Integrating Operations

Arcan Resources is a Calgary-based junior exploration company. One of its core plays is developing Devonian tight carbonates in central Alberta. The company drills about three dozen wells a year on a pad system. It uses conventional directional steering methods, with a 2,500-metre vertical and a 1,500-metre lateral in each well.

Mike Krooshoop is drilling manager for Arcan. When he first signed on, he wanted to make his mark. “At the time, it took about 20 days to drill a well and run the liner,” he recalls. “I came up with an aggressive plan that pushed the bits to the limit, and we completed the well in less than 17 days. It was a record time for the company, and I felt very proud.”

Unfortunately, the vertical wellbore spiralled, and the dogleg was too tight. “The [vice-president] of production came to me and said that the rods were buckling and we couldn’t get the pump past the kick-off. Because of that, the well produced 50–100 barrels per day less, which tends to add up over a three-year well life.”

Krooshoop realized that his big mistake was not communicating with the other players on his team. “It’s nice to be able to say that you completed a well in record time, but if the production engineer can’t get the projected production because the hole is poor, then he doesn’t say, ‘Hey, great record,’ he says, ‘It’s your fault.’”

Several years ago, Halliburton launched an initiative called digital asset, in which drilling and completion experts work with the company’s suite of proprietary hardware and software to oversee the life cycle of a client’s well, from inception and drilling to stimulation and production. Eric Hards, senior project advisor with Digital Asset, is all too familiar with Krooshoop’s unfortunate circumstance. “There is so much opportunity for miscommunication, especially at handover points like when the drillers hand over the well to the completion and stimulation people. We are eliminating those handover points and making the process much more seamless.”

Drilling in North America is undergoing a revolution, as new equipment, processes and techniques are introduced on an almost daily basis (see related stories). The driver for all this change is the array of new unconventional plays that have emerged in the last several years. The Barnett and Eagle Ford shales in Texas and the Bakken formation in North Dakota have proven to be major producers in the United States, but Canada also abounds in unconventional potential. In Saskatchewan, Bakken production has risen from 1,000 barrels per day in 2004 to 67,000 barrels per day in 2011, and recent land sales have raked in $1.4 billion for the province.

In Alberta, the Devonian Duvernay shale, which underlies much of the province, is considered the source rock for the Leduc reef plays that launched the modern era of petroleum exploration in Canada. Much of the $3.5 billion spent on land sales in 2011 was fuelled by companies like Encana Corporation and Chevron Corporation looking to build a land position in the oil-rich rock. Most of the wells drilled are still confidential, but details that have emerged indicate excellent prospects. In late 2011, Celtic Exploration Ltd. drilled an 1,800-metre lateral into the shale in the Kaybob area, which flowed 2.1 million cubic feet per day and 75 barrels per day with a 56 degree gravity condensate.

Regardless of the play, industry participants agree that operators need to seek out the most efficient means of tapping the resource. “Unconventional wells are no different from conventional wells,” says Brad Dunbar, fixed-cutter product manager for Halliburton. “Clients want to lower their operating costs, to drill to the final depth faster and improve overall performance.”

And that, says Dunbar, means every facet of exploration and production is increasingly coordinated to maximize performance and efficiency. “There is a trend toward operators and service companies to work more as a team, to use software to plan out the best possible performance, to make sure you have the best combination for each well.”

“One of the key things we are starting to do with the integrated stimulation workflow and the shale field optimization workflow is to get all disciplines—geologists, geophysicists, engineers, well planners—into one space where it allows people to communicate,” says Rich Dodds, strategic business manager, Digital Asset. “That way, everyone has access to every nugget of information. the whole process is underpinned by technology, but the real value is that people are talking to one another.”

The concept of integrating all facets of the well life cycle is not new. “There have been various forms of integrated operations since the 1980s,” says Chris Mackie, vice-president of marketing and business development for Baker Hughes Canada. “Traditionally, clients see service companies entering the picture at the drilling phase, but the biggest evolution is our involvement at the geoscience stage, where we look at the reservoir properties and then tailor the field operation to get the best long-term return on investment. On a recent multi-well project, we delivered an 11 per cent reduction in the overall drilling cost by working in an integrated fashion with our customer.”


