Digital techniques and automated operations can revolutionize oilfield cost savings.

Some integrated and independent operators are getting a competitive edge by building digital foundations into new fields as they seek to get the greatest number of barrels out of the ground at the lowest cost. At the same time, the biggest service companies in the industry are coming out with solutions to help them do it right.

Digital oil field promises approach the potential of yesterday's e-commerce, but savvy operators can learn from the advice of Bill Bartling, senior director of marketing at SGI, who said, "It's all about making money. It's not about cool stuff."

Let's talk about saving money. Real-time automated monitoring of operations saved a Los Angeles, Calif.-based customer of SGI

US $210 million on a single platform at a rate of $15 million per well, Bartling said. Statoil saved up to $40 million in rig time on North Sea wells and saved another $400 million by better well placement.

Hovey Cox, Schlumberger Information Systems director of real-time initiatives, said oilfield case studies have shown:

• Dynamic drilling doubled the target hit ratio and reduced drilling costs 15%;
• Dynamic production lowered maintenance costs and increased production 3% to 12%;
• Portfolio optimization saved 10% on capital allocation and increased field cash flow 25%;
• Global secure data access resulted in a 12% increase in reserves estimates; and
• Streamlined stakeholder interaction reduced costs up to 50%.

Calvin Cobb, vice president and general manager of Invensys, said that now most systems are designed for oilfield equipment. In the future, systems will help people optimize and manage their businesses.
No one company can claim to do the digital oil field by itself. A package approaching fully automated remote monitoring and control of company operations is not available. The closest solution to a complete package requires collaboration among several companies.

The technology is still in the maturation stage with companies working by experimentation and optimization. Digital data, digital work processes, integrated visualization systems and reliable broadband communications are eroding organizational boundaries because they lower organization costs and create a faster, more flexible business with access to the best and brightest minds in the business, Cobb added.

Conversion

To make the conversion to an automated system, added Tim Tipton, vice president of technology services at Marathon Oil Co., a company needs:

• To emphasize senior leadership buy-in;
• To embrace continuous process improvement;
• To facilitate access to people problems;
• To accept the idea that no idea is bad;
• To encourage internal and external collaboration; and
• To take a disciplined approach to identify, value and implement new technology.

When Jerome Beaudoin, chief information officer at Devon Canada, made the plunge into a digital operation, his parent company was growing from a mid-sized oil and gas company to the largest independent in the United States. It had to evaluate acquisitions and find property ripe for disposal.
It had to manage its assets carefully because shareholders expected acquired properties to make money.

The company listed three objectives:

• Streamlining the variance analysis process - for capital and operations expenditures, volumes and budgets;
• Improving well life-cycle management; and
• Improving regulatory reporting and management.

In slightly more than 8 weeks, Devon Canada went from 20 touch points for approval for each project to three approval processes. It converted from 15 different individuals for checks and balances to approval on an exception basis. Approval time dropped from 2 weeks to immediate.

Now it gets better communication, improved collaboration and greater visibility of strengths and weaknesses.

Expectations

BP at Valhall and Statoil at Gulfaks are already seeing benefits from their approaches to the digital oil field.

In an article for BP's Frontier magazine, editor Terry Knott outlined BP's vision of the field of the future.
"We are driving toward a step change in the way we manage our current and future fields. The net result will be a reduction in the capital and operating costs associated with producing hydrocarbons and an increase in the volumes we deliver. There is a very large prize beckoning, which we believe to be in excess of half a billion barrels of additional oil reserves in the medium to long term," said Howard Mayson, BP exploration and production business vice president for reservoirs and wells, in the Frontier article.

From BP's point of view, the field of the future uses integrated technology for real-time data management, combined with tailored business processes to continuously monitor oilfield operations and operate them from a distant location. That operational information will be completely accessible to company decision makers who can solve problems from the bottom of the well to the point of sale.

"In the longer term, we foresee that offshore we will be able to have minimum facilities installations, many of them normally unstaffed and remotely monitored and operated. Onshore, we envisage single operating centers located in each producing basin controlling wells and plants across large areas, maximizing the oil and gas delivered to the market," added Andy Leonard, manager of the field of the future program core team.

The point of digital change is the same point that encourages people to go to universities, take training courses and do the thousands of things that make them better at their jobs. Beaudoin said, "The future is looking to technology that will capture the real value of people, to create a wireless world to integrate all field people to home-office decisions."

Challenges

The industry faces a lot of challenges in
the move to a digital, automated operation.
Among those challenges, according to Marise Mikulis, energy industry manager with Microsoft Corp., are:
• Articulating the business problem and deploying the technology without failure;
• Delivering the new concept in a timely manner;
• Overcoming time, money and people constraints;
• Shepherding the culture change within the organization;
• Anticipating and preparing for future change while honoring legacy data and applications; and
• Dealing with technical uncertainties.

