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Advanced technology will improve operations in the coming year.
Technology is the lifeblood of the oil and gas industry, and its constant evolution is an enjoyable journey for those of us who cover this exciting business.When the E&P editors were tasked with choosing top technologies to highlight in this issue, we turned to a number of sources, including our newly installed editorial advisory board. Their vast knowledge base combined with our interaction with the industry has resulted in this overview. One thing we want to stress is that the technologies are not in rank order; rather, they are arranged in a traditional Exploration – Drilling – Production – Offshore order.
1. Potential Fields
A few decades ago, experts in potential fields technology such as gravity or magnetics were shunted aside as 3-D seismic held the promise of true subsurface illumination. Then geophysicists began to discover that 3-D was not always the magic bullet. Meanwhile, the US Navy was developing a new form of gravity gradiometer that could be used on a moving platform.
While this technology has been commercially available for a decade, only recently have geophysicists begun to sit up and take notice. The Navy’s technology, called full-tensor gravity gradiometry (FTG) and licensed to Bell Geospace, helps locate previously unknown targets. It accurately maps subsurface density contrasts caused by target geology and helps map their geological setting.
The Bell Geospace gradiometer uses all tensor components to offer a shape, form, and dimension to subsurface geology, making the FTG a key tool when unraveling complex geological puzzles.
ARKeX is using gravity gradiometry imaging to provide much higher resolution than earlier gravity measurements because it measures small density variations by measuring the gradient of the earth’s gravity field. The high-resolution and high-bandwidth measurements can complement traditional seismic technologies in addressing imaging and illumination difficulties and imaging complex geologies to determine velocity and density relationships.
One of the key benefits of this technology is its ability to scan very large areas very economically. Gravity gradiometry measurements are taken by airplane over land and by airplane or ship in the marine environment. This ensures that cultural and environmental sensitivities are met while costs are kept low.And by using a multidisciplinary approach that combines these measurements with seismic, borehole, and magnetic data, operators can create a more accurate earth model.
2. Acquisition Geometries
Over the past 10 years or so, advances in seismic processing have arguably been the biggest story in the seismic sector. Poor-quality data could be reprocessed using newer, better algorithms to better image the subsurface.
But in the past couple of years, acquisition techniques have come into their own. The general perception of land data, for instance, is that it never is as good as marine data because technical and economic hurdles reduce these surveys to sparse geometries that resulted in poorly sampled and noisy data.
High channel-count recording systems, high-productivity vibroseis techniques, and advances in wide-azimuth (WAZ) processing have been game-changers on land, according to an overview on CGGVeritas’ website. New vibrators can act independently of each other through an acquisition scheme called slip-sweep.With wait times significantly reduced, land crews see huge increases in productivity and can record data up to 100 times the density of conventional land surveys. These new-generation land acquisition techniques also are 10 times denser than a marine WAZ survey.
BP and others are using simultaneous shooting, where seismic sources are fired at the same time or randomly. BP’s technique is called independent simultaneous sweeping, and a current survey in Libya is achieving at least 1,000 shots per hour. Other companies are trying simultaneous shooting in both land and marine surveys.
Since the first WAZ towed streamer marine survey in 2005, volumes have been written regarding the different acquisition geometries available for these surveys and the pros and cons of each. But in each case, the resulting dataset provided a much clearer image of the target, particularly under salt.
More recently, WesternGeco introduced the concept of coil shooting, where the vessels move in a circular geometry rather than a linear geometry. A coil shooting survey typically uses a single vessel, but the company now is introducing the concept of “dual coil shooting,” which uses two recording vessels with their own sources and two separate vessels, all sailing in interlinked circles. The trace density of the design is 2.5 times greater than standard WAZ survey designs, and signal-to-noise is further enhanced to illuminate weak subsalt reflections. Advanced processing techniques such as 3-D generalized surface multiple prediction and reverse time migration are used to further improve the imaging.
