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Ahmed, Ary N. (Wintershall Dea Norge AS) | Grunhagen, Henrike (Moreld Ross Offshore) | Moyano, Bernardo (Wintershall Dea Norge AS) | Andersen, Charlotte Faust (Moreld Ross Offshore) | Bøyum, Eivind (Schlumberger) | Mohamad, Radzieman (Schlumberger) | Bolandtaba, Saeed Fallah (Wintershall Dea Norge AS) | Ben Mansour, Wesam (Wintershall Dea) | Ajala, Olawale Ibrahim (Wintershall Dea) | Sadigov, Subhi (ResOptima AS)
Abstract The Brage field was discovered in 1980 and started production from its Fensfjord reservoir in 1993. The Fensfjord Fm. is a highly heterogeneous reservoir with low STOIIP density. Lack of zonal control and several drainage strategies throughout the years make production allocation and drainage history very complex. Thus, achieving a full field history match in the Fensfjord reservoir through deterministic modeling has always been a challenge. Current STOIIP estimates indicate that there is room for several more producers. However, identification of target areas for future wells are associated with high uncertainties. Using advanced stochastic modeling and ensemble-based methods has reduced the uncertainties and thereby improved the history match quality and understanding of the reservoir. Bayesian statistical methods have been applied to combine the structural and well path TVD uncertainties, and generate multiple realizations of the top reservoir surface, isochores and well trajectories, serving as additional history matching parameters. Based on this input, an ensemble of static models was iteratively conditioned to the dynamic data resulting in a significant improvement of the history match quality. Sensitivity analysis have been performed to identify and breakdown the impact of the uncertain parameters on the in-place volumes. This paper shows how the new integrated approach has increased the predictive power of the model, resulting in identification of several infill targets for future drilling campaigns.
The last year has seen people in many sectors unexpectedly confronting a new challenge—working remotely. Even before this, our industry has been trying to operate fields remotely (either partially or fully) and make operations smarter and more automated. Key drivers are to improve safety in operations, maximize production, and make operations more efficient. These efforts have been enabled by the rapidly changing technology landscape—in sophisticated acquisition and analysis of data and increased connectivity (from both fiber-optic and cellular networks). It also has been accelerated by the push across the industry to digitalize. We now acquire, process, and analyze much more detailed operations data and use the analysis to actively control wells and operations. This feature highlights recently presented papers that cover the following topics. How Digital Transformation Has Progressed. Paper OTC 30794 discusses similar efforts in other sectors, including marine/ship building and auto manufacturing. Paper SPE 200728 discusses use of a digital twin to improve operational efficiency in a mature brownfield setting (Brage Field in the Norwegian North Sea). Paper OTC 30488 describes extensible and scalable remote monitoring and control using a digital decision assistant. How Technology Has Enabled Data Acquisition and Analysis From Relatively New Sources [e.g., Distributed Temperature Sensing (DTS) or Distributed Acoustic Sensing]. Paper SPE 200826 describes seven DTS applications from around the world that monitor well integrity, stimulation, and injection profiles and identify gas, water, or sand production. Paper OTC 30442 and other papers from the Bokor field in Malaysia describe DTS data from fiber-optic cable behind casing in wells with smart completions. Papers IPTC 19574 and SPE 202349 show how pressure telemetry can enable wireless control of completions. The Path to Fully Remotely Operated Fields. Paper SPE 203461 discusses the design and execution of digitalization and remote operations in a new development area with high hydrogen sulfide (the Mender satellite field in the UAE). Paper SPE 202667 describes the applications for multiple autonomous robots controlled remotely. Digital transformation of work flows and operations clearly is happening across the industry and adding significant value. The next frontier on the digital transformation and Industry 4.0 journey might be to achieve step-change increases in oil and gas recovery factors. Recommended additional reading at OnePetro: www.onepetro.org. SPE 200728 - The Digitalization Journey of the Brage Digital Twin by Peter Kronberger, Wintershall, et al. OTC 30442 - Innovative Solution for IWAG Injection Monitoring Using Fiber-Optic Cable Cemented Behind Casing in an Intelligent Well: A First in Malaysia by Nur Faizah P. Mosar, Schlumberger, et al. SPE 202667 - Operations Room: A Key Component for Upscaling Robotic Solutions on Site by Jean-Michel Munoz, Total, et al. OTC 30488 - Machine-Learning-Enabled Digital Decision Assistant for Remote Operations by Vitor Alves da Cruz Mazzi, Intelie, et al. IPTC 19574 - Research and Application of Downhole Remote Wireless Control Technology Based on Gas Pressure Wave in Tubing by Mingge He, China National Petroleum Corporation, et al. SPE 202349 - Pressure Wave Downhole Communication Technique for Smart Zonal Water Injection by Quanbin Wang, China National Petroleum Corporation, et al.
