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Abstract In the 1990's many oil plays in the North Sea were originally deemed uneconomical due to the limited technology available to address the associated challenges. Horizontal and eventually multilateral applications were introduced to address this challenge. For over two decades multilateral technology has extended the production life of these fields by continuing to evolve to meet the demands of increasingly complex subsea applications. Over this history, multilateral applications have evolved from dual-laterals with standalone screens and commingled flow to tri-lateral and quad-lateral intelligent completions as common multilateral completion strategies in the North Sea. A significant number of wells originally completed as a dual-lateral have since been recompleted twice or even three times to produce reserves previously left behind. As investment and availability of new fields decline, operators face challenges to extend the production life of mature fields while also working to reduce overall development cost, cycle times, and carbon footprint. Further challenges include delivery of wells and facility systems using less in-field construction hours at a lower baseline cost. This paper will focus on the evolution of a mature well in a region that has been installing multilateral wells for over two decades. Originally drilled as the world's first tri-lateral well and several years later re- drilled again as a quad-lateral to add further reservoir contact. As production decline and strategic targets esteemed to be more profitable are within reach from the same template, further re-drills as a dual-lateral and then a further quad-lateral has been utilized to add significant reservoir contact for further economic production. It highlights the technology used to keep this well on production for over two decades and the benefits of expanding the use of this technology as fields become slot restricted. It also highlights the benefits this technology delivers in significantly increasing reservoir exposure and the time savings brought by drilling new lateral legs in existing subsea wells. The case study will include discussion of workover operations, completions, isolation methods, and lateral creation systems. Through four separate multilateral installations in one subsea slot, the production life has been extended beyond 20 years. The paper also provides insight as to methodology for continually improving reliability of multilateral installations to maximize efficiencies.
Abstract Formation compaction and subsidence forces due to reservoir drawdown have the potential to inhibit the function of sliding sleeves and similar completion systems. The sliding sleeves discussed have the ability to be opened and closed multiple times, allowing for flexible stimulation and production operations. Field data suggested a link between high sliding sleeve function forces and preceding zonal production. The objective was to minimize these effects to give the operator full functionality of the sliding sleeves over the life of the well. This paper will outline how this was achieved, and the results of comparative lab testing. The overall approach was to (1) understand the magnitude and effects of the formation forces, (2) implement product improvements, and (3) validate results through lab testing the proposed solutions. A case study was conducted for 4.5 in. 21.5 lb/ft & 5.5 in. 32.6-35.3 lb/ft casing and sliding sleeves installed in the Valhall field. Wells drilled in the Valhall field had previously suffered production casing collapse failures due to formation compaction and subsidence (Pattillo and Kristiansen 2002). Switching to the current heavy weight casing resolved the issue. The heavy weight casing collapse pressure ratings were used in the early analysis to determine maximum uniform collapse resistance and radial deformation of the sliding sleeve components. Thick-walled cylinder calculations were insufficient for predicting the effect of the non-uniform loading exhibited downhole, as well as predicting metal-to-metal contact within the sliding sleeves due to abrupt changes in geometry. FEA modelling was completed for predicting metal-to-metal contact due to a non-uniform load. Sleeves with improved mechanical collapse resistance were designed and built. Lab testing was conducted by applying a mechanical radial force simulating the formation load to (1) the original sleeves, (2) the newly improved sleeves, and (3) host casing samples. Sliding sleeve performance was assessed through the resultant opening and closing forces. Test results verified the model for radial deformation due to formation forces, and the effect on sliding sleeve performance. The improved sleeves showed no change in performance with a range of applied radial load, whereas the original sleeves showed significant increases in function force. Completion design improvements can enable novel methods of well stimulation and production in areas prone to formation compaction and subsidence forces. These forces can have major effects on the completion and production of a well but are rarely quantified and accounted for in sliding sleeves or similar completion systems designs. At the time of writing, the improved sliding sleeves have been successfully run in a field trial, though did not produce prior to functioning.
