Real-time data, reservoir model combination addresses GOM challenges

Schlumberger is focusing on addressing geological and reservoir challenges in the Gulf of Mexico that lead to narrow operating environments, Wallace Pescarini, vice president, deepwater operations at Schlumberger, said. “As you access the reservoir, drilling through the salt, in the pore and frac gradient, and in very narrow operations, the weight window adds challenges during the drilling process.”

By Joanne Liou, associate editor

Growing activity in the Gulf of Mexico (GOM) reflects the industry’s capability to meet increasing operational challenges in deepwater, where activity has returned to pre-moratorium levels despite more stringent regulations. Schlumberger, which relocated resources to other basins during the moratorium period, has moved resources back to the GOM as activity returned and is continuing focus on geological and reservoir challenges that lead to narrow operating environments.

“That is a challenge for the GOM, and some potential shallow hazards, such as shallow water flow or near-surface faults, add more complexity to the operation. As you access the reservoir, drilling through the salt, compounded by uncertainty on the pore and frac gradients and very narrow operation mud weight window, adds challenges during the drilling process,” Wallace Pescarini, vice president, deepwater operations, said.

To address such challenges, Schlumberger is combining real-time drilling evaluation data with the reservoir model using advanced interpretation techniques to analyze and act on the data in real time. Seismic-guided drilling is one example, in which the LWD checkshot data are used to constrain the surface seismic model in real time to help narrow down the depth uncertainty and to identify overpressure zones in front of the drill bit, Mr Pescarini said.

In the GOM, petrophysical and seismic data from offset wells are used to create a model of the formation pressures. “By leveraging the latest advances in computing power, we are now able to re-migrate the seismic model around the well while drilling,” he stated. “This allows us to predict the formation pressure up to 1,500 ft (457 meters) in front of the drill bit.” The drilling program can then be modified to reflect the real-time predictions.

Another trend that continues to evolve, mainly to respond to the described operational complexity, is the capability to bring drilling experts together as an integrated team during the planning and execution phases, supported by real-time workflows. “This is a trend you are seeing in the market. Specifically in the GOM, we are very well supplied with these experts and have located them in our PetroTechnical Engineering Centers to ensure that a collaborative environment is created.”

Andy Hawthorn, Schlumberger business development manager, earth model building, explained that there is a four-fold increase in deepwater NPT due to wellbore instability and mechanical instability, during a presentation at the company’s re-launch of its Digital Technology Theater in Houston in March.

The ultimate aim is to drill fewer wells but produce more oil. “To be successful, every well has to be in the right place and be able to produce over the entire life of the field,” Andy Hawthorn, Schlumberger business development manager, earth model building, said during a presentation at the company’s re-launch of its Digital Technology Theater in Houston in March. “Industry statistics show that with GOM wells in over 3,000-ft water depth, about 45% to 48% of all wells require a sidetrack. Of those, 50% require more than one sidetrack, which means we’re not getting it right the first time, all the time.”

Close collaboration among operators, contractors and service providers will be key going forward, as downhole nonproductive time (NPT) continues to increase, driven by the increasing geological complexity of deepwater E&P. “There is a four-fold increase in NPT due to wellbore instability and mechanical instability,” Mr Hawthorn said. “There is also a four-fold increase in the number of times BOPs are activated as the complexity of wells increases.”

Reducing NPT will require a combination of efficiencies within the drilling operation, coupled with putting wells in the right place the first time so it can produce over the entire life of the field. “You have to combine softwares and combine disciplines and expertise. You have to understand how much uncertainty you have in your measurement and the assumptions you made in your workflows before you hand it to the next set of people to do the next sequence of processing.”

For a project in the subsalt Wilcox structure in the GOM, Schlumberger generated 1,000 models of what the top Wilcox would look like. “This is the starting point because attempting to quantify on the amount of uncertainty allows you to make the correct measurements that drive the uncertainty down, allowing you to make objective decisions,” Mr Hawthorn explained. A simple one-dimensional stretch in most cases is no longer adequate. “We are dealing with a 3D, and increasingly, 4D environments. This requires a better approach.”

Digital Technology Theater

The Digital Technology Theater (DTT) in Houston is a key platform Schlumberger is using to help operators in the Gulf of Mexico. A re-launch event in March focused on showcasing the company’s deepwater technologies and services. The upgraded DTT features a 25-ft-wide screen powered by six high-resolution Barco projectors.

