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Calcium carbonate (CaCO3) scale formation in production wells and process systems is a well-known challenge in the oil and gas industry. Various strategies are selected to prevent scale formation (proactive, e.g. by scale inhibitors) or to remove scale when it has formed (reactive, e.g. by acid treatment), depending on the severity of the problem and the complexity of the production system. Lack of access for remedial actions may be a limiting factor in subsea and unmanned installations and scaling may represent a larger risk of production losses or system failures.
The scale management strategy and design of new wells during field development are based on thermodynamic calculations, kinetic studies and field observations. Experience has shown that wells with high temperature and high pressure drops are more prone to downhole calcium carbonate scaling.
Field experience has been collected and systemized based on operations of oil and gas-condensate fields in the North Sea and Norwegian Sea. The observations have been compared to thermodynamic calculations and aligned to kinetic modelling, defining the critical saturation ratio (
The Oseberg field in the North Sea is producing from oil and gas-condensate wells at various reservoir temperatures (98-128°C). The field comprises platform and subsea production systems and one unmanned wellhead platform. Seawater has been injected for pressure support in some areas, while gas injection or depletion are the driving forces in other segments. The CaCO3 scale potential and management strategy have been evaluated for new wells in a field life perspective. Risk of production losses and maximizing cost benefit are key selection criteria, and the variety of wells requires individual solutions. The paper discusses the need for downhole continuous injection of scale inhibitor, compared to batch scale inhibitor squeeze treatments and/or acid treatments. Guidelines for optimum operation of these wells to avoid scaling are presented.
The Operator and the license partnership have set an extremely high ambition for recovery from the Johan Sverdrup field, even before a barrel of oil has been produced. How is this possible? This paper describes the characteristics of the reservoir, as well as early assessments and investments for improved oil recovery (IOR) to ensure flexibility. In addition, data acquisition, reservoir monitoring, new technologies and digitalisation, as well as new ways of working are addressed. This will be the key enablers for a recovery of more than 70% of the field’s oil resources.
Johan Sverdrup is the third largest oil field on the Norwegian Continental Shelf (NCS) with a recoverable volume range of 2,2 to 3,2 billion b.o.e. The reservoir is characterized by excellent reservoir properties with a strongly undersaturated oil. The primary drainage strategy is water flooding, including re-injection of all produced water, supplemented by water-alternating-gas (WAG) injection at the end of the oil production plateau. The field came on stream in October 2019.
Going back to the early stages of the Johan Sverdrup field development, it was obvious from the start that this would be an independent development solution with a long lifetime. Given the excellent reservoir, this was considered as a unique opportunity to plan for a high resource exploitation, and make sure that future business opportunities in this context could be utilized in a technical and economically attractive way.
A very early screening was conducted to investigate which IOR measures should be further matured. With subsurface evaluations as the base, this maturation also included assessments on technical feasibility and potential implications for development solutions. The objective was to ensure sufficient flexibility in early field design. It also implied that the Johan Sverdrup license had to consider pre-investments prior to any implementation decision.
Data acquisition and reservoir monitoring strategies were also started early on, which e.g. led to a full field Permanent Reservoir Monitoring (PRM) decision, with installation starting summer 2019. This gives a baseline for parts of the field before production start, and when completed in 2020 it will be the world’s largest fiber based PRM system. Fiber optics are also installed in the wells. In addition, a dedicated observation well is part of the development plan. The idea is that PRM and fiber data results, in addition to repeated logging in the observation well, will be key information to evaluate business cases for future IOR or new technology measures.
Digitalisation has also been a key aspect of this, and several subsurface-focused digitalisation initiatives have been implemented during the field development, giving the operator the opportunity to implement new ways of working and enabling new ways of cooperation in the partnership as data and applications are shared within the owner group in a digital setting. The overall objective of digitalisation in this context is to further optimize the analysis and management of the Johan Sverdrup reservoir – and hence value of the Johan Sverdrup field – for the license owners.