3. Fracture Detection
As operators have made a mad dash to drill up shale plays, they have begun to discover that there is more to the shales than meets the eye. Despite the fact that these are resource plays rather than structural traps, it is not a simple matter of poking holes in the ground. A little reservoir characterization goes a long way toward finding the sweet spots and avoiding the duds.
Shale plays contain fractures, and depending on the shale, these fractures either need to be avoided to prevent “thief zones” from capturing frac fluids, or they need to be intercepted to provide a conduit for the natural gas to reach the well bore. “A common feature of shale and tight-rock plays is that they invariably have an embedded fracture system that has to be understood to achieve optimal exploitation,” said Bob Hardage of the University of Texas’ Bureau of Economic Geology. “I do not think anyone questions the statement that shear-wave data react to fractures and stress fields much more dramatically than do compressional-wave data.”
To acquire the shear component of the data requires multicomponent seismic. This is acquired through using three orthogonally oriented geophones. Sources can be either conventional (dynamite or vibroseis) or shear-wave sources that shake the ground horizontally as well as vertically.
The benefit of acquiring shear waves in fractured plays is the phenomenon of shear-wave splitting.When vertically aligned fractures or unequal horizontal stresses are present, the shear wave becomes polarized and splits into two waves, a fast and slow wave. The fast shear wave is aligned with the fractures, while the slow shear wave is aligned perpendicular to the fractures.
Interest in the shale plays is helping to promote the use of multicomponent techniques, which have been overlooked in the past due to lengthy processing time, among other issues. “The processing time has come down orders of magnitude, the software is more user-friendly and enables better visualization of multiple datasets, and the engineers are asking for the data,” said Tom Davis of the Colorado School of Mines. “The last point is what is really going to drive this technology.”
Within the last eight to 10 years, directional drilling has become the predominant method of opening up reservoirs. By controlling the well path through improved downhole tools, drilling companies have helped provide maximum exposure to hydrocarbons within reservoirs. In addition to bringing on new resources, horizontal drilling also has proven valuable for enhanced oil recovery (EOR) methods. In older fields, where serious problems can be found at bottom, horizontal drilling can help EOR efforts by steering clear of sour environments and opening well paths out of harm’s way.
Dogleg severity and increased build rates in standard development wells can wreak havoc on advanced downhole tools such as LWD/MWD and rotary steerable systems. Building curve in a directional setting exerts a vast amount of increased friction and stress on these tools. Electronics and batteries tend not to hold up beyond temperatures 350°F (177°C). For this reason, high-end triple-combo LWD systems often are left out of the horizontal drilling process. High stresses on the drillstring pose the potential of stuck pipe, twist-off, and resulting fishing and hole-cleaning operations. High friction force between the bottomhole assembly and the hole wall, particularly inside the curve section, increases the possibility of slide mode drilling difficulties.
Having more data often leads to improved production. Reservoir characterization adds much in the way of economic ultimate recovery; having more information on the rock can improve steerability during the drilling process and ultimately improve the precision of most frac jobs such as in unconventional shale plays.
While LWD tools can be the weakest link in the drillstring for hard formations and HP/HT conditions, this will not remain the case. Improved sensor technology along with improved designs in the tool string will ultimately provide a standard method of acquiring more data throughout the drilling process.
In 2010, Weatherford International Ltd. helped a Middle East operator revitalize a mature field, ultimately creating additional recoverable reserves. The company developed a 4 3/4-in. slimhole triple-combo LWD system that allowed the operator to gather directional, gamma ray, density, neutron, and resistivity data in high-dogleg (up to 68 degrees/100 ft or 30.5 m), ultra-short-radius wells without making multiple logging runs after landing the well.
With this and other successes in real-time data acquisition milestones during horizontal drilling within the last couple of years, the industry should see major advances in LWD/MWD tools and technologies. While horizontal drilling has inherent advantages for improving overall production, adding better real-time data acquisition technology will bring on the next evolution in drilling efficiencies.