“With so many disparate groups and disciplines involved in deepwater projects, collaboration is absolutely fundamental to ensure that the project is carried out safely and successfully. The DTT is a good example of how the various groups can integrate and communicate,” Keith Tushingham, Schlumberger Information Solutions (SIS) DTT producer, said.

In April, the DTT was used to connect to the Schlumberger office in Aachen, Germany, to connect a client to the basin modeling experts. “Global tele-presence is common place today, but being able to transmit large amounts of data to remote locations is a different matter,” he said. “That requires good latency connectivity and cloud-based collaboration capabilities. This is the difference that the DTT brings to an organization”

Schlumberger will open another DTT in Kuala Lumpur in July to serve the Asia market, and other centers are planned for Oslo, London, Dubai and Calgary by the end of this year. Each center will address specific regional challenges.

“As SIS is focused on these industry challenges, it’s catalyzed a broader integration across our organization,” Mr Tushingham stated. “This allows us to integrate and get access to the breadth of all our expertise.”

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Baker Hughes Releases JewelSuite 2012 Reservoir Modeling Software

HOUSTON, TEXAS (Apr. 30, 2012) – Baker Hughes announces the release of JewelSuite™ 2012, the latest version of the global oilfield service company’s reservoir modeling software that makes it simple for operators to evaluate potential sweet spots and analyze thousands of wells.

JewelSuite 2012 reservoir modeling software now offers enhanced functionality with a complete workflow for unconventional plays. An ongoing dialogue with current Baker Hughes customers assisted in the development of the newest version of JewelSuite. The 2012 software improves the understanding of unconventional plays with integrated 3-D models that enable visualization of all relevant datasets.

The software now includes Blue Marble Geographics’ GeoCalc™ coordinate transformation library ensuring correct well placement and offers a workflow for unconventional plays that enables sweet spotting from regional models to detailed reservoir or well models. Users can easily analyze sector models and run different production scenarios. The ability to study a smaller subsection without recreating the model allows for the comparison of different sweet spots quickly, as well as a juxtaposition of the impact different fracture plans may have.

JewelSuite 2012 also offers improved performance and usability. It can handle very large data sets and allows customers to view and analyze thousands of wells at once. Additionally, JewelSuite provides improved efficiency through enhanced connectivity to Computer Modelling Group’s IMEX™ and GEM™ reservoir simulators, also using Tartan and LGR gridding. This allows for the analysis and optimization of detailed flow behavior around the wellbore and its fracture stages.

The latest version of JewelSuite also incorporates enhanced Multi Point Statistics through a more intuitive interface with faster run times, and enables batch processing of property modeling. The latest software offers a significant step to helping operators develop the tailored plans they need in today’s unconventional plays.

# # #

Baker Hughes is a leading supplier of oilfield services, products, technology and systems to the worldwide oil and natural gas industry. The company’s 58,000-plus employees today work in more than 80 countries helping customers find, evaluate, drill, produce, transport and process hydrocarbon resources.

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Quickly build and update complex reservoir models accurately. With our geomechanic and hydraulic fracturing software, we build targeted workflows for unconventional plays.

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Reservoir drives choice of RSS vs mud motors

Rotary steerables suit narrow formations; mud motors may be more cost-effective in broader boundaries

By Eric Malcore, Weatherford International Ltd

The ratio of directionally drilled wells to vertically placed wells is increasing. Access to progressively harder to reach reserves is driving more complex well geometries, which predicate the use of rotary steerable systems (RSS) to enhance rate of penetration (ROP), improve borehole quality and reduce torque and drag and stick slip. The various RSS technologies available today have revolutionized the drilling process in horizontal and deviated wells by facilitating greater intermediate reaches and longer laterals, allowing casing to be run more easily and allow proper weight transfer.

The service industry estimates that RSS technologies account for approximately $3.5 billion of the estimated $15 billion directional drilling market. The dynamics are shifting in favor of RSS.

Although not a new technology, high-performance mud motors also have become an accepted and reliable method in directional drilling operations, in many cases providing a cost-effective alternative to more costly rotary steerable tools.

Knowing when to choose a rotary steerable system and when to use a high-performance mud motor is critically important to optimize the drilling project from both an engineering performance and a cost perspective.

