Extended Reach Drilling Wells Research Articles

A New Model for Cleaning Small Cuttings in Extended-Reach Drilling Based on Dimensional Analysis

A wellbore’s cleanliness affects drilling efficiency, economy and drilling safety directly in extended-reach drilling operations. Wellbore cleaning in extended-reach drilling has always been a tough problem. Field experience has shown that inefficient transport of small cuttings is a main factor for excessive drag and torque during extended-reach drilling. However, very little is known about the transport of small cuttings. In this paper, we use the data fitting method of dimensional analysis and regression analysis to establish a wellbore cleaning model for high-inclination sections, then use water and Polyanionic Cellulose (PAC) as a drilling fluid to analyze the settlement cleaning of small cuttings in the wellbore. The data from the example wells were used for field simulations to finally derive many factors like drilling fluid density, drilling fluid displacement, drill pipe rotation speed, diameter of cuttings and annulus hydraulic diameter, which affect the thickness of the dimensionless cutting bed. The results show that the dimensionless cutting thickness decreases with increasing drilling fluid density, drilling fluid displacement and drill pipe rotation speed; and increases with increasing cutting size and annular hydraulics diameter. Meanwhile, the effect of drilling fluid discharge, drill pipe rotation speed and cutting size on the thickness of the dimensionless cutting bed decreases as their values increase. This model can be utilized to design parameters in drilling and to predict the transport of cuttings in high-inclination sections. The successful establishment of the wellbore cleaning model for small cuttings in high-inclination sections of extended-reach drilling wells is highly innovative, which is a successful combination of theory and practice and has important guiding significance for promoting the development of wellbore cleaning technology.

Selection of Optimal Well Trajectory Using Multi-Objective Genetic Algorithm and TOPSIS Method

This study presents a novel approach for optimizing well paths in extended reach drilling (ERD) wells. Different trajectories can be used for ERD wells, each with its pros and cons. Previous research overlooked certain objective functions in single-objective optimization and lacked an autonomous method for selecting the best solution from Pareto optimal solutions in multi-objective optimizations. Furthermore, they lacked comparing different profiles in well design. Risk assessment and operational factors, which greatly influence optimization and drilling success, were insufficiently considered. This study utilized the multi-objective genetic algorithm (MOGA) and the technique for order preference by similarity to an ideal solution (TOPSIS) method to select the optimal well path based on torque, wellbore length, risk (e.g., keyseat), and required tools. First, all possible trajectories were determined, and MOGA identified the optimal path with minimal torque and length. The fuzzy decision-making method automatically selected the best solution from the Pareto optimal solution set. The associated risks and required tools are evaluated for each trajectory. Finally, the TOPSIS method selected the optimal trajectory based on torque, length, risks, and required tools. The case study demonstrated that the undersection path was the most advantageous trajectory for ERD wells, with a 60% closeness to the ideal state. The multiple build trajectory achieved 57% closeness, while the build and hold and double build paths had lower closeness values (43 and 28%, respectively). Consequently, it can be inferred that in the context of ERD wells, it is preferable to carry out the deviation process at deeper depths.

Technology Focus: Extended-Reach and Complex Wells (May 2023)

A clear change in the last 2–3 years is that the energy transition is becoming the undisputable trend for almost all major oil and gas companies and oilfield services providers, as evident from the news of rebranding, the roll-out of companies’ new strategies, and announcements of commitments to net zero. Geothermal energy, especially within deep, hot, dry rock, is abundant around the globe. It can be a great opportunity for the majors to boost their energy-transition process and open new business opportunities. Previously, however, deep geothermal development activities were rather limited and participation from the majors was sporadic. One reason was that drilling into such extra-hot and extra-deep impermeable rock could render excessively high cost and risk, making the development of deep geothermal energy far from economical and scalable and discouraging many companies from entering this hot spot. The domain expertise and technologies in the oil and gas industry such as integrated project planning and operating, extended-reach drilling (ERD), high-pressure/high-temperature drilling tools, multilateral drilling and completions, geomechanics, flow and thermal dynamics modeling, and artificial intelligence have been fueling the ongoing march for new records on ERD, multilateral, and other complex wells. They have made it possible to drill faster, further, and with more production, which will be the keys to accelerating the learning curve, filling the technology gap, and breaking the economic barrier on deep geothermal drilling, which in turn will attract more players to this new arena. A bold move of the majors into deep geothermal drilling could accelerate the removal of the economic and technical hurdles in harnessing the enormous baseload renewable energy and meanwhile backfeed new drilling technologies developed in deep geothermal applications to the oil and gas industry for a more sustainable future. Recommended additional reading at OnePetro: www.onepetro.org. SPE 206616 Deep Geothermal Well-Construction Problems and Possible Solutions by Mikhail Yakovlevich Gelfgat, Gubkin University, et al. SPE 200792 Lessons Learned and Case Studies of Overcoming Sustained Casing Pressure in Extended-Reach Wells by Svetlana Nafikova, SLB, et al. IPTC 21439 Application of Multilateral Wells for Production and Enhanced Oil Recovery: Case Studies From Canada by Eric Delamaide, IFP-Technologies

Concurrent 5. Presentation for: Seamless in seam – new geosteering technology delivered challenging coal seam gas project with success

