Technology and innovation are critical factors in the oil and gas industry’s continued success. Without a constant push for new ways of doing things, areas such as deep water and unconventional resource plays would still be out of reach. Companies, research centers, and academia work tirelessly to perfect existing techniques while pushing the boundaries to examine additional possibilities.

In this spotlight on R&D, several companies discuss trends that guide their research dollars.

Taking a macro view

While many major oil companies scaled back their research efforts in the 1980s and ‘90s, they still are at the forefront of pure science R&D, leaving more of the applied science to their service company partners. For instance, Statoil has been a long-time believer in investing substantially in its own R&D activities and now has three research centers in Norway alone. The company’s R&D cluster, with facilities in Trondheim, Bergen, and Porsgrunn/K?rst? in addition to a heavy oil technology center in Canada, exists to establish and execute Statoil’s R&D portfolio in line with its corporate technology strategy. This, it hopes, will position it for future technology leaps.

The operator has decided to triple its 2013 technology research budget for the Arctic alone to US $43 million (NOK 250 million) from $14 million (NOK 80 million) in 2012 as it bids to close the technology gaps that exist for Arctic projects. In particular, it is focusing much of its current Arctic research, in conjunction with Norwegian universities, on ice management.

The operator’s R&D program also is maturing the concept of an Arctic drilling unit, able to drill year-round in ice-bound conditions in varying water depths. Based on Statoil’s specialized category “A” and “B” rigs developed for the Norwegian Continental Shelf, the Arctic category unit will be able to operate in varying water depths and will involve integrated operations in drifting ice.

Functions the company is aiming to deliver include a management system to reduce ice impact, an optimized drilling package for faster drilling and increased rig availability, and solutions to ensure that the rig dynamically maintains its position. At present, according to Technology, Projects, and Drilling Executive Vice President Margareth Ovrum, no robust solution for dynamic positioning dedicated for ice operations exists. “When we see a technology need, we try to fill the gap ourselves. We have now directed our strategic focus towards developing technology for exploration and production in ice. A new dedicated unit has been established to solve these challenges,” she said.

She added that Statoil was developing more robust solutions for both permanent and floating production solutions for the Arctic as well as other technologies, including shooting seismic in ice.

BP’s R&D efforts currently total around $640 million annually on both its upstream and downstream sectors, with around 35% of that global spend figure being invested in R&D activity through UK-based institutions. Along with its own research centers, BP also has a policy of investing in programs with UK universities and government initiatives. For example, the BP Institute (BPI) was established as an interdisciplinary research institute at Cam-bridge University more than a decade ago. The BPI’s research has touched on everything from oil recovery to areas such as geological storage of COand ocean currents. Oil recovery remains a subject close to BP’s heart. According to Chris Reddick, vice president of EOR for BP, only 3.5% of global oil production today comes from EOR projects. “A lot of effort is needed to improve that,” he said at the recent PETEX 2012 event in London. Within BP, the company’s own equivalent figure for EOR-related production on a gross basis is about 100,000 b/d, with its goal being to increase that amount. Reddick said BP’s global hydrocarbon portfolio contains a significant proportion of oil resources, which are the target of EOR techniques that are currently the subject of R&D studies. These are focused on improving both pore scale displacement and sweep efficiency. Outlining BP’s approach in screening, evaluating, testing, and applying these techniques, he highlighted the following:

  • Analysis of resources using a “reservoir technical limits” process to identify the most leveraging recovery processes and their targets;
  • Laboratory scale tests, often using innovative experimental methods, to assess recovery process performance;
  • Centrally funded field trials to prove the effectiveness of the process at the interwell scale; and
  • Centrally supported deployment for programmed take-up across the company.

Addressing the eventual deployment of EOR technologies and techniques, Reddick added that BP has had to adapt its stance on EOR to meet the needs of its portfolio. “EOR methods that complement waterflooding are an area we are focusing on,” he said.

He also mentioned the issue of getting EOR into a project’s life cycle earlier in the process as a key area. “If we can apply it earlier in the life of a field, we can get more oil out of the field,” he added. He also commented that BP and the wider industry still need to “broaden the applicability of EOR solutions” as well as accelerate the development cycle time for new EOR solutions.

One example of the successful evaluation and early take-up of this kind of technology within BP is its LoSal EOR waterflooding and sweep enhancing polymer treatments, both of which are part of its Designer Water suite of EOR technologies.