5. Drill Bit Design
Decreasing the time it takes to get to total depth (TD) is paramount for successful drilling projects. A number of bit manufacturers are working to further enhance bit design to optimize and work in conjunction with specialized bottomhole assemblies (BHAs) and rotary steerable tools.
In 2010, Baker Hughes began field testing its Kymera drill bit, a hybrid bit that features a coalescence of roller cone and PDC technology into a single design. The new bit design will be commercially introduced in early 2011.
Complex well profiles, hard and interbedded formations, and rig or equipment limitations increase the potential for shorter runs, expensive tool damage, and ultimately reduce operator profitability. These are just some of the key issues affecting the application gap between PDC and roller cone technology. Kymera hybrid drilling technology is designed to exploit the best attributes of each bit type, bridging the gap between them.With the cutting superiority and continuous scraping of diamond bits and the rock-crushing strength of roller cones, this repairable bit has proven to survive highly interbedded formations with smooth drilling and excellent tool face control.
In key 12.25-in. US applications, Kymera’s hybrid technology has resulted in drilling rate improvements of up to 62%, with single bit run lengths extended by more than 200%, shaving days off standard well times.
In the range of PDC bits currently on the market, Encore Bits LLC has designed its SideWinder PDC bit to deliver ultimate directional performance. The bit’s design eliminates gage pads entirely in favor of making the cutting structure as active in the lateral aspect as it is in the vertical. Specifically designed for directional control and performance, the SideWinder can eliminate BHA trips when drilling horizontal curves,and it has been shown to reduce sliding time by 40% to 70% in the lateral. In addition to improving ROP across the board during high angle directional drilling, the bit also exhibits minimal vibration for longer LWD life.
As PDC technology improves, bit design will continue to improve the speed with which operators can reach target depths.
6. Microseismic Fracture Mapping
Perhaps the biggest aid to maximizing reservoir contact is the ability to “steer” fractures in real time using microseismic fracture mapping.With an array of directional geophones deployed in a nearby offset well, stimulation engineers can detect and interpret the microseisms that occur as the formation fractures. Answer plots are available in the stimulation control center at the well site within seconds.
Applications are many, and each is critical to a successful stimulation. Perhaps the most important is the ability to observe where the fracture is propagating so geohazards can be avoided. In the western part of the Barnett, for example, there is a danger of fracing down into the Ellenburger, which is wet.An instant of inattention could turn a potential gas producer into a saltwater well.With real-time mapping, stimulation engineers can either stop pumping or pump a diverter to avoid fracturing into the water zone.
Another equally important application is the ability to change pumping schedules or even stage locations on the fly based on real-time observations of fracture propagation. This allows engineers to maximize reservoir contact and avoid treating zones that already have been treated from a previous stage.
New techniques like “zipper fracs” or “simul-fracs” are facilitated by microseismic mapping. These techniques have been successful in preventing treatments from propagating into offset wells and are particularly effective in multistage treatments of long laterals.
Many shale gas wells, as they mature, become candidates for a re-frac treatment. Some operators believe in sealing off the old perforations with a casing patch or a cement squeeze job before attempting a re-frac. Others just initiate new perforation clusters and start pumping, keeping an eye on the fracture propagation using microseismic. If the treatment attempts to re-enter an old set of perforations, they simply pump a diverter that “steers” the treatment into the new perforations.When new fracture patterns are overlaid onto previous microseismic maps, the operators get new insight into complete reservoir exploitation.
7. Stimulation Technology
Service and supply companies are in a race to improve well treatment success on a number of fronts. Some start at the beginning by providing drilling fluid that is customized for the particular shale being drilled. Not only does the custom fluid benefit drilling efficiency and hole quality, it helps subsequent treatments and production by minimizing drilling formation damage.
Fluid chemistry is designed for each shale play. One company explained that the Marcellus could require two or three different formulations to optimize the fluid for different areas of the massive play.