Presented on Tuesday 17 May: Session 5 A recent coal seam gas (CSG) appraisal project posed several challenges. The target reserve area had limited seismic data available and yet had complex structure with several faults of variable orientations and throws between 2 and 25 m. Dual-lateral extended-reach drilling (ERD) wells needed to be drilled in order to access this reserve, with a 1000 m in-seam section for each lateral planned to maximise production. Conventional technologies for CSG projects included motor bottom hole assembly with a boundary mapping tool for geosteering in the coal seams. However, for drilling ERD wells in this unknown area, these methods were insufficient to deliver success, due to the limited mapping capabilities and drilling efficiencies. Recently there has been significant development on the directional resistivity-based mapping tool, on both the measurements and processing. The operator adopted a new mapping-while-drilling technology which has the first-in-industry tool with axial, tilted and transverse antennas integrated in one module. This new technology can provide high-resolution multilayer mapping with doubled depth of investigation, even when drilling out of the coal seam. The results from utilising this new tool, together with a rotary steerable system for directional control, were very encouraging. The new multilayer mapping-while-drilling tool mapped both the top and base of the coal seam throughout horizontal sections in-seam. In addition, it detected the coal seams during landing and after fault-crossing from up to 4 m true vertical depth away, enabling the team to navigate through complex fault zones confidently, and to deliver the project with success. To access the presentation click the link on the right. To read the full paper click here

Seamless in seam – new geosteering technology delivered challenging coal seam gas project with success

A recent coal seam gas (CSG) appraisal project posed several challenges. The target reserve area had limited seismic data available and yet had complex structure with several faults of variable orientations and throws between 2 and 25 m. Dual-lateral extended-reach drilling (ERD) wells needed to be drilled in order to access this reserve, with a 1000 m in-seam section for each lateral planned to maximise production. Conventional technologies for CSG projects included motor bottom hole assembly with a boundary mapping tool for geosteering in the coal seams. However, for drilling ERD wells in this unknown area, these methods were insufficient to deliver success, due to the limited mapping capabilities and drilling efficiencies. Recently there has been significant development on the directional resistivity-based mapping tool, on both the measurements and processing. The operator adopted a new mapping-while-drilling technology which has the first-in-industry tool with axial, tilted and transverse antennas integrated in one module. This new technology can provide high-resolution multilayer mapping with doubled depth of investigation, even when drilling out of the coal seam. The results from utilising this new tool, together with a rotary steerable system for directional control, were very encouraging. The new multilayer mapping-while-drilling tool mapped both the top and base of the coal seam throughout horizontal sections in-seam. In addition, it detected the coal seams during landing and after fault-crossing from up to 4 m true vertical depth away, enabling the team to navigate through complex fault zones confidently, and to deliver the project with success.

Extended-Reach Drilling Hits Mainstream To Squeeze Difficult Reservoirs

Though expensive and complex, extended-reach drilling (ERD) is moving more into the mainstream as the industry is driven to develop frontier reserves in fragile environments like the Arctic where drilling from shore to off-shore targets reduces a project’s infrastructure costs and environmental footprint. A form of directional drilling, ERD is also being used increasingly to tap into hard-to-produce reservoirs, making viable projects that might otherwise be written off as noncommercial. This article highlights how the Russian Far East became the ERD epicenter in the past decade, given ExxonMobil and Rosneft’s extensive use of ERD in developing Arctic resources offshore Sakhalin Island, and how ERD is becoming more widely used in regions as diverse as the Gulf of Thailand, off-shore Brazil, and the Arab Gulf. By definition, an extended-reach well (ERW) is one in which the ratio of the measured depth (MD) vs. the true vertical depth (TVD) is at least 2:1 (PetroWiki). An ERW differs from a horizontal well in that the ERW is a high-angle directional well drilled to intersect a target point, a feat requiring specialized planning to execute well construction. ExxonMobil subsidiary Exxon Neftegas Limited (ENL), which operates the Sakhalin-1 license area offshore Russia’s Sakhalin Island (Fig. 1), has been pushing the limits of ERD for nearly 2 decades with innovative technologies and sophisticated well planning, making the Sea of Okhotsk a place where any ERD drilling record set today may easily be broken tomorrow. Russia’s state-owned Rosneft (which has a 20% stake in Sakhalin-1) owns bragging rights for having drilled the longest ERW well on record to date. Rosneft announced in November 2017 it had drilled a 15000-m horizontal ERW from the offshore Orlan gravity-base platform at Chayvo field situated in 14 m water depth in the Sea of Okhotsk, topping four previous records set between 2013 and 2015 that had reached between 12450 m and 13500 m (Fig. 2). In a news release at the time, Rosneft called the well “super complex with a DDI [directional drilling index] of 8.0 and a 14129-m stepout.” The release went on to say that the Sakhalin-1 Consortium could (as of the 2017 announcement) claim to have drilled nine out of the world’s 10 longest ERD wells. According to Rosneft, the project had set five world records for measured depth of wells between 2013 and 2017. In April 2015, development well O-14 was drilled with a length of 13500 m. That broke a 2014 record when the 13000-m Z-40 well was completed. In 2013, records were announced for wells Z-43 and Z-42 which were drilled, respectively, in April and in June 2013 with lengths of 12450 m and 12700 m. Rosneft credited ExxonMobil’s patented “Fast Drill” drilling optimization process that can increase rates of penetration (ROP) by up to 400% as a significant innovation contributing to the ERD success story at Sakhalin-1. One of the largest foreign direct investments in Russia, Sakhalin-1 operates under a production sharing agreement (PSA) with its license area off the northeastern coast of Sakhalin Island, comprising the Chayvo, Odoptu, and Arkutun Dagi fields.

