The oil and gas industry produces a tremendous amount of energy, but it also uses a tremendous amount of energy in the process. This creates a bit of a conundrum when new discoveries are hundreds of miles offshore or in extremely remote areas. The industry is tackling the challenge on a number of fronts.

A rapidly growing area is the use of dual-fuel engines and pumps, where natural gas is substituted for some of the diesel in a drilling or fracking operation to reduce cost and emissions. Several companies are offering dual-fuel solutions to their customers.

Offshore, a challenging area is providing power to subsea installations. Efficiency, reliability and standardization are all key concerns as offsets get longer, and operators are looking at a future subsea field in which there are no topsides installations and the power plant is on the seafloor.

Renewable energy is an area of increasing interest since many fields are in areas that receive lots of sunshine or wind. Operators are even harnessing the energy of their produced water to reduce electricity demands.

Finally, the use of digital technology is growing to enable operators to digitally plan for the movement of their hydrocarbons before a bit hits the dirt. Streamlining operations in this way can lead to more efficient development at a lower cost.

Power comes in many forms, and the next few pages examine the myriad options available to the industry today and tomorrow.

Dual-fuel solutions on the rise

Who says you can’t run a diesel engine on natural gas? Increasingly, companies are saving money by using field gas to power their drilling, completion and production operations.

By Rhonda Duey, Executive Editor

Natural gas can be a valuable commodity, or it can be a nuisance. When it is produced in a market that has no use for it, it typically gets flared, and as one famous satellite shot of the Bakken attests, that’s a lot of gas being vented into the atmosphere.

An alternative to flaring has recently gained popularity—dual-fuel power generation. These systems are capable of running on just diesel or a combination of diesel and natural gas and can even use field gas as a power source. In a fairly recent period of time several companies have come up with dual-fuel solutions that can replace as much as 70% of the diesel needed to run wellsite engines, according to Baker Hughes’ Connexus magazine.

According to Cummins’ website, the basic idea behind dual-fuel engines is that natural gas is substituted for diesel in the engine combustion process. Natural gas is introduced into the air intake system. Diesel is introduced near the end of the compression stroke and ignited, which also ignites the natural gas. “Dual-fuel engines deliver the same power density, torque curve and transient response as the base diesel engine does,” the website notes.

CAT has created a technology known as dynamic gas blending (DGB). According to literature from CAT, the DGB kit automatically adjusts to changes in incoming fuel quality. This allows engines to run on a variety of gases from associated gas to vaporized LNG with no loss of performance, according to the company.

CAT has teamed with several companies to expand its reach in this area. For instance, it recently announced a distribution agreement with FlexGen Power Systems to sell FlexGen’s full line of solid-state generator products, which can pair with any of CAT’s natural gas engines to improve power quality and reliability while reducing fuel consumption, maintenance and emissions, according to the companies. Recapture Solutions also uses CAT industrial engines to operate its generators, which can run on nearly all rich sweet gases, including flare gas. They also can switch to and from propane when natural gas isn’t available.

Cummins also offers natural gas engines in the 800-hp to 3,500-hp range for well servicing operations. The company’s website indicates that by 2020 Cummins predicts that nearly 30% of its high-horsepower engine production will be natural gas “due to the increasing abundance of the fuel and its relatively low cost.”

Additionally, it has recently teamed with Hythane to provide OptiBlend components on its rigs. The companies have teamed up to fully integrate the dual-fuel components with the engine and skid structure, providing a common control panel for both the engine controls and the dual-fuel control. The diesel oxidation catalyst and gas train have been integrated into the roof structure, and protective fuses and electrical components have been integrated into the Cummins Kato generator. The OptiBlend system is capable of replacing approximately half of the diesel with natural gas, according to company literature.

Baker Hughes offers what it calls its Rhino bifuel pump. The Rhino is a hydraulic fracturing unit, and many of them have now been converted using a diesel engine and a separate bifuel conversion kit. Programmable logic controllers (PLCs) signal a throttle valve that controls the gas entering the system and the substitution rate. Once combustion takes place, the PLCs gradually increase the amount of gas being injected.

Baker recently completed a project with Cabot Oil & Gas in the Marcellus Shale. While using the Rhino system the company twice set a Cabot record of nine fracture stages being completed in 24 hours. Cabot estimated that the use of the system allowed it to use 110,000 fewer gallons of diesel with its own field gas.

