In the discipline of geosteering and reservoir mapping, exceptional development and improvement of inversions to interpret deep azimuthal resistivity (DAR) and ultradeep azimuthal resistivity (UDAR) data sets has been the privileged area of research and development in our industry for more than a decade. For the continued evolution of UDAR services, another full cycle of improvements is needed, including a new hardware design for the acquisition system. The next-generation acquisition system will have to support more accurate measurements characterized by a higher signal-to-noise ratio, better control of the directionality, increased depth of investigation, and improved resolution of the inverted interpretation. The novel triaxial collocated multi depth azimuthal resistivity (MDAR) platform presented could support the ambitions to make new step changes in planning and geosteering of development wells in complex reservoirs (injectite sands, faulted reservoirs), mapping oil-water contact/moving oil-water contact (OWC) in mature reservoirs and improve geological model updates. The novel logging-while-drilling (LWD) integrated drilling and reservoir mapping platform introduces a triaxial MDAR modular design, generating triaxial calibrated measurements at shallow, medium deep, and ultradeep spacings. The deep transmitter placed only 7 ft behind the bit, and the shallow resistivity array are fully integrated with a rotary steerable system. The new LWD triaxial antennas are designed to improve the precision of remote boundary mapping, generate an accurate inverted resistivity profile for qualitative reservoir model updates, and extend the depth of detection (DOD) in every direction. Triaxial collocated antennas paired with MDAR architecture are not only improving the mapping of near and far boundaries but also provide the necessary type of measurement sensitivity and frequency range to unlock look-ahead capabilities in any wellbore deviation for an effective, predictive geosteering and reservoir mapping workflow, especially when coupled with real-time seismic-based multi physics solutions. The impact of the novel MDAR platform on geosteering, reservoir mapping, and geostopping capabilities will be shown with real well examples from both the field test facility and two separate siliciclastic fields on the Norwegian Continental Shelf (NCS). The positive effects on the reaction time of geosteering and reservoir mapping operations when using this new integrated MDAR design with a robust rotary steerable technology are evaluated, with comparison to previous DAR and UDAR technologies. The improved signal-to-noise ratio related to the new triaxial collocated antenna vs. previous UDAR not co-located and pseudo-triaxial technologies significantly helped to reduce the uncertainty of remote boundary detection. The combination of MDAR hardware and seismic-based digital solutions is also the key to unlocking predictive look-ahead solutions. This predictive workflow allows for optimizing geosteering operations while reducing drilling risks, predicting structural changes up to 300 ft (100 m) ahead of the bit. Through the presentation of real-time examples from the field test facility and NCS siliciclastic fields, this paper introduces the impact of a novel LWD triaxial and collocated antenna design, enabling the MDAR concept within an integrated drilling and reservoir mapping platform. The integration of a deep transmitter at 7 ft (~2 m) behind the bit, coupled with an MDAR architecture, allows this new platform to reduce the geosteering reaction time, thus reducing drilling risk and providing a smoother trajectory in complex geological scenarios. This innovative platform architecture unlocks look-ahead capabilities in all wellbore angles, from vertical to horizontal wells, while increasing the depth of detection and improving the mapping accuracy of remote reservoir boundaries.

Complications during drilling and completion operations caused by subsurface geology have a significant impact on rig time, cost, assets, and even human life, if risk and incident severity is not well understood. Risk and tolerance evaluation processes are essential for completing successful drilling programs and final casing designs. While log-based correlation methodologies can be used, they are limited to scenarios where appropriate offset well data control exists, and they only provide information after the hole has been drilled. The development of technologies that provide warning of a hazardous zone before it is penetrated are therefore desirable. Ultradeep Azimuthal Resistivity (UDAR) tools are deployed for such scenarios and provide high value when used in integrated interpretations to identify hazards ahead of drill bit. Seismic data is used as a first step to predict and map subsurface characteristics such as pressure regimes, faults, and fluid contacts. Offset and pilot hole data further complements assessment of these features enabling more precise risk assessment. Commonly, near-bit measurements such as resistivity and gamma ray have been used for these correlations in conjunction with sonic and density measurements. The mapping of horizons from seismic data can have 10s to 100s of meters of vertical uncertainty, while offset data in exploration campaigns is typically sparse and near-bit measurements require drilling into the zone of risk. Pilot holes therefore become a costly necessity, however, if sufficient resistivity contrast exists UDAR can be used for remote boundary mapping, without drilling into the geohazards, thus reducing cost and de-risking the operation. This paper presents several case studies where UDAR technology was deployed in near vertical to horizontal wells to map geohazards before they were penetrated using different techniques, allowing optimization of the stopping point in diverse scenarios. This includes a case where the technology was used to geostop in a horizontal section prior to penetration of a major structural sealing fault plane that bounded the productive reservoir interval. UDAR has been successfully used to manage seismic uncertainty, support the decision-making process for core point selection, reduce exposure of unstable overburden shales and geostop above abnormal and subnormal pressure zones. Mapping a geohazard and proactively stopping at a particular depth is a complex operation and evaluation of the rock properties with respect to the sensitivity of the measurements and uncertainty in the models is important. Limitations in measurement sensitivity can lead to potential masking of top reservoir picks and increased uncertainty in both boundary positions and the inverted resistivity. Improvements such as new UDAR transmitter designs being embedded into Rotary Steerable Systems allow near-bit placement of this technology, demonstrating the continual evolution of this technology and how it assists risk mitigation in geostopping applications.