Serious stability problems in boreholes drilled in transversely isotropic rocks have led to several studies related to the combined effect of wellbore trajectory and weakness plane inclination. The stability analyses of wellbores drilled in fields that were affected by slip along the weakness planes were carried out with software based on the weakness plane model. However, this model is discontinuous and cannot capture features of some transversely isotropic rocks. The Hoek & Brown criterion, adapted to anisotropic rocks, is a continuous criterion that can predict mud pressures in a complete range of inclination of the weakness planes. However, this criterion requires a consistent number of triaxial tests, for the determination of the controlling parameters at various inclinations of the weakness planes. Here we propose a novel procedure for the prediction of wellbore pressures in transversely isotropic rocks (typically shales) with the Hoek & Brown criterion coupled with the weakness plane model. The procedure requires a set of uniaxial compression tests performed on rock specimens at different inclinations of the weakness planes and one triaxial test carried out at an inclination of the weakness planes in the range 50 -60 . For our purposes we used the results of lab tests carried out on Opalinus clay.
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.
With an increasing focus on identifying cost-effective solutions to well design with a minimal impact on productivity, this paper will focus on an alternative to cesium (Cs) formate as the perforation fluid in the high-pressure/high-temperature (HP/HT) Gudrun Field operated by Equinor. Cs formate has been used with success for drilling and perforating many HP/HT wells. However, because of the significant cost of this fluid coupled with low oil prices, Equinor wanted to perform testing to assess the performance of an alternative oil-based mud (OBM) as a perforation fluid. In this paper we describe the extensive qualification testing that we have conducted, which includes coreflooding using representative plugs from Gudrun Field under downhole temperature and pressure conditions. In addition, eight API RP19B (2014) Section IV perforation tests have been conducted to compare the performance of the Cs formate with the OBM. These tests were undertaken using gas- and oil-saturated cores to reflect different production scenarios. The main aspects of the perforation operation that were reflected in the test design were as follows:
On the basis of the results of the coreflooding combined with the API RP19B (2014) Section IV testing, the OBM was selected as the perforating fluid for use on Gudrun Field. The perceived benefits of using the OBM were as follows:
Perforation modeling is described, and a comparison is made between this and the API RP19B (2014) Section IV tests. Finally, the well-startup experiences and the production data are presented, demonstrating the effectiveness of the OBM as a perforation fluid.
Almost simultaneously, advances were made in understanding both the processes within the source rock organic matter that accompany the generation and expulsion of hydrocarbons and in the acquisition, processing, and quantitative interpretation of 3D seismic data. In particular, as organic matter in shales in unconventional plays generates and expels hydrocarbons, porosity is formed in the organic matter and the organic matter becomes more dense and more brittle. As these changes are occurring at a micro-scale, extraction of hundreds of different attributes from a well-imaged 3D seismic volume has made it possible to observe changes at a macro-scale in seismic lines and horizons within that volume. Seismic attributes derived from pre-stack inversions yielding rock mechanical properties from shear (Vs) and compressional (Vp) velocities and density, when calibrated with well log and/or core measurements, can be combined to calculate TOC, pore pressure, rigidity, and compressibility because these properties cause fundamental changes in how seismic waves travel through the rock.
Equally important, the escalation in computing power via methods such as machine learning, neural networks, and multivariate statistics has made it possible to interpret large amounts of data. All of these innovations have contributed to better identification of sweet spots within unconventional plays. Such sweet spots include areas with elevated TOC values, enhanced porosity, and zones that can be targeted for fracking.
One of the primary advantages of seismic data is that it provides information in those areas in between control points/wells. This information in turn helps operators to better select targets for wells and for landing zones. Carefully tied 3D seismic inversion and integration with petrophysical and rock data further allow for detailed characterization of unconventional reservoirs. The enhanced ability to identify the best potential drilling targets has significant economic implications in terms of risk reduction and improved chances to find economic prospects.
