/or fracture mechanics, meaning we need much tighter control on the materials and a higher level of data accuracy. This requires a higher level of documentation. Both design methods are valid and will deliver the same objective, if the same procedures are followed.” API also has documented that the ASME Boiler and Pressure Vessel Codes (BPVC) be utilized to design pressure vessels for pressures above 15,000 psi but not with current ASME BPVC codes, Mr Kocurek noted.

API has formed several committees aimed at bringing together specialists from all aspects of the business – downhole tools, tubulars, BOPs, risers, subsea and surface production equipment and topsides – to agree on ways the industry should handle operations above 15,000 psi. That effort is the first step in the huge process to align critical design codes.

“As we approach HPHT conditions above 15,000 psi, where there currently are no standards,” he said, “we have to ensure we maintain consistency in standardization and give both the industry and the general public the confidence that we can manage this process.”

Part of challenge is simply keeping tracking of what is essentially a moving target – the various emerging definitions of HPHT. Currently, conditions below 15,000 psi and 350°F are generally considered simply HPHT. Anything 15,000-20,000 psi and 350-400°F is defined as extreme HPHT, and conditions above 20,000 psi and 400°F are being referred to as ultra-HPHT.

“The bar keeps rising,” Dr Kusinski said. “The pressures and temperatures that are challenges today will be different tomorrow.”

The consortium has found that it often takes a multidisciplinary team of subject matter experts’ time and work to identify gaps and needs, said project manager Jim Chitwood, who has been with DeepStar since the beginning. Several years ago, Mr Chitwood was involved in an extreme-HPHT deepwater gas field technology gap assessment project called Diablo, in the eastern GOM.

“Although the Diablo project was focused on deepwater HPHT, the hardware developed was actually applied with jackups in shallow water,” he explained. “Today, as we get into deepwater and ultra-deepwater, there are qualified designs for marine BOP stacks for 20,000 psi, but the highest rating deployed to date is 15,000 psi. We get into the marine class-BOP systems once we get beyond jackup water depths.”

One of the weaknesses that the Diablo project identified was a lack of critical pressure, volume and temperature (PVT) data for simulation and modeling. That led to an US Department of Energy (DOE) study now being conducted under the auspices of the National Energy Technology Laboratory to identify the PVT properties of high-pressure fluids, going up to 40,000 psi on qualification.

“Without that base data, it is difficult to simulate production and flow through the reservoir,” Mr Chitwood noted. “We’re looking at opportunities operators will be going after in five to 10 years, identifying what the technology gaps and needs are and working to find appropriate solutions.”

DeepStar contributing members build and sell deepwater-applicable technologies. DeepStar’s role is to identify and define operators’ technology needs, build technology-specific roadmaps and provide enabling funds at critical milestones to help ensure timely and integrated development of technologies, explained project manager Art Schroeder. “Operators also want an appropriate level of standardization and interchangeability of equipment – for example, an autonomous-underwater-vehicle (AUV) that will properly interface with BOP, subsea processing and other complex underwater systems. They are also looking for reliability, repeatability, accuracy and affordability.”

DeepStar also has a regulatory committee that provides connectivity between the developers and providers of technology to the regulatory agencies, such as the US Bureau of Safety and Environmental Enforcement (BSEE) and the US Coast Guard. “This is important, because once technologies are matured, they can be more readily adopted and deployed if regulatory concerns have been previously addressed as part of an overall stage-gated process,” Mr Schroeder added.

Incentives for Innovation

Established as a nonprofit corporation by the DOE in 2002, RPSEA provides financial incentives for experts from within and outside industry to develop technology, with funding coming from federal royalties. The corporation has established working groups that bring together industry representatives and academics, all contributing their expertise on a volunteer basis.

RPSEA’s Ultra-Deepwater Program was launched in 2007 to look at current and anticipated challenges from various perspectives. The program is sponsoring a variety of HPHT projects in various phases, from well testing to drilling to completions, all with a safety component to address challenges in waters greater than 5,000 ft and specific to the GOM.

“The deeper the reservoir, the more likely HPHT conditions will be present,” Mr Pappas continued. “This is exacerbated when the rock contains salt, because as salt expands over geologic time, it compresses the rock around it, which adds to the pressure and can actually push up some of the deeper reservoirs – that had higher temperatures to start with – closer to the surface. These reservoirs tend to be larger but more expensive and riskier to produce.”