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.

Equinor has played an important role the last decade in testing and development of ultra-deep azimuthal resistivity (UDAR) measurements both for Look-Ahead and Look-Around applications. Today, more than 70% of Equinor high angle or horizontal wells are drilled with UDAR-technology. In this paper, the authors will review the use of UDAR in Equinor the last decade and highlight both successful use and real-time challenges related to interpretation of the inversion results. UDAR-technology and inversion algorithms have been very powerful for reservoir mapping to geosteer or geostop according to plan. However, we forget far too often the fact that we need a good understanding of the reservoir to interpret and evaluate the uncertainty in the inversion result. The number one mistake in a real-time setting is to interpret a resistivity contrast as a specific layer in the reservoir (for instance top reservoir) and hold on to that same interpretation even if we drill away from that contrast and may cross multiple layers as distance to the observed contrast increase. Other challenging real-time UDAR-exercises relate to uncertainties in the prediction of resistivity inside the reservoir and reservoir thickness from inversion results when still drilling above the reservoir. A third mistake often seen real-time is detailed interpretation of 1D-inversion results, even when other indicators are pointing towards 2D/3D complexities in the reservoir. Equinor and other operators have pushed for more and more advanced inversion solutions leading to 3D mapping capabilities for more complex reservoirs. The UDAR advances the last few years are important for Equinor’s planned roadmap ahead. However, 1D-3D inversion results can result in wrong decisions if the uncertainty in the inversion result is not managed correctly. We see a need to investigate how to best exploit UDAR-technology and inversion results within its limits, but also ensure assumptions are not extended beyond an acceptable uncertainty level. Better handling of uncertainties in geosteering operations will become increasingly important for the well economy with smaller targets, complex geological settings, and varying sweep efficiencies. How can we best handle the uncertainty in inversion results in real-time operations to avoid wrong decisions that can potentially destroy well economy? This is an important question which will be addressed and should be handled in the future if UDAR-technology is to continue having an important role in many of the wells to be drilled the next decades.

Equinor has played an important role in the last decade in the testing and development of ultradeep azimuthal resistivity (UDAR) measurements both for look-ahead and look-around applications. Today, UDAR technology is applied in more than 70% of Equinor’s high-angle or horizontal wells. In this paper, the authors will review the use of UDAR in Equinor over the last decade and highlight both successful use and real-time challenges related to the interpretation of the inversion results. UDAR technology and inversion algorithms have been very powerful for reservoir mapping to geosteer or geostop according to plan. However, we forget far too often the fact that we need a good understanding of the reservoir to interpret and evaluate the uncertainty in the inversion result. The number one mistake in a real-time setting is to interpret a resistivity contrast as a specific layer in the reservoir (for instance, top reservoir) and hold on to that same interpretation, even if we drill away from that contrast and may cross multiple layers as distance to the observed contrast increases. Other challenging real-time UDAR exercises relate to uncertainties in the prediction of resistivity inside the reservoir and reservoir thickness from inversion results when still drilling above the reservoir. A third mistake often seen in real time is the detailed interpretation of one-dimensional (1D) inversion results, even when other indicators are pointing towards two-dimensional (2D)/three-dimensional (3D) complexities in the reservoir. Equinor and other operators have pushed for more and more advanced inversion solutions, leading to 3D mapping capabilities for more complex reservoirs. The UDAR advances over the last few years are important for Equinor’s planned roadmap ahead. However, 1D through 3D inversion results can result in bad decisions if the uncertainty in the inversion result is not managed correctly. We see a need to investigate how to best exploit UDAR technology and inversion results without extending assumptions beyond an acceptable uncertainty level. Better handling of uncertainties in geosteering operations will become increasingly important for the well economy with smaller targets, complex geological settings, and varying sweep efficiencies. How can we best handle the uncertainty in inversion results in real-time operations to avoid inaccurate decisions that can potentially destroy well economy? This is an important question that will be addressed and should be handled in the future if UDAR technology is to continue its important role in well placement in the next decades.