While 3D seismic data is being used routinely by numerous companies to predict the mechanical properties, density, and associated TOC of many formations, there is yet to be a direct link made between TOC loss, kerogen conversion, and the associated changes in rock properties. This work documents the importance of TOC loss during maturation and its effects on rock properties like porosity, density, brittleness, and how those advances coupled with the advances in quantitative interpretation of 3D seismic data are enabling the unconventional operators to predict location, thickness, landing zone, and sweet spots with appropriately acquired, processed, and interpreted 3D seismic. Meticulously calibrated 3D seismic inversion and integration with petrophysical and rock data permit detailed reservoir characterization of unconventional reservoirs.
Updated methods for the back calculation of original TOC have been developed using well logs, rock measurements, and 3D basin modeling to assist in locating and developing unconventional reservoirs. In addition, petrophysical measurements that reflect TOC and porosity and are related to fundamental properties controlling the seismic response can be extracted from the seismic reflection data. In turn, seismic attributes derived from pre-stack inversions yielding rock mechanical properties from shear (Vs) and compressional (Vp) velocities and density, when calibrated with well log and/or core measurements, can be combined to estimate TOC, pore pressure, rigidity, and compressibility because these properties cause basic modifications in how seismic waves travel through the rock.
This study shows advancements in studies of: 1) TOC loss with increased thermal maturation, 2) how this loss affects the development of organic porosity, 3) how kerogen becomes denser, harder, and more brittle with increasing maturity, and 4) how recent developments in quantitative interpretation workflows for 3D seismic data facilitate estimation of TOC and determination of rock mechanical properties from shear (Vs) and compressional (Vp) velocities and density. Further integration of geochemical, geomechanical, and geophysical technologies and measurements will provide improved estimates of present-day TOC that can in turn be extended to relative maturity and percent conversion.
Examples provided in this work illustrate prediction of present-day TOC, porosity, density, and mechanical properties extracted from high fidelity pre-stack inversion. Pre-stack inversion along with machine learning can be used to predict rock properties such as porosity, TOC, organic matter quality, rigidity, and pressure and to correlate those properties back to well productivity for improved execution. Relating present TOC estimated from seismic to TOC loss and kerogen property changes with increasing maturity is possible by combining the results of these technologies.
Though analysis and inversion of painstakingly acquired modern 3D seismic data is capable of estimating porosity, TOC, matrix strength, and pore pressure, the latest work on rock property changes as hydrocarbons mature and are expelled isn't typically addressed in most studies. Increasing communication between disciplines might improve estimation of these properties and extend the capability to assess the extent of TOC loss during maturation and the porosity increases that accompany it. This ability is especially important in the intra-well regions where the potential of 3D seismic to extend data between control points enables better reserve estimates and high grading of acreage. After carefully calibrating a quantitative 3D seismic interpretation with a 3D basin modeling analysis of the source rock potential and maturity, an operator is better prepared to high grade acreage and attain the most economic development of unconventional resources.
The escalation in computing power means there are hundreds of different attributes that can be extracted or calculated from a well-imaged 3D seismic volume. Using quantitative calibration of fundamental geochemical measurements such as TOC, pyrolysis, and petrographic measurements of vitrinite reflectance that yield the quantity, quality, and maturity of organic matter in combination with well log and seismic data creates a model for identifying sweet spots and the areas in the target formation that exhibit high TOC, high porosity, and elevated brittleness. Further integration and calibration of changes occurring at the micro-level in organic matter in unconventional plays with their impact on the signatures of data at the macro-level can provide information on the types of hydrocarbons most likely to be found in these sweet spots as well as identifying which zone(s) in the target formation are most likely to be amenable to fracking. Used together, the advances outlined here result in a technological evolution that could have a substantial impact on: 1) the approach to and 2) the economics of the exploration and production of unconventional plays.