Drilling Dynamics, Mechanical Specific Energy Data Help Drill Record Extended-Reach Well

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203335, “Using MSE and Downhole Drilling Dynamics in Achieving a Record Extended-Reach Well Offshore Abu Dhabi,” by Nashat Abbas and Jamal Al Nokhatha, ADNOC, and Luis Salgado, Halliburton, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. Complex extended-reach-drilling (ERD) wells often present challenges with regard to geological aspects of data requirement and transmittal, reactive geosteering response times, and accuracy of well placement. Such scenarios may require innovative approaches in Middle East carbonate reservoirs. The objective of the complete paper is to illustrate that, by assessing the details of reservoir geology and key operational markers relevant for best practices, drilling approaches can be customized for each reservoir or scenario. Reservoir Background and Geology The planned reservoir section is a single horizontal of approximately 25,000-ft lateral length at a spacing of 250 m from adjacent injectors. The well was drilled from an artificial island. Field A, a shallow-water oil field, is the second-largest offshore field and the fourth-largest field in the world. Horizontal drilling was introduced in 1989, and an extensive drilling campaign has been implemented since then using steerable drilling technologies. This study is concerned only with wells drilled to develop Reservoir B in Field A, which contributes to the main part of initial oil in place and production. The thick limestone reservoir is subdivided into six porous layers, labeled from shallow to deep as A, B, C, D, E, and F. Each porous layer is separated by thin, low-porosity stylolites. The reservoir sublayer B, consisting of approximately 18-ft-thick calcareous limestones, was selected as the target zone for the 25,420-ft horizontal section. ERD, constructed on artificial islands, began on 2014 with a measured depth (MD)/true vertical depth (TVD) ratio approaching 2.2:1 or 2.4:1. A recent ERD well, Well A, was drilled at the beginning of 2020 with a MD/TVD ratio of 5:1. This value is a clear indication of progressively increasing challenges since the start of the project. Mechanical specific energy (MSE) has long been used to evaluate and enhance the rate of penetration (ROP); however, its use as an optimization tool in ERD wells has not been equally significant. This may have been mostly because of historical use of surface-measured parameters, which do not necessarily indicate the energy required to destroy the rock, particularly in ERD wells. Using optimization tools as part of the bottomhole assembly (BHA) downhole close to the bit provides actual weight-on-bit (WOB) and torque-on-bit (TOB) applied to the drilling bit to destroy the rock and, thus, results in more-representative MSE measurements to optimize drilling parameters and ROP in ERD wells.

The Halladale–Speculant fields: the first nearshore gas fields to be developed from mainland Australia

Extended-reach drilling (ERD) is becoming an increasingly common technique used to explore for hydrocarbons and develop fields in areas where simple vertical wells cannot be drilled due to access problems, stakeholder concerns, environmental issues, poor reservoir quality and/or cost. While these types of wells are generally more expensive and technically challenging to drill than vertical wells, they can be very cost-effective, and if a discovery is made, considerably quicker to monetise when future development costs are also taken into consideration, particularly in offshore environments. In 2014–2015, the conventional Exploration and Production division of Origin Energy (now Lattice Energy) drilled three onshore-to-offshore ERD wells and a geological sidetrack in the Otway Basin with horizontal offsets of 1929, 2576, 4239 and 5152 m targeting an undeveloped gas field (Halladale) and exploration prospect (Speculant) located in Victorian state waters near Port Campbell. The three wells (Halladale-2, Speculant-1 and Speculant-2) and sidetrack (Speculant-2ST1) were drilled during a single drilling campaign from the same pad to reduce mobilisation, drilling and development costs. Halladale-2 was designed to develop the Halladale Field, while Speculant-1, -2 and -2ST1 were designed to evaluate the Speculant Prospect. Both Speculant wells and the sidetrack encountered significant gas columns with Speculant-1 and Speculant-2ST1 subsequently completed as producers after being successfully flow tested. A 33 km onshore pipeline was then constructed to transport the gas from Halladale and Speculant back to the Otway Gas Plant (OGP) for processing and sale. The arrival of first gas at the OGP from the Halladale and Speculant gas fields on 26 August 2016 marked a significant milestone for Origin Energy in terms of accelerated project delivery. It also represented the end of a 15-year journey for Halladale from exploration to discovery to development. The drilling campaign also set several records in the process with: (1) Speculant being the first offshore field to be discovered from mainland Australia; (2) Halladale and Speculant being the first offshore fields to produce gas back to mainland Australia from onshore wells; (3) Halladale-2, Speculant-1 and Speculant-2 being the three longest onshore-to-offshore wells drilled to date in Australia (in horizontal departure terms); and (4) Halladale-2 being the longest well (in mMDRT terms) drilled to date in the Otway Basin. Speculant is a good example of how transition zone (TZ) seismic and ERD technology can be used successfully to explore and develop resources in areas previously considered too difficult by using more conventional seismic acquisition and drilling technology.

