Accurate estimation of mud weight (MW) helps to conserve wellbore stability in real-time drilling operations. Determination of proper MW requires a correct understanding of the stress field, natural fractures, pore pressure, rock strength, borehole trajectories, etc. It is a problematic task especially in, highly inclined wells, deviated wells, and near salt formations due to uneven variations in wellbore stresses. Proper MWs are difficult to apply at target depths of the unstable formations because of uncertainties existing inside the wellbore. There are no reliable tools or techniques available that can precisely determine the optimum value of MW. This paper proposes a novel and more convenient approach to estimate the safe MW for deviated wells using surface measured data. In this study, Bagging and Random forest ensembles have been utilized to model the relationship between sensors measured variables and MW. The proposed framework has been trained and tested on real-time Norwegian post-drilling data. Artificial neural networks (ANNs) and support vector regression (SVR) have also been utilized in this study for comparison purposes. The analysis of prediction results clearly reveals that Random forest ensemble has acquired the highest coefficient of correlation and minimum estimation errors. The performance of Ensemble methods is found to be superior to the ANNs and SVR models. The proposed approach can be useful for the determination of MW required at different depths of reservoir formation and maintaining the wellbore stability during real-time operations.
Maintaining a stable borehole and optimizing drilling are still considered to be vital practice for the success of any hydrocarbon field development and planning. The present study deliberates a case study on the estimation of pore pressure and fracture gradient for the recently decommissioned Volve oil field at the North Sea. High resolution geophysical logs drilled through the reservoir formation of the studied field have been used to estimate the overburden, pore pressure, and fracture pressure. The well-known Eaton’s method and Matthews-Kelly’s tools were used for the estimation of pore pressure and fracture gradient, respectively. Estimated outputs were calibrated and validated with the available direct downhole measurements (formation pressure measurements, LOT/FIT). Further, shear failure gradient has been calculated using Mohr-Coulomb rock failure criterion to understand the wellbore stability issues in the studied field. Largely, the pore pressure in the reservoir formation is hydrostatic in nature, except the lower Cretaceous to upper Jurassic shales, which were found to be associated with mild overpressure regimes. This study is an attempt to assess the in-situ stress system of the Volve field if CO2 is injected for geological storage in near future.
This paper is based on the analysis of the ultrasonic/sonic data of the 9 5/8-in. casing logging of the 14 wells of the Varg field within the Norwegian Continental Shelf. While writing this papper Varg field was undergoing a plug and abandonment (P&A) phase after 19 years of production. High-quality bonding is observed behind the 9 5/8-in. casing far above expected theoretical top of cement within single casing areas. This bonding is attributed to the formation influence. Formation is used as an alternative to traditional cement barriers during P&A, and its use is regulated by the legislation.
The paper aims to develop better understanding of the mechanisms responsible for formation bonding development. The percentage of observed bonding at "high" and "high and moderate-to-high" quality is calculated within each well and is related to the various factors that could influence formation bonding development. Factors such as duration of time lapsed from well completion to well logging, type of well (producer versus injector), geological formation, type of drilling mud used, duration of production periods, volumes of production, and well deviation and azimuth were looked at to determine observable trends and relationships.
The results of the study allowed us to conclude which factors are critical or influence formation bonding. Based on the observations, recommendations can be made for the selection of the first well to be logged on the planned P&A campaigns. Correct selection of the first well saves time and resources on the formation testing for the qualification of the formation as a barrier.
Valler, Victoria (ION) | Payne, Nathan (ION) | Hallett, Thomas (ION) | Kobylarski, Marcin (ION) | Venkatraman, Girish (Engie E&P Norge) | Rappke, Jochen (Engie E&P Norge) | Fairclough, Dirk (Monarch Geophysical Services)
consuming area to be addressed during velocity model building. In addition to their impact on deeper structures and prospects, re-worked injectites are increasingly being considered for hydrocarbon potential themselves. In order to handle the challenges above we should consider ways of producing an accurate velocity model of these structures within a framework that is efficient and commercially timeviable. Here we present a holistic approach and case study to model-building in and around injectites that utilizes robust broadband data pre-processing, a semi-automated identification and modeling of injectite bodies and subsequent high-resolution tomographic updating. Our results show that this method enables us to produce a highly accurate and detailed model of a complex injectitefield and subsequent improvement on the deeper image within the timeframe of a conventional model building iteration.
Presentation Date: Wednesday, October 17, 2018
Start Time: 8:30:00 AM
Location: 208A (Anaheim Convention Center)
Presentation Type: Oral
In the mature fields in Norway's North Sea, extended-reach drilling (ERD) well designs were implemented to reach distant reservoir target zones. Resulting from this change, the 12.25-in. overburden section, which drills through mostly shale with various hard and thin dolomitic limestone sections, had to be modified from a 5,000- to 7,000-ft vertical section to a 10,000- to 12,000-ft section at a tangent inclination anywhere from 35 to 70°. Drill-bit designs that used to drill the vertical overburden section consistently in one run currently require up to three bits to complete the modified tangent sections caused by excessive damage to the diamond cutting structure.