Among the solutions RPSEA is examining are novel well testing methods for ultra-deep fields (both HPHT and not), and a subsurface downhole safety control valve for 30,000 psi – much higher than what the industry is currently seeing but something anticipated in eight to 10 years – and for 350°F, which are toward the higher end of what is expected in the GOM, Mr Pappas explained.

On the drilling side, the agency has looked to the aerospace industry to come up with a proposed design for a 20,000-psi drilling riser that uses less metal and is wrapped with a lightweight carbon fiber that reduces the riser’s weight by 40% to 50% for use in water up to 15,000 ft deep. In conjunction with that project, RPSEA has enabled the development of a proposed connector design that, once approved by the DOE, will be proposed to BSEE for offshore testing.

A coiled-tubing (CT) drilling and intervention system to address high-pressure conditions in deep subsea wells is also on the table, with the intervention application to be field-tested initially. “Extreme high-pressure wells require a lot of horsepower and very large equipment to re-enter if done conventionally,” Mr Pappas noted. “CT has been used successfully for many years onshore for clean-outs, to move equipment and open and close valves, especially in deviated wells, and there should be no reason we can’t do this offshore. The solution will require specialized risers to handle the water segment. We’ve developed the process from a hypothetical 60,000-ft and a 30,000-ft aerial level; now we need to design the specific equipment and test it in the field.”

On the production side, RPSEA is looking at high-pressure flexible pipe instead of steel centenary risers, for facilities. “Flexible pipe is already being used for shallower and lower-pressure, lower-temperature situations but has not been constructed and tested for 10,000 to 15,000 psi or for temperatures over 250°F,” Mr Pappas said.

The entity is also funding a study to determine a mechanism for predicting steel and related alloy corrosion in reservoirs with 25,000 psi and 400°F.

Sensors and control systems

In 2008, RPSEA awarded a contract to an engineering consulting firm for Improvements to Deepwater Subsea Measurements. One objective of the project was to develop an advanced design of a combination pressure-differential pressure (P-DP) sensor cell for use in multiphase subsea flow meters for HPHT operations. Developed for temperatures of at least 500°F and a minimum of 15,000 psi, the sensor cell has been tested to 22,500 psi.

In addition to increasing the environmental operating range of the subsea flow meters, the tiny silicon sensor chips (P and DP) provide a warning in case of an emergency, such as sudden injection of gas. Conventional subsea multiphase and wet gas flow meters are limited to measure production fluids at a maximum temperature of 257°F and operating pressures of 10,000 psi.

The multiphase flow meter was initially developed to measure flow for offshore operators commingling their production through a central pipeline, said Dr Jim Hall, co-founder and CEO of the Letton-Hall Group. “The producers need to know which company puts how much oil and gas into the pipeline. Sometimes, the total measured by the subsea flow meters doesn’t equal what comes out at the end, and that can result in a multimillion-dollar problem.” But operators have also encountered another problem: As wells get deeper, HPHT production occurs.

The P-DP sensor will improve measurement for both the fair share issue and well management in HPHT wells by more accurately measuring how much is flowing, as well as what is flowing – oil, gas or water. “The unit will fit into existing multiphase flow meters but allow them to operate at higher pressures and temperatures,” Dr Hall explained. “In the next RPSEA project, we’re taking the initial technology and repackaging it into a smaller size. The sensor cell must be small enough to go into a device that can be lowered through production tubing and located at a particular location in the well where an operator can know what is happening in real time, instead of waiting for something to happen at the surface.”

This will be the first DP cell for downhole HPHT applications, he added. The new development program for this sensor cell will be 2 ½ to 3 years in duration.