Making energy takes energy. These types of systems help stretch that energy a little bit farther.

Powering the abyss

Operators and suppliers work to overcome challenges in power delivery for subsea fields in deeper, farther and colder climes.

By Jennifer Presley, Senior Editor, Offshore

Today’s smartphones have more processing power than the computing system that safely guided NASA’s Apollo 11 spacecraft to the moon and back more than 45 years ago. For all of the differences between smartphones and the NASA system, their shared similarity is that without a steady supply of electric power, each would be a useless block of assembled raw materials. On land, at sea or on the seabed, the challenge of providing a steady supply of electrical power to thirsty industrial consumers is a global one.

As the oil and gas industry shifts more of its offshore processing operations from the topsides to the seabed, the “subsea factory” concept continues its transition from idea to reality. In 2015 all eyes will focus on Åsgard and Gullfaks as Statoil brings the world’s first subsea compression systems online in the fields. Seen as the next big step in the transition, its success will bring the company closer to meeting its subsea factory goal by 2020.

Making the transition

The shift from the traditional subsea power supply options to the next generation is being spurred on in part by the discovery of attractive prospects in deeper or more remote waters. The disbursements of these resources over a larger area will require longer step-outs from surface platforms to multiple locations. These are challenges that operators like Shell have been working on for some time.

“In general, when you think about discoveries in the Gulf of Mexico and Brazil, we really haven’t had too many subsea tieback systems that can be classified as being truly ‘remote’ from existing infrastructure. The discovery itself may be a remote field, i.e. far away from land and existing infrastructure, but the actual offset distance to the host facility has typically been less than 30 miles [48 km],” said Ajay Mehta, technology delivery manager, Shell E&P Deepwater Projects. “Given that, we have been able to deploy traditional power supply systems even as the overall complexity of subsea systems and the total power demand have increased.”

Three specific areas of focus for the company are reliability, retrieval and standardization.

“The first thing everybody talks about with power systems is about efficiency and minimization of transmission losses,” he said. “But with efficiency improvements as a given, we are putting a much larger emphasis on reliability and are working closely with our key suppliers in this area. In these deepwater settings, we also think a lot about our intervention capability. If something goes wrong, how are we going to fix it? We’ve consequently paid a lot of attention to the reliability of power systems. The third area is equipment retrieval and carefully thinking about the ease of accessing the system and doing any remediation work on it,” he said.

“Another key dimension that we’ve focused on is looking at how we can standardize some of these solutions we’re implementing,” he said.

The push toward standardization in subsea systems is one that has certainly garnered considerable interest by both operators and contractors.

“The reality of the business is that there are no two fields that are identical. Inevitably, you’re going to have to make trade-offs if you go with a standard design solution,” he said. “You will have situations where for some field applications you might have more functionality than you actually need, whereas in others you might have to live with some of the constraints that are inherent with a standard design solution. We therefore have to carefully think about the actual requirements of a given field with a holistic systems mindset and drive standard solutions wherever possible.

“For example, when you think about subsea tree systems, you certainly can apply a similar type of tree system for a given type of reservoir. When you talk about power, basically you want to make sure that the overall building blocks are the same.”

Next generation

For Bjørn Rasch and his team, the “subsea future is electrical.” Speaking at the recent Underwater Technology Conference in Bergen, Norway, Rasch—head of subsea power for Siemens Subsea Systems—added that he thinks “this is very much what the operators want to achieve. That in the future, we have less topside installations and move toward complete subsea processing plants with subsea power distribution on the seafloor.” Siemens is one of several companies working on next-generation subsea power systems. Rasch is leading the development of the company’s Subsea Power Grid (SPG). The SPG program started in 2010 to develop a subsea power supply and distribution system. It is currently undergoing long-term endurance testing as part of the qualification process.

The designs used in the R&D program were based on proven industry systems and equipment. The four main building blocks of the medium-voltage alternating current (AC) SPG include transformer, switchgear and variable-speed drive (VSD) and a power control and communication system, Rasch explained.

The step-down transformer is the main interface between the single power supply cable—typically with a transmission voltage up to 100 kV—and the power distribution system. From the transformer, voltage is reduced to 36 kV before it is distributed to the switchgear and then on to the individual VSDs—where the voltage is stepped down again to 6.6 kV—for each pump or compressor.

