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.
The Barnett Shale field of North Texas is the most prolific and fastest growing natural gas field in North America.1 The field has a multi-trillion cubic feet equivalent upside potential, but efficient extraction of natural gas from the Barnett shale poses drilling and geological challenges. Geological complexity of this field requires precise placement and drilling of the well as per the directional well plan. Some of the major drilling challenges that affected drilling efficiency were downhole drill-string dynamics, high torque and drag, hole pack-offs and loss circulation. Engineers determined that early detection of downhole problems such as high vibrations, poor hole cleaning and high equivalent circulating densities (ECD) were key to improving drilling performance. To overcome these challenges state-of-the-art advanced technology tools were run to acquire real-time drilling data and images. Real-time drilling data acquired was inclination/azimuth close to the bit, bore/annular pressure and vibration/stickslip. Drilling data gathered in real-time were crucial to detect and eliminate potential drilling problems before they became a problem. Real-time geological data transmitted to surface were formation resistivity and azimuthal gamma ray measurements. High-resolution images were developed from real-time azimuthal gamma ray measurements. These images could be utilized to precisely detect bed boundaries and accurately estimate formation dips. This strategy has been implemented to drill several wells in the Barnett Shale with excellent results. Advanced technologies have helped in significantly improving drilling performance and in precise placement of the wellbore. Significant reduction in rotating hours has been achieved. Introduction The Fort Worth Basin covers approximately 15,000 square miles and is located in north-central Texas.2,3. This basin is a shallow, north-south elongated trough and 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 and the basin shallows onto the positive feature of the Bend Arch to the west.2,3 In its deepest area adjacent to the Muenster Arch, the Fort Basin contains a maximum of 12,000 ft of sedimentary section.1 In this area, the Barnett Shale can reach a thickness greater than 1,000 ft.2,3 In the core area of the Newark East Barnett Shale Field, the Barnett shale is encased by tight carbonates, which act as fracture barriers during the completion process.2,3 A typical stratigraphic column2,3 of the Fort Worth basin was previously published. (Janwadkar, S. et al.: "Advanced LWD and Directional Drilling Technologies Overcome Drilling and Completion Challenges in Lateral Wells of Barnett Shale," paper SPE 110837).
Typically S/J type directional land wells of North America utilize steerable downhole motors. This selection has some limitations: trips to adjust AKO for build/tangent/drop sections, potentially less than optimal hole quality from string rotation, possible drillstring/BHA/casing wear, potential hole enlargements requiring increased cement volumes and high torque/drag due to wellbore tortuosity. Closely spaced wells require precise control of wellpath to prevent collision. Multiple corrections to wellpath may increase wellbore tortuosity. Rotary steerable systems (RSS) requiring rotation of drill string are typically cost prohibitive for this application/environment. To overcome these challenges research, field testing and ten years of experience gained with other rotating/non-rotating rib steering systems has culminated in the development of a new state-of-the-art directional drilling system. The system, specifically designed for low inclination 3-D wellbores, utilizes an automated rib-steering closed loop system with a non-rotating drill string. Since the introduction of this innovative/sophisticated system many wells have been drilled in North America with build/drop of 3°/100 ft. Vertical/build/tangent and drop sections can be drilled without tripping. Tangent section inclination remained within 0.2°. Wellpath corrections were made while drilling by system's automatic closed loop control. The new system has reduced drilling/completion time, minimized hole enlargements, reduced torque/drag to help deliver smooth high quality wellbores and increased efficiency of cementing operations. This has allowed the operator to log and set tubulars easily and quickly, leading to early production. The innovative system has potential applications in many similar areas of the world to drill simple/complex S/J type wells without string rotation. Low-inclination wells can be drilled with precision and efficiency due to the closed loop's constant control over wellpath, and the ability to drill long sections without tripping for BHA changes. 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.1 Building on this success, the operator contacted a leading service provider to identify opportunities for improving drilling performance of low inclination directional wells. To meet the operator's aggressive drilling schedule and achieve performance improvement, a team of operator and service company staff developed a strategy that included application of advanced directional drilling technologies to meet the directional requirements as per well plan while significantly enhancing hole quality and wellbore placement precision. Geological and Drilling Background The Fort Worth Basin (Figure 1), 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, 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 ft of sedimentary section in its deepest area adjacent to the Muenster Arch.2 In this area, the Barnett section2 can reach a thickness greater than 1,000 ft. In the core area (Figure 2) 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 3.
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