RSS Proves Valuable In Vertical Wells

JANUARY 28 The Better Business Publication Serving the Exploration / Drilling / Production Industry RSS Proves Valuable In Vertical Wells While originally engineered for demanding horizontal and directional drilling, rotary steerable technology is providing highly accurate well bore placement in vertical drilling applications, enhancing the ability to maintain verticality during drilling, reducing drilling times, and improving drilling safety. By William D. Dee Kruse, Goke Akinniranye, Andrea Bautista Gomez, Benny Poedjono, Bill B. Dubose, Roger B. Goobie and John Hobin HOUSTON Although developed initially for horizontal and directional applications, rotary steerable system (RSS) technology is providing highly accurate well bore placement, reducing drilling time and improving drilling safety in the Houston Exploration Company s (now Forest Oil Corporation) high-volume vertical drilling program in the South Texas Charco Field. The company drills 8-1 natural gas wells a year targeting the Perdido and Lobo sands, and over the past three years, many of the well locations have been in close proximity to lease lines. With stronger gas prices and the need to more fully exploit leases, the company decided in 24 to begin drilling more lease-line wells in the Charco Field. Very few lease-line wells had previously been drilled because of problems keeping the accumulated displacement inside the lease dimensions. Failing to stay within the hard line maximum of 467 feet from the lease line, as required by the Texas Railroad Commission, can have significant economic consequences. The operator cannot produce from any section of a well that crosses the line. Vertical wells can be brought back within the limits, but the corrective actions necessary to doing so are seldom economically feasible. Maintaining verticality during drilling remains challenging in many geologic environments and requires alternative drilling strategies. Traditionally, downhole positive displacement motors (PDMs) have been used to control well bore vertically in these South Texas wells. The drive system typically requires one or two additional bit runs to achieve the target objectives. Reducing weight on bit, or feathering, was also required to maintain a vertical well bore. However, the combination of a PDM drive system and lower-than-optimum WOB led to a dramatic reduction in penetration rates when steering was required, dramatically increasing the time to drill a well. RSS technology has addressed both of these concerns by allowing the application of higher WOBs for faster penetration rates while maintaining high levels of well bore placement accuracy. RSS technology has increased the number of drill sites available, since wells can be located much closer to lease lines. In addition, the technology provides real-time response, with instantaneous well bore corrections reducing drilling time by more than 4 percent in some cases. Onshore Vertical Wells As a relatively new technology, RSS has generally been used in complex, highcost offshore projects where the savings realized were significant as a result of the high daily spread rates. However, the experience in drilling onshore in South Texas demonstrates significant benefits from using a fully-rotating RSS for vertical drilling applications in highly-faulted, fractured and dipping formations where vertical control is paramount. Optimum recovery of each lease s resources becomes economically viable with RSS. In fact, the technology makes it possible to locate surface locations right on the 467-foot hard line maximum. Historically, the number of wells placed near lease lines has been limited by the difficulty in maintaining verticality, slow penetration rates from having to slide the BHA to steer the well path back to vertical, and increased time and costs to complete wells. Using a steerable motor requires that the orientation of the bend is maintained to achieve the desired tool face setting. However, reactive torque from the PDM makes it difficult to accurately control tool face direction. The magnitude of this problem depends on the torque generated at the bit, which in turn, is a function of bit aggressivity, PDM torque output, drilling parameters and the formation. As a result, steerable PDM drilling often requires a compromise in bit selection and drilling parameters. In the past, most wells drilled with a PDM have used roller-cone bits instead of PDC bits to better control the tool face while navigating the well bore back to vertical at the cost of additional trips for Reproduced for Schlumberger with permission from The American Oil & Gas Reporter

