DRILLING AND WELL COMPLETION
Extending the reach of ERD:
How far can we go?
A collection of technologies now exists that, when combined, will allow extended reach drilling to reach astonishing lengths. But the cost of those technologies - the business case - will be unique for each situation.
Perry Fischer, Editor, and Victor Schmidt, Drilling Engineering Editor
The “E” in ERD, (Extended Reach Drilling) will eventually stand for “extreme.” ER wells test the limits of technology and require considerable modeling on the technical feasibility of well construction. A recent Offshore Technology Conference session brought together the latest thinking on extended-reach drilling. This is mostly a synopsis of that session.1-7
Perhaps the best way to present the session is to break it down into the various components of conventional well construction: planning, rig selection, mud requirements, drillstring, casing, cementing, logistics and HSE considerations.
THE DRIVERS AND LIMITS
Drilling the world’s longest extended reach well gives a company a reputation for being on the cutting edge. That, and bragging rights. This is the case with the recent new world record extended reach well, the Z-11 on Sakhalin Island. Drilled into Chayvo field by ExxonMobil (Exxon Neftegas Ltd.), the well, at 37,016 ft, has the longest MD of any ER well. This beats the previous record at BP’s 37,001-ft Wytch Farm well by only a few feet, (assuming that we can measure with the necessary accuracy). Wytch Farm bests Total’s 36,693-ft well at Tierra del Fuego. As fascinating as the technology is, all of these wells were drilled for the business case.
Application for a new plan has been filed for drilling BP’s Liberty field off Alaska’s North Slope. The plan is to drill six ER wells in the 40,000-ft-plus range, using a purpose-built rig, from man-made Endicott Island, some 8 mi to the west, where infrastructure already exists.
Magellan, Tierra del Fuego, Sakhalin and the planned Liberty wells represent the case where the cost to drill just a few miles offshore is either more expensive, unfeasible due to weather extremes, or both. Still, environmental consideration is often a plus. With Wytch Farm, environmental considerations were the primary driver for ERD.
For an offshore-sited ER well, it will be cost-effective in the niche case of a fixed platform that is an extended-reach distance (however defined) from a newly delineated reservoir addition. This could make it cheaper than either building another platform, or contracting a floating rig. Day rates for a platform rig are about $32,000, whereas a semisubmersible with a working depth of less than 1,500 ft, will cost about $140,000 a day. The difference in a 60-day well is $6.5 million per well. Add to that the cost of subsea completions and tieback, or the building of a new platform, and the economics could favor ERD.
An additional bonus with all ER wells is that, being horizontal, they generally are inherently better at draining the reservoir and maximizing production with the minimum number of wells.
Experience to date shows that most ER wells are drilled with a TVD between 5,000 and 10,000 ft and an offset between 10,000 and 15,000, Fig. 1. The maximum ERD length most often mentioned as being theoretically possible is 50,000 ft.
Fig. 1. All ERD wells, both offshore and on land, show a region of TVD and offset, where most wells are drilled.
WELL CONSTRUCTION OVERVIEW
For these extremes to be possible, the geology must be “cooperative,” and most conventional equipment will probably be inadequate. When conventional equipment is used, all of the specifications will need to be as good as they can get: hook weight, casing type and design, top drive torque and capacity, friction reduction (including roller technology), mud program, the best rotary steerable systems, very little borehole tortuosity, and the best drillpipe system design. Alternative materials, such as aluminum, titanium and composites, will likely be required.
For any ER well, the controlling conditions to establish feasibility are:1
- Maximum torque loads of both the top drive and drillstring component torque capability
- Maximum drillstring tensile rating, and load, with respect to the capability of the rig’s hoisting system
- All tubulars (casing, tubing, drill pipe) must be capable of sliding or rotating into position without buckling or developing excessive positive or negative weight
- Weight on bit must be adequate
- Mud circulation for adequate hole cleaning, with consideration for drilling annulus size, and any interaction with ECD and fracture gradient
Technical solutions to the above conditions tend to be:1
- Multiple drill pipe sizes. These tend to be large OD for large holes, and small OD for small holes. Also, different materials (e.g., first, high-strength steel, then titanium, then aluminum) in different drillstring sections may aid in achieving extreme ER wells
- Larger-diameter casing
- Tapered casing strings. However, an OTC paper on ER well construction found that single-diameter construction would be the most feasible for these extreme (50,000 ft) ER wells.2
- Managed pressure drilling
- Lightweight drill pipe and casing.
- Thin drilling fluids
- Large pumps (3 X 2,200 hp, 7,500 psi)
- Large top drives (60 to 85 kft-lb at high RPM).