The modern concept of integration is based on several trends that have emerged over the last few years. One major change is the demolition of “silos,” the vertical separation of geological, geophysical and engineering tasks, and the construction of lateral collaborative teams that communicate throughout the life of the well. “You can now have small, virtual teams that meet by video conference, use data collaboration, and work together and hand off tasks around the globe,” says Mackie. “Whether you’re in Houston or Calgary or Norway, you now have the ability to bring the best person to the task at hand.”

The value of constant communication can pay dividends in a myriad of ways. If a driller is penetrating a sand formation and his rate of penetration suddenly drops, he might think he’s broken a bit and pull out, notes one industry expert. But if the geologist has let him know that the sand has shale lenses, he knows what is happening and keeps drilling.

Another important trend has been the consolidation of vast volumes of geologic, seismic, drilling and production information. Companies now have unified master databases where propriety information and learning are captured. They also integrate public information as well as service company expertise. “Halliburton has a huge database of learning and integrated systems,” says Dave Savelle, technology director for Digital Asset. “We see an awful lot more than even our largest customers. We can augment each technology and workflow.”

The array of knowledge allows companies tremendous leverage when producing unconventional plays. “In many of the shale plays, and in regions of tectonic stress like the Canadian Rockies, it is important to understand the geomechanical stress in the reservoir,” says Mackie. “We do this by integrating seismic, geologic and petro-physical information with drilling and production engineering experiences. The orientation and magnitude of those stresses has a great impact on well design, well trajectory, well spacing, stimulation and optimizing production from fractured reservoirs.”

The evolution of software also allows far greater reduction of risk and optimization of the best available technologies. “Our customers want to reduce risk and save money at the same time,” says Mackie. “On the drilling side, we have Oasis Drilling Performance Services that is designed to optimize planning and performance. The planning optimization has two facets: the algorithm side, which works to reduce risk, and the databasing side, where we can look at similar situations and analyze the data to improve performance.”

Much of the planning stage focuses on controlling torque, drag, and sticking and slipping. Torque is the amount of circumferential force on the bottomhole assembly (BHA). Drag is the amount of axial force as the drill string pushes down into the rock. Excess torque and drag can cause loss of directional control, a tendency for the hole to spiral, and an increase in sticking and slipping. Sticking occurs when the bit is over-engaged in the rock and it stops drilling; energy builds up in the string and eventually overcomes the stick, and the bit slips, causing vibration and damage to the BHA.

“We do a lot of analysis and planning using a suite of software,” says Halliburton’s Dunbar. "SPARTA analytical tools are used to do strata analysis, looking at the strength of the rock that the bit will pass through. We then use iBitS design software to design and look at the behaviour of the bit during various rates of penetration. Direction by Design [DxD] software is used to look at the various trajectory forces on the bit as it cuts a curve through a formation. MaxBHA software looks at the entire BHA and how it will behave during drilling.”

Cost-effectiveness is a major consideration while planning a horizontal well. The drilling engineer has to decide, for instance, at what depth to kick-off; if he or she chooses 10,000 feet and 3.5-degree dogleg, less footage is drilled overall, but there is a higher possibility of getting stuck. If the engineer chooses to kick-off at 8,000 feet and have a three-degree dogleg, there is less risk of sticking, and torque and drag, but the well footage is longer. Thanks to planning software, hundreds of design scenarios can be compared to optimize the best combination in terms of time, risk and cost.

Return on investment is also critical. A 4,000-foot lateral might increase production seven times over a vertical well, and a 5,000-foot lateral might increase production 7.5 times. The engineer can run a score of scenarios to determine if the extra 0.5 is worth enough to recover added costs.

Although new processes and technologies that improve performance, reduce cost and increase production are always welcome, Krooshoop recommends a conservative approach. “It’s important to improvise and try new technologies, but my advice is to implement one improvement at a time, as it makes it much easier to evaluate what is adding short-term value, and what is adding life-cycle value. It costs me $60,000–$70,000 per day to drill. It’s no good if I save money by going to a water-based mud, but I add five days to my drilling time.”


Currently, research and development is focused on pushing the envelope. “In the short term, we are going to see operators testing the boundaries of lateral length,” says Todd Broome, production manager for Halliburton’s horizontal completion tools. “On average, a lateral is around 5,000 feet, but we are seeing horizontal legs of up to 10,000 feet in the Bakken.”