From shallow horizontal drilling to ERD wells: How scale affects drillability and the management of drilling incidents

The context of drilling operations is quite variable in geometric scale and complexity. Wells range from Extended Reach Drilling (ERD) wells with measured depths greater than 10 km to exceptionally shallow wells no longer than 2 km but only 200–300 m in true vertical depth. With the objective of achieving greater levels of drilling automation, it is important to understand how the well geometrical scale impacts drillability and the management of drilling incidents.The robust control of the drilling process necessitates the correct management of delays in the system. Some sources of delay are directly linked to physical dimensions, while others are the results of the system infrastructure. Time delays due to the travel of information through a medium belong to the first category while delays due to signal filtering or processing and actuator latency belong to the second category. The transient response of the drilling system greatly influences the controllability of the drilling process and both the detection and reaction times for drilling incidents such as over-pulls or pack-offs.This paper proposes a categorization of the various sources of delay in a drilling system. A brief review of similar sources of delay in other industries is presented first, and then the sources of delay are characterized into four classes: the elasticity, inertia, and friction of the physical system, measurement refresh rate and latency, processing latency, and maximum actuator acceleration. Delays within these four classes are quantified for three different scenarios: a 10 km-long ERD well, a shallow horizontal well, and a three-dimensional shale well. Illustrative examples of the four classes of delay are presented within these scenarios. Any drilling automation system faces a varying set of constraints for each application, which should influence both the automation procedures themselves as well as sensing requirements.The paper illustrates how scale influences the necessary constraints in drilling procedures, by comparing the delay within the full range of drilling scenarios. Human operator and rig system reaction time and variable awareness to drilling dysfunctions are the most limiting factors in improving drilling efficiency. The automation of drilling procedures with robustness considerations for scale and latency issues therefore plays an important role in increasing drilling performance.

The Effect of Different Drilling Fluids on Mechanical Friction

A very important aspect in highly inclined wellbores is the mechanical friction. For extended reach drilling (ERD) and through tubing extended reach drilling (TTERD) this can be a limiting factor. Friction caused by the contact between the drill string and the well casing or borehole is dependent on the drilling weight and fluid properties. Drilling fluids play an important role in determining mechanical friction. The use of oil-based drilling fluids with higher lubricity can reduce torque and drag behavior and minimize stick and slip. Reducing mechanical friction will improve drilling efficiency in general, and will in particular enable longer reach for ERD wells. This paper presents results from experimental laboratory tests where the mechanical friction has been investigated. Friction behavior was investigated for different drilling fluids; water-based and oil-based drilling fluids both with and without solid particles. A pin on disk setup was used for these experiments where a spherical ended steel pin was slid against a rotating disk made of granite. The test results show that the mechanical friction in general is smaller with oil-based than water-based drilling fluids in the presence of solid particles.

Technology Update: New Intelligent Completion System Enables Compartment-Level Control in Multilateral Wells

Technology Update Although early inflow control devices and intelligent completions (ICs) were introduced almost 20 years ago, completion technology has not kept pace with advancements in drilling technology. Today, wells completed in multilayered reservoirs, multilaterals with compartments of varying pressure, and extended-reach drilling (ERD) with wellbores as long as 12 km are becoming common. In complex, hard-to-reach reservoirs and tighter formations, operators need to maximize reservoir contact in every well to optimize reservoir drainage and minimize costs. Yet the evolution of ICs has lagged, creating a technology gap with significant ramifications. IC reliability has been steadily increasing over the years, reaching more than 97% for the life of the well in many applications. Most permanent downhole monitoring and control solutions still consist of a separate “kit” of products rather than an integrated system. Traditional IC systems lack sufficient real-time measurements in individual producing zones to facilitate “cause and effect” decision making. Without detailed compartmental information and control in case of water or gas breakthrough, operators are forced to restrict production, intervene, and in some instances work over the entire well. Until recently, there has been no way to maintain production from other unaffected zones during the long diagnostic process of production logging, well testing, interpretation, and execution of an appropriate well intervention. The typical optimization cycle substantially raises operating costs while delaying vital production for weeks or months. Consider Saudi Aramco’s experience with ICs in remote oil fields, where tight formations and a shortage of suitable surface locations drove the need to dramatically increase reservoir contact per wellhead. Before 2007, the company had successfully drilled and completed a number of multilateral ERD wells, achieving more than 5 km (16,400 ft) of reservoir contact per well. These maximum reservoir contact (MRC) wells were completed with then state-of-the-art IC technology. Completions consisted of permanent downhole gauges (PDGs) and downhole flow-control valves (FCVs), which could be partially or fully opened or closed by hydraulic control lines from the surface. Monitoring and control stations were installed in the motherbore above the junction to each side lateral.