TECH TRENDS 28 FIGURE 1 Cross-Section of Charco Field Geologic Environment the hole section. Orienting a PDC bit can be time consuming and inefficient. The bit is frequently pulled off bottom to control the reactive torque, and it is often necessary to reduce WOB to maintain the desired tool face. Tool face angle is proportional to the torque generated by the bit. PDC bits, by nature, generate high levels of torque. The combination of the drive and bit systems, coupled with the lower-than-optimum WOB, leads to a dramatic reduction in penetration rates. A conventional rotary BHA can also result in inefficient drilling when strict verticality is required. As with a steerable PDM assembly, the directional behavior of the conventional rotary assembly is a function of the formation, drilling parameters and stabilizer gauge and placement. To maintain verticality, drilling parameters must often be adjusted to less-thanoptimum requirements, which again sacrifices penetration rates. Push-The-Bit System Two basic types of rotary steerable technologies are available: push-the-bit and point-the-bit systems. Point-the-bit systems aim the bit at an angle in the desired direction, creating the curvature necessary to deviate the well path while continuously rotating the drill string. Conversely, push-the-bit RSS technology steers by using hydraulically-actuated pads to push against the sides of the well bore, displacing the tool and the bit in the direction desired. A push-the-bit configuration was used on the Charco Field wells, with three pads sequentially pushing against the side of the bore hole as the drill string rotated while a central control valve remained stationary. A bias unit consisting of an internal rotary valve controls the hydraulic actuation of three externally-mounted pads, while a control unit housing the geostationary electronics package and directional instrumentation controls the tool s behavior. The control unit holds itself stationary inside the rotating collar, and derives power from the flow of drilling fluid across an impeller. Attached to the downhole end of the control unit is a control shaft that extends into the bias unit. The control shaft is stationary when the control unit is stationary. A valve on the end of this rod seats over three ports that rotate together with the rest of the bias unit. As each port passes beneath the stationary valve, drilling fluid is diverted into it, activating one of the three pads. The process results in each pad pushing out at the same relative position in the bore hole to force the bit in the opposite direction. The amount of time that the control unit is held stationary over a given period determines the tool s dogleg capability. A stabilizer acts as a third point of bore hole wall contact for directional control. FIGURE 2 Locations of Well Groups Selecting the option of string, integral blade or sleeve-type stabilizers allows the position and size to be varied to fine-tune BHA behavior in different environments. Like all steerable technology, the RSS tool is placed in the BHA directly above the bit and below the measurement-whiledrilling/logging-while-drilling equipment. The bit is screwed into the lower connection of the RSS and the MWD/LWD tools are screwed onto its upper connection. Charco Field Geology The portion of the Charco Field where the vertical wells are being drilled using RSS technology consists of 35, acres and is divided into east and west segments by three large faults (1,-1,5 foot throws) that trend northeast-tosouthwest. There are two primary pay intervals: the Perdido and Lobo sands. Figure 1 shows a schematic cross-section of the geologic environment. The upper pay interval is the Perdido Sand package, part of the Middle Wilcox formation. The Perdido is characterized by multiple stacked gas reservoirs, with A, A-1 and B being the three primary

FIGURE 3 ( Group A Wells) Group A - start RSS @ 1, ft. and end RSS @ 9, ft. FIGURE 4 2, Depth versus Cost (Group A Wells) 2, 4, 6, 4, 6, 1, 12, 14, 2, 4, 6, 8, 1,, 1,2, 1, 12, 14, 2 4 6 reservoirs. Formation tops range from 8,4 feet subsea west of the big fault to 1,6 feet subsea east of the big fault. The Perdido Sands can dip as much as 45 degrees. The lower Lobo Sand package is part of the Lower Wilcox formation. The pay intervals are the Lobo 1, 3 and 6 sands with the occasional stray sand. Formation tops range from 12, feet subsea west of the big fault to 14,4 feet subsea east of the big fault. The Lobo has multiple fault planes with 35-7 degrees dip. It is common to drill through multiple faults with 3-1 feet of throw in a single well bore in the Lobo section. The geologic intervals and subsea depths encountered while drilling include: The Jackson Shale, which extends from the surface casing shoe to 1,5 feet; The Yegua-Cook Mountain-Sparta complex to 3,6 feet; The Queen City to 4,6 feet; The Reklaw Shale to 6,4 feet; The Carrizo Wilcox to ±7,8 feet; and The Vela Shale at feet. Intermediate casing is set into the transition zone in the Vela Shale. While steering using conventional steerable motor assemblies, the Queen City can be problematic because of the variability in formation compressive strengths encountered (2,-3, psi), making it very difficult to hold tool face while sliding. The