Degradable fiber technology is the key ingredient for many new treatments. Originally designed to prevent proppant from slumping down to the lower portion of the fracture wing, the degradable fiber applications have blossomed since their introduction. Particularly useful as diverters, the degradable fibers can steer the fracture treatment into untreated areas; after a few days, they dissolve, returning the previously diverted zones into producing zones with conductivity restored.
Essentially, stable proppant “pillars” support the frac and keep it open while proppant-free channels connect reservoir volumes with the well bore. The result is elimination of skin that frequently occurs in the proppant pack from crushed proppant, formation fines, fluid damage, multiphase flow, and non-Darcy effects. Wells have shown more than a 50% improvement in gas production compared to conventionally treated wells. Both initial and sustained production rates have shown significant improvement as well.
8. Production Planning
A comprehensive and seamlessly integrated family of planning tools has been implemented and applied during the well construction stage. Their objective is to improve the well’s ultimate production potential. A good way to describe these tools is to borrow a phrase from BJ Services (now a Baker Hughes company). The phrase, which applies to all major service companies, is “Understand the reservoir first.”
This describes a process of gathering information that is critical to the well’s or reservoir’s ultimate production performance. It is important to stress the word “family” because no one technology can achieve the desired result. Geological, geomechanical, and petrophysical measurements are essential ingredients to understanding the reservoir and designing the most effective way to exploit it.
If conventional core is available, many valuable clues to formation mineralogy and petrophysical and geomechanical properties can be derived from it.Wireline logs, many measurements of which also are available from LWD tools, play a major role in developing comprehensive reservoir knowledge to support completion and production decisions. Standard triple-combo tools provide a reliable base from which to add embellishments.
Chief among these are elemental capture spectroscopy logs that give a continuous log of formation mineralogy that provides a basis for perforating and stimulation decisions. Formation stress analyses are facilitated by advanced acoustic logging platforms, primarily those that deliver directional compressional and shear slowness information that yields rock strength parameters used in fracture design. Natural fractures and rock texture can be identified and profiled using microresistivity tools, and a new dielectric propagation tool provides critical information to solve formation anisotropy issues and refine the basic hydrocarbon saturation analysis with continuous textural measurement of the cementation factor, saturation exponent, and cation exchange capacity.
Armed with the foreknowledge provided by these tools, engineers and geoscientists are able to optimize completion designs for maximum well performance. Later, as production declines, the information helps take the guesswork out of enhanced oil recovery plans. On a larger scale, comprehensive reservoir management scenarios benefit from a complete knowledge of the reservoir in advance of their implementation.
9. Deepwater Risers
Riser design is one of the biggest challenges for deepwater development. In the next several years, the industry will face more challenging reservoirs in hostile environments, deeper water, and remote operating areas. Advances in riser technology will be critical to developing those fields.
At the Offshore Technology Conference in Houston in early May, ABS gave an update on riser technology, spotlighting its partnership with Horton Wison Deepwater, a move ABS believes will strengthen its knowledge for the certification of risers and flowlines as a certified verification agent for these installations.
Kenneth Richardson, ABS vice president of Energy Development, summed up the reason for cooperative efforts. “Riser technology is becoming increasingly important with ultra-deepwater developments,” he said. “With this agreement, we will strengthen our technical teams, adding experience, technology, analytical software, and engineering services to address not only today’s riser systems, but also anticipate the systems of the future.”
Since 2005, a number of offshore contractors have installed free-standing risers, with Acergy, Heerema, Saipem, and Technip offering proprietary designs.
The first buoyancy can-supported, dry-tree, top-tensioned production riser was installed on Anadarko’s Neptune spar in the Gulf of Mexico in 1996/1997. It was the first spar-based floating production system using multiple production risers.