Hussain, Sajjad (Schlumberger) | Dahroug, Mohamed Saher (Schlumberger) | Mikalsen, Belinda (Schlumberger) | Christensen, Karianne Holen (Schlumberger) | Nketah, Daniel Ndubuisi (Schlumberger) | Monterrosa, Leida (K&M Technology Group) | Van Aerssen, Mark (Wintershall Dea) | Angell-Olsen, Frode (Wintershall Dea) | Midttun, Mons (Wintershall Dea) | Rouxinol, Ricardo (Wintershall Dea) | Henriksen, Norolf (Wintershall Dea) | Fjeldsbø, David (Odfjell Drilling) | Ritchie, Graham Martin
Abstract Drilling a nine km (Kilometers) extreme ERD (Extended Reach Drilling) well by a rig which was initially designed for six km and on a platform that did not provide any empty well slot posed a challenge to the Brage asset team. The well (A-36 A/B) was planned with an ambitious slot recovery operation removing all casing strings to surface to allow for a 24-inch sidetrack. Due to unexpected challenges during the slot recovery only a 19-m window between the 28-in conductor shoe (at 315-m MD) and the old 13 3/8-in casing stump was available. A very successful kick-off using a mud motor and Gyro-While-Drilling bottomhole assembly (BHA) was performed. An RSS (Rotary Steerable System) BHA was used to drill the rest of the section Both "push the bit" and "point the bit" RSS technologies were the key enablers in drilling long sections and helping to deploy casing strings. The well was successfully geosteered through two reservoirs, including a new reservoir landing strategy, adding valuable extra reservoir meters. The reservoir Mapping-While-Drilling and Magnetic Resonance-While-Drilling service helped to navigate in challenging reservoirs maximizing reservoir exposure. Advanced polyglycol Water-Based Mud system was utilized in 24-in section followed by advanced Oil-Based Mud (OBM), and Low Solids OBM systems enabled drilling this extreme ERD well. An upgraded Cuttings collection and transportation system meeting ERD requirements and offshore slop water treatment system also played key role in drilling optimization. Real-time monitoring of critical well construction operations was performed using specialized technologies. Optimized Viscous Reactive Pill (VRP) was successfully used for the first time in North Sea to provide cement plug base at deeper depths (7200-m MD) resulting in a successful kick-off using "point the bit" RSS systems. An ERD specialist subsidiary of the service company was involved in ERD design verification and training of offshore personnel. Outstanding equipment reliability of surface equipment and downhole tools enabled shoe-to shoe drilling of these sections. The OneTeam culture combined with the main service provider integrated solutions, and an open-minded and brave approach led to drilling longest well in this brownfield ever. It was completed 32-days ahead of plan with all objectives met. The deep lower screen completion was successfully deployed, and the well is producing as expected. This 9,023-m MD well is the longest Offshore well drilled by the Operator and 2nd longest drilled by the Operator ever.
