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RPO shows how industry plans Reasonably prudent operator standard, widely used in industry, denied for Point Thomson Kristen Nelson Petroleum News
Chevron, one of the Point Thomson working interest unit owners, provided an expert witness to talk about the reasonably prudent operator standard at the Point Thomson remand hearing the week of March 3.
Alaska Superior Court Judge Sharon Gleason ruled late last year that adopting the appellants’ (Exxon Mobil Corp., BP Exploration (Alaska) Inc., Chevron U.S.A. Inc. and ConocoPhillips Alaska Inc.) argument that the Point Thomson unit agreement mandates the reasonably prudent operator standard “would run counter to the regulatory and statutory provisions that were in effect at the time of the contract’s creation.”
“The applicable effective regulation at the time of contracting in 1977 required a determination by the State ‘that the agreement is necessary or advisable in the public interest … and adequately protects all parties in interest including Alaska,” Gleason said.
The testimony, however, provided insight into how industry develops projects — and how a consultant evaluates those developments.
An outside evaluation Richard Strickland, P.E., president of The Strickland Group, a petroleum consulting firm, has a Ph.D. in petroleum engineering and has been consulting since the mid-1970s; fulltime since he left a position teaching petroleum engineering at Texas A&M in 1982. Among his clients, he is currently consulting for the State of Alaska, he said, on corrosion issues at Prudhoe Bay.
Strickland told Commissioner of Natural Resources Tom Irwin and Hearing Officer Nan Thompson he has consulted for major oil companies, independent oil companies, lessors, lessees, state governments and national governments for 30 years. He developed an early independent numerical model and used it to troubleshoot for companies.
In the process, he said, he learned that reservoir performance is more than just what happens down in the reservoir — it also involves decisions by the operator: “how he plans to develop; what kind of data he collects; how he tests his wells; how he drills his wells”; as well as the economic situation when decisions are made and the political and regulatory environment.
Over the last 15 years, Strickland said, “I’m really called upon to try to create the mosaic of not only the reservoir issues but also all these overlying factors, including … how the decisions are made … (and) the environment in which those decisions are made.” That work, he said, helps stakeholders “understand what happened or how to go forward or, in many cases, how to hold their partners accountable for their actions.”
The state’s alternatives
Strickland said he thinks the state has alternatives to terminating the Point Thomson unit — the issue was remanded to DNR to allow the Point Thomson working interest owners to suggest alternatives to termination.
He said the state could accept the 23rd plan of development; or if the state doesn’t like the 23rd POD it could propose changes or propose its own POD.
People have said that if the unit were terminated it would take 10 years to get to where the present owners are, but Strickland said he thinks it would take longer than that, perhaps 15 years. Once you resolve clear-title issues, and the acreage is leased, then the lessees have to negotiate and create a new unit, he said.
Then you have to shoot new seismic, because even if one of the present Point Thomson lease owners were part of a new ownership group, seismic is proprietary and “has very specific agreements about what it can and can’t be used for. I would be astounded if this seismic were not shot under proprietary conditions and proprietary agreements,” he said. Even if one party had rights, he said in his experience those rights are always limited.
Then new exploration wells would have to be drilled and new data gathered: “They have to repeat the entire process,” he said.
And, subject to changes in technology over those 15 years, Strickland said he didn’t think a new operator would have a POD vastly superior to the 23rd POD: “If it’s basically the same set of data then you’re going to have the same thing,” he said.
RPO standard Strickland said there isn’t a textbook definition of reasonably prudent operator. Based on his experience working on RPO standards, he said the reasonably prudent operator “should try to maximize the recovery; he should use prudent technical procedures and sound economic principles.” But technology changes: “I don’t think it’s correct that he could use one principle and 20 years later be still using that when technology has advanced. You continue to work the problem using prudent technical procedures.”
The goal is maximizing recovery using prudent technology and sound economics, but in the context of the circumstances — including rules in place and the contract.
“That’s the mosaic that I’ve used to describe the situation that the operator is in when he makes his decision.” A range of results are available to the operator and “the standard is of average prudence.”
Strickland said the operator’s decision doesn’t have to be perfect. “It has to be reasonable in light of the circumstances.”