Advances in the critical blowout preventer (BOP) control system have become priorities for both the industry and for BSEE, which is expected to mandate additional regulations. Previous documents out of the US Department of the Interior have discussed the need for multiple blind shear rams and the inclusion of casing shear rams. This could have a significant impact on the design of the emergency control systems, said Earl Shanks, chief technologist for Oceaneering Intervention Engineering (OIE). The company’s BOP Controls Group is developing a 7,500-psi differential pressure subsea control system, an upgrade to the conventional 5,000-psi system, to supply fluid and functions to operate the new-generation 20,000 psi-and-higher BOPs. The 144-function multiplex (MUX) electro-hydraulic control system uses both surface and subsea equipment to control the BOP stack

“The key feature of the upgraded design is the regulator, which accommodates 7,500 psi of control fluid, providing a way to store more fluid with fewer accumulator bottles (of either nitrogen or helium) on both the lower BOP stack and the lower marine riser package while still supplying the control system with 5,000 psi,” Mr Shanks explained. The lower BOP stack is where the accumulators are located for the shear rams and other emergency systems. Once optional, the deadman autoshear is now mandated by BSEE. For those systems, the stored volume requirements cannot easily be carried out for 5,000 psi stored fluid in the lower stack accumulators for the requirements of higher shearing pressures and greater volumes.

“It takes more pressure to overcome higher bore pressures,” Mr Shanks explained. However, as water depths increase, the hydrostatic pressure provides a slight balancing effect, so less pressure is needed to close the rams.

“If an operator or drilling contractor wants flexibility, he almost has to have 7,500-psi differential pressure with a 20,000-psi BOP to be able to cut anything other than drill pipe,” he continued. “Most deepwater wells have a long intermediate string that is very thick (10 ¾ or 14 in.) to contain the pressure, and they take a lot of pressure to be cut.” That function typically necessitates the use of a casing shear.

The new system will have enough functions to support the deepwater drillships with seven-ram BOPs that many contractors are now ordering. “Operators want to know more about what is going on in real time,” Mr Shanks noted. “They want to know the emergency accumulator pressures and whether the valves are firing, and they want to see positive read-backs.”

Gauging with precision

Among far-reaching technologies already available is the Schlumberger Signature quartz gauges, a line of memory gauges used in exploration and appraisal well testing that can withstand temperatures up to 410°F and 30,000 psi.  The portfolio includes three designs. The first is a standard pressure and temperature quartz gauge. The second is a high-pressure but standard temperature gauge with capabilities up to 30,000 psi, developed to address GOM challenges related to high pressure but not necessarily high temperature. The third design is a high-pressure and high-temperature gauge.

“When we talk about HPHT, there are obviously several categories that define the term. It’s also appropriate to make the distinction between HP and HT because they rarely occur together, the GOM Shelf being one exception,” said Paul Sims, testing services product champion for the Signature quartz gauges.

“High temperatures are most common with conventionally pressured gas or geothermal wells, while high pressure is found in oil wells at conventional temperatures,” he said. “We’re now seeing wells up to and exceeding 500°F and 30,000 psi, so we’re focused on developing tools to service those conditions. As the industry steps out into deeper waters and higher-pressured reservoirs, we will be ready to move further with this technology,” he said.

Among the technical challenges that come with wells of this nature are measurement quality and materials, including seals, metals and fluids. But the primary challenges related to the development of the Signature quartz gauges have been electronics and power, Mr Sims explained. “When we talk about high-temperature conditions, the equation of time is critical to reservoir evaluation,” he said. “How long can the tool survive downhole, and how reliably can we predict it?

Key to the development of the gauge has been the ceramic multichip module (MCM), which marks a switch from plastic components, specifically metal chips encapsulated in plastic that can corrode under high temperatures.

Within in the ceramic MCM chip is an application-specific integrated circuit that condenses the functionality of many electronic components into a single chip. “In this way, we’ve reduced the number of components and electrical connections, which elevates the reliability of the tools,” Mr Sims noted. “The circuits themselves are designed for pressure measurement, and they operate consuming very little power, reducing the contribution to self-heating of the downhole tools, which is a significant electronics-related challenge.”

Schlumberger also has a technology center dedicated to developing power sources, such as batteries, for downhole tools. “A battery capable of operating at 410°F is critical to the performance of electronics in terms of their overall success or failure,” Mr Sims said.

In a high-temperature gas well offshore India, the Signature quartz gauge provided continuous high-temperature pressure measurements during a 15-day exploration test, he continued. In this case, the water depth was not critical, but the reservoir depth exceeded 16,000 ft. “Because the gauges could withstand the very high temperatures, which peaked at 418°F, they could be placed closer to the reservoir and were able to deliver accurate, conclusive data to help the client establish the commercial viability of the reservoir.”

