Summary The Granite Wash unconventional gas and oil play of the US midcontinent has a multitrillion-cubic-feet-equivalent upside potential. The condensates and natural-gas liquids associated with this gas play make it one of the most-prolific and fastest-growing unconventional fields in North America. However, efficient extraction of hydrocarbons from the Granite Wash play poses drilling and geological challenges. The Granite Wash deposit has significant lateral variation, with extremely abrasive thinly bedded sandstones. Geological complexity of this field requires precise placement and navigation of the wellbore in real time to overcome the variable characteristics of the reservoir. To overcome these challenges, logging-while-drilling (LWD) technology was used in conjunction with geosteering. An azimuthal gamma ray image was used to determine formation bed dip and stratigraphic complexity within the reservoir. Multiple-propagation resistivity measurements were used to correlate position within the reservoir and indicate formation porosity. The LWD data was transmitted in real time by means of satellite to a remote reservoir-navigation center where the reservoir-navigation engineer incorporated the real-time data into the geological model. This strategy has been implemented to drill with excellent results, as compared with the offset wells. The initial production rate obtained was 19.4 MMcfe/D (cfe = cubic foot equivalent). The well was completed 10 days ahead of schedule, resulting in significant cost savings. With the successful implementation of real-time reservoir-navigation and drilling technology, the operator accelerated their drilling program. The results are significant organic production growth, improved drilling performance, precise placement of the wellbore, and significant reduction in rotating hours at lower drilling and production costs.
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.
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.
Woodford Shale of Oklahoma is emerging as one of the fastest growing natural gas fields in North America because it has all the characteristics required for a profitable shale-gas play. More than $2 billion were spent in 2008 on some of the major productive intervals in this field. Although the upside potential is tremendous, efficient extraction of natural gas from the Woodford Shale poses several drilling and completion challenges. Low porosity and permeability limits well productivity. Complex well profiles and extended length laterals are required to maximize productivity. Long laterals posed several drilling challenges such as excessive slide drilling time, difficulty controlling well trajectory, unacceptably low penetration rates, high torque, and high drag. Engineers determined that wellbore tortuosity and high friction factors caused inefficient transfer of weight on bit and reduced rate of penetration (ROP). Existing rotary steerable systems available are typically cost prohibitive for this application/environment. To overcome these challenges, research, field testing and several years of experience gained with other automated rotating and non-rotating rib steering systems has culminated in the development of a new state-of-the-art rotary steerable closed-loop system (RCLS). This system, specifically designed for 3D wellbores for rotary steerable directional drilling in low spread cost land-drilling applications uses an automated rib-steering closed-loop system. Since the introduction of this innovative system, many wells have been drilled in North America with build/drop of 8°/100 ft. Bottomhole assembly (BHA) modeling software with finite element analysis was used to optimize BHA design. This strategy has been implemented to drill several wells in the Woodford Shale with excellent results. The new design of RCLS coupled with advanced BHA modeling software has significantly improved the drilling performance. The results achieved are excellent control over the well trajectory in the curve and lateral, improved transfer of weight to the bit, minimum torque and drag. Drilling complex well profiles have increased the length of laterals by several hundred feet. This has enabled additional recovery of gas, and the days required to drill the lateral interval have been reduced by more than five days. Introduction Oklahoma's geology presents numerous challenges for the oil and gas industry. In the past, the operator had faced several problems while drilling in Kiowa and Washita Counties of southwestern Oklahoma. Extreme geological complexities had posed several drilling challenges. The operator in conjunction with the service provider had implemented advanced drilling technologies and drilling optimization to significantly improve drilling performance in southwestern Oklahoma (Simonton et al. 2005). Additionally the service provider had completed several drilling optimization projects in Oklahoma and north Texas (Bone et al. 2005; Poulain et al. 2004; Janwadkar et al. 2006; Janwadkar et al. 2007). Building on this success and to meet the operator's drilling schedule, the operator and the service provider once again teamed up with the objective to improve drilling performance in their current drilling project in Canadian County. The current drilling project comprises drilling horizontal wells in the Woodford Shale of the Anadarko basin (Fig. 1) located in the Canadian County of Oklahoma. Fig. 2 shows the geological provinces of Oklahoma in addition to the major fault systems.
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