The power control and communications system is designed to provide data collected by sensors located through SPG components back to the topsides monitoring facility. It also distributes auxiliary power to the VSD controls for status reporting before the system is fully energized.

The system is being qualified for up to 30 years of operation in up to 3,000 m (9,843 ft) of water. A contract for full load operation via a pilot project is expected in 2015.

Looking past 2020

What are the power challenges after 2020? Researchers at GE Oil & Gas see a couple of areas where moving forward will create opportunities for innovation.

“Focus will be around system availability, around improving condition monitoring and—like the rest of the industry—there will be a focus on cost,” said Kristin Elgsaas, power product manager for GE Oil & Gas - Subsea Systems. “We are working to ensure that we offer an integrated and great system. It is why GE is now moving toward becoming a system integrator where we can leverage our complete portfolio. To create an integrated and optimized system, you have to look at everything from power generation through supply and then the function.”

“In the near- to mid-term we can make do with AC for quite some time. Looking into the far future, we see increasing number of loads, deeper water and probably very long step-outs with probably not as many loads but a higher load, like compression,” she said. “We need to start looking at these things now because the adoption of new technology by industry takes quite a lot of time.”

Solutions that use direct current (DC) voltage for power also are under consideration in addition to other alternatives such as low frequency transmission and pressure tolerant electronics, simplifying the deepwater design of electric power products.

“From a conventional perspective, a DC system could go much further and allow you to transfer considerably more power,” she said. “I think it is something interesting to consider, understanding that it is not going to happen tomorrow. The DC systems we see topside today do not necessarily fit for subsea. In the long run it is something that could possibly address both the longer step-out issue and the higher number of loads.”

There are several challenges in working with DC systems. For example, its nature is different than AC and will require new insulation materials, in particular for dry and wet mate electrical connectors.

“DC gives additional challenges to the insulation system than a conventional AC system, so we think that we’ll need to develop, or at least qualify, new materials for use with DC,” said Svend Rocke, chief engineer of subsea power for GE Oil & Gas - Subsea Systems. “On the insulation materials side, there needs to be more work done on its development and qualification. We need to understand better the long-term DC aging mechanisms to be able to deliver high reliable systems and products.”

Renewables provide a new alternative

New forms of energy can save on costs and reduce emissions.

By Rhonda Duey, Executive Editor

Fossil fuels and renewables don’t need to be at odds. While the hope of many is that someday renewable energy sources will replace oil, gas and coal, the reality is they’re not there yet. However, the technology shouldn’t be overlooked by those who need reliable power sources to run their oil and gas operations.

Wind and solar are the main energy sources that jump to mind when the word “renewables” is uttered, but there are other potential sources as well, including geothermal energy and even energy generated by ocean tides. All of these energy sources are being examined as operators look for novel ways to generate energy while reducing emissions.

Solar

Much of today’s solar energy is stored in photovoltaic panels, which despite improvements are not the most efficient storage devices. In the oil industry, the power of the sun is captured in a different way—by using mirrors to focus the energy to produce steam.

Chevron’s Coalinga Field in California is one of the beneficiaries of this technology. It began a pilot project a few years ago in which more than 7,600 mirrors focus solar energy into a boiler, producing steam to produce the heavy oil.

Chevron has relied on steamflooding for many years in its California fields, but the EOR project has come at a cost—generating steam requires some form of energy, and using fossil fuels creates emissions. Desmond King, president of Chevron Technology Ventures, explained in a video the need for a renewable technology. “It’s important to us in areas where there may be a high carbon cost and also important when we’re looking to use steam for [EOR] in areas where hydrocarbons may not be available or are too expensive to generate steam,” he said. Added Mike Walneuski, construction project manager for the Coalinga Power to Steam project, “I think Chevron has stepped up in the right direction, looking at opportunities to reduce natural gas usage, conserve energy, take advantage of the vast solar energy we have here in California and do better things for the environment.”

In another pilot project in Oman, Petroleum Development Oman teamed with GlassPoint Solar to build what is called an enclosed trough to create steam. The technology also relies on mirrors housed in a greenhouse that track the sun throughout the day. By December 2013 the system was generating 500 tons of steam per day with a success rate of 98.6% uptime, and by January 2014 the project was producing enough steam to replace 1 MMcm (36 MMcf) of natural gas.

