Intelligent reservoir management systems - innovation in search of standardization

March 1, 1999
This article first appeared in the September issue of Offshore without some sections. It appears here in entirety. In a scramble to define a potentially paradigm-shifting technology, the terms "smart well" and "intelligent completion" are being replaced by the universal term "intelligent reservoir management system" or IRMS.
William Furlow
Technology Editor
This article first appeared in the September issue of Offshore without some sections. It appears here in entirety.

In a scramble to define a potentially paradigm-shifting technology, the terms "smart well" and "intelligent completion" are being replaced by the universal term "intelligent reservoir management system" or IRMS.

This is not just an evolution of semantics, but a ideological shift the service industry hopes will appeal to the consumers of these high-end, high-concept systems. Key to the IRMS nomenclature is the absence of the terms "well" and "completion." Also key is the inclusion of the term "reservoir." After all, it is the reservoir engineer whom the companies have to woo if they hope to see their designs purchased and installed.

Beyond such marketing tactics, the industry is painfully aware of the skepticism entrenched in the minds of most oil companies. Despite the attractive upside offered by integrated downhole controls, data acquisition, and communication with the surface, oil companies are conservative with respect to this new technology. It is ironic that in an industry built on taking risks new technology is slow to be adopted.


When the industry talks about standardization of equipment in IRMS, it is really talking about standardization of communications. No one is suggesting that the functions and tools become standardized across all reservoirs; this would defeat the purpose. Rather, the industry would like to see a variety of products from a variety of vendors that can communicate with each other and can be controlled from the same console. This plug-and-play approach would save time and money, as well as simplifying the installation of such equipment, thus reducing the risk of failure.

Such communication is already possible, but is difficult and costly. To get smart tools from different companies to talk to each other requires the installation of an interface card. Each different tool requires a different card, a potentially expensive addition.

A standardized communication system would allow for an endless variety of mix-and-match systems from different companies customized for an individual application. The problem is, in such a fast growing, emerging technology, it is hard to spot which communication system would make the best standard. Competitors would offer resistance to giving up the communication interface they have spent time and money developing, and hardware would have to be retrofitted.

Ideal interface

Even in the inconceivable situation in which everyone involved is willing to cooperate, it is still too early to know exactly what would make an ideal communication system, because future requirements are not yet fully developed. This could evolve into a situation where the "standard" limits the growth of the technology.

Those involved in this technology point out that while customers insist that a communication standard should be a top priority, this is not the case across the industry. In many critical areas there is no standard between vendors. This is simply how the business and competition evolved.

There are so many different applications that attempts to standardize often meet with failure. In addition to this challenge, manufacturers are intuitively interested in offering customers an integrated system to solve their problems, not provide a component to someone else's system design.

There are a number of alliances already in existence developing this technology. No one corporation currently has all the "components" of a system within its portfolio, such is the complexity of these systems. It is interesting to note that consolidation between some of those involved will actually result in more players in the market place. Specifically, the Baker Oil Tool/Schlumberger alliance is breaking up. That will result in a new Baker/Western Atlas alliance and a Schlumberger/Camco alliance.

Focus on failure

In the business of IRMS, most attention is focused on the reliability issue. One of the main "tools" being used to address that concern is failure mode and effects analysis. What are the failure points of the specific design? What are the consequences of failure? PES commissioned a study by the US Department of Defense Reliability Analysis Center to determine where redundancies would be required in its system. The center reported that such redundancies would be required for system components located below the packer.

A more ambitious Deepstar JIP study is currently underway using the nonprofit company, Southwest Research Institute of San Antonio. Southwest Research has expertise in testing oilfield equipment and has connections to the aerospace industry. Deepstar's Reliability Forecast Methodology Development for Prototype Equipment study is being conducted by a subcommittee of the Drilling and Completions committee and is chaired by Bill Landrum of Conoco.

Landrum said there are a number of similarities between the systems used in IRMS and in aerospace "fly-by-wire" systems. Fly-by-wire refers to the switch by combat pilots from having a mechanical connection between their controls and the flaps and rudder of the plane. These controls are now electronic and hydraulic, as are those used in IRMS.

For obvious reasons, there has been a great deal of failure analysis conducted by the US Department of Defense to ensure the reliability of these systems in fighter aircraft. This information was compiled by the Reliability Analysis Center (RAC).

Under contract by Deepstar, Southwest Research will work with RAC to analyze this aerospace and military data with the goal of identifying reliability methodologies that can be applied to the oil industry. Landrum said failure analysis is a top priority for anyone considering an IRMS.

Market driven evolution

It is currently anticipated that the market, rather than any industry study groups, will dictate any movement in the direction of standardization of communication systems. This is typically the case with new technology. In a free market, customer needs ultimately dictate how a technology develops.