With the introduction of ultradeep azimuthal resistivity (UDAR) logging-while-drilling (LWD) tools toward the beginning of the last decade, the oil and gas industry went from real-time mapping of formation boundaries a few meters from the wellbore to tens of meters away. This innovation allowed early identification of resistivity boundaries and promoted proactive geosteering, allowing for optimization of the wellbore position. Additionally, boundaries and secondary targets that may never be intersected are mapped, allowing for improved well planning for sidetracks, multilaterals, and future wells. Modern tool design and inversion algorithms allow mapping the reservoir in 3D and exploring the sensitivity of these tools to the electromagnetic field ahead of the measure point for look-ahead resistivity. Improvements in the technology over the past decade have changed the way wellbores are planned, drilled, and completed, and reservoir models are updated. This paper presents a case study summarizing the advances in UDAR measurements and inversions over the last decade. The case study presents the whole workflow from prejob planning, service design, and execution of one-dimensional (1D) and three-dimensional (3D) inversion in addition to the future potential of look ahead in horizontal wells. Prewell simulations provide a guide to expected real-time tool responses in highly heterogeneous formations. This identifies how far from the wellbore 1D inversions can map major boundaries above and below the well. A fault was expected toward the toe of the well, and UDAR was used as a safeguard to avoid exiting the reservoir. Standard 1D inversion approaches are too simplistic in this complex geologic setting. Thus, 3D inversion around the wellbore and ahead of the transmitter is also explored to demonstrate the improvements this understanding can bring regarding geostopping toward the fault and reservoir understanding in general. Successful geosteering requires personnel trained to handle complex scenarios. Geosteering training simulators (GTS) could be efficient tools for training to interpret inversions where the “truth” is known from realistic 3D model scenarios. The team can learn how to best exploit UDAR technology and inversion results within its limits and not extend the interpretation beyond acceptable uncertainty levels. It will also be addressed how the understanding of inversion uncertainty could be updated in real time in the future. The continued future success of UDAR technology and 1D to 3D inversion results for look-ahead and look-around applications will depend heavily on uncertainty management of the inversions to avoid wrong decisions and potentially reduced well economy.

Abstract The Byrding asset on the Norwegian Continental Shelf (NCS) successfully drilled a two-branched horizontal producer in a structuraly complex area with many faults, changes in reservoir properties laterally, and an uncertainty on oil-water contact (OWC) levels along the trajectories. The key inputs for optimal well placement of the two branches were measurements to map the reservoir top while drilling and the OWC up to approximately 20 - 30m TVD from the wellbore. Before deploying the ultra-deep directional resistivity tool, it was critical before drilling to evaluate how top reservoir and OWC would be mapped by inversion of electromagnetic measurements. The reservoir conditions were challenging with a low resistivity contrast towards reservoir top and a gradually changing resistivity towards the OWC. It was, therefore, critical in the pre-job phase to help all involved in the future geosteering operation to get familiar with using the ultra-deep resistivity real-time interpretation to meet the objectives and to update the geomodel after drilling. To plan the well placement job a new workflow was applied to build a realistic geomodel based on geological understanding, legacy offset wells measurements, and seismic interpretations. Then potential scenarios generated from this geomodel were used to simulate synthetic ultra-deep directional resistivity responses and inversions results, synthetic standard LWD-data, and seismic. Finally, an updated geomodel was built after the drilling campaign, validated through "Model-Compare-Update" traditional iterative process using synthetic and real data. In conclusion, the pre-job analysis was important to understand how to interpret reservoir top and OWC. This knowledge was used in real-time while drilling and post-operation to update reservoir top interpretation and the OWC position. This case study describes the importance of having a workflow to build a realistic high resolution geomodel that is validated with all the subsurface measurements at different scales. Deployment of such highly integrated workflow open new horizon for the collaboration between service company and operator for improved pre-job planning, real-time decisions and post-job integrated interpretation. Furthermore, integrated interpretation of data from the two wells with seismic performed over the post drilling analysis is proven to be essential to ensure future production steering of the two-branched horizontal producers. An alternative ultra-deep azimuthal resistivity inversion algorithm was successfully used while drilling along with the standard inversion to better interpret reservoir top in the context of low resistivity contrast from this case study. An important, and unprecedented effort of pre-job planning was conducted to select optimal LWD real time dataset required. IT and "cross-platform-data-exchange" challenges were overcome to allow an extensive and innovative use of realistic geomodel scenarii for multiple measurements simulation, including from synthetic ultra-deep resistivity inversions results, standard LWD-data, to seismic interpretation.