Geothermal

According to information on the U.S. Department of Energy’s website, geothermal power can be used for oil and gas “coproduction,” in which low-temperature power conversion units can generate power from produced water. A heat exchanger transfers the heat from the produced water to a second fluid with a lower boiling point. The second liquid turns to gas, driving the turbines. This is a zero-emissions process, and the energy produced can power the field or be sold into the grid, the website states.

Technology benefits include capacity ranges of 500 kW to more than 10 MW, design flexibility and reduced lead times, scalability, and the ability to use off-the-shelf technology, it adds, estimating that the water produced each year from oil and gas operations could generate up to 3 GW of power.

According to information from Access Energy, which provides an organic rankine cycle product, any well that produces water that is at or above 82 C (180 F) is eligible for this type of technology. In addition to offsetting the site’s electricity needs, these systems decrease net operating costs, extend the life of the field and in some cases are eligible for renewable energy credits.

A test case funded by Gulf Coast Green Energy (GCGE) and the Research Partnership to Secure Energy for America used an ElectraTherm Green Machine on a Denbury Resources producing oil well. According to GCGE’s website, the well produces at 2,896 m (9,500 ft) under geopressure and produces 800 bbl/d of oil and 4,000 bbl/d of water. The hot produced water is being used to generate energy to run the electric submersible pump in the well. “Projects like this qualify for a 30% Investment Tax Credit from the IRS,” the website notes.

Tidal energy

One of the newest forms of renewable energy being researched is the potential to harness ocean tides using underwater turbines similar to wind turbines. Issues abound, from finding stable places to house the turbines to the potential for damage to marine life. But the concept is gaining ground.

In an article on RenewableEnergyWorld.com, several locations in the U.K. were discussed that show promise for putting energy from tides into the grid. In the article, tidal stream technologies are described as an evolution of the wind turbine adapted to a greater density than air.

Generating electricity with these devices requires a current speed of 2.5 m/sec (8 ft/sec), and even in rapidly moving currents requiring smaller rotor diameters, the rotors can reach 12 m to 20 m (39 ft to 66 ft) in diameter and rotate at about 15 rpm.

A study of the Severn Estuary bordering England and Wales was completed in 2010, and it was determined that a series of tidal lagoons could be fitted with turbines to provide up to 1.2 TW/year of power. The plan is to use a balanced technology approach in which different technologies can be employed collaboratively.

Several companies familiar with the oil and gas industry are looking at tidal energy, but not necessarily from an oil and gas standpoint. Siemens installed the first commercial tidal current power plant, SeaGen, offshore Ireland. The plant can produce up to 20 MW/d.

“From a technology point of view, SeaGen looks like an underwater windmill,” said Gerda Gottschick of Siemens. “It consists of two twin axial flow rotors mounted on a support structure. Each of its two drive trains weighs 27 [mt] and is equipped with a rotor measuring 16 m [59 ft] in diameter.”

She added that the system can produce electricity for up to 20 hours a day regardless of weather conditions.

“The current project is only a starting point,” she added. “Siemens believes in the potential of tidal power plants and keeps investing in this technology.”

So far, though, the company and its partners have not made any inroads into powering offshore (or onshore) oil and gas facilities.

Modec Inc. also is working on a hybrid turbine that harnesses power from both wind and tides. The Savonius Keel & Wind Turbine Darrieus (SKWID) combines Modec’s Darrieus wind turbine with its Savonius current turbine, which will not only generate tidal energy but also act as a ballast to provide stable performance.

So far the company hasn’t tested the system to provide power to offshore facilities, but Norihiro Yuzawa of Modec’s New Business Development Group said this could be a further market. “Now we are fabricating the SKWID prototype and doing onshore testing,” Yuzawa said. “The first SKWID will be launched offshore this autumn, and we will start offshore testing after the launch.”

E&P success: digitally powered

Modern software applications allow operators to fuel E&P decisions digitally before they translate to the physical realm.