An extensive study into the offset ERD wells and corresponding bit dull conditions helped identify that the cutting structure damage originated from high-point load impacts to the shoulder of the bit while transitioning through the thin, hard dolomitic limestone formations; the damaged cutters were being tangentially overloaded. Through further bit modifications, it was determined that this type of damage could not be addressed using typical bit design modifications (e.g., increased cutter density, increased blade count, etc.); therefore, a unique design solution was developed and implemented.
This solution involved combining analytical simulations and a dull condition analysis to develop an improved method for using the backup cutting structure to support the high tangential loading on the primary cutting structure during hard, high-inclination transitions. In most dual-row cutting structure designs, the backup cutters are on the same radial position as their parent primary cutters and are underexposed, engaging the formation only at a specific depth of cut or after the primary cutters are worn down a certain amount. When positioned as such, the backup cutters do nothing to support the tangential loading on the primary cutters. By moving the backup cutters actively on profile with the primary cutters and offsetting them to their own radial positions, the backups could now actively support the high tangential loads occurring on the primary cutters when engaging the hard dolomitic limestone.
This simple but unique modification enabled the bit to handle the transitions and drill the entire next 11,000-ft+ ERD section in one run while also providing the fastest rate of penetration (ROP) to date, with an increase ranging from 30 to 40% compared to previous runs. The success has been repeated a dozen more times since, each time providing a new record ROP for an ERD section. The improved dull condition could also allow for more efficient designs in the future for further improvements to drilling performance. The successful reduction of tangential impact damage could have implications for various bit designs globally that incur a similar dull condition.
This case study aims to share the experience and improve the understanding of downhole shock and vibration and demonstrate how it can be prevented using thorough offset analysis, an advanced bit design, downhole mechanics module, and detailed drilling roadmap. The new approach delivered a step change in the performance of the 17 ½-in. section in Valemon field, in the Norwegian sector of the North Sea. Employing a one-run strategy through this extremely demanding section could eliminate the need for a dedicated motor run to withstand high shocks through the sandy interval with interbedded limestone and cemented sand layers. Using a point-the-bit bottomhole assembly (BHA) with a detailed drilling roadmap for every group of formations secured smooth drilling, pull out, and running of the intermediate 14-in. × 13 3/8 in. casing to provide integrity to drill 12 1/4-in. section.
An advanced bit design balanced drilling with low aggressiveness through sand without compromising the performance through the interbedded limestone stringers and claystone. The conical-shaped cutter placed behind the main PDC conventional cutters successfully controlled the depth of cut through the sandy intervals and mitigated the downhole shocks.
A detailed drilling roadmap was developed to define formation-specific drilling parameters to mitigate the shock-related failures on similar lithology.
A downhole drilling mechanics module was used to provide real-time axial, lateral, and torsional shock and vibration data, which enabled adjustment of surface drilling parameters accordingly.
Many facets of geology involve processing large sets of data, and recognizing patterns. Still, geology largely remains a qualitative study where professionals spend endless man-hours pouring through reports to build models for predictive analysis. Machine Learning is a subfield of analytics and computer science which is dedicated to using pattern recognition to build models. In traditional data analytics an algorithm is applied to data which then yields a result, but Machine Learning compares large sets of data with results from analysis to create an algorithm and models which can then be used for predictive analysis. In this paper we will examine large sets of curve data from the Norwegian Continental Shelf, and compare it with the classifications for the stratigraphy and geological structures from the Norwegian Petroleum Directorate to build models using different Machine Learning strategies. During the analysis the data and result sets are divided into three parts, where half is to build the model, and fourth is used as preliminary test set to improve the algorithm and the final fourth to test the final algorithm. The efficacy of the algorithm is determined by how close to the results of the final test set the model can classify the layers. The results of this analysis can not only be used to classify stratigraphy for new wellbores with data, but also identify anomalies and errors in classification in the database. In addition, the algorithm can show which sensor data correlate and contribute to the classification of sedimentary layers.
Davison, J. M. (Shell Global Solutions International B.V.) | Salehabadi, M. (Shell UK Exploration & Production) | De Gennaro, S. (Shell UK Exploration & Production) | Wilkinson, D. (Shell UK Exploration & Production) | Hogg, H. (Shell UK Exploration & Production) | Hunter, C. (Shell UK Exploration & Production) | Schutjens, P. (Shell Global Solutions International B.V.)
ABSTRACT: At the end of field life, wells require permanent plugging and abandonment (P&A) as part of decommissioning activities. Some UK fields developed in the 1970’s are reaching their end of field life, with UK industry estimates predicting well P&A costs over the next 30-40 years of 24 billion dollars. As well as the high financial cost, there is a significant HSSE exposure to ensure safe and reliable P&A such that no escape of hydrocarbons is possible to the near surface environment.