The RPO also “requires taking into account the interests of all the stakeholders,” he said, including, in this case, the State of Alaska.
Analyzing RPO In analyzing whether an operator meets a reasonably prudent operator standard, Strickland said there are three steps.
The first is whether the operator was prudent in his analysis of relevant information; was the work performed in a prudent fashion? Or did the operator overlook something massive that’s going to result in waste.
Based on that analysis, did he formulate a prudent plan of development?
And last, in looking at the POD from a larger perspective, from the interest of all parties, “would carrying out the POD be prudent?”
Risk and uncertainty play into the decision-making process, he said, and offered a brief tutorial on project design to illustrate.
Data accumulation is the first step — in the case of Point Thomson drilling and logging of the exploratory well at the field, the core that was taken from some of those wells, fluid samples and eight 3-D seismic surveys. Then there’s data reduction, he said: all of those 3-D seismic surveys are combined into one usable unified package; databases are built of the core data, the well data and the fluid data; and the logs are digitized. Then that data is analyzed: The seismic data is interpreted, for example.
Then all of the data is synthesized: A geologic model is built. “A huge amount of science goes into building that geological model and it’s come so far over the last 20 years,” Strickland said: It’s a long ways from three wells, a base map and a pencil.
Then reservoir models are built: The geological input is put into simulation models so that cases can be run, looking at different possibilities.
Based on those results, decisions are made about the project.
Uncertainty exists because factors like porosity aren’t known across the field: “It could be higher or it could be lower and that’s the concept of uncertainty — higher or lower,” he said.
And uncertainty leads to risk and the need to protect against the possible downside on a project.
Uncertainties for Point Thomson In analyzing the Point Thomson proposed POD Strickland said you look at uncertainties: there are geology and geophysics uncertainties such as “uncertainties as to thickness of the oil rim.”
On the reservoir engineering side there are uncertainties such as fluid analysis and fluid properties.
How are these concerns handled? Strickland said Exxon, the Point Thomson field operator, has applied advanced techniques to account for uncertainty in their analysis, using output from nine different geological models and more than a dozen numerical simulation models. Results are put through a regression analysis.
Strickland said the uncertainty and risk analysis Exxon did “is far beyond the reasonably prudent operator standard — the middle of that road, the average prudence. This is the very best … and has far exceeded the RPO standard,” he said.
Objectives of POD There were four objectives in the POD.
The first was initiation of production in a timely manner.
“The plans do that,” he said, with drilling beginning in the winter of 2008-09. There are five wells in the plan with a $400 million budget. The first two wells are for production and injection.
The plan meets the second objection of delineating the Thomson reservoir.
The third objective is to manage development risk.
Strickland noted there had been questions at the hearing about putting the initial injector and producer four miles apart, a greater than normal distance. It is unusual, “but I think it’s a great idea and a bold step,” he said.
“It is an excellent way to test communication across a long distance and this is necessary to bring the field into full production and full development.” Strickland said placing the wells that far apart “investigates the compartment issue. It’s not until you start pushing stuff through the reservoir that you really find out about compartments. And you can quickly figure out if you’re on the low side of the equation and if you are, then have the time to try to fix that through the wells.”
The fourth objective was to facilitate future development and Strickland said this plan accomplishes that through expandable infrastructure.
Would RPO implement the plan? Strickland said a reasonably prudent operator would implement the plan.
In spite of excellent planning, unexpected things will happen in the execution of a $1.3 billion project. “And it requires the flexibility of a plan to recover from that unexpected result.”
He said that as he understands the state’s petroleum tax system, “this phased approach holds down development costs and is a benefit to the state.” Given the level of uncertainties, “I don’t think it would be prudent for an operator to dive into a full-field development.”
With full-field development you have to build all of the facilities at the same time.
Just on the issue of compression you’d be risking that compression rates in the design are going to work well in the field and if you start with full-field development you’re buying a lot of equipment with the concept untested.
A risk on the down-hole side is whether the reservoir will deliver needed rates from individual wells.
At the high pressure rates at Point Thomson, some of the technology is going to be cutting edge, he said, “and you can’t dive into full-field development” without learning the technology.
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