Managed-Pressure-Drilling Technology Succeeds in the Harding Field

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166170, ’Managed-Pressure Drilling, Casing, and Cementing Enable Success in Conventionally Undrillable Wells in the Harding Field,’ by Mohamed A. Mashaal, Tom Fuller, Chris J. Brown, and Robert Paterson, BP, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed. This paper presents a case history of a North Sea well in which managed-pressure drilling (MPD) was used as the enabling technology to drill, case, and cement the well, with particular focus on the planning process, design methodology, and execution particulars. A novel fluid-pressure- transmission pill (FPTP), composed of a crosslinked polymer, was also used to maintain hydrostatic pressure while tripping bottomhole assemblies (BHAs) and during deployment of the liner and sand-control equipment. Background and Drilling Challenges The Harding field is a mature North Sea platform development upon which an infill-drilling project has been initiated to access the remaining oil. This oil tends to lie in more-distant, hard-toreach targets, including those in the far north of the field and a new field located south of the platform. These would be accessed by extended-reach-drilling (ERD) wells. A combination of reservoir depletion and weak interbedded sands and shales has resulted in a further reduction in the already narrow mudweight (MW) window between fracture and formation-collapse pressures. The window had decreased from 2 to 0.7 lbm/gal, equivalent to a 200-psi bottomhole- pressure (BHP) window. ERD to access the oil accumulations most distant from the platform would generate equivalent circulating densities that are 50% greater than the available MW window, so these wells are not conventionally drillable. After MPD proved to be an effective strategy for a test well (IC6) in the Harding field, the decision was made to apply MPD to two ERD wells (PNE4 and PNE2) that had not achieved their objectives. A subsequent investigation into the shortcomings of these wells led by the subsurface team resulted in a reworking of the pore-pressure/fracturegradient predictions for the northeast of the field, taking the depletion in that part of the reservoir into account. Sand/ shale interfaces at the margins of the reservoir, and sand/sand interfaces created by the injection of sand through the main reservoir body, also appear to result in localized fracture-gradient reduction. These combined factors resulted in a reduced MW window compared with that previously used in well planning. Hydraulics modeling strongly suggested that drilling PNE2a (the redrill of PNE2) would be unachievable conventionally, and drove the decision to use MPD for the reattempt. PNE2a would include a 12¼-in. overburden section, a highly challenging prospect containing more than 6,000 ft of shale, as well as the 8½-in. reservoir section, which was expected to have significant sections of shale where instability had previously caused drilling problems (see Fig. 1).

Setting the Bear Free: Challenges of the Deepwater Ursa A-10 ERD Well

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 163525, ’Setting Free the Bear: The Challenges and Lessons of the Ursa A-10 Deepwater ERD Well,’ by John Gradishar, SPE, and Gustavo Ugueto, SPE, Shell Upstream Americas, and Eric van Oort, University of Texas at Austin (formerly with Shell Upstream Americas), prepared for the 2013 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 5-7 March. The paper has not been peer reviewed. This case history presents the highly challenging extended-reach deepwater well, Ursa A-10, drilled in the Ursa (Latin for bear) prospect in the US Gulf of Mexico (GOM). This 30,000-ft well, drilled from the Ursa tension-leg platform (TLP) to a vertical depth of 18,000 ft and a horizontal displacement (HD) of 20,000 ft, targeted the Yellow sand in the Ursa/Princess section of the greater Mars-Ursa basin. During drilling of the original hole, a subsequent sidetrack, and two mechanical bypasses, several significant hole problems materialized that led to extensive nonproductive time. At least five independent borehole-failure mechanisms were encountered. Introduction In the aftermath of the tragic 2010 Macondo/Deepwater Horizon event, it is important that the industry share case studies on successful wells. It also is important to share information on wells that proved to be very challenging. Sharing learnings, best practices, and experiences on such wells will raise the overall level of proficiency in constructing these wells throughout the industry. As is often the case, more is learned from adversity than from outright success. This is the main reason that the Ursa A-10 case is presented. Over the last decade, world-class extended-reach-drilling (ERD) wells have been drilled in the continued development of the Mars-Ursa basin in the GOM. These high-deviation wells are distinguished by depth [true vertical depth (TVD) greater than 17,000 ft], HD greater than equal to ;20,000 ft, and overall measured depth (MD) greater than equal to 30,000 ft. Challenges include a geopressured deepwater environment, complex casing programs, and special drilling issues. The combination of these challenges makes the Ursa A-10 case noteworthy. ERD wells have been drilled to longer HD and overall MD, but those wells generally had simpler casing programs and a more-forgiving pore-pressure/fracture-gradient environment with associated drilling margins. Larger margins leave more room for such things as equivalent-circulating-density (ECD) and annular-pressure fluctuations, mud problems (such as barite sag and hole-cleaning and associated pack-off problems), accommodating manageable levels of borehole instability, and implementation of limited redesign philosophies.

Thin-Oil-Column Extended-Reach Drilling at Sakhalin

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 163487, ’Case History of a Challenging Thin-Oil-Column Extended-Reach- Drilling Development at Sakhalin,’ by Vishwas P. Gupta and Shea R. Sanford, SPE, ExxonMobil Development Company; Randall S. Mathis and Erin K. DiPippo, SPE, Exxon Neftegas; and Michael J. Egan, AIPC, Consultant to Exxon Neftegas, prepared for the 2013 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 5-7 March. The paper has not been peer reviewed. ExxonMobil, operator for the Sakhalin-1 project, planned an additional drilling campaign at the Chayvo field, Sakhalin Island, Russia. The focus of this campaign was to develop a thin-oil-column reservoir by use of extended-reach drilling (ERD). This overview describes the planning of these wells at the edge of the ERD envelope, the associated technical and operational challenges, and the complexity of targeting a thin oil column in an ERD environment. Planning of these wells involved building upon the operator’s previous experience and the use of additional tools and methods to address unique challenges. Introduction The Sakhalin-1 project comprises the Chayvo, Odoptu, and Arkutun Dagi fields off the east coast of Sakhalin Island, Russian Federation, as shown in Fig. 1. Development drilling at the Chayvo field started in 2003 with extended-reach wells drilled from an onshore wellsite pad with the Yastreb drilling rig. In 2005, further development drilling commenced from the offshore Orlan platform. In 2008, the Yastreb rig was moved approximately 75 km north to the Odoptu onshore wellsite pad and drilled nine ERD wells as part of the initial-stage development of Odoptu. Following the Odoptu campaign, the Yastreb rig was moved back to the Chayvo onshore wellsite in 2011 for further development and infill drilling of the Chayvo reservoirs. As of October 2012, 15 of the 20 longest ERD wells in the world had been drilled in the Sakhalin-1 project, with the recently completed Well Z-44 at Chayvo field setting a new measured-depth (MD) record at 12 376 m. Significant well-design parameters, tools, and techniques that enabled these challenging wells are detailed in the complete paper. The technical challenges included uncertainties in the location of the oil column and fluid contacts, the need for very accurate well placement for effective reservoir drainage and for preventing early gas/water breakthrough, completing long horizontal intervals, and high-torque/drag effects. The geologic uncertainties and wellbore-positioning challenges were addressed with a combination of a single near-horizontal pilot hole to locate the fluid contacts and a novel technique to minimize vertical-position uncertainty by use of formation-pressure measurements while drilling. Extensive torque/drag modeling and wellbore-stability modeling were performed to design the wells and equipment and define operational parameters. Completion designs were optimized to ensure successful placement in long horizontal intervals.