ABSTRACT: CCS is a well-studied technology to efficiently reduce anthropogenic CO2 from the atmosphere, which is believed to be one of the main factors contributing to global warming. In this paper, we investigate possible changes in the mechanical properties of a shale caprock, when in contact with injected CO2. Through diffusion, and concentration gradient, the injected CO2 mixes with the caprock pore fluid, modifying its pH from basic to acid. Different experiments are performed to demonstrate the effect of CO2 on mechanical properties of the North Sea Draupne shale caprock. The sample was exposed to CO2-sat brine for about 20 days under a confining pressure of 20 MPa and a pore pressure of 10 MPa. The poroelastic properties such as Young's modulus, Poisson's ratio, bulk modulus as well as the strength were then measured. Even if a slight increase is observed on the strength, this early-age effect of CO2 on Draupne shale seems very little and is within the experimental error. The results of P-wave velocity measurements reveal a possibility that CO2 may be coming out of solution during the test. In order to address this possibility, the experimental conditions are being reviewed and continuous measurements (every minute) of Young's modulus and Poisson's ratio are performed on the sample from consolidation to failure, through the flowing of CO2-undersaturated brine.
CO2 capture, transport and geological storage (CCS) is a well-studied technology to efficiently reduce anthropogenic CO2 from the atmosphere, which is believed to be one of the main factors contributing to global warming (Gislason et al., 2010; Lu et al., 2012; Torp and Gale, 2004). The studied storage sites include saline aquifer, unminable coal seams and depleted oil/gas reservoirs. The reservoirs are usually sealed by a shale caprock of around a hundred meters of thickness, which has low permeability and low porosity. One of the major challenges in geological sequestration is to demonstrate that the CO2 is stored safely in the reservoir (Xue and Ohsumi, 2004). When injected into reservoirs in which pressure and temperature are higher than 7.2 MPa and 31°C, respectively, the CO2 is at supercritical state (scCO2). Buoyancy forces (due to the difference in the density of CO2 and that of the in-situ pore fluid) potentially results in the rising up of CO2 molecules from the reservoir to form a plume at the reservoir–caprock interface. Identified risks include CO2 leakage through poorly sealed, failed injection wells or improperly abandoned wellbores. It can also leak through connected faults or fractures in the caprock (Harvey et al., 2012; IPCC, 2005; Lu et al., 2010; Nelson et al., 2005). The concentration gradient of CO2 between the plume at the interface and the pore fluid of the caprock leads to the diffusion of CO2 into the caprock. This may change the pH of the pore fluid from basic to acid, which may affect the mechanical properties in terms of strength and stiffness and therefore impair the mechanical integrity of the caprock formation. Most investigations on CO2 storage have been focused on geochemical effects of CO2 on reservoir or caprock. Experimental studies include chemical exposure and mineral analysis (Balashov et al., 2015; Huang et al., 2013; Jun et al., 2013a; Jun et al., 2013b; Olabode and Radonjic, 2017; Pan et al., 2018; Wollenweber et al., 2010). Bush et al. (Busch et al., 2016) presented an extensive review on the sorption and swelling of CO2 in clay minerals. Studies focusing on mechanical changes due to CO2 exposure of shales are still not numerous (Cerasi et al., 2017; Lyu et al., 2016; Ojala, 2011; Skurtveit et al., 2012). This paper presents a further investigation of the effect of CO2 on the poroelastic properties of a shale. To this end, a Draupne shale is tested in various compression experiments including CIU (consolidated isotropic undrained test) and UCS (unconfined compressive strength).