Ram Shenoy, CTO of ConocoPhillips, pointed to advances in high-performance computing coupled with advances in algorithms for modeling and simulation in different fields – elastic full-waveform inversion in geo- physics, molecular modeling methods in chemistry, and the life sciences transplanted to chemical recovery processes in oil and gas. He said that networking and telemetry advances are allowing the instrumentation of the oil field to an unprecedented extent.

“Advances in IT – particularly mobile applications, networks, and telemetry – are enabling many applications of computing in environments where it was not previously possible in the oil field,” Shenoy said. “Real-time troubleshooting and diagnosis of production facilities in offshore and remote environments is one example. Another is real-time control of the drilling process to optimize the time spent in wellbore construction.”

He added that the industry is beginning to examine the implications of nanotechnology research in a variety of areas, such as coatings to combat corrosion and new types of miniaturized sensors that use carbon nanotubes, enabling new types of interfacial science at nanometer-length scales.

Some of the company’s priorities revolve around low-permeability and shale plays around the globe. Given ConocoPhillips’ current and anticipated position in unconventional reservoirs, this is a focus area spanning all aspects of reservoir characterization, development, and production.

“Another emphasis is to make advances in geophysical imaging, seismic and otherwise, to establish our position in deepwater and thick subsalt plays globally,” Shenoy said. “We also are looking at technological advances in deepwater facilities – for instance, subsea and downhole power management, more effective ways of managing drilling processes, and assuring access to hydrocarbons in a safe and predictable manner – to reduce the cost of exploiting deep water while being safe and environmentally responsible.”

As is the case with many companies queried, Conoco-Phillips is very aware of the need for technology to minimize the environmental footprint across the range of the company’s operations. One example Shenoy cited is managing the use of water in operations, including oil sands, unconventional reservoirs, and producing facilities . Another is to develop technology to ensure deepwater operations are safer and cause minimal disruption to the environment.

Royal Dutch Shell has an extensive R&D effort for both upstream and downstream challenges, but lately it has focused on subsurface challenges. Teaming with a variety of service companies and academicians, Shell is devoting a great deal of science – and funding – toward advancing industry understanding of current and future challenges.

For instance, geophysical surveying has been challenged by the need for “new ways of thinking,” according to Dirk Smit, chief scientist, Geophysics. “We believe the trick is to drive down the cost of these measurements by an order of magnitude, at least,” Smit said. “We think we have identified the technologies that will allow us to do that, and that will drive a profound change in the seismic industry.”

In unconventional plays, reservoir engineers are discovering that standard equations such as Archie’s equation and Darcy’s law to derive the physical properties of reservoir rocks, while providing reliable methods to gain a better understanding of the rock properties and flow characteristics in conventional reservoirs, are not well suited for this new type of formation.

“Darcy’s equation doesn’t apply here, and we know that,” said John Karanikas, chief scientist, Reservoir Engineering. “We need to replace it with something. Would that something be Darcy’s law with a modification factor? Would it be something with the same structure of equation but a more complicated modification of the permeability, called an effective permeability? How do I measure the scaling factor of that permeability?”

He added that the equations, in their current form, are too simplistic to describe the organic nature of shale rocks. “It’s a question of whether we can expand them in a convenient way to account for the new phenomena,” he said. “My first response would probably be, ‘not immediately,’ because there is nothing about absorption or desorption in Darcy’s law. It’s not even part of the saturation. That needs to be modified.”

What is needed, he said, is a methodology that would allow scientists to go from the pore-size scale to the reservoir-size scale at which the derived laws or coefficients can be applied.

One approach is nanotechnology. The goal, said Vianney Koelman, chief scientist, Petrophysics, is “not to study nanomaterials to death.” Rather, the plan is to translate the understanding into a methodology for engineers to use. “We want to understand what is happening at the micro scale, what the dominant mechanisms are that make the hydrocarbons mobile,” he said. “That should translate into a parameter that describes producibility. It will be a permeability-like parameter but one that will depend on entirely different microscopic features of the rock.

“The next question is how to scale it up. How do we translate that into producibility at the reservoir scale? That will be part of an engineering approach that we will look at later. I’m pretty sure we can crack that nut.”

