Roller cone bits have dominated the 8–1/2" steerable application in Abu Dhabi due to their proficient steerability, consistently achieving the required build rates in the soft Nahr Umr shale. In the vertical section, PDC bits often achieve up to four times the penetration rates of TCI bits. However, directional performance when using PDC bits to build angle was compromised by fluctuations in reactive torque resulting in poor tool face control and inconsistent build up rates. The overall result was poor penetration rate and performance compared to roller cone bits. The operator and a service company utilized a new design process and cross functional team approach to aggressively seek new steerable PDC technology to drill the curved section with controllable torque response and consistent directional behavior while achieving the full penetration rate advantage of PDC bits. This process was complemented by the Well Delivery Limit process (WDL) that was already established by the operator that focused on delivering high value wells with significantly reduced costs. The team analyzed the drilling operations from virtually every perspective using numerical models, laboratory drilling tests, and field testing. The key to the PDC solution was the team process that identified the relevant drilling problems and performance requirements in order to develop the needed technology. After 30 bit runs from November 2001 to June 2002, the team reduced drilling costs by $44.26 per foot for a total savings of $3,792,367 over 85,682 ft and 2,386 drilling hours. The average ROP for the section doubled from 18 ft/hr with TCI bits to 36 ft/hr. The current ROP record stands at 60 ft/hr over a 3,169 ft interval. Introduction The operator and bit manufacturer have a history of joint optimization of roller cone technology in this 8–1/2" interval, improving cutting structure and metal face sealed bearing performance. The operator has documented these achievements, along with two failed attempts to drill wells with PDC bits.1 Despite advances in directional drilling technology and more powerful positive displacement motors (PDM), even as recently as late 2001, IADC code 517 roller cone bits were the only technology that could provide both tool-face control and build up rates required for the well plans. The lithology for this section consists of short section of limestone, followed by long section of soft shale to the landing point in a limestone reservoir. All PDC attempts failed to achieve any significant drilling improvements because of poor tool face control and inadequate build rates through the soft shale. Seeing an opportunity to reduce drilling costs, engineers from the operator, bit supplier and motor supplier developed a new technology for steerable PDC bits through an open and cooperative process. Well Plan The 8–1/2" interval starts at approximately 6,600 ft at the bottom of a limestone interval where unconfined compressive strength (UCS) ranges between 9 and 21 ksi. At approximately 7,400 ft, a 3 to 5 ksi UCS shale is encountered which extends to the top of the reservoir at 8,100 ft. Almost half of the directional work takes place in the soft shale before the reservoir is penetrated at around 40 degrees of inclination. The limestone reservoir features alternating soft and hard layers, with the softer rock around 9 ksi UCS and the firmer rock 15 to 26 ksi UCS. Figure 1 shows a plot of the rock type and compressive strength versus depth while Figure 2 shows two typical well plans. Directional work continues until the well is horizontal and measured depths often extend to 9,500'.