Testing the limits

Halliburton has opened a High-Temperature Gas Testing Facility at its Technology Center in Carrollton, Texas, to address high-energy testing being driven by market demands for high-pressure reservoirs with gas exposure. The facility will test capability for completion equipment to 40,000 psi and temperature ranges from 35°F to 700°F.

Operators also want documentation that HPHT tools are reliable and personnel experienced to eliminate nonproductive time (NPT), particularly on the new dynamically positioned (DP) rigs, where spread rates are approaching $1.5 million/day, said Vince Zeller, global product manager for Halliburton’s testing & subsea business line.

“We have an operator in Malaysia who is drilling and will perform a drill stem test (DST) on a well expected to reach 480°F bottomhole temperatures with 15,000-psi reservoir temperature,” he said. “We are qualifying tools for this well to 500°F for 15 days at 15,000 psi. We also have operators in the GOM who need ultra-high pressure capable tools, with reservoir pressures reaching 30,000 psi but temperatures below 300°F.”

For ultra-pressure GOM fields, Halliburton has tested equipment for 4,000 hrs (167 days) to demonstrate the functional capabilities of the DST tools, he added. “Operators are looking at fracturing through the subsea safety tree and the DST tools without pulling the BHA during the frac job, again to reduce rig time and costs.”

While much of the innovation is on the pressure side, temperature is often considered the most challenging of aspect of HPHT development. “Higher-yield metallurgies allow completion equipment to be built to withstand high-pressure containment; however, developing seals and elements that can withstand and remain contained at high temperatures in these high-differential pressure applications is a significant challenge,” said Ian Penman, global advisor for  Halliburton’s completion tools business line.

HPHT By the Numbers

•     HPHT: Between 10,000 and 15,000 psi and below 350°F.

•     Extreme HPHT: 15,000 to 20,000 psi and 350°F to 400°F.

•     Ultra-HPHT: Above 20,000 psi and 400°F.

“Completion equipment developed for HPHT applications to current American Petroleum Institute and International Organization for Standardization standards still must be verification-tested by third-party institutions. Investment in new facilities to build, test and qualify equipment has to be made to move at the pace of the industry.”

For drilling applications, Halliburton’s Sperry Drilling Services has a line of measurement-while-drilling (MWD) and logging-while-drilling (LWD) sensors for providing reservoir measurement and evaluation when drilling in harsh environments with pressures up to 25,000 psi and temperatures near or above 400°F. The ExtremeHT-200 Triple Combo LWD service includes optional resistivity, azimuthal density and neutron porosity sensors for providing accurate formation evaluation in conditions up to 392°F. The ExtremeHT-200 and UltraHT-230 sensors provide directional data and steering capabilities with the option of wireline-quality formation evaluation measurements and real-time drilling optimization for extreme- and ultra-HPHT reservoirs.

The RockStrong coring system, featuring a swivel assembly that can sustain high stress and vibration levels, was designed to deliver high-quality core samples in extreme wellbore environments, with no pressure and temperature limits, said Cathy Mann, director of strategic marketing for Halliburton’s drill bits & services division.

“The system was built to overcome the ultra-deepwater coring issues and high-vibration levels associated with very hard and abrasive rock and tight, multi-layer formations.”

The system includes a spacer assembly in the top section, which acts as a spring to absorb axial vibrations that can damage or cause a fracture in the core. Fractured rock or rubble can jam in the inner tube and interfere with coring the target formation, an expensive process to reverse.

The technology has been deployed globally, including a North Sea HPHT well where it was used to cut 501 ft of core in four runs with 98% recovery, according to Halliburton.

Project 20K is a trademarked term of BP. DeepStar is a registered trademark. ExtremeHT-200 Triple Combo LWD Service, ExtremeHT-200 and UltraHT-230 are trademarked terms of Halliburton’s Sperry Drilling business line; RockStrong is a trademarked term of Halliburton.

Click here to read a sidebar article on new wireline pressure-control equipment breaking barriers in an HPHT well and to see an exclusive video demonstrating National Oilwell Varco (NOV) ASEP Elmar’s NOLA wireline pressure control equipment.