SPE Technical Directors Think Cooperatively: Working Outside the Lines

SPE’s technical directors are focused on problems that require working outside the bounds of their discipline.

Stubbornly low recovery rates from unconventional reservoirs led to a collaboration between the directors in drilling and reservoir engineering because cooperation is required to understand opportunities, find solutions, and apply what has been learned.

Fiber-optic cable’s potential to improve shale well performance led the production director to look for ways to increase the number of applications offering multiple benefits, which touches on a wide range of concerns over the life of a well.

Rapidly escalating project costs led the projects, facilities, and construction director to look outside the profession for ways to measure and manage project complexity. The goal is to recognize the time and money needed to integrate complex systems, and look for ways to manage those issues.

Overruns are also often linked to social concerns that never appear on a project’s list of technical risks. The director for health, safety, security, environment, and social responsibility wants the industry to think more about the broader impact of its projects, which can lead to opposition from affected communities.

Reaching all the above goals will depend on technically skilled people who see the big picture, which is why the director for management and information is emphasizing the need for engineers to broaden their perspective to better understand the business side of the equation, and profit from ever-more data and new approaches.

A seventh perspective has been added to the discussion: a director representing academia. The first person to hold the job, Dan Hill, the head of the department of engineering at Texas A&M University, has set out to understand the needs of universities globally.

The fact that directors representing reservoir interpretation and drilling and completions are collaborating on ways to improve recoveries from unconventional reservoirs says something about what is required to do that. David Curry, the Director for Drilling and Completions, and Olivier Houzé, the Director for Reservoir Description and Dynamics, say cooperative effort is essential for this project.

“Our two disciplines overlap,” Curry said. The combination of those who analyze what is in the ground and those who drill and complete the wells is needed to seek better ways to measure what is underground, model its behavior, and use those insights to reconsider how best to develop this poor-quality reservoir rock. And the collaboration will ultimately have to draw on the technical skills represented on the SPE board.

The potential reward for even relatively small gains of these enormous resources is immense, as is the room for improvement. “As far as we know, in most cases, they are producing 5% and if they are really lucky, 10% of the hydrocarbon in the shale reservoir,” said Curry. In comparison, the best conventional formations yield 50% or more of the oil in the ground.

Increasing unconventional recoveries is a hot topic for the SPE technical directors, who see it as a significant issue that deserves greater industrywide attention. It is not as if the issue has not been noticed by the industry, but the pair would like to push work efforts expanding the range of possible remedies.

The starting point for Curry and Houzé is asking questions: How do hydrocarbons move through rock to reach fractures? What is the geometry of the network of fractures? What tools can be found to test the geochemistry? Can carbon dioxide injections enhance recovery?

A favorite phrase of Houzé’s is the value of information. “Before changing things, we need to understand them,” he said. “In order to do that, we need to expose our doubts on what we know today.” A fundamental question for him is gaining a better understanding of how much oil can be drained in the area surrounding each well.

Drilling and reservoir are a marriage of necessity. Delivering more water and sand into a reservoir by adding more fracture stages to more wells clustered closer together has improved results. Getting beyond the current limits is likely to require something other than doing more of the same.

“The value of information has been something of an issue,” Houzé said. “What mattered was how much we were drilling and fracturing. Now we know we will not be able to escape the addition of information when considering how to improve our primary recovery ratio or do enhanced oil recovery.”

In this relationship, reservoir engineers need more data gathered by those doing the drilling and completions. And many of the ideas for adding recovery using better analysis will depend on precisely placing tightly spaced wells in the most productive spots. A better understanding is likely to require the development of better diagnostic tools, and winning the support of drillers, whose spending and operational decisions define what can be tried.

“Our formation evaluation techniques were developed primarily with clastic or carbonate reservoirs,” Curry said. “We do not know how to evaluate effectively what hydrocarbons are present in the structure of shale, much less what is mobile.” Better methods for characterizing rock properties before and during drilling are needed to ensure the most productive well position.

The ultimate economic test of those measures is what can extracted from the volumes of hydraulically fractured rock. Curry said that depends on “how effectively do we connect each element of the reservoir with the well?”

Wells should also be designed to facilitate refracturing, and possibly with casing designed to facilitate drilling added laterals off the wellbore later on.

One measure of the value of information is the spending choices made. Houzé tracks it with the question: If a limited amount of money is left in a budget for a well, would the engineer in charge spend it on adding a fracture stage or a downhole pressure/temperature gauge?

Houzé said that 3 years ago, an added stage would have been the choice, but now he sees greater interest in what can be learned using the downhole sensor as there is more evidence that it can be used to make decisions leading to better long-term production. “All of this information we are gathering today will help us to improve our recoveries. We need to do our homework,” he said.

Expanding production will also require contributions from production engineers using long-term well monitoring to improve reservoir stimulation methods and artificial lift systems.