In the long-term future, service companies are looking to deploy artificial intelligence, where software monitors real-time drilling and analyzes what is happening in order to forewarn or guide operations. “We are working on that right now,” says Dunbar.

Another major goal is real-time leveraging, or predictive analytics. “You take real-time information and use case-based knowledge to predict the performance of the system,” says Savelle.

In the meantime, the oil and gas industry has plenty of valuable ideas to absorb and implement. “There is a great opportunity to improve understanding through communication and education about the importance of what everyone does, as well as the importance of what they do to everyone else’s job,” says Krooshoop. “Experienced drillers tell me, ‘If you just want to focus on your job, then you’re going to over-promise and under-deliver.’ They coach us to be part of a team, to provide the best usable wellbore—not a wellbore in the fastest time.”


New Kit On The Block

Latest Hardware Makes Drilling, Stimulation And Production Faster, More Efficient

The array of exciting new plays sweeping across North America requires new and innovative technologies to make them economically viable. Many operators are adapting a kit that was developed for offshore wells, making them work onshore. The conventional rig, with a fixed derrick and a manual rig floor, is rapidly being replaced by automated drilling rigs (ADRs). The derrick has been superseded by a self-erecting hydraulic telescoping mast. The mast itself has a hydraulic top drive built in, and is equipped with a torque wrench and automatic pipe handler. Conventional manual tongs have been upgraded to hydraulic power tongs.

The ADR operator uses digital controls to set up the various functions and operating parameters for each well (such as upper and lower hoist limits and speed), by using the rig’s programmable logic controllers. The rig functions are controlled by various joysticks, including the drawworks joystick that raises, lowers and stops the travelling blocks, and the top-drive joystick that operates the pipe handler rotation. The driller monitors equipment and operation on touch screens that report on vital components such as the mud pump, torque wrench and rotary table. Drilling information can be displayed in real time and compared to historical performance in order to consistently optimize weight on-bit and rate of penetration.

ADRs reduce non-productive time dramatically. While conventional rigs may require 20 loads to move from site to site, comparable ADRs can have as little as four, with the self-erecting mast and other components mounted onto trucks, trailers and skids. Some rigs that are designed to drill multiple wells on the same pad use a hydraulic system in the substructure to “walk” the rig at speeds of 15–30 feet per hour between wells. These innovations can add 45–75 drilling days per year compared to a conventional rig of similar capabilities.

Lateral wells, especially in plays where the reservoir bed may be thin, require advanced directional drilling methods. Steerable mud motors, which use a mud-driven turbine in the bottomhole assembly (BHA), are now being replaced by rotary steerable systems (RSS). The primary component of RSS is the steering tool, divided into push-the-bit and point-the-bit. Point-the-bit has an electric motor that is offset on the drive shaft; the electric motor rotates in the opposite direction of the drill string, holding the shaft geostationary and keeping the tool face pointed in the desired direction. Push-the-bit has a series of pads that rotate with the string and push on the side of the borehole and exert a force in order to deflect the bit in the direction the operator wants to drill.

The direction of the steerable tool is measured while drilling with a directional module that measures inclination and azimuth using tri-axial magnetometers and gravity sensors. The BHA contains a transmitter/receiver to send data up-hole and receive commands back downhole. The most common transmitter/receivers transmit coded pulses through the mud system.

Steerable systems also commonly incorporate logging while drilling, or LWD. LWD tools include resistivity, gamma ray, sonic, pore pressure and a host of other specialty devices. In a shale play, operators use gamma and sonic to keep on target and to develop the hydraulic fracturing package. “With an LWD suite of services, coupled with our reservoir modelling services, you can steer the bit faster and more accurately,” says Chris Mackie, vice-president of marketing and business development for Baker Hughes Canada. “We recently completed a 14-well project where we worked as a team with a Canadian customer. We were able to show a 40 per cent reduction in drill time.”

Mud helps drill bits in several ways. “It removes cuttings as the bit penetrates the rock, it lubricates the string and BHA to reduce friction, and it cools the bit,” says Brad Dunbar, Halliburton’s fixed-cutter product manager. “A diamond-edge bit starts to turn to graphite when it reaches around 1,000 [degrees] Celsius, so it’s important to keep its temperature below 800 [degrees] Celsius. There are many different types of lubrication, from pure water to a water-mud mixture, to synthetic mud or oil-based mud. You choose the best lubrication based upon not only how well it helps the drilling process, but also how it interacts with the reservoir. Some muds can penetrate half a foot into the reservoir, which inhibits the flow of petroleum to the wellbore.”