The Barnett Shale field of North Texas is one of the most prolific and fastest growing natural gas fields in North America with a multi-trillion cubic feet equivalent upside potential. However, the area presents numerous drilling challenges. In the vertical section, roller cone bits had unacceptable low penetration rates while PDC bits suffered premature damage. High torque and drag along with low penetration rates hampered drilling the curve and lateral sections. To address these challenges, a detailed engineering analysis was performed utilizing sophisticated BHA and drill string modeling software. Engineers studied offset wells and drillstring modeling including buckling load analysis, critical speed analysis, and torque and drag analysis. As a result of the study, engineers determined that bit whirl and stick-slip were resulting in premature bit damage and reduced ROP while drillstring buckling resulted in inefficient transfer of weight on bit. Modeling helped design a BHA that mitigated buckling while optimized drilling parameters avoided critical speeds. The improvements resulted in 42% to 121% higher penetration rates with minimal damage to the PDC bits. The 8¬3/4" vertical section was drilled in one PDC run in 60 out of 104 wells resulting in significant reduction in rotating hours and average cost per foot. The new BHA reduced drillstring buckling and significantly reduced torque and drag while drilling the curve and lateral sections. The authors will describe the significance of applying principles of buckling load and torque and drag analysis; to design technically sound BHA's. They will also discuss how to utilize drillstring dynamics to avoid critical speeds. Introduction Low porosity along with other geological/lithological challenges has hampered the efficient extraction of natural gas from the Barnett Shale for over 40 years. During the last several years, the operator has been utilizing fracturing technology which has significantly increased production in the field.[1] Drilling lateral sections further enhanced production/economics in the region (Figure 1). On an average, a horizontal well produces triple the cubic feet of gas compared to a vertical well at only twice the cost. Building on this success, the operator contacted a leading service provider to identify opportunities for improving drilling performance. To meet the operator's aggressive drilling schedule and achieve performance improvement, the team developed a strategy that included optimizing drilling methods to improve horizontal well delivery time. The goal was to achieve a significant increase in ROP drilling the vertical, curve, and lateral intervals. Geological Background The Fort Worth Basin (Figure 2), is a shallow, north-south elongated trough encompassing approximately 15,000 square miles in north-central Texas.[2] The basin is bounded on the north, northeast, and east by faulted basement uplifts of the Red River Arch, the Muenster Arch, and the Ouachita Structural Front. The southern limit is defined by the Llano Uplift.[2] To the west, the basin shallows onto the positive feature of the Bend Arch. The Fort Basin contains a maximum of 12,000 feet of sedimentary section in its deepest area adjacent to the Muenster Arch.[2] In this area, the Barnett section can reach a thickness greater than 1,000 feet.[2] In the core area (Figure 3) of the Newark East Barnett Shale Field, the Barnett shale is encased by tight carbonates which act as fracture barriers during the completion process.[2] A typical stratigraphic column of the Fort Worth basin is depicted in Figure 4. Drilling Optimization Process Structure Drilling optimization has resulted in significant improvements in drilling performance in the region.[3–5] The structure of the drilling optimization process followed by the service company is show in Figure 5. This process is comprised of four phases: pre-project, planning, drilling, and post-well. Each phase consists of clearly defined steps and peer review Figure 5.
fax 01-972-952-9435. AbstractEconomical development of deep oil and gas wells in the Marlow field in Southern Oklahoma requires efficiently drilling a complex geological structure with faulted and highly dipping formations. Operators typically employ conventional motor directional systems to keep inclination to a minimum in the 8-3/4" vertical hole section. While this type of bottom hole assembly (BHA) has improved directional control, it still leads to unacceptable angle building tendencies/dogleg severity and poor vertical hole quality resulting in additional directional issues in subsequent hole sections. In addition, the conventional directional assembly increases well costs due to multiple deviation correction runs with different BHA configurations resulting in more flat time, lower cumulative bit penetration rate, and more bits/runs per section.To address these issues, the service company studied drilling performance, mud logs and wireline data from offset wells. The resulting analysis detailed the key problems and led the operator to set new objectives for the 8-3/4" vertical hole section of achieving the highest possible rate of penetration (ROP) while maintaining a near-vertical wellbore. An implementation strategy was outlined that had two main components including a sophisticated vertical drilling system (VDS) with a new polycrystalline diamond compact (PDC) bit technology.This approach has been utilized to drill the 8-3/4" hole section on two wells with the following results: Reduced inclination from 22º to 1.5º (VDS) and reduced dogleg severity (DLS) from 4º/100ft to just 1º/100ft (VDS). The new system has also reduced torque/drag and delivered a smooth quality wellbore and totally eliminated costly correction runs. The increased wellbore quality has allowed the operator to log, then set 5 ½" casing without incident. The operator has experienced increased performance when kicking off below a section drilled with the new BHA (VDS/bit) improving directional control and aiding geosteering to the target reservoir.
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