Sau-Wai Wong, Shell’s R&D manager for Unconventional Gas Technology, said that for the industry to optimize its completions technology, it needs a better understanding of the reservoir and how the fracture fluid interacts with the rock. Key technical considerations for the industry include:

Finding geological sweet spots;

Optimally and safely drilling, completing, and fracture-stimulating the wells;

Understanding how production will flow through the ultra-tight rock to the fracture network and wellbore;

Developing and applying surveillance technologies to monitor the wells, reservoir, and surrounding environment during injection and production; and

Effectively treating, recycling, and reusing the water. “Fracture stimulation is a critical technology in unlocking unconventional gas and oil, and to be able to optimize our design, we need a better understanding of the fundamental subsurface processes,” Wong said. “For example, if the wells do not produce, we need to know why. Is it because of suboptimal fracture stimulation or poor geology?”

Wong said that this type of research is in its infancy. In a tight reservoir, the rock must be broken up to create pathways that the fluid can escape into and eventually be produced to the surface via the wellbore. Hydraulic power provides the energy to break the rock.

“The question is, are there any other forms of energy that we can send far into the ground that can create that energy?” Wong said. “Different people are taking different approaches. There are mechanical methods and electrical methods. Or maybe a combination of those. It’s a long shot, but I think that’s what R&D should do.”

EOR presents the challenge of dealing with the interactions between the water, oil, and rock surface. The goal is to detach the oil from both the water and rock and make it move on its own. “Rather than being in small droplets that are suspended in the water, the oil droplets need to be connected into strings that then flow through the rock,” said Bruce Levell, chief scientist, Geology. “The attractive force takes place at the atomic scale on the surface of the rocks that is interacting with the surface of the fluids. And what we’ve discovered is that some techniques for analyzing catalysts in refineries are particularly suitable for analyzing the surfaces of rocks in very fine detail.”

In refinery-based catalysis, the active sites of the catalysis substances must be repeatedly accessed by the gases or the liquids that are flowing past them and repeatedly reused to bring molecules together. “We’re really interested in the atomic surface layer, and what we’re finding is that the bulk is by no means representative of what’s on the surface,” Levell said. “For example, a surface polarity or charge can be related to clay minerals or bonds in the lattice that are free, and those are interacting with polar compounds in the oils. If you can change the ionic strength of the water, you can change those electrostatic attractions and detach the oil from the rock surface – and you can do that simply by exchanging the bivalent ions of the calcium and the magnesium into water with a monovalent ion, like sodium.”

Magnetic nanoparticles are being studied for these applications. Sergio Kapusta, chief scientist, Materials, said emulsions are relatively easy to separate using the magnetic field, and oil becomes attached to the nanoparticles. When using the magnet, it moves the oil along with the nanoparticles out of the water phase.

“This has been known for some time,” Kapusta said, “but we didn’t know exactly what size of particles we could use, what strength of magnetic field was required, and whether it would work when we put it all together. We now have the theoretical framework.”

Collaborative efforts

The Research Partnership to Secure Energy for America (RPSEA) was established to facilitate a cooperative effort to identify and develop new E&P methods for ultra-deepwater and unconventional natural gas and to ensure that small producers continue to have access to the technical and knowledge resources necessary to continue their contribution to energy production in the US.

In the onshore area, the biggest and most exciting thing that’s driving R&D activity at RPSEA is the interest in unconventional gas research, particularly shale gas and tight unconventional liquids production, according to Robert Siegfried, RPSEA president. “Those are resources that have the opportunity to dramatically change the energy picture in the US and the world, but it’s going to need some new and improved technology to reach its full potential,” Siegfried said. “I think the key technologies that are going to be required are those aimed at ensuring that we can develop the resource not only economically but with an environmental footprint that’s acceptable to the communities that are involved as well as the population at large.”

He mentioned water management as a key issue going forward. “There’s a lot of water that needs to be sourced and also produced water that needs to be treated and managed after the treatment process, which needs to be either disposed of or treated and recycled,” he said. “And the technologies for both sourcing and managing the large amount of water that’s associated with unconventional resources is going to be an area of a lot of R&D opportunity.”

More efficient fracture treatments are another area of research. Current treatments do not stimulate the entire reservoir, he said. “I think there are opportunities to improve that so that we can access a greater reservoir volume for the same sort of surface infrastructure and surface impact,” he said.