Curry and Houzé also want to promote early work on enhanced oil recovery methods, such as using carbon dioxide injections to mobilize oil in areas beyond the fractures. And to gain a fundamental understanding of these ultratight formations. “I think we are going to find real value at the material science level about the interaction of hydrocarbons, water, and clay-rich rocks,” Curry said.

Answers provided by this search will need to offer near-term benefits. “With the price (of oil) coming back down, operations must be cost-effective now rather than 5 years from now,” Curry said.

And they are seeking long-term gains. “What is done today will affect our ability to get more hydrocarbons in the future,” Houzé said.

There are enough fiber-optic monitoring systems in unconventional wells to convince Shauna Noonan, the Technical Director for Production and Operations, that the technology is valuable, and has the potential for far wider use in unconventional fields.

In costly deepwater wells, fiber-optic cables have become a common feature with multiple applications, from monitoring pressure and temperatures along the wellbore to tracking production rates at different locations. In heavy oil production, they are able to stand up to extreme temperatures, providing valuable data on the distribution of steam heat.

In shale, fiber-optic use has been limited, but Noonan sees growing interest. “I am getting contacted by operators,” she said. “There is more focus on unconventional wells.”

They see fiber as a way to answer pressing questions, such as how fractures in closely spaced wells interact with each other. But making this a regular feature will require addressing practical concerns. Noonan said potential users need to see that it can be dependably installed at an affordable price, and there are available applications for managing and interpreting data that can be used without specially trained personnel.

Early adopters, such as Shell and ConocoPhillips, are finding fiber installations useful, she said. For example, temperature measures can be used to monitor fracturing in the well, as well as the impact of fracturing in a fiber-equipped well, and in wells nearby.

Temperature measures made by fiber-optic cable banded around the outside of the casing offers an accurate measure of the temperature, needed to predict the time needed for cement to set. The heat created by chemical reactions during curing can be used to observe if cement reaches the spaces it is supposed to.

Later in the life of a well, these installations can be used as a low-cost alternative to running production logs, allowing more frequent measurements.

The downside is that shale development requires drilling many wells and the cost of fiber, and its availability, represents a far larger percentage of the total cost than in deepwater production wells, which can cost about 20 times more to drill and complete. Improving the cost/benefit analysis will require more widely used applications over the life of the well, better ways to manage the prodigious amounts of data gathered, and more cooperative work to improve the interpretations offered.

“We need to start sharing information for reliability monitoring, data interpretation, and even data evaluation,” Noonan said. “It will become more interesting and relevant.” There are barriers to such collaboration, from negotiating legal agreements needed to protect intellectual property to concerns about revealing proprietary well data.

Creating the multiple applications needed to justify fiber investments in shale wells will require support from those doing drilling, completions, reservoir analysis, and production monitoring. It could provide the raw material for advanced analysis and provide direct observations of things such as the condition of the cement, which can lead to concerns regarding safety and the environment.

“It is one downhole monitoring tool that I have seen that brings in so many disciplines,” Noonan said. “One piece of fiber is bringing in valuable information from drilling until late in a well’s life.”

The fact that big projects often finish late and over budget is not news. But it becomes a more pressing issue when oil prices drop as they have.

Commonly, the point of attack is negotiating discounts on hardware and services when demand is slack. Howard Duhon, the Technical Director for Projects, Facilities, and Construction, has been thinking about ways to prevent the overruns with a better understanding of how projects are designed, cost estimated, and executed.

His starting point was seeking input from members on SPE Connect. One question that drew a lot of comment was: Is cost an emergent property of projects? First, Duhon had to answer questions about what is an emergent property, which is a term from systems theory describing something that cannot be quantified by adding up the sum of its parts.

The idea can be applied to estimating the cost of complex projects, such as offshore platforms or liquefied natural gas plants, where complex components must be integrated into a working whole. “The point is we estimate costs by separating a project into a bunch of systems, set the cost for each system, and then add those together. But in complex projects, it probably doesn’t work that way,” Duhon said.

Connecting components often reveals unanticipated differences that prevent systems from working together, as well as interference among subcontractors working within tight spaces and timelines. It all adds time and expense. As a result, he said, “It might not be valid to add it all up.”

It is not hard for those in the field to acknowledge the problems caused by complexity and cite examples of it from past projects. But measuring the degree of complexity and using that calculation to pinpoint where it could lead to trouble are questions to be answered. Greater standardization using proven systems could reduce the risk by using interconnected components that are known to work together.

Complexity can also be a negative caused by the nature of the design teams, whose evolution mirrors the intricacy of the facilities they are creating. Coordination is an issue when there are “too many subject matter experts on too many different teams spread out all over the world,” Duhon said. A changing cast of key players, which has become more common as experts hop from job to job, adds to the difficulty.

When the issue of surging costs was raised, it sparked a discussion among the technical directors when they met at the 2014 SPE Annual Technical Conference and Exhibition in Amsterdam.

Duhon is also looking for approaches developed outside the oil business in industries that have faced similar problems. “A lot can be learned from other industries that have confronted the same problems,” he said.