Puntervold, Tina (University of Stavanger, Norway) | Khan, Md Ashraful Islam (University of Stavanger, Norway) | Torrijos, Iván Darío Piñerez (University of Stavanger, Norway) | Strand, Skule (University of Stavanger, Norway)
Abstract It is well-known that seawater flooding has been a huge success for hydrocarbon recovery from the fractured chalk reservoir, Ekofisk, on the Norwegian Continental Shelf. Extensive laboratory studies the last decades have shown that Smart Water flooding has potential of greatly improving oil recovery beyond that obtained by standard waterflooding, due to wettability alteration, which improves reservoir sweep efficiency. However, to be economically viable compared to seawater injection, the Smart Water must be cheap, easily available, and must substantially improve oil production. Thus, the objective of this work was to investigate if a tailor-made, but cheap Smart Water could enhance oil production compared to seawater injection in an offshore chalk reservoir. Is seawater the smarter choice in offshore chalk reservoirs? Two reservoir chalk cores were used in this study and initial reservoir core wettability was estimated from optimized, in-house laboratory core restoration procedures. The potential for wettability alteration and resulting oil recovery by seawater (∼33000 ppm salinity) and Smart Water (<5000 ppm salinity, containing 20 mM SO4, Ca and Mg) were compared in spontaneous imbibition tests at reservoir temperature (>100 °C). Waterflooding at various rates was also performed to evaluate the displacement performance, with regards to water breakthrough and ultimate recovery, of the two injection brines studied. Reproducible initial wettability was confirmed in both reservoir cores, making a comparison of brine performance easier in spontaneous imbibition tests. The restored cores behaved initially mixed to oil-wet, imbibing limited amount of water. Both seawater and Smart Water showed potential for wettability alteration, although oil recovery by spontaneous imbibition by Smart Water was not improved compared to that by seawater. By low-rate waterflooding the Smart Water was more efficient than seawater due to the water being forced into the interior of the cores causing faster and more pronounced wettability alteration at microscopic scale, hence generating stronger positive capillary forces than in the spontaneous imbibition process. It was concluded that Smart Water flooding can potentially improve recovery beyond that obtained by seawater flooding in fractured chalk reservoirs. This high-temperature offshore chalk reservoir case study demonstrates that seawater is able to alter wettability of mixed to oil-wet reservoir chalk in a similar way as previously reported for outcrop chalk. Additionally, although seawater injection seems to be a good choice offshore, there is still potential of tailoring a Smart Water composition to both accelerate oil production, delay water breaktrough, increase ultimate oil recovery, thus lowering the field residual oil saturation if its injection is timely implemented.
Abstract Logging-while-drilling (LWD) ultra-deep resistivity technology can explore the reservoir on a similar scale to seismic, so interpreted resistivity models can be combined with seismic sections to enable oil field operators to delineate pay zones better, improve reservoir understanding, and eventually achieve higher reservoir contact value by proactive geosteering. Currently, there is no industry-adopted processing software which supports different ultra-deep tools. This paper presents the first vendor-independent, gradient-based stochastic approach for ultra-deep data inversion while drilling. Industry literature review was performed to determine parameters of ultra-deep tools, investigate their responses, and add them to the list of supported devices. Inversion algorithm is based on stochastic Monte Carlo method with reversible jump Markov chains and can be launched automatically without prior assumptions about the reservoir structure. Finally, it provides an ensemble of unbiased 1D formation models explaining the measurements as well as uncertainty estimates of model parameters. Parallel running of several Markov chains on multiple CPUs with both gradient-based sampling and exchanging their states makes the algorithm computationally effective and helps to avoid sticking in local optima. The proposed approach enables gathering of ultra-deep tools from different vendors under a common interface, along with other resistivity tools, joint processing various resistivity data with the same inversion workflow, and representation of inversion deliverables in unified format. Due to the large formation volume being investigated, the ultra-deep readings become complex. To be interpreted, such responses require multi-layer models as well as special multi-parametric inversion software. Working in high-dimensional parameter space, stochastic Monte Carlo inversion algorithms might not be effective due to the limitation of sampling procedure that usually generates new samples through the random perturbation of the few model parameters and does not consider their relations with other model parameters. This may lead to a high rate of proposal rejections and a lot of unnecessary calculations. To overcome this issue and guarantee real-time results, the presented approach employs Metropolis-adjusted Langevin technique which evaluates the gradient of posterior probability density function and generates proposals with a higher posterior probability of being accepted. Additionally, a special fast semi analytical solver is utilized to compute the gradient simultaneously with tool responses, with almost no extra computational costs. Application of the developed software is shown on synthetic scenarios and case studies from Norwegian natural gas and oil fields. The presented approach is identified as the first vendor-independent gradient-based inversion algorithm operating with any measurements of ultra-deep and deep azimuthal resistivity tools available on the market. The algorithm is high-performance and ensures real-time inversion results even in case of multi–layer formation models required to interpret ultra-deep measurements. The software may help oil field operators to resolve reservoir structure at a larger scale and pursue a more informed reservoir development strategy thus making more confident geosteering decisions.