Offshore, the Macondo tragedy has focused attention on safe operations. But Siegfried said there are exciting new technologies to help the industry do a better job in deepwater offshore development. “One of the technology trends out there has to do with just getting the raw data we need to see what’s going on in the subsurface and manipulate things in the subsurface,” he said. “The technology for autonomous underwater vehicles (AUVs) coupled with better imaging technologies that will allow informa- tion on what’s going on near the seafloor to be seen by operators at the surface is exciting. One key area of technology is imaging technologies; systems using infrared light as well as acoustic sensors are getting better images that will allow AUVs to go down in challenging environments and be a lot more effective in terms of both monitoring and controlling subsea operations.”

Improved data collection techniques are another area of potential improvement. This will include better seismic technologies and better application of controlled-source electromagnetics. “That lets us have a better idea of what we’re going to be drilling into and to plan operations more effectively,” he said. “And the ability to put more facilities at the subsurface, I think, is something that’ll be a real enabling technology in terms of processing and power generation.”

Nuts and bolts

Service companies are the workhorses of oil and gas R&D, focusing on both pure science and applied research that improves existing products. Much of their R&D efforts are focused on the challenges their clients face in the field.

Rustom Mody, vice president, Technology at Baker Hughes, noted that challenging operating environments and more progressive philosophies are leading to exciting technological advancements. “Increasingly, operators are willing to invest in technologies that will reduce their long-term overall risk,” he said. “This is a big shift from the previous prevailing philosophy of incurring risk to spend less at the outset.

“As the saying goes, necessity drives invention. The tagline should be: Investment funds it.”

Mody sees the industry as “on the cusp” of a new era in upstream R&D. “This trend is focused on increasing long-term reliability and reducing risk in extreme environments,” he said. “Most exciting among the trends we see are in materials science and monitoring and control.”

In the area of monitoring, he said, the operative word is “control.” The industry has been able to gather data downhole for quite some time but is just now perfecting its ability to decipher and analyze those data and use them to control operations.

“There is tremendous potential for improving both short- and long-term reliability and safety as well as reservoir understanding,” he said. “We are integrating downhole surveillance, monitoring, and control capabilities in drilling and completion equipment.”

Mody noted that the intelligent well market continues to expand, and there is broader acceptance of electronics in downhole equipment and development of remote-actuated annular casing packers. “Through integrated interpretation, we can combine data from all available resources to improve value and better help operators make the best decisions through a combination of drilling data, wireline, seismic, reservoir models, and geomechanics data,” he said. “We also need materials that can handle the extremely high temperatures of [steam-assisted gravity drainage operations] (SAGD), the extreme pressures and temperatures of subsea environments such as the Lower Tertiary, and acid gas. Much of our research in materials at Baker Hughes is focused on nano-scale materials; new polymers; and high-strength, corrosion-resistant metallurgies.”

For instance, the company has developed a new nonmagnetic hard facing that is up to eight times more wear-resistant than current materials. Slick coatings and smart materials such as shape-memory polymers, high-strength dissolvable metals, thermoelectric polymers, and time-control shielding materials are just some of the materials being researched and developed.

In the area of drilling and evaluation, using real-time formation data to geosteer the well on a more precise path is generating effective wellbores for completion and production, Mody said. “The result is an optimized reservoir, both initially and throughout its life,” he said. “The integration of interpretative data from multiple sources is driving a new level of decision-making for increased value. Likewise, a new generation of hybrid drilling bits, combined with drilling dynamic models, is improving the drilling time and quality for new wellbores.

“Downhole instrumentation, both wireline and LWD, is benefiting from greater reliability at ever increasing temperatures. Producing wells can now be better controlled with respect to water and gas management. New downhole fluid analysis techniques combined with efficient sampling tools are improving the accuracy and the models for deeper reading and novel sensors such as mineralogy, [gas-oil ratio], optical, and others.”

Mody added that remote actuation also is being implemented into surface equipment such as top drive cement heads. The technology is superior from an HSE perspective, he said, by removing personnel from close proximity to the head during higher risk well operations such as high-pressure circulation and ball or dart dropping.

“Instead, a compact, battery-powered console can be hand-carried as needed on the rig floor to monitor and control operations,” he said. “The heads are designed with their own battery and compressed gas tanks, which allow rotation and actuation independent of rig power supplies. These are all exciting developments that were not even concepts five years ago.”