Perhaps the biggest selling job for this technology is being tackled by those inside the oil and gas operating companies. They are the ones who bear the burden of demonstrating the potential for increased net present value of the reserves, improved production rates and reduced operating expense throughout the life of the reservoir - all this in the face of increased capital expenditures for such systems. Through an increasing number of well supported industry workshops and forums, "ammunition" is being exchanged between the service organizations and operating companies to assist in the advancement of the technology.

Strategic approach

When discussing the future of the IRMS, Trevor Burgess, Vice President of Marketing for Schlumberger Oilfield Services, says his company is in the midst of a realignment designed to offer customers integrated solutions. This new approach is a handy fit for IRMS, which covers a wide range of the services and products Schlumberger and other service giants provide.

When a producer thinks about IRMS, it is thinking in terms of making a substantial up-front investment with the goal of lowering costs down the road. There is no way around the fact that IRMS technology is very expensive. Even the simplest, low-tier operations which offer downhole monitoring are relatively expensive. The high-tier market, which includes remote intervention, is so limited at present that Burgess puts the entire market at 20-30 wells over the next two years. That's not his company's share, but the whole market.

This means that costs are extremely high. Not so high that they could not save the customer money when compared to a workover rig down the road, or lower recovery rates, but high enough that the customer must be sure the system will eliminate the need for workover and optimize recovery.

Complex reservoirs

According to Halliburton, the general application of this technology, for the near term, is within very complex reservoirs. This includes fields with multiple layers or a heavily faulted reservoir that is difficult to predict in terms of well patterns and optimal locations for wellbores. In deepwater and subsea fields, these systems are ideal. Although they cost a lot up front, they can easily reduce costs down the line and pay for themselves in reduced intervention costs and increased recoverable reserves.

Still, it will take time to prove that active reservoir management will yield better recovery. The application can be modeled to some extent, but without case studies of long-term success, it will be difficult to get the industry as a whole to buy into this value as a justification for these up front costs. Schlumberger sees three primary advantages the IRMS can offer:

  • Reduction of a producer's capital outlays by improving drilling and completion performance
  • Improvement of the well's performance
  • Improvement of recoverable reserves.
All of this adds up to making the most of every development well drilled. Burgess said a properly applied IRMS placed at the right location on a well-understood reservoir can improve recovery by as much as 10%. This technology also can avoid, or at least postpone, the need for a workover by allowing an operator to complete multiple horizons in the same wellbore simultaneously at great cost savings.

This ability to reconfigure the well at will means the zones are perforated and produced under a controlled system. These flows are commingled in the wellbore, using sliding sleeves to provide selective access to different horizons. In a deepwater field this can mean savings of $200,000 a day in dayrates for a semisubmersible drilling unit, multiplied by the several weeks needed to work over the wells.

Forward modeling

In ideal application, the IRMS looks attractive. The producer spends some money up front, but enhances recovery and saves a bundle down the road. The problem is that this best case relies on intimate understanding of a reservoir's performance. Without detailed reservoir modeling and the expertise to interpret such a model, the IRMS will not pay off. For example, why should an oil company spend a bundle to deal with fluid invasion if such invasion never occurs?

Forward reservoir modeling is the key enabling technology that will unlock the potential of IRMS. Without detailed modeling, the reservoir management system cannot be designed or applied properly. Burgess characterizes modeling of the reservoir and prediction of its performance to be a risk management issue.

Such modeling should be able to identify risks to production expected in a given well. Forward modeling would be able to detect such threats downhole before they reach the wellbore. Armed with these tools and this information, a customer can make an informed analysis to determine if the up front cost of the IRMS is justified and how the system should be designed to detect certain threats and optimize production.

Such systems, which include monitoring equipment as well as the ability to correct problems as they develop, is the highest evolution of IRMS currently envisaged and has the most narrow market for application.

Subsea, other drivers

Burgess identifies the development of subsea wells as one of the major driving forces behind IRMS technology. This, along with interest in deepwater fields, has put an emphasis on diagnosing changing downhole conditions and reconfiguring a completion without intrusive intervention (the Schlumberger definition of a smart well).

With a worldwide offshore subsea market of 200 wells a year, for example, including deepwater wells, as well as satellite fields tied back to existing structures, that is not a very big market for the service companies to divide up. When only a third of these wells are considered high-tier candidates for the monitoring and intervention version of the IRMS technology, then the market grows even smaller.

Out of this very limited number of potential clients, the big three service companies must recover the substantial development costs of creating these unique downhole systems. How much will an oil company be willing to pay? At what point is it cheaper to just take one's chances and pay the costs of a workover down the road? As dayrates continue to drop, the availability of deepwater rigs for workovers could eventually broaden, cutting deeper into the economics driving IRMS development.

It is ironic that as IRMS developer margins shrink, the customer is demanding absolute reliability from these systems. However, such a demand makes sense. After all, who would be willing to make such a major commitment up front to have an equipment failure down the road or find that the system installed does not address the problems experienced in the well.