The technologies for managed pressure drilling (MPD) and underbalanced pressure drilling (UPD) have been around for several years, but they are just starting to gain traction in the onshore industry. With conventional mud, the driller increases the weight to avoid a blowout, but then risks permeability damage at the reservoir well interface. With MPD, the driller balances the mud weight as close as possible to the reservoir formation pressure. With UPD, the driller places the mud weight at less than the reservoir formation pressure, so that there is very low formation damage, which allows the hydrocarbons to flow for early production. In order to avoid a blowout, a downhole hydraulic valve is installed so that the driller can close off the well and secure the reservoir pressure so that it doesn’t flow to surface.

Drilling fluids materials are also getting much more sophisticated. Drillers are experimenting by replacing barite with five-micron-sized particles of manganese oxide. The manganese oxide weights up the mud, but does not plug up the reservoir, allowing for greater permeability at the reservoir/wellbore interface. Industry participants note that by designing a sophisticated drilling fluid process, the operator can increase production by 20–30 per cent.

Over the last several years, research and development has allowed advances in polycrystalline diamond compact (PDC) cutters and drill bit bodies. PDC bits are made of synthetic diamond powder that is pressed under one-million pounds-per-inch pressure, and 2,000 degrees Celsius, to form a cutting edge that retains its sharpness for extended drilling. Matrix bodies are created using powdered metallic tungsten carbide that is then mixed with a binder and formed under heat to create a strong, rigid foundation for the PDC cutters. New steel formulations are also being developed for bit bodies. Drillers can now choose one customized bit that can drill the vertical, dogleg and horizontal sections of the well, eliminating several trips out of the hole.

The stimulation and completion components of an unconventional well can easily exceed the drilling costs, and much research and development is focused on making the process more efficient and economical. In a traditional plug-and-perforation fracturing technique, a service company lowers a perforation gun to the interval and perforates the casing. They then pull out and hydraulically fracture the perforation. The hole is then plugged above the perf. This process is repeated on the intervals above. Several dozen fractures are typically performed on each well.

In order to speed up the process, Halliburton recently adapted production-sleeve technology to the fracking operation. The RapidFrac system uses a metering process that enables a single ball to open multiple sleeves isolated within an interval by swellable packers. Up to 90 sleeves can be incorporated into any one horizontal completion, ensuring maximized stimulated reservoir volume. In a paired set of test wells in the Bakken, Halliburton was able to cut the frac time from four days to two days, and significantly reduced water usage. “We are using this in North Dakota, and the practice is migrating north into Canada,” says Ron Dusterhoft, a solutions director for Halliburton Digital Asset.

Coiled-tubing fracturing is also becoming very sophisticated, says Dusterhoft. “When it comes to coiled tubing applications, Canada is a global leader. The system we are using in Canada has no limits on the stages per well, and it is very efficient in terms of hydraulic horsepower, requiring around 2,000 horsepower, versus 20,000 horsepower for conventional high-injection-rate systems, commonly used in the United States.”

Service companies are also offering real-time collaborative technology in which the operator and expert consultants can measure stimulations as they occur with microseismic and tilt-meters in order to understand the best way to frac a reservoir. “We operate more than 30 BEACON centres [real-time operation centres] around the world where jobs can be viewed and managed in real time with support and expertise available 24/7,” says Mackie.

Finally, offshore technologies used to produce multi-zones from horizontal wellbores are gaining traction onshore. Known as flex wells or intelligent wells, they rely on fibre optic technology and production equipment that incorporates an array of monitors and devices to control downhole valves. “Fibre optic technology is having a big impact on production,” says Mackie. “You place gauges downhole to see what is happening in real time. With this information, you can, for example, vary the operation of electric submersible pumps to maximize production and reduce costs.”


 Timely Lessons

Workflow Software And Technology Allow Drilling Operators To Catch Learning On the Fly

Oil companies around the world are well aware that valuable geoscience and drilling information is often lost due to a lack of formal process for capturing it. Master databases are now being designed to incorporate and leverage the proprietary interpretations geoscientists make to seismic and geological knowledge. But timely and effective processes to permanently secure vital information while drilling have been ad hoc. Now, service providers are working on ways to capture lessons learned behind the drill bit through integrated workflow technology.