This document is an expanded abstract. Summary Uncertainty quantification has become an increasingly important request in the decision-making process for targeting infill drilling. Serious weaknesses in current reservoir models can be directly attributed to the lack of proper uncertainty handling. In a mature field as the Brage oil field in the northern part of the North Sea, east of the Oseberg field, where there are many long horizontal wells, uncertainty in well markers and well paths have a tremendous impact on the structural uncertainty (+/-10m). These variations on their own can either create or kill infill drilling targets. A stochastic workflow for dealing with uncertainty on horizontal well trajectories has been derived for a consistent updating of velocity and depth models. Such an automated stochastic workflow is an example of a Digital oilfield operation system (DOOS). Introduction The coming age of Digital Oil Field operations in oil companies implies the conversion of today knowledge-based data processing and modelling workflows into automated intelligent ones, representing digital operating systems or DOOS. DOOS are designed for optimizing performance and turnaround time of geophysical processing and modelling workflows, thus enabling real time and safer E&P decision making. They make use of machine learning algorithms specific to Earth Data, that are regionalized (they have coordinates) and uncertain. As statistics are key to Artificial Intelligence of Big Data, geo statistics (and more precisely probability models) are the corner stone of machine learning algorithms for processing Big Geo Data. Method Geostatistics for optimizing reservoir operations The main characteristic of an oil reservoir is that it has not been manufactured and is an a priori unknown environment to human activity, generating natural uncertainty and risk when operating it. Oil reservoir is a natural resource that is out of direct reach and there is no such thing as an exact representation of the subsurface that would allow for making 100% confidence or 0 risk operational decisions. Handling this natural “uncertainty” and making best possible operation decisions have been the driver of the research and developments of Geostatistics as described by Georges Matheron in the “Theory of Regionalized Variables” (1), and “Estimating and choosing” (2).
Serajian, V.. (GeoMechanics Technologies) | Diessl, J.. (GeoMechanics Technologies) | Bruno, M. S. (GeoMechanics Technologies) | Hermansson, L. C. (Ridge) | Hatland, J.. (Ridge) | Risanger, M.. (Ridge) | Torsvik, M.. (Wintershall Norge A/S)
Abstract The objective is to investigate potential fault reactivation caused by high-volume injection into a North Sea well to assess the risks associated with converting a production well into a water injection well. The well is located within the Brage Field less than 100 meters from a major fault and there is concern for fault reactivation due to high volume water injection near this fault. An integrated 3D geologic, fluid flow and geomechanical model was developed for the area of interest to evaluate fault reactivation risks. The 3D integrated models were constructed based on seismic horizon data and well logs. The 3D fluid flow model was calibrated and history matched using the pressure and temperature data from the current well and other adjacent wells. The developed 3D fluid and heat flow model was used to estimate pressure and temperature distributions adjacent to the fault after water injection in the target well. The results of the 3D fluid flow model were then imported into the 3D geomechanical model to predict the induced stresses and displacements near the injection zone and on the face of the fault. The results of the integrated geologic, fluid flow and geomechanical models indicate that the poro-elastic stresses induced by high volume injection into the proposed well are not sufficient to induce major slip on the nearby main fault, considering a wide range of reasonable physical and material property assumptions for the fault. The results of this study are used in specifying the maximum daily water injection rates in the proposed well without the fault reactivation concerns. With the proposed water injection rate, the sealing capacity of the major fault will be guaranteed and the injected water will be directed into the reservoir for pressurization and water flooding purposes.