Abstract In this case study, we present the use of a new look-ahead resistivity technology to solve a challenge on the Valemon field where the top of the reservoir could not be mapped from surface seismic. The objective was to extend the overburden section deep enough to secure sufficient formation strength at the casing shoe while eliminating the risk of accidental drilling into the reservoir below. The application of the new technology secured standard casing design, and eliminated the extra time and costs associated with implementation of the managed pressure drilling technique. The target was to extend the 12 ¼-in overburden section 10-15m TVD into the Viking Group, as this formation generally provides sufficient formation strength for the 9 7/8-in casing shoe to enable conventional drilling of the following reservoir section. As there was a risk that the Viking Group could be absent or very thin in this area of the Valemon field, the look ahead measurement was used to monitor the formations ahead of the bit while drilling. Detection of higher resistivity ahead of the bit indicating an approaching reservoir would enable stopping prior to drilling into it. No reservoir response was detected ahead of the bit, and this enabled a safe extension of the 12 ¼-in section into the Viking Group as per the objective.

A vision in the oil industry for decades is becoming a reality. Finally, we are able to drill and react proactively to formation resistivity properties several meters ahead of the drill bit, instead of reacting to measurements behind the bit. Through a technology collaboration between operating and service companies, a targeted technology development for measuring resistivity contrasts ahead of the bit in real time to reduce cost and risk during drilling operations was developed. Two electromagnetic look-ahead (EMLA) prototypes have been developed for 121/4- to 14-in. boreholes. The EMLA tool is modular and consists of a low-frequency transmitter inserted in the rotary steerable drilling assembly 1.8 m behind the bit and two to three receivers spaced out in the drillstring. The EMLA tool uses the same sensor technology and operates with the same multispacing and multifrequency measurements as the commercial ultradeep "look-around" directional resistivity tool. The formation structure ahead of the bit is interpreted by inversion to differentiate sensitivity around the tool from effects ahead of the bit. The look-ahead capability is dependent on the transmitter-receiver spacing, frequency, resistivity around the tool, thickness of the target, and the resistivity contrast ahead of the bit.The EMLA tool provides a step change with regard to precision in detecting changes in resistivity properties ahead of the bit in vertical and low-angle wells. The ability to react to resistivity contrasts ahead of the bit has a direct impact on how wells are drilled. The main application of EMLA to date has been to drill the well section above the reservoir closer to top of reservoir to avoid complications in the shale above the reservoir, as presented in two case studies. Challenges related to salt drilling are addressed in another case study where the salt exit was detected 30 m ahead of the bit. Improved precision in coring-point selection is another potential application.