Workflow technology uses a combination of software and hardware to look at what the driller expects to see, what is actually being encountered and how the new knowledge can be used to enhance not only the well being drilled, but all wells in the future. Dave Savelle is technology director for Halliburton’s Digital Asset. “The Digital Asset organization looks for opportunities to integrate our people, processes and technologies into workflows for the entire [exploration and production] life cycle,” he notes. “The concept was first put forward in 2006, and work started in 2008. Our first two modules, released in 2010, were the Reservoir Contact Workflow and the Stimulation Monitoring Workflow.”

Halliburton’s workflows break the process down into three facets: Model, Measure and Optimize. “Whether you are drilling a well or conducting a frac job, you leverage real-time capability when the work is being executed in order to compare what is happening to the model and to be able to optimize your work while the job is going on,” says Savelle. “The subsurface doesn’t often react the way the model has predicted, so you have to respond to changes, capture that new information, then model the next process with the lessons learned. The Stimulation Monitoring Workflow allows us to use microseismic to gauge whether a frac is going where it should be compared to the predicted model, all in real time.”

The impetus to capture and incorporate drilling data began offshore, where wells can cost hundreds of millions of dollars. “Traditionally, companies have come to service providers seeking out discrete services, such as the best bit or fluid at the cheapest price,” says Savelle. “Now, how our customers purchase from us is evolving. Offshore operators are gravitating toward integration; we’re seeing around 25 per cent of wells in the Gulf of Mexico using some variation of the process.”

The next logical step after integration was real-time control over not only the drilling process, but also the ability to incorporate data while the bit was still in the hole. Halliburton recently finished a project with an operator in a deepwater field in the Gulf of Mexico. “We did Model, Measure, Optimize from end to end. We were able to show a significant decrease in NPT [non-productive time], above 10 per cent; that makes a big difference offshore.”

The Digital Asset team has 60 members, but Halliburton is also leveraging its sizeable development group for research and development. “As an example, we are developing the Drilling Performance Workflow with the subject-matter experts from our Sperry Drilling, Baroid, Drill Bits and Landmark Software & Services product service lines,” says Savelle. “The workflow will reduce drilling days by focusing on drilling elements such as reducing torque and drag, hydraulics management, etc.”

Halliburton is also working with their Landmark product service line on the Collaborative Well Planning workflow, which builds a reservoir model and a well pattern model, and even the drill path, dogleg and length of lateral. “It can do a 500-well plan in a matter of minutes,” says Savelle. “In all, it will have 32 discrete technologies. While the drilling program is underway, it can examine real-time information and incorporate changes. For example, the model may have oriented the lateral wellbore perpendicular to the primary reservoir fracture pattern, but microseismic or tilt-meter information during stimulation indicates that the well direction should be adjusted a few degrees off perpendicular.”


Service companies around the world view automation as the next paradigm step. “What can we do to preemptively look at where we’re going to be, and automatically adjust when needed?” says Savelle. “We are not talking about taking control out of the hands of the engineer, or compromising safety. We are talking about placing more science behind the engineer so that he can make better decisions right on site.”

Another major goal is real-time leveraging, or predictive analytics; the drilling system takes real-time information and uses case-based knowledge to predict the performance of the system. “The O&G [oil and gas] industry is ahead of many sectors in a large number of areas, but they are way behind in predictive analytics,” says Savelle. “In retail, for instance, a teller scans a tube of toothpaste through the till, and there is a whole series of actions running right back to the warehouse. There are many technologies in [the industry] where we could apply predictive analytics. For instance, you examine the track of a meandering lateral wellbore and predict that, within 24 hours, there is a 50 per cent chance of encountering a stuck pipe.”

Can workflow processes be adopted for hot plays, like shale oils in the United States and Canada?

“There are many opportunities for integration onshore, and they are being developed,” says Savelle. “During the start of the shale boom, operators were doing a very high volume of drilling to meet lease obligations. Now, they are catching their breath and saying, maybe carpet bombing isn’t the optimal way to develop this shale. They want a smarter approach in which they reduce drill time and increase frac penetration. We are now seeing about 10 per cent of shale wells following the integration process.”

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