Abstract This paper presents the technical features and the associated benefits of a new integrated expandable under reamer technology, and showcases the field testing of the technology in the Brage field at offshore Norway and the achieved results. Historically, the overburden stratigraphy at Brage field has been challenging for drilling. The unstable green clay and Draupne shale formation, the casing and completion programs and Equivalent Circulation Density concerns associated with drilling extended reach wells necessitate hole enlargement while drilling. In particular, the 12 ¼″ section has a planned Total Depth (TD) right below the Draupne shale, inside which the calcite stringers also present, and a near bit reamer significantly increases the likelihood of getting down the 10 ¾" casing. A new integrated under reamer technology was utilized to address the challenges in drilling five sections of a well in Brage: 14 ¾ ″ × 17 ½″, two 12 ¼″ × 13 ½″ sections and two 8 ½″ × 9″ sections. The new under reamer is fully integrated with the company's rotary steerable system, which enables unlimited on-demand activation and deactivation cycles through downlinking with each cycle taking less than 5 minutes, flexible and optimal placement of the reamer in the bottom hole assembly (BHA), and real time feedback from downhole. The flexibility of the placement in BHA allows the under reamer to be used as a near bit reamer, a main reamer, or both. When used as a near bit reamer, the reamer can reduce the rat hole length to a minimum of 4 meters in the same drilling run, eliminating the need of a dedicated rat hole elimination run. The real time feedback includes confirmation of the blade activation status and a hole opening diameter log, reducing operational uncertainties for under reaming and saving rig time for a shoulder test that is otherwise required. The technology proved its effectiveness as a reliable main reamer as well as a near bit reamer for rat hole elimination while satisfying all requirements for directional drilling and enabling Measurement While Drilling (MWD) and Logging While Drilling (LWD) measurements. For the 12 ¼″ × 13 ½″ section, both main and near bit reamers were activated simultaneously while drilling the last 68 m to TD and a good drilling performance was observed from the run. The new technology provides unique features such as unlimited cycles of activation and deactivation through downlinking, flexible placement in the BHA and real time confirmation of blade activation status and hole opening diameter. The paper will describe these features in detail, and demonstrate how they can help the operators to reduce operational risks and save cost. It will also showcase a unique drilling application where three cutting / reaming elements in the BHA are actively present simultaneously and the associated drilling performance.
Abstract The ability of cement to achieve a pressure seal across the reservoir section for the life of a well becomes ever more difficult to achieve because of increasing depths and more complexity in well design and operations. Mature fields with depleted zones combined with the desire and ability for extended reach wells exacerbates the challenge of delivering a cement-only, fit-for-purpose liner. To address this challenge, an operator and service company have joined forces to design, develop, and qualify a hydraulically expandable metal well annular barrier (WAB) assembled on the outside diameter (OD) of a liner while maintaining full-bore inner diameter (ID). Intended initially for use in Norway's Valemon field, the operator is also exploring options for other applications in the Snorre and Brage fields, also offshore Norway. This paper discusses the design, development, and qualification of the metal WAB, including: review of the design, material selection to achieve the required expansion, the unique outer seal design to deliver the pressure differential requirements, and intended applications to date. The final qualification process exceeds the industry-established guidelines in ISO standard 14310 (which defines requirements for packers and bridge plugs for the oil and gas industry).
ABSTRACT: The North Sea Brage oil field has been in production for over 15 years. To further develop the field efficiently, the properties of the complex Fensfjord reservoir required thorough evaluation using loggingwhile-drilling (LWD) technology. In addition to the main objective of optimizing the well productivity of the known upper Fensfjord sandstone reservoir, good pay zones in the reservoir compartments are also required identification for zone completion. Formation pressure and mobility tests were performed to update the reservoir compartmentalization model and to examine the mobility of the in-situ hydrocarbons. The Brage field has numerous petrophysical evaluation challenges in the Fensfjord formation because it consists of fine-to-medium grained sandstones interbedded with calcite cemented sandstone bands that include bio clastic material. Conventional density and neutron porosity log interpretation is highly affected by the lithology and difficult to correct to the accuracy needed. Additional interpretation methods are required. In this paper we focus on nuclear magnetic resonance (NMR) applications in horizontal wells in the Brage field and how real-time T2 measurements bring value in understanding the reservoir, particularly when determining the properties of the different reservoir zones in the Fensfjord formation. Log examples and results gathered from the different methods are presented and evaluated in the paper. Prior to drilling, a synthetic permeability model was built for the Fensfjord formation to evaluate the relationship between saturation and permeability. To enhance the accuracy of the LWD magnetic resonance interpretation several iterations were carried out on the parameters used in the evaluation to determine the best Brage field-specific petrophysical parameters. The synthetic permeability model was used as a guide in determining the optimum magnetic resonance MR constants to be used. These investigations confirmed the reservoir evaluation and demonstrated that the NMR log interpretation enhanced the reservoir understanding.