Technology challenges

The biggest mechanical challenge this technology faces is in cabling, Burgess said. This refers to the actual cable that would transmit power and telemetry from the surface down to the seabed, through the wellhead, down the completion, through the packer, and into the drain hole.

Burgess said fiber optics have come a long way in their ability to move electronics to the surface and measure temperatures downhole, but they still present a pressure seal problem below the mudline. Some telemetry can be controlled wireless, but this still leaves the question of power.

If a producer puts in a high-end IRMS, it will expect a return in reliability, postponing the need for a workover, for instance, and a zero failure rate. Customers are also looking for expert data management. Burgess said all the forward reaching data and mechanical technology anyone could imagine would be of no help unless it is properly interpreted in a timely manner that allows the correct decision to be made in time to optimize production and avoid problems.

This means more than simply installing the hardware and explaining the software. It requires a long-term commitment by the service company to assist with the management of the reservoir. Such a commitment could mean these systems are rented by the customer for a large up-front fee, then leased over the life of the well with an agreement that rewards the service company for enhancing the production of the reservoir. Such an agreement would form the basis of a long-term relationship between the owners and the service company needed to properly apply a high-tier IRMS.

Ultimately, the IRMS has the potential of allowing a producer to produce what it wants, when it wants, depending on the optimization of the reservoir and, of course, the price of oil. Burgess said with intricate downhole sensors, it might one day be possible for oil analysts to log on and check the real-time production rate of a company's wells the way it is now possible to check the company's stock price.

Power below the packer

Halliburton is attempting to overcome the problem of cabling by designing an electrohydraulic system to provide power below the packer. In addressing this problem, the Halliburton PES alliance looked at different combinations of technology including all electronic, all hydraulic and other designs including fiber optics. The group settled on electrohydraulics because of the proven track record of hydraulics in the oil field.

The hydraulic power will be used primarily to provide locomotion downhole. Electric power would be used primarily in other applications with a emphasis on minimizing electrical power requirements downhole. The group will be able to access wells where power transmission through umbilicals or subsea control systems is limited.

Halliburton has embraced an open systems design that will allow their IRMS to operate with devices such as flow meters built by other providers. This equipment would be able to plug-and-play, using the Halliburton Signet protocol. In this format, equipment from any manufacture could be used with the Halliburton system as long as it meets with the company's reliability and performance requirements.

Systems integration

Halliburton agrees that systems integration is key to a successful IRMS. Data acquisition, transmission, storage, and usage issues are central to reservoir optimization. The data must be available to those involved so they can make accurate and timely decisions on how to optimize production.

Data acquired real-time, downhole is going to increase substantially the amount of information the operator and service company will have to process. If this additional information is to be useful, there must be an efficient way to process and store it that promotes easy access for critical decisions.

The danger is that the additional information will be gathered but not used efficiently, because it takes too long to process and interpret. "If we don't overcome these hurdles then all we are going to do is collect reams of data," said Bill Vidrine, Smart Well Completion Product Champion for Halliburton.

Beyond gathering and transmitting the data, the core function of the IRMS is to be able to use this excellent information to optimize production. "We get the data, we analyze it, and it gives us some knowledge, but the value comes from the application of that knowledge," said Jerry Wauters, Production Manager and Global PSL Coordinator for Halliburton. Reservoir optimization is the big picture. This is what is driving all these competing teams in their IRMS efforts, and it includes wellbore data, as well as far well data.

Driving the technology

Halliburton explains that while the problems are customer driven, the solutions must be industry driven. The customer comes to the service company with a problem and the service company develops the solution.

Early drivers of this technology, according to Halliburton, wanted to decrease well intervention costs and improve production and injection profiles to bring more production in sooner. As subsea developments became more popular, the technology grew with it. Also, increased recoverable reserves is a cash driver.

Customers' wants and needs differ so broadly that it is difficult to see where the development priorities should be. Halliburton and others are focusing on the reservoir optimization priority. By developing some potential solutions, the service companies give clients an idea of what they can and can't do with IRMS. While the technology itself has grown out of customer needs, the detailed applications each provider invents are then available to the entire market.

This rapid innovation has been one of the limiting factors to the technology, according to Halliburton. Customers are quick to compliment this innovation, but because it is so new they are not sure what to ask for. High up-front costs and limited knowledge add to the confusion.

Halliburton said it is understandable that something as innovative as IRMS would be slowly adopted. As the technology is better understood, this adoption rate should increase. Producers are waiting to see what kind of long-term payoff this technology will have.

When a prospect accustomed to evaluating the cost of a traditional completion looks at the numbers of an IRMS, it is difficult to convince them that the long-term benefits will offset these costs. When producers apply a team approach, this model is typically an easier sell. According to Halliburton, such teams have a much better appreciation of the total asset value and the opportunities to increase the value of the overall project, rather than an individual facet of the project.

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