Optimization Delivers ERD Performance Boost - Sakhalin Island

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 150959, ’Successful Optimization Strategies Combine To Deliver Significant Performance Boost at the Edge of the ERD Envelope-Sakhalin Island, Russia,’ by Richard W. James, SPE, Paul Pastusek, SPE, and Gary R. Kuhn, SPE, ExxonMobil; Anton Andreev, Exxon Neftegas; and Jeffrey R. Bailey, SPE, and Lei Wang, SPE, ExxonMobil, prepared for the 2012 IADC/SPE Drilling Conference and Exhibition, San Diego, California, 6-8 March. The paper has not been peer reviewed. Many performance-enhancement initiatives were used by the operator of the Sakhalin-I project in drilling and completing the extended-reach-drilling (ERD) program at the Odoptu field, Sakhalin Island, Russia. The initial seven-well ERD program was expanded to nine wells, including the world-record Well OP-11. The operator’s redesign philosophy to remove limiters from the drilling process resulted in significant performance improvements in all areas of drilling and completion operations. Background The Odoptu field is one of three fields developed by Exxon Neftegas off the coast of Sakhalin Island, Russia, as part of the Sakhalin-I Project (Fig. 1). The climate is subarctic, with temperatures lower than freezing more than half of the year, and temperatures can drop below −40°C. The field is at the northeastern edge of the Eurasian tectonic plate and is subject to significant earthquake activity, the most recent of which was rated 7.6 on the Richter scale in 1995. Drilling began in the Chayvo field in 2003, following mobilization of the Yastreb rig to the Chayvo onshore well-site. After drilling one cuttings-injection well and 20 ERD wells, the Yastreb rig was upgraded and moved to the Odoptu North wellsite in late 2008. Drilling commenced from the Chayvo offshore well-site with the installation of the Orlan platform in 2005, where an additional cuttings-injection well and 19 ERD wells were drilled. During the move from Chayvo to Odoptu, significant upgrades were made to the rig on the basis of lessons learned at Chayvo and to accommodate the higher torque anticipated at Odoptu. The new topdrive could deliver 91,000 lbf-ft of torque at 130 rev/min. A larger mast was required to accommodate the new top-drive, and an additional generator was installed. The drillstring was upgraded to provide significantly higher torque capacity. In addition, the handling capacity of the cuttings-injection unit was increased. Drilling began at Odoptu in April 2009 (with the cuttings-injection well) and ended in February 2011 (with completion of Well OP-2). Although seven ERD wells were planned at Odoptu initially, the program was expanded to nine wells as a result of drilling successes and favorable production performance. The wells included Well OP-11 with 12 345-m measured depth (MD) and 11 479-m horizontal reach. The Yastreb rig has drilled more than 300 000 m of hole. Following the Odoptu program, the Yastreb rig was moved back to the Chayvo onshore well-site to drill additional ERD wells.

North Sea World Record Installation–Deepest Sealed Multilateral System

Summary In October 2010, the deepest-set sealed multilateral (ML) junction in the industry was installed at 6900-m measured depth (MD) in Oseberg South Well 30/9-F-9 AY1/Y2. The differential pressure across the junction in the well was expected to be in the range of 250 bar. To meet this pressure requirement, a junction system rated to 370 bar was identified. The high-pressure junction components and entire multilateral system have undergone an extensive testing and qualification program, including several component tests and a full-scale system interface and integration test. A 10¾-in. precut window was installed as an integral part of the 10¾-in. liner. The plan was to perform the milling operation through this window. A stuck-string incident during the 10¾-in. liner installation accidentally caused the liner to drop in the hole. The liner ended up at the wrong orientation, and the window could consequently not be used. The main bore was drilled to total depth (TD) at 8583-m MD, and the 7-in. liner was run and cemented. After the liner perforation, the BL operations started with the installation of an anchor packer and a latch interface assembly (LIA). The milling operation was performed in a two-step operation with milling of a first-pass window by use of a downhole milling machine before installing a whipstock and performing the second-pass milling operation. The lateral branch was drilled to TD at 8258-m MD, and a 5½-in. screen completion was run and dropped off into the 8½-in. open hole. The junction was finally stung into a completion deflector, simultaneously with an openhole seal stinger entering the top of the screen liner in the open hole, tying the branches together. A 6900-m upper completion string with inflow control valves was finally installed to allow for surface control of the two branches. Despite severe drilling problems in the transport sections of the well, the ML operations were deemed successful. Major risk and challenges with this well design involved orientation of the 10¾-in. liner (to position the premilled window) at this depth, debris management after milling operations, and general depth control during junction construction. Debris management in particular became essential as the backup ML solution meant milling steel rather than aluminum. Although the two different reservoirs could be drained by two conventional extended-reach-drilling (ERD) wells, this would be a less cost-efficient solution. Furthermore, the construction of an ML well means that the aforementioned challenges drilling the transport sections had to be handled only once. The successful installation at this depth has proved that ML technology is feasible for use in ERD wells, either to improve the total reservoir exposure or to reach multiple targets from one well.