Independent inversion of base and monitor seismic surveys can yield estimates of elastic properties that are inconsistent with expected production effects. We therefore propose a global time-lapse inversion scheme, involving joint inversion of base and monitor data. All vintages and input angle stacks are combined in a single objective function, which is optimized using simulated annealing to estimate the time-variant distribution of elastic attributes that best matches all available data. The multi-vintage nature of the optimization allows us to incorporate flexible, user-defined rock physics constraints on the evolution of
Abstract The rapid deployment of distributed temperature sensor (DTS) systems in the oil and gas E&P industry provided the engineers with large amount of real-time, downhole data. Although the basic principles for DTS operations are simple, the interpretation of the downhole data presents a challenge for the production engineer. Inflow profiling has been promoted as the prime reason for the installation of DTS systems, though DTS data are currently used in all aspects of production engineering. The differences between the thermal properties of oil, gas and water allow the detection of unwanted fluids using DTS. Monitoring of the produced fluid temperature allow the engineer to prevent the formation of wax and hydrates, ensuring effective flow assurance. This paper examines a novel DTS application by analyzing the effect of scale deposition on the temperature profile of a conventional producing well. The low thermal conductivity of scale deposits increases the temperature of the producing fluid in the scaled region. A sensitivity study has examined the expected range of temperature increase caused by scale deposition to determine the conditions under which the flowing fluid temperature increase is a maximum. Low to moderate production rate environments with low water production yield the greatest increase in flowing fluid temperature when scale is present. The thermal insulation provided by the scale causes a unique temperature profile. Quantitative analysis allows the scale thickness to be determined. Introduction Solid deposition in the production tubing presents a big challenge for the production engineer; it reduces the well production, leads to equipment failure (e.g. overheating of ESPs, blocking of downhole valves), increases project operating costs (OPEX) due to the need for scale dissolver treatments and, in certain situations, creates health and safety issues. Examples of production solid deposition problems are:Organic DepositsWax Deposition Hydrate Formation Inorganic Scale DepositsCarbonate Scales (e.g. Calcium Carbonate CaCO3): precipitated by decreasing pressure (e.g. Venturi flow meters) and increasing temperature (ESPs) Sulfate Scales (e.g. Barium Sulfate BaSO4) forms when two different brine streams mix. Downhole monitoring for scale deposition could provide a valuable tool for the engineers overseeing wells in environments where logging is not practical, such as subsea developments. In North Sea Visund field , which is a subsea development, the impracticality of caliper logging did not allow the correct determination of the depth where CaCO3 scaling deposition started. Scale deposition can extend a significant distances along the tubing e.g. in the Brage field in the North Sea, CaCO3 scaling extended for 400m (˜1300 ft) . One well in the Miller field in the North Sea represents an extreme scaling problem since scale treatments have to be carried out on weekly basis to avoid complete loss of the well . The objective of this paper is to investigate the temperature behavior in wells where scale deposition is occurring and to quantify the temperature changes that occur within the scaled region. Understanding this behavior can aid in determining the possibility of detecting scale deposits in the production tubing using Distributed Temperature Sensor (DTS) downhole temperature data. Although, scale detection is never, and never will be, a major application of DTS; such a secondary application can form an extra incentive to justify installation of a DTS system.