This paper discusses the role Geomechanics has to play in potentially reducing well P&A costs, but also ensuring integrity of the wells and formations over long time scales. Recent experience in the UK North Sea has highlighted the requirement for detailed geomechanical knowledge of the field. We will focus on three key areas for geomechanical analysis. Firstly, we discuss reservoir pressure re-charge and in-situ stress response, from simple pressure-depth plots to more complex 3-D numerical modelling of the stress changes in reservoirs and surrounding formations. An added level of complexity compared to ‘conventional’ geomechanical modelling is the ability to forward predict the reservoir pressure recharge over hundreds of years and the commensurate response of the in-situ stresses. Secondly, as well as the modelling of stress changes over time, Geomechanics has a key role to play in determining the opportunity of using shale creep deformation to create annular barriers in the place of cement. Lastly, in some cases the preferred P&A design for a well is not possible due to well access issues which then requires cross-flow analysis linked with the geomechanical response of permeable formations. This approach is required for containment risk assessment and application of ‘as low as reasonably practicable’ (ALARP) assessments for well and formation integrity. Each of these subjects will be covered with field examples from the UK North Sea which demonstrate the Geomechanical workflows employed and the impact these have had on the business.
The objective of this paper is to share the results obtained from in-depth analysis using a down hole mechanics and dynamics monitoring sub, which lead to the first successful Gullfaks Satellite 14 ¾ x 17 ½ -in Rathole elimination operation through challenging lithology.
Shallow gas is encountered in the Gullfaks South area at a true vertical depth of between 335-339m (from MSL), and a casing design incorporating a 16-in liner is utilized to isolate this interval. A 14 ¾ x 17 ½ -in section is then drilled to isolate weak and unstable formations, and in all previous wells this section was drilled with a two run strategy. The first run to drill to section target depth (TD) while hole opening, followed by a dedicated second run to open the rathole. An opportunity was identified to improve well construction performance by eliminating the dedicated run to open the rat-hole, and tailoring the bit design to overcome the challenging lithology and high levels of shock and vibration seen on offset wells.
Detailed pre-job planning and BHA design analysis was combined with new downhole technologies to overcome these challenges. Dual reamers were used within a Rotary Steerable System (RSS) BHA to drill the 14 ¾ x 17 ½ -in section and eliminate the rat-hole in one run. This innovative approach involved drilling to section target depth (TD) using an upper ball drop reamer, tool positioned 45 meters behind the bit for hole enlargement while drilling, and then pulling back to position the bit at rat-hole shoulder. At this point the upper reamer was de-activated and a lower on demand hydraulically activated reamer, mounted directly above the RSS was opened to eliminate the rat-hole. Due to excessive shocks & vibrations experienced on offset wells, a down hole drilling mechanics & dynamics sub was utilized to provide real-time information about downhole forces and BHA motions, combined with a tailored bit design to control depth of cut in sandy intervals. This unprecedented approach resulted in 2.5 days saving.
Ahlberg, Jill (Baker Hughes) | Fang, Lei (Baker Hughes) | Hoff, Kjell Rune (Baker Hughes) | Manseth, Arvid (Baker Hughes) | Schwartze, Sascha (Baker Hughes) | Larsen, Johan Fredrik (Statoil) | Borlaug, Kjetil (Statoil) | Longvastøl, Karl Gerhard (Statoil)
This paper presents technical features and associated benefits of a recently developed under reamer technology and its applications in the offshore Norway Oseberg South field to drill 12 ¼? × 13 ½? and 8 ½? × 9 ½? sections. It discusses the results of the operations and demonstrates how the operations benefited from the new technology.
In today's drilling operations, expandable reamers are broadly used to support optimized casing and completion programs and to reduce operational risks such as high Equivalent Circulating Density (ECD), drilling troublesome formations and reaming well path conformities. The currently available hole enlargement technologies, such as ball drop and hydraulically activated reamers, carry intrinsic risks and limitations.
To address the challenges associated with currently available under reamer technologies, expandable reamer technology was recently developed jointly by a service company and a major operator, and was field tested offshore Norway. The under reamer, which is fully integrated with the company's existing Rotary Steerable System (RSS) Bottom Hole Assembly (BHA), provides unlimited, on-command activation cycles, optimal placement within the BHA in multiple configurations and real-time feedback via mud-pulse telemetry. The feedback from the reamer includes confirmation of blade activation status, health of the tool, and vibration and stick-slip measurements. Because of the flexibility of its placement in the BHA, the reamer can reduce the length of the rat hole to a minimum of 4 m compared to the standard 30 to 70 m in the same drilling run, eliminating the need for a dedicated clean-out run. The reamer also enables reliable and unlimited activation / deactivation cycles with each cycle taking less than 5 minutes, saving operational costs for the operators.
The under reamer was successfully deployed to drill challenging 12 ¼? × 13 ½? and 8 ½? × 9 ½? sections in the offshore Norway Oseberg South field. The 2497 m long 12 ¼? × 13 ½? section and 900 m long 8 ½? × 9 ½? section were both drilled to Total Depth (TD) in one run, with all requirements on directional control and Measurement While Drilling (MWD) / Logging While Drilling (LWD) met. The technology was proven to be a reliable and flexible hole enlargement while drilling solution that elevates drilling performance, reduces operational risks and lowers operational costs.