According to Thierry Brizard, executive vice president, Technology for CGGVeritas, it is an exciting time in upstream research. “At CGGVeritas we are focusing on key areas to provide affordable answers to the central challenge of our clients: maximizing recovery of conventional and unconventional oil and gas,” he said. Areas of study include dense seismic acquisition via high channel-count operations to deliver high-resolution imaging, robotization to ensure efficient seismic acquisition in the new context of dense geometries, automation of some key aspects of the seismic workflow to handle the tsunami of data generated by high channel-count operations, joint seismic/nonseismic inversion for high-fidelity imaging, advanced modeling to optimize all aspects of seismic acquisition, and advanced seismic illumination to address the diversity of subsurface geologies.

CGGVeritas has been actively partnering with other companies to push these innovations. With respect to robotiza- tion on seismic acquisition, the company announced in November 2012 that it had entered into a collaboration with Saudi Aramco to conduct a major joint R&D project, known as SpiceRack, to develop, manufacture, and commercialize an innovative robotized solution for seabed seismic acquisition. “This solution is based on the deployment of self-propelled recording nodes, and we expect it to lead to a step change in the efficient delivery of reservoir-quality seismic data,” Brizard said. “Both companies will draw on their extensive seismic acquisition experience and allocate resources to the SpiceRack project, and CGGVeritas will create a unique Center of Excellence for Automation in Geophysical Acquisition in the Dhahran Technology Valley within the new technology center we are jointly opening with [Arabian Geophysical and Surveying Co.], our Saudi joint venture with TAQA.”

For dense seismic acquisition and advanced seismic illumination, the company has launched cross-disciplinary technology projects mobilizing all CGGVeritas divisions and value-added technology partners, he said.

Frank Van Ginhoven, senior vice president, Fluor Corp., noted a few trends that he and his research cohorts find particularly exciting. “These trends include shale gas recoveries and associated water treatment solutions, sour gas processing and safety, oil sands (SAGD and associated water treatment technologies), subsea processing of oil and gas, LNG pipelines, the concept of intrinsic safety in design (as a result of Macondo), deepwater production, Arctic production, and processing challenges given the fragility of the environment,” he said, adding that Fluor’s R&D priorities include safety, water, and environmental sustainability. The company also is increasing its focus on sour gas, sulfur processing, COcapture technologies, energy efficiency, and the Arctic.

At Halliburton, the “greening up” of everything, particularly in the realm of chemistry, is a key focus, according to Greg Powers, vice president, Technology. “From a chemistry perspective, we’ve been thinking a lot about water,” he said. Halliburton has introduced CleanWave, a system that uses electricocoagulation to remove sus- pended solids. This allows use of flowback and produced water as part of the next fracture and eliminates significant hauling of water on and off the site, effectively giving multiple-pass uses for fracture water.

The CleanStream system is Halliburton’s solution to the bacteria problem in the oil field. Instead of relying on chemical biocides, which pose environmental challenges of their own, the system uses high-powered ultraviolet light to control bacteria while minimizing or eliminating the need for chemical biocides.

Another chemistry trend is zonal isolation, which has been conventionally provided by cement. Powers said that Halliburton’s WellLock resin is not really cement; it is actually a polymer being used as cement in cases where there are small leaks in the annulus. “Because it exhibits Newtonian behavior, WellLock resin can be placed more easily into micro-annuli than conventional cement,” he said. “Tight casing leaks, the type that bleed off pressure but won’t accept a continuous injection rate, usually must be broken down with acid to increase the leak area so that even a fine-mesh cement slurry system can enter. However, this resin is able to penetrate the small leak much more readily without prior acidizing.”

Modeling is another R&D challenge at Halliburton. Powers said that one of the issues in unconventionals is how many fractures to perform for the best production. “You can do a fracturing treatment and not get any production, which is expensive and time-consuming,” he said. “The goal is to only do fractures that are highly effective and avoid nonproductive zones.”

The company recently launched its Knoesis service, a proprietary suite of software applications that provide improved knowledge of the reservoir and its stimulation characteristics. Knoesis’ 3-D fracture matching software is being used to understand, optimize, and help reduce the risk of the shale asset by understanding well spacing, stage spacing, and asset development plans, he said.