Abstract Statoil has played a key role in testing and development of the new ultra-deep directional resistivity (DDR) logging while drilling (LWD) measurements for high angle and horizontal wells the last 4 years. Inverted resistivity images provide an overview of geological structures and fluid contacts tens of meters around the wellbore. The ultra-deep look around measurements, sensitive to resistivity contrasts up to 30 m away or even more in favorable conditions, are a step change, when it comes to possibility to position the wellbore strategically in the reservoir and to characterize reservoir structure and properties. This paper will present how the new DDR measurements have been applied with success in an operating license on the Norwegian Continental Shelf (NCS). Long horizontal wells in the reservoir sections have been identified as a key strategy to increase recovery. The main benefits from the DDR measurements in the license have been to maximize reservoir exposure by active geosteering, to optimize well placement above oil-water contact, and to increase subsurface understanding which is important input for future well plans. The DDR measurements are already a commercial service with regard to well placement and reservoir landing. Statoil is however also actively pushing for improved reservoir characterization, by coupling geomodels and DDR modeling and inversion software. This paper will also present how standard LWD logs and images can be combined with the DDR inversion results, to build a near-wellbore 3D structural model supporting all available data. This is an important step towards an extended use of the new data not only for well placement, but also for increased subsurface understanding and geomodel update. Background The willingness to invest in R&D has been a key success factor for the development of the Norwegian petroleum industry since the very beginning. Operators on the NCS have pioneered innovative technology such as horizontal drilling, time lapse seismic surveying (4D), and subsea technology. The development of horizontal drilling and multilateral wells in the thin oil rim on Troll is an example of Norwegian technological excellence, which released reserves worth more than NOK 500 bn that would otherwise have been left in the ground (Mikkelsen et al. 2005). The development of horizontal drilling has been a key component of improved oil recovery on NCS. More than 50% of all production wells today on the NCS are highly deviated or horizontal. Global companies have used the NCS as a testing ground for new technology such as horizontal drilling and new LWD measurements to geosteer the long horizontals. Given the ability to drill with high angles there is also a considerable value in geosteering this type of wells for correct well placement with regard to formation boundaries and fluid contacts. Statoil, together with the former Hydro, has been pushing electromagnetic measurements (EM) while drilling for geosteering long horizontals with great success. Examples from Troll, Grane, Velsefrikk, Oseberg and Gullfaks fields demonstrate the added value from both non-directional and directional bed-boundary mapping tools in the past, where NCS has played a key role in development and testing of LWD EM-measurements (Iversen et al. 2003; Wiig et al. 2005; Constable et al. 2012).

Abstract The last decade has shown a significant development in resistivity measurement technology providing directional resistivity at a larger scale than conventional logging tools. The latest development can identify resistivity contrasts ten's of meters around the wellbore. Statoil has tested deep look-around resistivity on a range of fields during the last 2 years and recorded data in more than 10 wells on the Norwegian Continental Shelf. The look-around images provides information at a scale that bridges the gap between conventional logging and seismic and adds important new pieces to the reservoir characterization puzzle. In good reservoir conditions, resistivity contrast up to 30 m away from the well-bore has been observed. This study will focus on results from the Visund and Åsgard fields, and will demonstrate how the device was used in a range of different applications in the geosteering operation: Detection of the reservoir boundary up to 20m TVD away. Detection of oil bearing reservoir from within underlying shale, through a water zone. Detection of Gas-Oil Contact (GOC). Detection of Oil-Water Contact (OWC) up to 20m TVD away. Detect faulting of the reservoir. These examples will highlight why deep look-around resistivity is a step change related to the possibility for doing pro-active well placement of highly deviated wellbores as well as for gaining a larger reservoir understanding. The imaged variation in resistivity contrasts can be related to geologic zonation and fluid content on the reservoir scale, which opens up a much better cross-disciplinary communication between geophysicists, geologists, petrophysicists and reservoir engineers. Finally, the deep resistivity images contribute in optimization of completion solutions when incorporating information on the reservoir scale.

Depth differences of up to 20 m were observed between wireline (WL) and Logging While Drilling (LWD) depths in the Kristin field. Kristin is a HP/HT gas/condensate field in the Norwegian Sea. These depth differences introduce unacceptable depth uncertainty for both reservoir modeling and well operations. Procedures were implemented to help understand observed depth differences. These included routine logging of radioactive markers installed in casing strings, adopting primary depth control procedures for all WL descents, and recording Gamma Ray correlation logs during all relevant runs/passes to allow depth comparisons. Wireline depth initially was believed to be superior and depth differences that increased systematically with depth were believed to result primarily from stretch in drill pipe due to temperature and suspended pipe weight. For later wells with higher inclination, the validity of downlog wireline depths was questioned. Formation tops based on wireline depths resulted in questionable local corrections to seismic time-depth maps, with significant implications for mapped reservoir volumes. Simplified models were adopted to estimate pipe stretch/compression due to temperature, string weight and drilling parameters. Results obtained could explain only about one-half of earlier shifts applied to LWD logs. A similar methodology was developed to correct wireline depths for stretch, with estimated corrections far exceeding standard assumptions. Following run and pass-specific correction of both LWD and WL logs, depth uncertainty was significantly reduced. Detailed depth corrections are recommended to both LWD and wireline logs for future wells with high angles or large depth differences. A key recommendation is to maintain today's "Driller's depth" (LWD depth) and "Logger's depth" (WL depth) as separate wellsite depth references to avoid operational mistakes. In addition, it is helpful to establish a new "Corrected depth" based on corrected LWD- and/or WL depth for use in subsurface models.