Park, Joonsang (NGI) | Blomberg, Ann (NGI) | Waarum, Ivar-Kristian (NGI) | Totland, Christian (NGI) | Yakushev, Evgeniy (NIVA) | Pedersen, Geir (NORCE) | Sauvin, Guillaume (NGI) | Griffiths, Luke (NGI) | Eek, Espen (NGI) | Grande, Lars (NGI) | Walta, Axel (NGI) | Bohloli, Bahman (NGI) | Soldal, Magnus (NGI)
Measurement, monitoring and verification (MMV) are vital to ensure the conformance and containment of geological carbon storage (GCS). This requires cost-efficient and multidisciplinary approaches. To investigate this challenge in an offshore environment, we have studied and tested different monitoring approaches, covering seismic, electromagnetic, micro-seismic, active and passive sonar, and chemical sensing methods. The studies in the manuscript are based on laboratory- and field-scale tests. The data of our current interest are various as mentioned above, and for both deep- and shallow-focused monitoring. We measured laboratory geophysical data in the scenario of CO2 flowing through a fracture in a sandstone core sample (De Geerdalen Formation, Svalbard, Norway) to see the possibility of detecting leakage. The field-scale feasibility was also demonstrated through a synthetic modeling study. Laboratory acoustic emission tests were performed with North-Sea relevant rock samples to evaluate the micro-seismic applicability to offshore GCS monitoring. Acoustic and chemical sensor technologies are considered essential for marine monitoring of the seabed and water column, but knowledge and documentation on how to optimally use and combine these technologies is scarce. During a recent controlled CO2 release experiment, we have investigated the performance of different acoustic and chemical technologies for application to GCS monitoring. By quantifying the capabilities and limitations of different acoustic and chemical technologies, we aim to provide operators with the knowledge needed to maximize monitoring performance while minimizing the number of sensors and costly operations.
First, it was learned through a laboratory rock physical test that electromagnetic signal is relatively sensitive to CO2 flow through fracture (and potentially faults as well) compared to seismic. The acoustic emission tests showed that reservoir sandstone core samples are subjected to induced seismicity, whereas the cap-rock or shale are rather quiet during these tests. To be conclusive, more tests and data analysis are required. Nevertheless, the up to date result indicates that detection of leakage in shale only via micro-seismic might be challenging. Initial results from the cotrolled experiments releasing CO2 to the water column indicate that a small amount of CO2 in gas phase may be detected from a large distance (100s of meters) using a broadband echo sounder. Passive acoustic detection of a small leak (1.15 l/min) was feasible from a distance of 10m. A plume of dissolved CO2 was detectable using chemical CO2 and pH sensors placed 4-10 m from the origin of the leak, when releasing CO2 at a rate of 5-6 l/min. Finally, we have investigated how to integrate the deep-focused geophysical and shallow-focused seafloor monitoring techniques. In our study, we have used a set of leakage scenarios (leakage path, rate, etc.) available in the literature. In addition, we have included into our discussion additional datasets e.g. surface/seafloor heaving and gravity not directly acquired in the current study but available through literature. We conclude that integrating different datasets and different disciplines are necessary to maximize the extracted information and eventually to save cost as well. In addition, relevant future R&D task candidates have been identified.
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.
The objective of this paper is to demonstrate how advancedrealtime monitoring (ARM) utilizing advanced hydraulic and mechanical modelling of the drilling process provided early detection of anomalies by giving diagnostic messages during drilling operations. These achievements can minimize non-productive time and invisible lost time and maximize the benefits and value of operations; if they are utilized to its full potential by operations. Some well cases are used to illustrate the methodology and its results. Among problems diagnosed are losses, stuck pipe during drilling and casing running, downhole equipment leakage and improper hole cleaning. In some cases, action was taken based on the diagnostics; and the operational conditions were modified to mitigate the situation. In other cases, the warnings were not taken seriously, the situation worsened until the problem was irreversible and a stuck situation occurred. In one well presented in the current study a stuck pipe situation happened during drilling 8½" section which led to a downtime of more than 20 days. By utilizing the ARM, it couldhave been possible to detect some early signs of the stuck conditions in the wellbore and avoid it. Another stuck situation in awell during 14-inch Casing running, led to downtime of more than 10 days which involved breaking out the casing above the stuck point and performing P&A. The ARM provided early signs of stuck casing that was about to occur, and these signs first started appearing about 15 hours before the pipe got completely stuck. This paper will present the Advanced realtime Monitoring ARM System and the modelling behind this. Also, the plans for further implementation and integration of this in the work processes will be discussed, before results from the first year of utilization will be presented with examples.