Abstract The objective of this paper is to demonstrate the problematic of asphaltene deposition during oil production via ESPs in Mittelplate oilfield. Furthermore, different measures implemented for prevention and removal of asphaltene precipitations are presented and summarized. Production impairment due to asphaltene deposition has been observed in two wells in Mittelplate oil field. First indications of asphaltene accumulations were noticed at the production well M-W1. The well experienced severe asphaltene-plugging issues resulting in rapid production decline. Damages caused by asphaltene precipitation in the ESP have been observed during tear down analysis. The well was regularly treated with solvent washouts to disperse asphaltene depositions. Despite high frequency of solvent washouts, the well productivity could not be restored. Later on, the well was shut in and recompleted into a water injection well according to the field development strategy to support the pressure in the reservoir. At the production well M-W2, a strong production decline was observed as well. ESP production behavior and laboratory analysis - determination of colloidal instability index (CII) based on saturate, aromatic, resin and asphaltene (SARA) analyses – confirmed high likelihood of downhole asphaltene accumulations. As a first attempt, the well was treated via solvent washout to remove asphaltene accumulations from the ESP. Following that, it has been decided to inject an appropriate asphaltene inhibitor through the chemical injection line (CIL) to mitigate further precipitation of asphaltenes within the ESP. Two candidate asphaltene inhibitors have been selected based on their effectiveness with respect to asphaltene precipitation in Mittelplate crude oil. Field tests started at the well to identify the most effective inhibitor at downhole conditions by optimizing the inhibitor dosage and respectively the asphaltene treatment. Preliminary results of field test application at the well M-W2 showed that continuous asphaltene inhibitor injection through the CIL is very effective under downhole conditions. Furthermore, surveillance procedures, such as monitoring of bottom hole flowing pressure, well production rate and inhibitor injection rate, are in place to understand and evaluate the effectiveness of the treatment. This paper presents the operational challenges and experiences related to asphaltene deposition during the oil production via ESP system in a mature North Sea oilfield. The early results of field test applications with different types of asphaltene inhibitors are presented. Lessons learned from field test applications and operational experiences have been summarized. In general, there are few similar field case studies available in the literature and therefore, the publication of the results would provide valuable information for other fields facing similar problems regarding asphaltene precipitation.