By Antony Brockmann, Schlumberger Information Solutions

This industry is powered as much digitally as it is physically. Operators must deal with significant and constantly changing information volumes. Repositories are updated in real time with field data from measurement equipment and sensors. As well as input and storage considerations, operators must ensure that asset teams stay productive and decisive in the face of this potential information overload. This is possible when they are able to access easily relevant, up-to-date information in context and then share this information to collaboratively solve problems in a single software platform.

In addition, E&P success depends on the quality of decisions made, which shapes every stage of the journey a hydrocarbon molecule makes from discovery to recovery. This hydrocarbon journey—or pathway—presents an opportunity for ideal end-to-end digital integration for the industry. The better the industry integrates to create holistic systems to drive decisions along the E&P process, the better it will perform. Modern software allows the required level of multidisciplinary integration to be realized to enable asset teams to make investment decisions in the digital realm and collaborate to reach optimal results.

The best investment decisions are supported by digital models that drive rich analysis and interpretation through the application of industry best practices. For example, an understanding of the dynamics of charge over geologic time can be gained by modeling hydrocarbon maturation and migration from source rock to trap.

The hydrocarbon pathway is enabled by integration on many levels—integration across each exploration, development and production phase; integration between the physical world and digital models; and the connection of technical experts with key decision makers. Each of these areas of integration improves technical and financial performance through increased exploration confidence, more efficient execution of capital projects and optimized production and recovery rates.

The hydrocarbon pathway is characterized by a series of important digital decisions at key project investment stage gates. For example, stochastic modeling of the key risk elements of trap, reservoir, charge and seal—in an integrated 3-D software canvas—can be used to inform the sanctioning of a wildcat well, which in turn, after appraisal, leads to the first decision gate in field development: the concept stage. Here multiple probable subsurface models are tested for economic viability as possible field development scenarios, informing critical engineering design investment decisions.

Subsurface reservoir uncertainties also can be integrated with the optimal placement and number of wells tied to appropriate network and surface facilities. Fiscal regimes are digitally married to stochastic production profiles in petroleum economics software before advancing to the design phase, where uncertainty is further reduced with ongoing reservoir, well and network simulation in an integrated asset approach. Additional simulations are used to understand the resultant variations in permeability and the impact of subsidence on predicted cumulative production.

Finally, during production, EOR decisions are increasingly required as the industry works to increase worldwide recovery rates. Appropriate EOR schemes must be considered and screened before the optimal solution is selected and scaled across many orders of magnitude—from a pore throat two microns wide to full-field studies of chemistry, sweep, connected porosity, permeability and wettability.

Case study: Kuwait Intelligent Digital Field

An example of how hydrocarbon pathway principles have been applied to a modern unconventional production scenario can be witnessed in the Kuwait Intelligent Digital Field project undertaken for the Kuwait Oil Co. (KOC). KOC needed an integrated digital solution to increase production and recovery rates in an HP/HT heterogeneous carbonate reservoir environment while helping to reduce costs and maintain safety and reliability in the presence of H2S and CO2. The company also sought to reduce nonproductive time (NPT) and shutdowns, better use data to accelerate decision-making, and improve multidisciplinary collaboration.

A solution combining the Avocet production operations software platform and OFM well and reservoir analysis software was chosen to introduce a server-based workflow-oriented approach to production management with data consolidated in one environment rather than in multiple applications. KOC also sought to create comprehensive workflows to automate data acquisition and conditioning, event detection, alarms and production performance management.

The solution is able to import and store data from a number of conventional applications to build production workflows that deliver intelligent notifications to optimize daily constraints. This includes ECLIPSE reservoir simulation software and PIPESIM steady-state multiphase flow simulation software, which can be seamlessly embedded to provide model-based pressure-volume-temperature analysis as well as estimations on production rate and network pressures. KOC’s new integrated solution enabled the project team to design real-time production surveillance and optimization workflows, automating and standardizing many existing engineering processes.

The results of these new workflows, including key performance indicator (KPI) information, are accessible to KOC users via a web-portal surveillance solution for monitoring production at a glance. KPIs were introduced as part of the system implementation to provide specific, reliable and accurate information tied directly to strategic production and business goals.

Immediate benefits

The new digital solution allows KOC to efficiently manage its knowledge base of technical data and collaborative insights. Acquired field data are better organized through the new integrated platform solution. Visually integrated datasets via management display screens improve access to tailored production information, allowing KOC to maximize data value through faster and more accurate decisions.