WELL CONSTRUCTION SPECIFICS
It has been estimated that the last 10% of the drilled interval of an ER well is 50% of the total drilling cost.3 It will take extreme planning, the best technology, and a bit of faith to drill a 50,000-ft ER well.
Well design.4 Pre-planning and technology selection are even more important with ERD than with conventional wells. One tool to help plan well construction is wellpath simulation software to quantify the limits imposed on the equipment. Schlumberger has developed a Trajectory Risk Index (TRI) that is a combination of two other indices: Trajectory Difficulty Index (TDI) and a Collision Risk Index (CRI). TDI characterizes the vertical component of the well’s path and the tortuosity of each segment. The CRI is a composite of several ratios: collision (Rcl), torque (Rtq), drag (RD) and build-up rate risk (RBU). Combining these factors yields the index:
Low-risk wells will have a TRI less than 1, medium-risk wells have TRI between 1 and 1.5, and high-risk wells have a TRI greater than 1.5. The advantage of calculating and defining a well’s TDI is that the index pulls all the well factors together to focus the driller on the cumulative effect of the challenges the well presents. Well path factors can then be adjusted to reduce the risk, or plans can be formulated to deal with the risks necessary to getting the ER well drilled.
For a given development project, TRI can help planners schedule wells, so that the easier wells (lower TRI) are completed first. This gives staff an opportunity to learn how the field’s rock formations will drill, providing additional time to overcome hole issues before the more difficult wells are attempted.
TRI also provides a benchmark against which future wells can be measured, both in engineering performance and in cost, Fig. 2. These factors can be tracked and assessed against the reserves developed by ER wells, thus optimizing the drilling project.
Fig. 2. TRI provides a cost and performance benchmark against which future wells can be measured.4
Wellpath guidance.5 ER wells need to follow the planned well trajectory as closely as possible, without corkscrews, undulations or other deviations, to reach their targets. They also need the smoothest wellbores possible. It is assumed that the best rotary steerable systems (RSS) will be used to substantially mitigate these wellbore concerns for ERD. Reduced wellbore tortuosity minimizes drag as the drill pipe progresses downhole. It is also assumed that the best downhole survey tools, riding close to the bit, will be used, as close as possible to real-time. These BHAs, in conjunction with RSS, will produce the smoothest, on-trajectory hole possible and give the best chance of success.
Drillstring issues.3 The primary considerations with drillstring are: overcoming high frictional drag forces, efficient hydraulic performance to optimize hole cleaning, penetration rates, good control of the well trajectory and minimizing drill pipe sticking. These considerations underscore the need for high torsional strength connections and high strength-to-weight ratio materials. Three types of materials: carbon-fiber-based composites, titanium and aluminum, need to be carefully considered.
Titanium drill pipe (TiDP). Small-diameter pipe (2 ½-in., 2 7/8-in.) was proven useful for ultra-short-radius drilling in several field trials and commercial applications. The extremely limited production, combined with the manufacturing process, makes the pipe cost at least seven times more than conventional pipe. Unless a market can be developed, this price difference will remain. The advantages, however, are considerable:
- Lower weight, with a density of 56% that of steel
- Strength-to-weight improvement (including steel tool joints) of about 37% over S-135 steel drill pipe, with minimum yield strength of 120,000 psi
- TiDP has good fatigue resistance and does not suffer from corrosion fatigue. However, it can be notch-sensitive in fatigue-inducing situations
- TiDP is highly resistant to erosion
- Much greater flexibility: Modulus of elasticity is 17 million psi vs. 30 million psi for steel.
This last property may be both advantageous in short-radius bends, and could be disadvantageous downhole. For the same amount of stress, TiDP will deform about twice as much as conventional drill pipe. This fact means that TiDP responds more slowly to changes made at the surface. It’s not well known whether “a learning curve” by the driller will be able to compensate for changes, such as torque and RPM as they work their way downhole.
Mid-body wear of TiDP could be a problem, since titanium is known to have significant wear rates when exposed to prolonged and stressed contact with steel. Perhaps some sort of hardbanding could mitigate this.
In light of this, it remains to be seen whether an operator will undergo the expense and learning needed to use TiDP, but it’s strength-to-weight ratio makes it a worthy contender. However, when compared to high-strength steels, this ratio advantage reduces to 15% improvement, from 37%.
High-strength steels. More than 550,000 ft of Z-140 grade and about 200,000 ft of V-150 are in use today. These grades provide 4% and 11% improvement, respectively, in strength-to-weight compared to S-135 drill pipe. Issues of toughness and ductility have largely been solved. A relatively new grade to the drilling industry - UD165 -has a 165-ksi yield strength. This is a 22% improvement over S-135. It is likely that UD165 will cost substantially less than TiDP.