Many horizontal or deviated wells are extremely difficult or impossible to drill without an RSS. A key benefit of RSS technology is that it directs well trajectory without sliding, a condition that impacts the stability and orientation of the drill string to rotate in one direction. Without proper rotation, the entire drill string can stick to the borehole wall, making it difficult to achieve the desired weight transfer to the bit to achieve planned penetration rates. RSS tools provide continuous rotation of the drill pipe, minimizing the risk of the pipe becoming stuck or buckling.

Sliding also creates more waste because the lack of rotation keeps the fluid in a static state, making it more difficult to remove cuttings. The cuttings then pack off around the bottomhole assembly, causing the drill string to stick. With the continuous rotation enabled by rotary steerable tools, however, the friction holds the cuttings in suspension, allowing the fluid to create a vortex around the drill string to provide consistent hole-cleaning.

RSS technology also reduces drag, allowing extension in well reach, especially important in horizontal applications. Rotary steerables typically deliver a smooth in-gauge wellbore and control the toolface at the bit, which provides more accurate directional control and less tortuosity. They also enable the use of logging-while-drilling (LWD) azimuthal sensors to obtain full borehole images.

Applying Precise Directional Control

An important factor in rotary steerable systems is that they provide precise directional control and are therefore suited to narrow zones as tight as 1 ½ ft. In that regard, the tools also can provide geosteering in these narrow reservoirs, where corrections can be made in real time without sliding.

An RSS was used to successfully drill and complete a section of a horizontal water-injection well with an 8 ½-in. hole in Abu Dhabi.

Using Weatherford’s Revolution rotary steerable system, the operator was able to drill 2,200 ft (671 meters) at a depth of 8,725 to 12,918 ft (2,659 to 3,937 meters) in less than 90 hrs in one run, saving 41 hrs of drilling time and achieving a significant cost savings without nonproductive time.

The same system was used in another Abu Dhabi water-injection well to facilitate drilling and completion of an ultra-narrow, 6-ft zone with a 6-in. hole size and a run length of 4,193 ft (1,278 meters).

The operator was able to drill almost 20 ft (6 meters) deeper than anticipated, reaching a target that otherwise would have been missed.

In an onshore Saudi Arabian field prone to lost circulation, differential sticking and hydrogen-sulfide challenges, the same technology drilled a 3°/100-ft (30-meter) dogleg section with a 6 1/8-in. hole in an extended-reach horizontal water-injection well to a target depth of 16,856 ft (5,138 meters). Average ROP was 35 ft/hr (11 meters/hr). Prior to deployment of the system, optimal ROP had been difficult to achieve with a steerable motor assembly.

The system drilled a total of 7,316 ft (2,230 meters) in one run, achieving a field run-length record and meeting the operator’s goal to minimize excess tripping time. The operation saved 24 hours in drilling time and associated costs and allowed the operator to avoid stuck-pipe and lost-in-hole risks that occur in similar extended-reach wells.

In the Bay of Bengal in Eastern India, the same RSS technology performed a record-breaking shoe-to-shoe run in a claystone formation, with interbedded sandstone, marl and calcareous clay. The deep exploratory well had an inclination of 34°. The system drilled a 12 ¼-in. in-gauge hole and then drilled to a measured depth of 4,918 ft (1,499 meters) to improve the average ROP and reduce the number of wiper trips and backreaming. Drilling time was 192 hrs, with an average ROP of 25.6 ft/hr (7.8 meters/hr).

RSS technology has been enhanced in recent years by the development of motorized rotary steerable systems, where a power section placed on the RSS tool provides additional rpm and torque while still achieving the benefits of control and eliminated sliding. This hybrid-type application is increasingly being used in regions such as the Middle East, where the rock and carbonates are especially hard.

High-performance mud motors can save 50% or more a day over rotary steerable systems. Mud motors also can be used with smaller rigs that can’t rotate fast enough to enable the rotary steerable mechanism to perform. However, rotary steerables provide greater precision in directional control, an advantage in tight formations.

High-performance Alternative

Despite its many benefits, rotary steerable technologies can present some disadvantages, including cost, if used in situations where precise directional control is not the primary objective. For example, to justify the expense of using a rotary steerable system, the savings in rig time and other costs must be greater than the rotary steerable cost.

Rotary steerable drilling performance is delivered from the use of surface rotation, making them rig-dependent. They offer limited selection of bit sizes and speeds, and they involve greater complexities, both mechanically and electronically compared with motors. The high rotation speeds can cause premature wear to the casing and drill string, which can be slightly decoupled by using an integrated power section with the RSS, albeit adding significantly to the cost.