Oil and gas companies are making long-term investments around the world in costly, technically complicated projects where unanticipated community concerns can significantly reduce the return on investment.

Trey Shaffer’s goal as Technical Director for Health, Safety, Security, the Environment, and Social Responsibility is to convince technical decision makers with a deep understanding of their project that success can depend on something outside the realm of design specifications and their professional skills—public acceptability.

“Many project delays are due to non-technical issues,” Shaffer said. There is not a simple formula to anticipate and avoid these issues during the planning stage, but the new technical director has ideas on how to better prepare the industry to

• Deal with issues beyond regulatory requirements.
• Recognize issues outside the workplace or outside the normal bounds of exploration and production (E&P) that will require attention.
• Understand that what works changes from place to place.

For example, this June, SPE will hold its first Health and Social Responsibility Forum in Miami, which will explore the role of the oil and gas industry in community health. It will feature experts from outside the industry in health, technology, and academia.
Shaffer said it is important to seek a wide range of viewpoints because the issues are not defined by a company’s property lines.

These issues range from the impact of noise and emissions associated with high-volume unconventional development in the US, to dealing with the health problems created when an oil company stations people in remote places with few medical professionals, whether in south Texas or Africa.

Both can have a profound impact on the business. One can lead to fights over drilling bans. The other can mean lost time for workers out sick or caring for their loved ones. Both point to the local nature of issues in this realm. “This is not a generic issue,” he said. “It is very specific to projects and regions.”

To help prepare industry professionals to deal with these issues, beginning at the 2015 SPE E&P Health, Safety, Security, and Environmental Conference–Americas in Denver in March, a sustainability training program will be offered for the first time.

Shaffer wants engineers outside of his discipline to be thinking about these issues. “Sustainability needs to be integrated into the way operations leaders think about their projects,” Shaffer said.

J.C. Cunha wants to broaden how engineers see their jobs. The Technical Director for Management and Information has had a long career in drilling and completions, but sandwiched in the middle of it was a 5-year stint as a professor at the University of Alberta in Canada. That led to a few more years in operations management and his current job as the drilling and completions technical training leader at Chevron.

To explain his thinking, Cunha told a story about his time at the university when he was asked to create a course for graduate students. Rather than putting together one in his specialty, deepwater drilling, he covered petroleum economics and risk analysis.

The goal was to offer “a much broader view of our industry” to students who already knew a lot about engineering, but far less about financially analyzing and executing projects, Cunha said, adding, “Why not give them something more close to our business? Why not give them some tools that will help them manage a project?”

Based on the area covered by management and information, it is a large set of tools. While it sounds like information technology, which is within the discipline, the area includes information systems, research and development, energy economics, strategic planning, risk management, and decision making.

And there is also training and education. As a recent addition to the board, Cunha was still seeking more specific projects to pursue during his term. One item on his agenda will be working closely with Dan Hill, the academic representative on the board. Cunha’s predecessor, Cindy Reece, focused her last year as technical director on petroleum education, which remains on his list of concerns. A forum on petroleum engineering education is planned for 2016. Cunha sees it as an opportunity, among other things, to consider what progress has been made since the previous forum in 2013.

And he will be looking for ideas from active technical sections in digital energy and analytics, encouraging them to bring in leaders from a wide range of job descriptions and countries.

“Professional engineers are more and more required to offer, in addition to technical skills, a knowledge of economics, development, and its risks,” he said, adding that SPE needs to encourage initiatives promoting development in those areas.

Last year, SPE added a director to represent academia. Now Dan Hill, the head of the Department of Engineering at Texas A&M University, has begun working on defining the job.

While the title is new, there is a tradition of having a representative from academia on the SPE Board of Directors to acknowledge its important role in petroleum engineering.

“It was commonly an at-large position or a technical director position. It was never a guaranteed spot,” Hill said. He added that, last year, it appeared the board would be without an academic representative, so 2014 SPE President Jeff Spath pushed to add a board member in this key area.

The mandate is a broad one. One of the pressing issues is the high percentage of professors reaching retirement age. “That will come up everywhere I go,” Hill said. “In our department here, we are doing a lot of experimenting with professionals … teaching undergraduate programs primarily. Maybe SPE can help universities in finding those kind of people.”

Other items on his agenda will depend on the input from the advisory board that he is forming and what he learns from visiting colleges.

“I am trying to see that SPE is understanding what is happening in the academic world. What are the problems and what SPE can do to make this better,” Hill said. “I need to know a lot about what is going on in petroleum engineering departments around the world.”

Hill’s job requires frequent travel, so he plans to add more stops on those trips to visit local universities. On a recent trip to Brazil, he learned that there are 28 petroleum engineering programs there, topping the 24 in the US. But there is a limit to what he can see first-hand. As evidence, Hill points to the approximately 300 SPE student chapters.

“The way our discipline is taught and the structure of departments varies tremendously around the world,” Hill said.