Pushing the Extended-Reach Envelope: Drilling a Record-Reach Well

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 151046, ’Pushing the Extended-Reach Envelope at Sakhalin: An Operator's Experience Drilling a Record-Reach Well,’ by Michael W. Walker, SPE, ExxonMobil, prepared for the 2012 SPE/IADC Drilling Conference and Exhibition, San Diego, California, 6-8 March. The paper has not been peer reviewed. Extended-reach drilling (ERD) has become a common means to access reserves economically from existing infrastructure, provide access to reserves that were previously out of reach, and reduce the environmental footprint of drilling and production facilities. ExxonMobil, as operator for the Sakhalin 1 project, recently completed drilling operations at the Odoptu field, located offshore Sakhalin Island, Russia. The Odoptu development drilled nine extended-reach wells from shore, culminating with the world-record-reach OP-11. This record-setting extended-reach well reached a total depth of 12 345-m measured depth (MD) (40,502 ft) and 1784-m true vertical depth (TVD), with 11 479 m of vertical section in 60 days with less than 1% nonproductive time. Introduction The Sakhalin 1 project comprises the Chayvo, Odoptu, and Arkutun Dagi fields, located off the east coast of Sakhalin Island, Russia (Fig. 1). As of January 2011, 15 of the 20 longest-reach wells in the world had been drilled in the Sakhalin 1 project, with the Odoptu Well OP-11 surpassing the 2008 Maersk Well BD-04A in Qatar. Because of limited exploration-drilling data from the Odoptu field, the development was designed to be performed in stages. The first stage of development was designed to ascertain drilling and production performance, thereby allowing future development operations to be optimized. Hence, the project included drilling a vertical disposal well and seven ERD wells, with two additional ERD wells added subsequently. Following the drilling of a vertical cuttings-reinjection well, the first two ERD wells at Odoptu were designed to ascertain the height of the oil column, thereby refining the remaining drilling objectives. The first well, Well OP-8, drilled an 8½-in. pilot hole that penetrated the reservoir section horizontally in the oil column and was geosteered updip to locate the gas/oil contact, measure reservoir pressures (and determine fluid gradients), and exit the top of the reservoir again at a 99° inclination. The pilot hole was then plugged, and a horizontal production hole was drilled and completed. The second well, Well OP-7, was drilled downdip to determine the pressure and fluid gradient in the aquifer leg of the reservoir. It was subsequently sidetracked horizontally through the oil column and placed into production. Using the pressure and fluid-contact data from these two wells, the height of the oil column was deter-mined and vertical placement of subsequent wells in the reservoir sections was highgraded.

Changing the Safe Drilling Window With Invert Emulsion Drilling Fluids

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 132207, ’Changing the Safe Drilling Window With Invert Emulsion Drilling Fluids: Advanced Wellbore Stability Modeling Using Experimental Results,’ by Terry Hemphill, SPE, Halliburton; William Duran, SPE, Saudi Aramco; and Younane Abousleiman, SPE, Vinh Nguyen, SPE, Minh Tran, SPE, and Son Hoang, U. of Oklahoma, originally prepared for the 2010 CPS/SPE International Oil and Gas Conference and Exhibition in China, Beijing, 8-10 June. The paper has not been peer reviewed. Often the range in drilling-fluid densities required to prevent hole collapse without fracturing the wellbore (i.e., the safe drilling window) is narrow. This often is the case for wells having high deviation angles, and is of particular concern in extended-reach-drilling (ERD) wells. With increasing stepouts, the drilling equivalent circulating density (ECD) continues to climb with increasing measured depth (MD) while the true-vertical depth (TVD) remains fairly constant. Introduction The drilling of challenging wells often is characterized by a narrow safe drilling window, with the fracture-initiation pressure as the upper bound and the wellbore hole-collapse pressure as the lower bound. For those cases where the collapse pressures are below the pore pressure, the pore pressure then serves as the safe-drilling-window lower bound. The safe drilling window commonly is gauged in terms of equivalent mud weight (EMW) and represents the acceptable range of density for maintaining wellbore stability. When the wellbore is circulated, for example during drilling operations, the EMW is equivalent in value to the ECD. When the wellbore is static, the EMW is equivalent in value to the equivalent static density (ESD). Depending on the downhole pressure and temperature conditions, the ESD often is not equal to the density measured under ambient conditions, especially when drilling with invert-emulsion drilling fluids (IEFs). In the modeling of stresses around an intact wellbore, the safe drilling window becomes more narrow with increasing hole angle. Specifically, a deviated wellbore profile requires increased EMW to prevent collapse and reduced EMW to initiate fractures. Hence, in ERD wells, the safe drilling window can become very narrow at the higher angles of deviation. In the drilling of ERD wells having long departures, the ECD will continue to increase with increasing MD, as the frictional pressure produced while circulating increases with hole length while the TVD does not increase by much, if at all. The effect of ECD in these kinds of wells serves to increase the operating EMW to the point where the upper bound of the safe drilling window can be violated and initiation of wellbore fracturing is predicted. Consequently, much effort has been focused in recent years to widen the safe drilling window safely without sacrificing wellbore stability.