The replacement cost of a rotary steerable system, if it is lost in the hole, can exceed $1 million, depending on the system and size. That does not include the replacement cost of the accessory tools.

In cases where deploying an RSS is either cost-prohibitive or impractical, a high-performance mud motor can also achieve desired results, provided it is used in the proper application. However, high-performance mud motors are best suited to broad target areas and zones that require less precision, or in doglegs that are too aggressive for an RSS.

Used since the early 1990s for a multitude of oilfield applications, high-performance mud motors achieve greater torque and ROP than conventional mud motors. The mud motor leverages the reduced rubber profile in the power section to gain additional torque, which creates less deformation as the rotor spins. The reduced rubber deformation translates into more torque for the bit, which in turn allows for higher ROP and more aggressive bit designs.

For operators, the key advantage is that a high-performance mud motor can result in daily cost savings of 50% or more over an RSS. Lost-in-hole costs also are significantly lower; a 6 ¾-in. high-performance mud motor has a typical lost-in-hole cost of $168,000.

High-performance mud motors can often out-perform standard, non-motorized RSS, which depend on the rig rotary table to spin the bit. The motor power component of the high-performance mud motor, on the other hand, provides bit rotation and power directly to the bit. High-performance mud motors also can be used in situations that involve smaller rigs that can’t rotate fast enough to enable the rotary steerable mechanism to perform.

Another benefit is that all bit types and sizes can be used with a high-performance mud motor, making it useful for a variety of applications, including situations where a particular bit that is not compatible with an RSS must be run.

High-performance mud motors do, however, require sliding for directional control, which typically reduces ROP. They offer poor and inconsistent hole-cleaning and poor hole gauge. Also, LWD sensors often get pushed back farther from the bit. Motor bend with high-performance mud motors can limit the drill string rotary speed or not allow any rotation at all. These factors must be considered in selecting this method of drilling.

It’s believed that rotary steerable technologies account for approximately $3.5 billion of the estimated $15 billion directional drilling market.

UAE Test Cases

High-performance mud motors have been used successfully in many deviated drilling operations and have achieved better-than-average ROP rates in three offshore test cases – the Thamama, Hith and Arab formations in the United Arab Emirates.

Seven wells in the Thamama Formation featured multiple target zones and were characterized by hard, Cretaceous limestone, but they presented no sliding issues. The operator used high-performance mud motors to drill the wells, which were not horizontal but had deviations ranging from 0° to 30° and had 8 ½-in. hole sizes.

The high-performance mud motors performed with an average ROP of 28 ft/hr (8.5 meters/hr). The best performance for the motors was 44 ft/hr (143.4 meters/hr), and the worst performance was 17 ft /hr (5.2 meters/hr). The Hith Formation also featured hard drilling conditions, with Jurassic anhydrite and dolomite rock but no sliding issues. The operator again drilled seven hole sections, all deviated but not horizontal, with 8 ½-in. hole sizes and a build section of 25° to 90°. In this case, the high-performance mud motors delivered an average ROP of 18 ft/hr (5.5 meters/hr). The highest ROP was 41 ft/hr (12.5 meters/hr), and the lowest was 9.88 ft/hr (3 meters/hr).

In the Arab Formation, featuring Jurassic carbonate/anhydrite rock, both sliding and directional control challenges were present. The lateral section was +/- 90°. Again, the operator drilled seven 8 ½-in. hole sections with high-performance mud motors.

The operation achieved an average ROP of 18 ft/hr (5.5 meters/hr). The best performance was 31 ft/hr (9.4 meters/hr), while the worst performance was 10 ft/hr (3 meters/hr).

The emergence of multiple technologies to optimize the drilling process can make selection of the proper technology confusing. Understanding reservoir properties along with diligent analysis of the well program, including formation, bit selection, directional program and other factors, must be considered when determining whether an RSS or a high-performance mud motor will achieve the best results in terms of cost and efficiency.

In tight or narrow formations where precise, directional control is needed, RSS are often the optimal choice for achieving drilling optimization and increased ROP. In zones with broader boundaries, a high-performance mud motor can provide results at a lower cost, provided issues such as sliding are carefully examined.

Revolution rotary steerable system is a trademark of Weatherford.

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