problem is even more acute in the Carrizo Wilcox (9,-15, psi compressive strengths). Although the variability in compressive strength is less, average compressive strengths are higher, and the greater depths result in lower penetration rates. In addition, the Carrizo Wilcox has occasional pyrite-rich intervals, which can be detrimental to PDC bits. RSS technology has addressed the inefficiencies of both conventional rotary BHA and steerable PDM assemblies in Charco Field vertical wells positioned on or close to the hard line of 467 feet from the lease line. Furthermore, RSS technology allows optimum drilling parameters to be applied while drilling, including using more aggressive PDC bits, and eliminates sliding intervals for faster penetration rates and reduced BHA trips while maintaining high levels of well bore placement accuracy. Case Study Wells Figure 2 shows the locations of groups of Lobo vertical lease-line wells. In all wells in groups A, B and C, the drilling fluid was a standard South Texas program of water-based mud in the intermediate section and oil-based mud in the production section. All the RSS wells were drilled between 24 and 26. In Group A, two wells were drilled using conventional rotary BHA techniques, one with a PDM, and two using RSS. The two RSS wells exhibited less than 1 feet accumulated displacement, whereas the conventional wells exhibited almost 3 feet. The PDM well drifted off by almost 45 feet from vertical (Figure 3). Of the five wells in this group, the third well, drilled with a PDM, required 26 days and the greatest number of days to reach total depth by far. The second and FIGURE 5 ( Group B Wells) Group B - start RSS @ 85 ft. and end RSS @ 9,7 ft. 2, 4, 6, 1, 12, 14, 2 4 6

TECH TRENDS 28 FIGURE 6 2, 4, 6, 1, 12, 14, fourth wells were drilled using RSS technology, and reached TD in 19 days, which was as fast as the two wells (first and fifth) drilled with a conventional rotary Depth versus Cost (Group B Wells) 2, 4, 6, 8, 1,, 1,2, 1,4, 1,6, 1,8, FIGURE 7 ( Group C Wells) Group C - start RSS @ 7 ft. and end RSS @ 8,5 ft. 2, assembly, but while maintaining better verticality of the bore hole. In terms of drilling cost, the lowest cost in Group A was achieved by the two conventional wells, whereas the highest cost was accrued by the PDM well. The two wells drilled with RSS achieved superior verticality at a slightly higher cost than the wells drilled with conventional BHAs (Figure 4). Of the Group B wells selected for the study, two were drilled using RSS, one with a PDM, and one using a conventional approach. As with the previous group, the RSS wells achieved significantly less displacement (less than 5 feet) compared to the PDM and conventional wells, which exhibited displacements greater than 35 and 45 feet, respectively (Figure 5). The fourth well (drilled RSS) reached total depth seven days sooner than the PDM well and 22 days sooner than the conventional well. This well holds the county record for fastest penetration rate from drill out to TD for an 8¾-inch intermediate section. RSS was used to help fight deviation trends in the section and to stay within the extremely tight lease lines. RSS technology kept the hole vertical, allowing the rig to keep constant WOB with no need to fan the bit or backream, which can add hours to drilling time. The bit was able to drill the entire interval at such a high penetration rate that drilling time was cut by 5 percent, more than offsetting the additional cost of RSS technology. Group B wells show a clear cost advantage for applying RSS, as shown in Figure 6. Comparing wells one, two and four (the third well was intentionally drilled to only 11,655 feet to test the Perdido Sand) shows a savings of $26, and $593, for the RSS well, respectively, over wells drilled with a conventional rotary BHA and a PDM, in addition to better verticality. In Group C, the wells drilled with RSS have 132 and 211 feet of accumulated displacement, whereas the conventional and PDM wells exhibit a range from 321 4, FIGURE 8 Depth versus Cost (Group C Wells) 6, 2, 4, 1, 12, 6, 1, 14, 2 4 6 12, 14, 2, 4, 6, 8, 1,, 1,2, 1,4, 1,6,

TECH TRENDS 28 to 48 feet (Figure 7). Of the first three wells to be completed, two were drilled using RSS. Again, the wells drilled with a conventional rotary BHA or PDM exhibited drill times up to 11 days longer. Examining the six wells drilled in this series reveals only one that provided a marginally lower cost than those drilled with RSS, as shown in Figure 8, but it took longer to drill than the RSS well. Cost-Effective Solution RSS technology has proven a cost-effective solution in lower-margin onshore drilling environments. In the Charco Field applications, the technology has been more reliable and effective than conventional steerable motor technology, allowing vertical wells to be drilled faster and at lower cost while maintaining the near-verticality required for small targets or lease-line obligations. The operator