Aluminum Pipes: A Viable Solution To Boost Drilling and Completion Technology

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 13758, ’Aluminium Pipes - A Viable Solution To Boost Drilling and Completion Technology,’ by M.Y. Gelfgat, SPE, A.V. Vakhrushev, D.V. Basovich, SPE, and V.S. Tikhonov, Aquatic Company, and A.C. Odell, SPE, and D.J. Brunnert, SPE, Weatherford, originally prepared for the 2009 International Petroleum Technology Conference, Doha, Qatar, 7-9 December. Modern extended-reach drilling (ERD) projects become more and more challenging. Some of the recently drilled ERD wells probably came close to the limits of available drilling technology. Future targets promise to be even more distant and challenging, which is why there is a need for advanced technology that can either reduce friction in a borehole or reduce the gravity force component acting between contact surfaces. Introduction Aluminum drillpipe (ADP) has a long application history in the USSR and Russia. It has been used for drilling since the end of the 1950s. By the beginning of the 1990s, ADP was involved in drilling 70 to 80% of all oil and gas wells in the Soviet Union. At the present time, approximately 1 000 000 m of ADP is in operation in Russia. Aluminum-Alloy-Drillpipe Performance The most important feature of aluminum alloys used as materials for tubular manufacturing is that, because they are three times lighter than conventional steel alloys, they provide considerable strength properties. This gives them an exceptional strength/weight ratio (i.e., the ratio of tension yield strength of the pipe to its weight in mud). Physically, this ratio can be represented as a length of drillpipe suspended under its own weight in a vertical borehole filled with mud when the stress at the top cross section reaches yield stress of the material. Properties of four aluminum alloys are given in Table 1 in the full-length paper. Despite the fact that aluminum-alloy drillpipe has two steel tool-joint parts threaded onto the aluminum-alloy-drillpipe body, the influence of their weight on the total weight of the assembled pipe is less than 30% and the equivalent density of ADP (which is a calculated density of multimaterial product) has little difference from the density of the aluminum alloy itself. Depending on the size and length of the pipe, the equivalent density of ADP varies from 3200 to 3600 kg/m3, because the initial density of aluminum alloys equals 2800 kg/m3. Most steels are 7800 kg/m3. This means that the weight in air of the ADP is approximately half that for steel pipe. When placed in drilling mud, ADP loses a greater percent of its weight because of a better buoyancy factor. For example 5 7/8-in. steel drillpipe becomes 15% lighter when placed in 1200-kg/m3 drilling mud, whereas 5 7/8-in. ADP loses 35% of its initial weight. ADP in horizontal sections of a borehole produces drag and torque nearly half that of its steel equivalents. This feature provides the ability to extend the limits of drilling from available rigs of limited-load and -torque capacity, decrease the wear of rig equipment (e.g., topdrive, wireline, and block-and-tackle system), and decrease the overall energy consumption of the drilling process. In the extreme applications of ultraextended-reach drilling, use of ADP could extend the displacement significantly.

Drillstring Technology for World-Class Extended-Reach Drilling

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18512, "Drillstring Technology Vanguard for World-Class Extended-Reach Drilling," by M.J. Jellison, SPE, and R.B. Chandler, SPE, Grant Prideco; M.L. Payne, SPE, BP; and J.S. Shepard, SPE, GlobalSantaFe, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May. Projects that will expand the extended-reach-drilling (ERD) envelope are in the planning stage in various parts of the world. Drilling engineers no longer are wondering if 50,000-ft ERD wells can be drilled but how this can be accomplished safely and efficiently. It has been estimated that the last 10% of the drilled interval can account for 50% of the total drilling cost. The full-length paper discusses the latest drillstring technologies that are essential to achieve the ERD targets planned for the future. Advanced Material Technologies Industry publications have presented the idea of using nonsteel drillstrings for reduction of torque and drag loads in extended-reach (ER) wells. Other torque- and drag-reduction and management tools and techniques that have proved successful are lower in cost, thus being the preferred methods for meeting current ER torque and drag challenges. The competition of these alternative technologies has inhibited the development of commercially available nonsteel drillpipe. The direction toward longer-departure ER wells has led to increased consideration recently for commercially available nonsteel drillpipe. Generally, three advanced materials should be included in this consideration—carbon-fiber-based composites, titanium, and aluminum. Each has been used in drillstrings with varying degrees of success. Each material has strengths and weaknesses relating to its use for drillpipe to drill ER wells and other critical applications such as ultradeep drilling and deep water. Carbon-Fiber-Based Composites. Composite drillpipe (CDP) is manufactured by winding carbon fibers over a mandrel while applying an epoxy matrix to encase the fibers and seal the assembly. CDP manufactured to date has had steel pin-and-box tool joints similar in design to conventional steel-drillpipe connections. The steel tool joints are attached to the composite tube during the winding process in which the carbon fibers are placed over specially designed ends of the tool-joint members to bond with the composite tube and resist fatigue in service. Currently produced CDP is approximately three times the cost of conventional steel drillpipe. As the technology improves and the capabilities of carbon-fiber manufacturers advance, this price differential may decrease. CDP offers several potential advantages over conventional steel drillpipe that could make CDP particularly well suited to ERD and other critical drilling applications.