Comparisons of high-strength steels often fail to factor the steel tool ends fastened to the non-conventional tube material. Table 1 factors in these ends, and uses a conservative (optimistic) approach by analyzing the range of three drill pipe products. While the Range-3 product lengths can offer efficiency advantages, they may present wear issues and elevated torque vs. Range-2 designs.
|TABLE 1.3 Strength-to-weight ratio comparisons of several steel and non-steel materials with steel tool joints attached.
Click table for larger image.
Aluminum drill pipe. Most of the experience with this kind of pipe comes from decades of use in Russia, where it is frequently and extensively used. Its obvious advantages are that it is non-magnetic and has lower weight. It is also less corrosive in some mud systems. Modern alloyed aluminum drill pipe has enhanced fatigue resistance. It can provide a unique solution to drill pipe weight and drag, and may comprise only the lower section of drill pipe.
Aluminum drill pipe can cost up to twice as much as conventional pipe. It has a relatively low weight-to-strength ratio of 69,000 psi (with the best alloy). Yield strength can drop off quickly in temperatures above 250°F. In addition, it generally requires a thicker wall than conventional pipe, which can affect hydraulic performance.
Carbon-fiber based composites. This epoxy matrix drill pipe is now being manufactured, but at up to three times the cost of conventional pipe. Its primary benefits are lower weight and a higher strength-to-weight ratio. It also is virtually immune to corrosion and resistant to fatigue. Besides cost, perhaps its only shortcoming is wall thickness, which can be double that of conventional pipe. This can negatively affect hydraulic performance. To compensate somewhat for this, the pipe OD has been expanded slightly.
Shoulder connection/makeup. Grant Prideco has been qualifying and testing a new, double-shoulder drill pipe connection since early 2004. The third generation double-shoulder design reduces makeup time by 50%. This could reduce cumulative trip times by more than 11.5 hr over the entire consultation process on ER wells. The new connection has improved torsional strength and is more streamlined for hydraulic efficiency.
BOP pipe shearing. Whenever higher-strength materials are used in drillstrings, it is advisable to contact the maker of the BOP stack. The manufacturer will know whether the material will shear or, in the absence of data, the maker can run the necessary tests to determine what modifications might be necessary to ensure BOP shearability.
Mud handling. While hole volume for most ER wells is similar to deep vertical wells (averaging about 18,000 ft in the GOM), wells near the edge of the present drilling envelope can require double the working volume of fluid. For the hypothetical 50,000-ft ER well, the longest presently envisioned, mud volumes will likely be two to three times that volume.
This eventuality requires thinking about mud storage and make-up, as well as pumping capacity required to keep a larger fluid volume circulating properly in a very long wellbore. Bulk material needs are greater and will require either additional shed space or more frequent mud-additive deliveries to meet the well’s needs.
Drilling hydraulics planning will be necessary to adequately clean the hole and meet bit-face hydraulic needs, while staying within equipment operating limits and pore pressure/fracture gradient limits. Flowrates must move the cuttings, but not degrade the hole, produce equipment wear or create high standpipe pressure, Fig. 3. Additional horsepower will be needed and will likely be increased by the addition of one or more mudpumps to service the drilling operation. Ramping up to a 7,500-psi, high-pressure fluid end from the standard 5,000-psi system, is the approach the newest rigs are using.6
Fig. 3. Flowrates must move the cuttings, but not degrade the hole, produce equipment wear or create high standpipe pressure.6
Mud rheology will require the blending of additional material into the fluid stream to overcome the added friction of long pipe sections on the low side of the hole. Whether friction reduction is done with chemical or mechanical additives, blending equipment will likely be used for longer periods and will require more durability than standard systems.
Cementing. Cementing the long extended reach section is difficult, and there is a tendency to inadequately displace mud and leave potential communication channels. Even the intermediate hole sections are getting longer. The cement used for these sections should be specially blended, lightweight slurries with delayed setting time. Three ways to reduce the density of cement are: adding water-extending additives like bentonite to the slurry, which will carry extra water in the mix, improve its flow characteristics and reduce density. A second method is to inject nitrogen gas bubbles into the slurry. This makes the slurry more compressible and reduces the Young’s Modulus for improved sheath elasticity. A third method is to add microspheres, hollow or solid, plastic or glass, to the slurry to decrease density.
Mixing and slurry stability are key factors to control. The goal is to develop and maintain a homogeneous blend that is stable enough to be emplaced. The use of a “sandwich” approach to mixing, which involves alternating cement with additive batches, gives good results. Bulk transfers should be done by pressurizing the top with air, while loading material from the bottom; this keeps the microspheres in suspension. Slurry should be created in small patches, which are then mixed together before pumping downhole.7
Rigs.6 For long-term ERD development work, a new class of drilling rig has been developed and is in operation. This rig class is represented by Parker Drilling’s Rig 262, Yastreb, presently onshore Sakhalin Island, drilling ER wells to develop Chayvo field offshore to the island’s northeast.
