Getting HPHT right is a real challenge for today’s industry, involving finding new materials, setting new standards and building competence in the industry. Elaine Maslin reports.
Ian Penman, senior global technical advisor, Halliburton. Photos from Offshore Energy Exhibition & Conference.
“Never underestimate a high-pressure, high-temperature well (HPHT) well.” That’s the advice of Bert Campfens, who, with 34 years’ experience at Shell as senior drilling engineer has some authority on the matter.
“Most of the time they [HPHT wells] move towards the ultra side, not to the other, and there is a lot more to it,” he warns, not least in the competency of staff.
HPHT is a growing business in the offshore industry and it is getting hotter and into higher pressures. Generally, the standard definition for HPHT is around 10,000psi and 300°C. But, the envelope is increasingly being pushed.
Ian Penman, senior global technical advisor, Halliburton, told a session on HPHT at the Offshore Energy conference in Amsterdam in October: “Now it is fairly easy to attain downhole equipment that attains [10,000psi and 300°F]. We are moving into the more extreme 15,000psi and 360°F area,” he says.
Campfens agrees. “10,000psi pressure and 350°F reservoir temperature is the current definition of HPHT. Today, [we are looking at] 20,000psi and close to 500°F and I think the industry has to start thinking.” Both Campfens and Penman were speaking at a session on HPHT at Offshore Energy in Amsterdam.
Going into these types of play, without enough knowledge and expertise, can be a risky business, Campfens says, who was chairing the session. In work with Shell off Africa, “What could go wrong, did go wrong,” he said. “We were fire-fighting all the time.”
He said a proper survey wasn’t done on local conditions, and the reservoir wasn’t tested deeper than 10,000ft, which meant when the team got to 20,000ft, the reservoir temperature was found to be higher than normal, resulting in equipment issues. “We worked on the limits of casing and well design,” he says.
Key, is making sure the organization has the competence to carry out such wells, Campfens says. “We didn’t have staff who had any experience in HPHT. All but one became very nervous when things happened,” he says.
Henk Kramer, senior wells engineer, Nederlandse Aardolie Maatschappij (NAM).
Indeed, the industry is doing some serious thinking about HPHT as the bar literally gets raised. “We are building qualified equipment to 15,000psi and 350°C, as we speak,” Penman says. Penman is also involved in API Committee 19, which is drawing up a raft of new HPHT downhole completion standards for the Gulf of Mexico, which will likely spread beyond the US.
The API Committee 19 is looking at everything from elastomers to metals, testing for longevity for ultra-HPHT (uHPHT), in equipment including packers, subsurface safety valves, flow control nipples, plugs, etc., seal assemblies, latches, and liner hangers, Penman says. Some have already been published, others are close to being published and work is starting in other areas to complete a suite of new standards.
However, with more stringent standards, in most cases, the result will be longer testing cycles, Penman warned. “Before, typically between contract award and when had to put equipment on the ground was about one year, and that was quite difficult to do that. With this new API implications you are looking at doubling that. There is a whole lot more involvement going in to a HPHT situation.”
Despite the extra time it will add, Campfens sees the API committee’s work as progress. ”For me, I see a huge step forward. There were no standards, how to get equipment, before. We are moving on.”
A material challenge
Materials selection for HPHT well construction is still a major challenge, however. Henk Kramer, senior wells engineer, Nederlandse Aardolie Maatschappij (NAM), in the Netherlands, outlined a minefield of often conflicting requirements for materials selection in HPHT at Offshore Energy.
“In principle you want to make the production casing as light and thin as possible. In that case, you do not need such a big rig and the annular clearance is bigger so that the flow dynamics are optimized. Also in terms of geometry you are restricted by the size of the BOP at the top and the size of the perforation guns you need inside the last liner at the bottom.
“In HPHT wells you need higher resistance to pressure. But, we cannot really change the OD too much because of the limits of the BOP, flow dynamics and other physical limitations.
“Same for the wall thickness, if you increase it too much the bit for the next hole section does not fit anymore. That leaves the yield strength as the most obvious to increase if the pressure rating needs to be higher.
“Then the H2S becomes an issue. Statistically all HPHT wells will produce H2S at some point in time. But that is not necessary always a problem. The issue is partial pressure H2S. Meaning the: pH2S = Total bottom hole pressure x fraction of H2S present. So, if a HPHT field develops H2S due to temperature at a later point in the wells life, the bottom hole pressure has gone down and you might be OK (or not).
“Chloride is also an issue, mainly in relation to temperature. Chlorides in combination with high temperature affect alloys, which is an issue for the production tubing, the tubing hanger and the casing hanger. And then what makes it really difficult is the combination of H2S and high pressure.
“The problem is, finding materials with sufficient strengths suitable to accommodate all of these requirements can be difficult as these can be in conflict,” he says.
Setting the grade
Some issues can be overcome by moving to proprietary steel grades from specific manufacturers for higher temperature uses, which can handle some H2S, if the pH is high enough. But, defining the parameters in the drilling phase, when you are yet to define the pH, is difficult. In this case, a ‘worst case’ is often assumed, which is typically a value around pH 3.5.
Strengthening the pipe, without increasing the yield strength too much, usually results in increasing its thickness, which then introduces manufacturing issues as it becomes more difficult to have homogenous properties through the metal during quenching, Kramer says. “So we are getting to a limit where it is increasingly difficult to make metals with the right properties,” Kramer says. “We have come a long way in HPHT wells but we still make steel the same way. We are getting to the edge of what we can do at current steel mills.”
Pipe connections also have to be as strong as the pipe. Usually, seal face imperfections are sealed with an API modified dope, which is a mixture of oil with zinc, lead, and copper elements in it. The lead particles especially help to smooth out the imperfections, but importantly, it is stable at high temperatures. But, rather than conflicts in material specifications or manufacturing capability, this time regulations, in the Netherlands, and it is expected in the UK, are set to phase out use of lead offshore due to environmental concerns and rightly so, Kramer says. There has been a lot of work done to create a green dope, replacing lead with Teflon flakes and other alternatives, but they are limited by temperature.
Gaining confidence in the connections also has to be built. Historically, every company had its own standards for testing connections, Kramer says. “Only in 2002, the industry came up with standard procedure for testing connections,” he says.
But since then, pressures and temperatures have increased and more confidence is needed in the connections.
An ISO standard for CAL IV testing has become more prescriptive and is pushing the connections very close to the edge of what is possible, and for HPHT requirements sometimes over the limit, which is a concern and often results in custom designed connections for a particular HPHT well, Kramer says.
Overall, “it’s getting more and more extreme what we need” to work in uHPHT environments, Kramer says.