estimates that 8 percent of the lease-line wells drilled to date would have been drilled using a PDM if RSS technology were unavailable, and the remaining 2 percent (five well locations) would have gone undrilled. These wells are estimated to yield 1.5 billion cubic feet of gas production per well over the life of the wells, cumulatively adding 7.5 Bcf from the five wells. Better weight transfer to the bit and using more aggressive bits to reduced drilling time is another key element in the economic impact of RSS technology. Taking an average across the field of days spent drilling with RSS versus a PDM or conventional drilling, the time from spudding to first sales gas was reduced by an average of five days. That translates into the ability to drill an additional two lease-line wells a year. When used as a directional drilling device, it also allows higher penetration rates and better bore hole control. With the increasing trend toward denser well placement, RSS technology s ability to economically drill in close proximity to lease-line limits can have a significant impact on resource recovery and the overall economics of a field. Overall, RSS technology has allowed the Charco Field operator to cost-effectively optimize the remaining reserve value of its producing leases and fully exploit the remaining potential in the fields. Editor s Note: The preceding article was adapted from a technical paper (AADE 7-NTCE-12) originally prepared for presentation at the American Association of Drilling Engineers 27 National Technical Conference & Exhibition, held April 1-12 in Houston. WILLIAM D. DEE KRUSE is consulting drilling engineer at Energy XXI. He previously worked for The Houston Exploration Company, which is now Forest Oil. Kruse started his career with Gulf Oil, and has worked as a field and in-house consultant and engineer in Houston since 1985 for various energy companies, responsible for drilling, completion and production operations. Kruse holds a degree in natural gas engineering from Texas A&I University. GOKE AKINNIRANYE is drilling engineering manager for Schlumberger North and South America in Houston. He joined Schlumberger in 1986 as a field engineer and has more than 2 years of oil and gas experience. Akinniranye has served as field service manager, senior instructor, technical manager and InTouch engineer. He earned a B.S. in geophysics/geology from the University of Ife, Nigeria. ANDREA BAUTISTA GOMEZ is Schlumberger s field engineer recruiter for North America. She joined Schlumberger in 22 as a Drilling & Measurements MWD/LWD engineer working in Southeast Asia and South and Central America. Bautista dedicated part of her career delivering PERFORM services in South America and the United States. She graduated from the University of America in Colombia with a B.S. in petroleum engineering. BENNY POEDJONO is the survey and data manager for Schlumberger s North and South American operations, and is based in Houston. He has worked for various segments of Schlumberger for the past 23 years with assignments in 22 countries. Poedjono serves on the Society of Petroleum Engineers and Society of Petrophysicists & Well Log Analysts Industry Steering Committee on Wellbore Survey Accuracy. He holds an engineering degree from the Institute of Technology Bandung in Indonesia. BILL B. DUBOSE is the rotary steerable systems business development manager, U.S. land, at Schlumberger. He has worked in various roles covering many locales for 28 years. His career started with an offshore drilling contractor as a roustabout and progressed to a toolpusher. Since then, he has been a fishing tool operator, directional drilling supervisor, drilling consultant, workover rig owner, and directional drilling operations manager. Dubose attended the University of South Mississippi and is currently enrolled in Villanova University s organizational leadership program. ROGER B. GOOBIE is a technical sales engineer for Schlumberger Drilling & Measurements Gulf of Mexico operations. He previously held the position of PERFORM /No Drilling Surprises manager for the Schlumberger Drilling & Measurements North and South America operations support center in Houston. Goobie joined Schlumberger as a specialist drilling engineer 11 years ago, and worked in Trinidad and Tobago, Venezuela, the Gulf of Mexico, Colombia, Brazil and India as lead engineer on several drilling optimization projects. He holds a B.S. in electrical engineering from the University of the West Indies St, Augustine in Trinidad and Tobago. JOHN HOBIN is Drilling & Measurements sales engineer for Schlumberger in Houston, a position he has held since 25. Prior to this, he served as field service manager in Wharton, Tx, and as drilling services engineer for the Atlantic Canada region. He joined Schlumberger as a field engineer in 1999. Hobin holds a B.S. in mathematics from Dalhousie University and a B.S. in chemical engineering from the Technical University of Nova Scotia.