For Tom Tilton, CTO and vice president, Research and Engineering for Weatherford, a “very active and interesting trend” is the development of automated systems for control and real-time decision-making during the drilling process. This technology promises to provide benefits in both well control and overall drilling efficiency, he said.

“During the production phase of wells, there is more use of surveillance to measure and monitor fluid properties,” he said. “Advanced monitoring technology and algorithms are being developed to analyze and maximize production. And predictive methods are being refined to improve the accuracy, shorten the pilot phase of asset development, and maximize overall reservoir recovery.

“In addition, there is considerable research underway to optimize the understanding and efficiency of fracturing in shale reservoirs and to minimize the environmental impact of these operations.”

Tilton added that Weatherford’s higher priority research efforts include shale reservoir analysis such as wellsite geochemistry methods and geomechanics analysis to enhance wellbore placement and fracability potential.

The company also is focusing on improving software tools to manage large volumes of production data as well as providing enhanced capabilities to analyze the data. Measurement capabilities are in development to provide highly accurate multiphase flow measurement at the well. Additionally, Weatherford maintains a strong technology focus on rig-site safety and removing personnel from harm’s way through the application of process automation for various rig operations. The automation provides options to increase productivity and efficiency in closed-loop drilling operations, cementing, and completion processes.

Breakthroughs on the horizon

When asked about new technology in the next decade, companies gave their forecasts.

Rustom Mody, Baker Hughes. Next-decade technological breakthroughs will be driven by the operators’ needs, including a new class of metals with step-change chemical properties for extreme environments, elastomers rated to 40,000 psi and 371°C (700?F), automated drilling with greater and faster horizontal reach, smart fluids and chemicals with self-tuned viscosity, smart proppants or fluid additives for formation fracture mapping and reservoir condition sensing, logging while fracturing, nanosensors for fracture and stress mapping, fully autonomous long-term wellbore sensing and control, and interwell tracer technology.

Thierry Brizard, CGGVeritas. Seabed seismic acquisition using self-propelled nodes is one such foreseeable breakthrough. We also expect to see affordable 1 million trace seismic acquisition implementing a new generation of seismic sensors/sources and processing algorithms.

Ram Shenoy, ConocoPhillips. I expect we will mature our understanding of unconventional reservoirs to the same level as conventional reservoirs. This will require fundamental improvements in our understanding of hydrocarbon transport in shales at the nanoscale level, which is lacking today.

To fully exploit deep water, we will need to develop equipment to operate in harsher environments than ever before. To recognize fruitful exploration plays, we will need to continue advancing geophysical acquisition and imaging. We expect that advances in IT and computing, coupled with advances in robotics, will begin introducing automation to do more comprehensive monitoring and control of operations while reducing the number of people placed in challenging operating environments, particularly offshore.

Frank Van Ginhoven, Fluor Corp. I think we will make enormous progress in the Arctic and in subsea processing and will reach new levels of safety in design and implementation. We will reuse most of the water we require in processing, and our facilities will be increasingly energy-efficient and green. We also will make substantial progress on reducing carbon emissions.

Greg Powers, Halliburton. In the next five to 10 years I think we will see breakthroughs in the areas of telemetry and automation and control. One is an enabler, and another is an outcome of that enabler.

The enabler is going to be high-speed telemetry. When we’re drilling, measuring, or logging, we want to know what’s happening at the rockface and want that information topside right away.

Then you have to consider how to process this massive tidal wave of information that is being generated in high speed. It’s clear that you have to process it at high speed, and you have to process it faster than humans can think. So the challenge is to effectively and safely share the command and control of what’s happening downhole between a computer and people.

Tom Tilton, Weatherford. Development of smaller next-generation downhole sensor technologies that require less power or are self-powered downhole could enhance the ability to evaluate and monitor reservoir performance to optimize production and provide continuous monitoring of wellbore integrity, thus improving safety and reducing the risk profile. Also, today’s fuel cells are cost-prohibitive for most oilfield operations, but the critical mass in the automotive industry could potentially reduce the cost, making them a viable option.

Robert Siegfried, RPSEA. I expect to see better processing technology for cleaning up water, either for recycling and reuse in the oil and gas development process or for other beneficial uses. I also think there's a lot of opportunity for an increased understanding of the basics of fluid flow that will then be translated into more effective tools for planning stimulation treatments and for designing reservoir management scenarios that maximize recovery and minimize the need for additional stimulation treatments.