One of the most recent installations was carried out by Technip, supported by contractor Jumbo Offshore. The project included installation of five buoyancy can-supported free-standing hybrid risers (FSHRs) for Petrobras America Inc.’s Cascade and Chinook ultra-deepwater project in the Gulf of Mexico. These five FSHRs are the deepest risers of this type installed in the world to date.
In April 2010, Petrobras awarded Technip a contract for the infield lines of the pilot system for the presalt Tupi field, in the Santos Basin 186 miles (300 km) offshore Brazil in 7,218 ft (2,200 m) water depth. The key challenges of this project are water depth and the large CO2 and H2S content in the produced fluid. A new riser monitoring system, using distributed temperature sensor technology, has been specially developed for this application and will be incorporated in the flexible pipes.
Sour service continues to be a challenge in riser development and will require additional R&D investment, as will some of the issues surrounding HP/HT.As pressure, temperature, and margins of safety go up, so does the weight of the system.And the complexity of the riser is impacted.
Wells are becoming more complicated. Instead of being drilled to 15,000 to 20,000 ft (4,570 to 6,100 m) subsurface, they are 30,000 ft (9,150 m) below the mud line. Drilling costs are escalating because of reservoir complexity.
Risers can be designed for these conditions, but testing in in situ conditions must be carried out before they can be commercialized and put into service. That series of events comes at a significant cost and requires considerable investment. Meanwhile, what is needed on the equipment side are improved tieback connectors, BOPs, and tensioner systems.
More investment could go toward preliminary processing subsea, which would eliminate some of the problems with processing before the risers move production to the surface.
Whatever direction development takes, it is a certainty that risers will continue to be one of the segments of deepwater production technology that will have to be improved if the industry is to successfully contend with tomorrow’s challenges.
10. Subsea Production
Subsea solutions can bring otherwise impossible fields into production and make marginal fields economical. For these reasons, subsea system spending is on the rise. Quest Offshore Resources Inc. has predicted global subsea activity for 2011 will reach US $6.2 billion, similar to market activity in 2008.
While the number of subsea installations increases, research is pushing the limits on capabilities. Boosting and other subsea processing technologies are being expanded to meet global needs.
FMC Technologies introduced its innovative ultra-deepwater caisson-based seabed booster system and deployed it on the Parque das Conchas (BC-10) project offshore Brazil, which came onstream in 2009, and the Perdido project in the Gulf of Mexico, which produced first oil in March 2010.
In May 2010, Baker Hughes installed Centrilift XP enhanced run-life electrical submersible pump (ESP) systems in two vertical subsea boosting stations on Perdido in the Gulf of Mexico, setting a depth record for ESP installation in 8,000 ft (2,438 m) water depth. This system allows direct vertical access for installing and retrieving the ESP systems.
Later in the year, FMC signed an agreement to supply 11 subsea trees rated at 10,000 psi along with two production manifolds, an artificial lift manifold containing four subsea gas/liquid separation and boosting modules, and related subsea controls for Parque das Conchas Phase II. Deliveries are to begin in 2012.
In November, the company signed a memorandum of understanding with Petrobras to develop future subsea technology solutions for oil and gas projects offshore Brazil for particular use on presalt and maturing fields.
In early December 2010, Statoil and Siemens signed a technology development cooperation agreement, part of which will address subsea technology.
Also in early December, Statoil awarded Aker Solutions the world’s first subsea compression contract for the ?sgard field. Mads Andersen, executive vice president of Aker Solutions’ subsea business area said the award signifies “a quantum leap for subsea gas compression within the oil and gas industry.”
Strides have been made in subsea intervention as well. One milestone, Expro’s AX-S system, is the result of seven years of development work in partnership with a number of companies and incorporating input from more than 200 vendors. The system provides a riserless, remotely operated subsea well-intervention solution that costs significantly less than a rig-based alternative. The system, which is deployed from a monohull vessel, is the first intervention technology that can operate efficiently at depths to 10,000 ft (3,000 m), which covers every subsea well in the world.