Rigs for ERD work need to accommodate very long tubular lengths, build stands off the drill floor and deliver increased power for drilling and fluid pumping. The Yastreb operates in a sensitive environment and is zero-discharge-compliant. Mechanized and automated pipe handling is needed to prepare the numerous pipe stands and reduce crew fatigue.
The rig’s modular design places non-critical path operations away from the rig floor, so that many routine operations can occur at the same time without interfering with each other. This optimizes crew time and allows the drilling operation to proceed without interruption.
Pipe is made-up and held horizontally in a stand-by rack, from which it is raised to the drilling floor as needed. Pipe-handling operations are mechanized, freeing the crew for other drilling-related duties. Gantry cranes, a tubular shuttle, floor monkey drawworks and iron roughneck operate together to produce an efficient pipe-handling process.
This rig, and others like it, must be delivered and erected in terrain that is often environmentally sensitive: muskeg, tundra or beach, as at Sakhalin Island. Logistic considerations are important, as are the size of modules and the equipment needed to deliver and erect the rig.
Planning for the pad site must also take into account the orientation of the template for the wells and the way that the rig will move from one to the other. Rig 262 uses a rail and hydraulic cylinder system to move laterally between locations for batch drilling of well segments.
Drilling hydraulics and cuttings removal are key components of ER wells that require more horsepower.
Moving people and bulk materials to the wellsite for ERD operations is a serious constraint. Most ERD operations operate from a few well-located sites, from which many wells are drilled.
These sites are often located in environmentally sensitive areas, such that transport into and out of the site can, itself, be an environmental hazard. In high-latitude operations, some sites are only available seasonally, once ice roads are constructed.5 These often distant operations require bulk storage space for materials, housing for crews and the necessities of life to meet people needs. With limited re-supply potential, these sensitive sites will need to move and store materials for many months of operation in a short time.
Of course, people will operate the drilling systems, and taking care of the crews is a whole subject of its own. ER wells present problems that will strain the best of crews. For instance, tripping many thousands of feet of drill pipe in and out of a well will take several crew shifts, and crew fatigue is a serious issue because of the repetitive nature of the work. Because there is so much pipe involved, the method of pipe racking and storage becomes an HSE issue. Automated systems are probably mandatory; only the degrees of automation, and the automation of ancillary systems, are options for consideration.
The technology to drill 50,000-ft extended reach wells is here. However, only high-end technology - including rigs, top drives, mud systems, drill pipe, cement, casing/running, or BHAs - can be used, making the cost steep. As operators begin to more routinely consider ERD as a viable option, whether for environmental, logistical, production enhancement, or some combination of these reasons, mass production of these pricey components will lower costs, and ERD will become increasingly common.
1 Foster, B. and T. Krepp, “Redefining the offshore ERD envelope: Techniques and technologies necessary for an expanding frontier,” OTC 19064, presented at the Offshore Technology Conference, Houston, TX, April 30 - May 3, 2007.
2 Bell, R., McGee, R., Zwald, E., Lewis, D. and P. V. Surayanarayana, “Single diameter technology capable of increasing extended-reach drilling by 50%,” Paper OTC 17828 PP, Offshore Technology Conference, Houston, May 1 - 4, 2006.
3 Jellison, M. J., Chandler, R. B., Payne M. L. and J. S. Shepard, “Drillstring technology vanguard for world-class extended-reach drilling,” OTC 18512, presented at the Offshore Technology Conference, Houston, TX, April 30-May 3, 2007.
4 Liang, Q. J., “Trajectory risk index - An engineering method to measure risks of multiple-well complex trajectories,” OTC 18508, presented at the Offshore Technology Conference, Houston, TX, April 30-May 3, 2007.
5 Alvord, C., et al., “RSS application from onshore extended-reach development wells shows higher offshore potential,” OTC 18975, presented at the Offshore Technology Conference, Houston, TX, April 30-May 3, 2007.
6 Husband, F. J., Bitar, G. and M. Quinlan, “ Extended reach: new generation frontier drilling rigs,” OTC 19067, presented at the Offshore Technology Conference, Houston, TX, April 30-May 3, 2007.
7 Kulakofsky, D., Oliveiro, A. and A. Almaraz, “Combining latest technologies enables successful completion of ERD exploration project off the coast of Tierra Del Fuego: Best practices from a case study,” OTC 18927, presented at the Offshore Technology Conference, Houston, TX, April 30-May 3, 2007.