Jonsbråten, Fredrik (Baker Hughes) | Iversen, Marianne (Equinor) | Røsvik Jensen, Kåre (Equinor) | Vik Constable, Monica (Equinor) | Haktorson, Hilde (Equinor) | Holbrough, David (Baker Hughes) | Wessling, Stefan (Baker Hughes)
Abstract The Troll oil field has been one of the largest oil producers on the Norwegian continental shelf for the last 25 years and is now moving into late life. The remaining oil column is thin, and the fluid contacts vary due to production effects. To extend field lifetime and secure the last reserves, enhanced well placement and increased drilling efficiency is needed to reduce cost and increase recovery in the long multilateral horizontal wells. Due to thin oil column and low reserves number, every meter correctly placed in the reservoir counts. To investigate these challenges a technology development project was initiated between Equinor and Baker Hughes to develop automatic interpretation of the oil-water contact (OWC) based on inversions, and automatic steering advice for taking faster geosteering (RNS) and downlink decisions placing the wellbores at the optimal distance to the OWC. Automating log interpretation is a complex task, but solvable given a known environment. As an engineering problem it must be split up into multiple smaller tasks that can be independently solved and when combined, solve the greater task. Logging while drilling (LWD) deep azimuthal resistivity data is run through inversion processing which provides a resistivity profile from which the OWC position is identified. The inversion input model constraints are set based on field/area specific data and is run automatically as drilling progresses. To assess the quality and validity of these results, several flag curves are computed and used. This automatic quality control of the OWC points enables the creation of a forward projection of this boundary. A steering advice is calculated, giving a recommendation on how to achieve the desired stand-off and inclination above the OWC as efficiently as possible. All the output from the automatic interpretation is published to a central datastore and is immediately available for the geoscientists to optimize operational decisions. Close co-operation between the operator and the vendor during the development and testing of the service has proven beneficial for identifying areas for further improvements. The service has been tested for well placement in actual producers. Several loops have been made in the development between the different tests and the learning curve has been steep in both companies. Based on the experiences and results from the actual wells, the project has moved into a new phase for further optimization of the steering advice and linking the automated steering advice to an Automatic Drilling Control (ADC) system to deliver a more automated closed loop service.
Abstract Fishbones’ Multilateral Stimulation Drilling Technology (MSDT) was installed for the first time in two conglomerate formation wells in the Edvard Grieg field in 2021. The field is located in the Central North Sea. The objective when installing MSDT is to increase productivity by enhancing well connectivity to the reservoir. This paper will discuss the development of the technology and its qualification, as well as installation preparation and results. The MSDT was developed in a Joint Industry Project (2012-2015) and has been installed in sandstone reservoirs with good results. To optimize drilling in conglomerate formation, further drill bit development was required. Enhancements to the drilling needle design was also undertaken to cope with the abrasiveness of the specific drilling fluid. Following successful development programs (2018-2020), the MSDT system was installed in two infill wells. In total, 53 and 61 MSDT subs were deployed with the 5.5" liner creating 159 and 183 laterals, respectively. The MSDT was integrated with Inflow Control Device (ICD) screens and swellable packers to constitute the total completion in the reservoir. Following the product development, full-scale testing programs and detailed well planning by allparties involved, the installations took place in Q2 2021. The MSDT ICD screen liners were deployed to Total Depth (TD) according to the plans. Pumping operations were executed to drill the MSDT laterals, with pressure responses indicating good extension of the needles. The first infill well equipped with MSDT came on stream in June 2021 demonstrating excellent performance, and well productivity significantly greater than the pre-drill prognosis. The production from the second well commenced in December 2021, also delivering excellent productivity. This paper will provide the details of the technology development and its limitations, reservoir challenges and completion design, as well as results, future improvements and plans for its implementation First time use of MSDT in conglomerate formation creates a potential game changer for productivity enhancement in tight heterogeneous reservoirs globally. In addition to increased productivity, the MSDT offers a solution that reduces the carbon footprint by the elimination of stimulation vessels and reduced rig time compared to conventional stimulation techniques.