Those appear to be challenging obstacles for a company to deal with in moving toward remote operations, but they are handling the challenge. Speaking at a Schlumberger Information Services seminar, Ihab Toma, vice president of global sales for the company, said only 35% of companies used simulation as a key part of their reservoir model in 2000. By 2006, he estimated 75% of companies
would use simulations continuously.

Elements

Don Paul, vice president and chief technology officer with ChevronTexaco, speaking at the 2004 Business Technology Summit and Global Energy Forum hosted by Microsoft and during an interview offered a look at the elements that have to fall in line to allow operators to ride the digital tidal wave.
First, companies need the data. They get data from exploration, development, production, pipelining, shipping, refining, distribution and marketing.

Imagine how long a currently producing oilfield would last without the data backing it up and showing operators how to continue its operation, he said. An oil or gas field can last decades and, "data must span the life cycle. Global value chains are highly leveraged on information and connectivity," he added.
Illustrating the amount of data, he said ChevronTexaco has 50 active seismic acquisition programs that generate 350 terabytes of data. A hundred reservoir simulation models need storage for 10 terabytes of data.

A large offshore field has a thousand input and output points and a 10-gigabyte-per-day data stream, but a refinery has 30,000 input/output points and produces 1 terabyte of raw data daily. It's up to the data manager to decide what to use.

Future

Operators of the future will use ubiquitous networked sensors for essential elements such as pressure, temperature electrical distribution. "Sensors are undergoing major advances," Paul said.

A company called Dust Inc. is making smaller, cheaper sensors. It now produces sensors 5 cu mm in size, and it's trying to scale them down to 1 cu mm with an electrical requirement so low that an AAA battery will power a sensor for 10 years.

At that size, if the sensors are cheap enough, a company can put them everywhere. It can spray self-orienting sensors along a pipeline, or any pipe, to continually report the status of flows, temperatures and pressure. The number depends on the goal. "You can sprinkle them like pixie dust. They organize themselves and constantly report. They probably will make them for a few dollars each," he said.
The biggest cost of sensing now is not in the sensors. It's in the labor costs of installing the sensors. If the industry is able to spray on the sensors, that major cost practically disappears. If something can be sensed and the data can be sent to a computer center, that data can be digitized, stored and analyzed.
With the sensors in place and the storage capacity for the data, operators will be able to manage oil fields like factories.

Those factories must be reliable and predictable. Every company tries to get more oil out of its assets at lower cost. If it has the data to predict the costs, it can manage those costs.

ChevronTexaco and Schlumberger are working together to develop the next generation of reservoir simulation, he said. Elements of that next-generation system include increased geological realism and better representation of uncertainty. It will provide increased realism and dynamics for wells with better physics and chemistry integrated in a real-time system designed for computers that will become available.

i-field

To bring that i-field into reality, the company must cover the full life of the field. It must be an integrated, instrumented, intelligent oil field. "Under full optimization, we're looking at continual sensing and making decisions in minutes and seconds," Paul said.

The oil patch has been moving toward automation for years. "The productivity of an E&P (exploration and production) professional has tripled in the past decade. Basically, we've substituted work stations for people," he said.

Next in line for the automated oilpatch, "We will have self-healing and self-organizing networks and computing systems. If you can't have self-organizing sensors, deployment costs go through the roof," he said. The industry already has fiber-optic cable that monitors wells along its full length. Particularly in deeper water, he said, the industry needs facilities that detect problems and make repairs themselves.
With the vast volumes of data that are becoming available, the industry needs to augment human interactions and cognition. Humans "may already be maxed out, or at least stressed. As the volume of data rises by a factor of 10, 100, 1000, if we can't handle the data, we'll have a wipeout (in the digital tidal wave) and productivity will fall," Paul said. "I think now, if we increase data volume by 100, production will fall."

In the commodities business, he said, "If you know the price, you know the revenues. To improve, you must increase the number of barrels per worker. I see more technology. I don't think we'll ever see more people."

In the longer term, he said, specialized technology and operating conditions for automation and performance optimization will require a higher level of measurement that will provide data for predictable models. Better computers will have to handle that.

It's relatively easy to install sensors in equipment in new wells, but it's a real problem in producing fields at a cost that makes economic sense.

A general rule of technology says that once costs fall everywhere, it will be widely adopted, like cell phones and digital cameras. The value proposition for the i-field is visible, but people in the industry still are waiting to see how the affordability materializes.

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