The new integrated framework provides production workflows from the field to the main office. It has enabled validation of high- and low-frequency data for all production optimization processes and models, transforming field measurements into predefined performance metrics. In addition, multidisciplinary collaboration has improved through the introduction of a common digital platform and interface, streamlining operations. Routine tasks have been automated, further increasing productivity. Production issues can be proactively identified through the new system, and NPT has been reduced by more than 50%.

Quantifiable safety benefits include the ability to recognize potential equipment hazards digitally before they present themselves physically. Chokes are now remotely operated and controlled, and remote monitoring and shutdown capability enables well closure and isolation to be undertaken from a safe location—all important capabilities given the unforgiving reservoir environment and presence of gases.

Digitally integrated decisions

Modern integrated software platforms have evolved to guide every key decision in moving hydrocarbons along the pathway from pore space to balance sheet. Whether the operating arena is conventional or unconventional, there will always be unforeseen challenges that arise over the life of a well. Decision-making agility, made possible by a streamlined but deep digital evaluation process, confers a distinct advantage to asset teams—whether that’s an improved reserve replacement ratio; lower finding costs per barrel; fewer dry wells; or the selection of optimal field development plans coupled with reservoir, well and network models to ensure lower overall capex/bbl and faster time to first oil.

Empowering oilfield safety practices

By David Dickert, Aggreko

With unconventional oil and gas operations in North America continuing to increase at an exponential rate, producers and service providers are working overtime to ensure the highest levels of productivity. However, the sense of urgency to meet production and revenue goals has the potential to impact job safety, causing safety to be deprioritized or overlooked.

According to an April 2014 Bureau of Labor Statistics report on fatal and nonfatal occupational injuries and illnesses in the oil and gas industry, support activities for oil and gas operations accounted for 58 out of 112 fatal work injuries recorded in 2011.

The potential for incidents can be especially high in the field of temporary power. Supplemental power installations can be one of the most dangerous services provided on an oilfield site. Without taking this into consideration, project engineers and managers could be cutting corners to get production online, compromising the safety of co-workers and customers.

Selecting a power provider with an established safety program is essential to not only guarantee a successful outcome of a production goal but to also ensure the overall well-being of all participants operating on site. When evaluating a temporary power company’s safety program, project managers should take into account several factors.

People

People on a project site should wear proper personal protection equipment while working where hazards exist. This requires steel-toed footwear, highly visible safety vests, head and eye protection, and cut-proof gloves. Technicians should provide proper certification that they are trained to install and operate equipment in a safe and neat manner. They should be geared with H2S monitoring devices, and there should be an option proposed to leverage alternative fuels vs. diesel to improve air quality around the workers.

Equipment

Oilfield equipment should be UL-listed and meet National Electrical Code standards for intended use. Generators need to be grounded using appropriate materials. The installation area should be clearly marked by the local utilities for any underground hazards, and cables must be rated for outdoor use. Operators should ask if there is an option to run generators via an alternative fuel source as well as the availability of remote monitoring services or telematics to track the performance of their temporary power installations to identify unforeseen safety issues.

Safety culture

A strong HSE program must be evident by the provider’s employees during on- and offsite operations. Power providers should discuss job site safety during daily pre-planning meetings, and their crews need to have Stop Work Authority. Contractor employees should be well-hydrated and properly rested when working in extreme weather conditions and areas of higher than normal activity, and the power provider should work with the operator to review HSE procedures in place and identify any potential hazards. A power provider should also insist that its subcontractors follow established safety rules while on site.

Experience

There is nothing more credible than real-world experience in the oil patch. Temporary power providers with a strong and established safety culture and record are valuable partners to add to a team. Companies promoting new equipment and lower costs without a verifiable track record should be examined closely. The operator should ask for real examples of previous installations comparable to its operation’s needs. If the power providers cannot produce comparable examples, this will likely introduce safety risk to the project, company and employees.

As exciting as times are in oilfield production, there can be no compromise for safety. If power generators are not properly installed, electricity can be very dangerous to the team. Teams should be empowered to cautiously evaluate and hire a temporary power provider that is engineering for safety as well as performance and reliability. It could require extra time and added costs to ensure everyone makes it home in the same condition as they arrived, but it’s a very small price to pay compared to experiencing an incident that could have been prevented.