Betancourt, Soraya S. (Schlumberger) | di Primio, Rolando (Lundin Energy Norway) | Blanco, Yon (Schlumberger) | Stirø, Øyvind (Lundin Energy Norway) | Lopes, Velerian S. (Schlumberger) | El-Khoury, Jules (Schlumberger) | Dykes, Thomas A. (Schlumberger) | Mullins, Oliver C. (Schlumberger)
Abstract We present a case study of the application of Fluid Mapping While Drilling (FMWD) to acquired logging-while-drilling downhole fluid analysis (FMWD-DFA) in the development stage of a North Sea reservoir. An extensive Wireline DFA (WL-DFA) dataset and Reservoir Fluid Geodynamics (RFG) study helped characterize fluid variations in the exploration and appraisal stages of this field revealing a complex reservoir charge history that results in fluid variations throughout the field and furthermore revealing connections between reservoir quality/productivity and in-situ fluid properties. In the development stage, knowledge acquired in the previous field phases guided well placement decisions and FMWD-DFA was used actively in well construction to validate and enhance the fluid model in this field. FMWD pressure and DFA measurements were acquired in five development wells in the field: three horizontals and two high-angle pilots. DFA measurements provide fluid composition and optical density, which correlates directly with the asphaltene content of the oil. Asphaltene gradients are modeled to assess thermodynamic equilibrium conditions and investigate lateral and vertical connectivity. DFA and other data streams integrated by the RFG analysis provided the base model: a relatively recent secondary migration of light hydrocarbon into the reservoir that resulted in different realizations of the mixing process depending on distance from the charge plane and rate of mixing. Well trajectories were designed to target sweet spots based on appraisal data; however, some level of uncertainty remains when entering the development stage. FMWD-DFA was used to understand fluid property variations throughout the field that may be associated to geological factors or resulting from fluid mixing processes that may yield localized asphaltene instability. FMWD pressure and mobility measurements complement this model and enable an assessment of current levels of pressure depletion from production in a neighboring field in hydraulic communication through a shared aquifer. This field example shows integration of DFA technology from different acquisition platforms at different stages of the life of the field. It illustrates how this technology is used to improve the understanding of the complex fluid variations in this field and make development decisions such as optimizing well design by ensuring placement within reservoir sweet spots.
Abstract Steady-state hole-cleaning models used to monitor cuttings during well construction rely on static parameters that portrait specific drilling scenarios disconnected from each other. This paper presents the integration of transient hole-cleaning models validated in the field into a digital twin of the wellbore deployed while drilling. Thus, enabling the monitoring of the evolution of cuttings, which reduces uncertainty around the state of hole-cleaning procedures and minimizes the associated risk. A digital twin of the wellbore equipped with physics-based transient models is prepared in the planning phase, and later deployed to a real-time environment. While drilling, smart triggering algorithms constantly monitor drilling parameters at surface and downhole to automatically update the digital twin and refine simulation results. The physics-based transient model continuously estimates cuttings suspended in the drilling mud and cuttings deposited as stationary beds, which enables evaluation of cuttings distributions along the wellbore in real time. Automation systems consume the predicted results via an aggregation layer to refine fit-for-purpose hole-cleaning monitoring applications deployed at the rig. The transient hole-cleaning model has been integrated into digital twins used during pre-job planning as well as in real-time environments. The system deployed in real-time successfully tracks the state of cuttings concentration in the wellbore during all operations (drilling, tripping, off-bottom circulation, connections) considering the effects of high-temperature and high-pressure on the drilling fluid. Moreover, since the model uses previous results as starting point for the next estimation cycle, it creates a dynamic prediction of how the cuttings evolve while drilling. Fit-for-purpose automation and monitoring services predict drilling issues related to hole-cleaning, downhole pressure, among others. Drillers and drilling optimization personnel receive actionable information to mitigate hole-cleaning issues and avoid detrimental effects for operations. The user interface (UI) presents how the cuttings distribution change with evolution of input parameters (rate of penetration, string rotation, and flow rate). A set of case studies confirm the effectiveness of the approach and illustrate its benefits. One case study from the North Sea illustrates the reaction of the model to changing operational parameters, while another combines along-string-measurements of density with the cuttings predictions to confirm the trend established by the predicted cuttings concentration.
John McDonald, OPITO CEO, discusses the purpose and work programs of the North Sea Transition Deal (NSTD) -People & Skills Strategy, a UK-based cross-industry strategy led by OPITO to develop skills for a net zero energy industry and an all-energy workforce for the future. Through the Energy Skills Alliance (ESA), the development of the strategy brought together leaders from across the oil and gas, renewables, nuclear and refining industries, as well as representation from within regulators, governments, and trade unions. John discusses how the ESA will now move from strategy development to the delivery of action to respond to supporting a transitioning energy workforce.