The need to evaluate cement behind multiple casing strings has become critical in the context of well plug and abandonment (P&A) or slot recovery. A particularly important case, addressed in this work, is the application to optimize P&A operations in offshore wells where the capability to evaluate barriers behind casing using tools deployed inside an inner tubing would reduce the costs associated with rig time and potentially (in case the presence of barriers outside the casing is confirmed) the unnecessary removal of casing strings. We present an approach using a combination of sonic and ultrasonic tools deployed inside tubing to characterize the near well bore environment and in particular, the annular fill and bond behind the outer casing, i.e. in annulus B. Extensive modeling and experiments were used to characterize the sonic response in a dual string geometry and identify features that inform on the state of annulus B. Some of the complexities and ambiguities in this complex scenario are addressed by using the ultrasonic tool to characterize the annulus behind the tubing (annulus A) as well as the tubing location inside the casing. Additionally, we combine the single feature answers with those using deep machine learning to learn the complex relationship of the subtle features in the through tubing sonic response to the finer variations of the annulus B state as indicated by ultrasonic cement maps acquired in the outer casing. We test and validate these answers on a number of field jobs and show the results of the through-tubing logging answers with the reference cement evaluation maps obtained after removing the tubing.

This study aimed to produce a pilot spatial model, building upon the existing quantitative Spatial Environmental Assessment Tool (SEAT), to evaluate risks associated with marine hydrokinetic energy (MHK) development within the Pacific Marine Energy Center South Energy Test Site, located off Newport, Oregon. The goal is to establish an approach for integrating natural resource sensitivities with changes in physical conditions caused by wave energy converter arrays to inform planning and impact assessment. To generate the model inputs, a benthic substrate proxy within the project area was defined as a "sensitive resource" input ( Receptor ), using the Risk ( Rτ ) output points from the SEAT model to identify areas that could be impacted by the operation of a MHK device ( Threshold ). Risks were further investigated by overlaying federally designated Habitat of Potential Concern, Essential Fish Habitat, and critical habitat to identify sensitive benthic resources ( Secondary Constraint ) within the project area. The last iteration of the model focused on using nearshore habitats for threatened coho salmon ( Oncorhynchus kisutch ) outmigrating from rivers to demonstrate how a higher taxon could be incorporated into the pilot model by assigning risk based on proximity to the shoreline. This approach allows the analyst to weight the sensitivity of natural resources and place secondary constraints and ocean conditions into the assessment for an integrated picture and can accommodate multiple taxa, seasons, habitats, and locations. Overall, the results of the four models were dependent on the weighting and scale of the data. The outcomes of this study are meant to demonstrate ability to integrate models and are not based on particularly defensible criteria. More rigorous literature review and risk assessment process would be necessary to demonstrate the project specific risk of impacts from MHK devices. This type of modeling can inform resource management and planning, and ultimately assist in identifying priority impact issues and mitigation needs throughout project siting and development, which will reduce risk and cost to developers.

Computational modeling (CFD) has made great strides in the last 20 years in fighting and overcoming its "expensive" stigma. The oil & gas industry has embraced the use of CFD to assess everything from the design of equipment, optimization of process flows, and hazards modeling of fire and explosion events all in an effort to strive for the goal of inherently safer designs. In current offshore facility design, CFD modeling, to assess the consequences of vapor cloud explosions has been established as common practice. For most major projects, CFD explosion modeling is used heavily in Feed and Detailed (later) stages of design. At these stages hundreds of scenarios are simulated and combined with extensive probabilistic and statistical calculations to define design loads of critical systems and assess risk. The primary advantage of using CFD is that it incorporates more details of the design and provides more realistic and design specific analysis. In the case of explosions, CFD provides valuable data for design, particularly explosion data that is significantly more accurate than that from simple open field models. Despite this adoption within the design process and decades of advances, CFD modeling practitioners still admit that there are increases of cost and time, when compared to the ever-present phenomenological approaches. This has kept many design processes from utilizing CFD in the earliest stages; namely Concept and pre-Feed. The arguments have traditionally been along the lines of: The design is progressing and changing too fast to allow time for CFD models to be built., There is insufficient model detail to construct viable CFD models., The early stage concerns can be captured "well enough" with simple approaches., etc. Modeling representations and approaches can be simplified and streamlined, while still providing the advantages of CFD. Variability in geometric representations can be captured with physics representations rather than needing to create predictive CAD geometry. These types of simplifications can increase the ability to simply change and update models and conduct early stage sensitivities in projects, while still capturing critical explosion effects. The purpose of this paper will be to show how these simplified approaches can be used in an effective and efficient manner in early stages of design. That the traditional arguments against early adoption of CFD can be countered, with the end result being greater early stage information and influence on the design. Allowing effective change at a time in the process when it is not cost prohibitive and other controls have yet to prohibit design changes. The result being a continued improvement in the goal of inherently safer design.

Loss-of-well-control (LOWC) events are generally defined as uncontrolled flow of formation or other fluids to either the surface or another subsurface formation. Such events are also known as blowouts. Blowouts can result in the loss of human life, catastrophic damage to ecosystems, and substantial economic losses. Many blowouts start with a "kick event", where the formation pore pressure becomes greater than the wellbore pressure, causing formation fluid to flow into the wellbore and combine with the drilling fluid (i.e., mud). Detecting a kick as early as possible is key to preventing a blowout. Conventional kick detection methods (e.g., monitoring mud pit returns, monitoring wellbore liquid levels) are usually time-consuming, resulting in delays during which the kick may grow in intensity and efforts required to re-establish well control may become more extensive. Some, more sophisticated kick detection techniques use instrumentation that can be costly. In this paper, an alternative, lower-cost, early kick detection method is proposed. Here a kick detection method is proposed that uses measurements from the instrumentation deployed on the drillstring to provide real-time information on the wellbore. Specifically, bulk density, acoustic (compressional wave) velocity, and electrical resisitivity are considered for use as detection parameters. These fluid mixture (combined formation and drilling fluid) properties as a function of kick fluid volume are estimated. Theoretically, these parameters are found to be sufficiently responsive to be used for kick detection. However, additional work is needed to determine how these parameters respond in experimental or field conditions.

The OFG AUV non-contact integrated Cathodic Protection (iCP) inspection system enables a fast and reliable approach to monitoring the state of cathodic protection systems on subsea pipelines. By measuring the electric field, the system monitors directly the change in electrical currents in the pipeline due to anodes or damage. This approach allows for improved monitoring of anode energy remaining, predicts anode end of life earlier than stab methods alone and pinpoints problem areas on the pipe that need attention. When combined with the camera imaging, multi-beam measurements, synthetic aperture sonar (HISAS), and chemical sensors, the OFG AUV iCP system provides a compelling set of measurements for pipeline cathodic protection monitoring and pipeline inspection. The advantage of the OFG AUV iCP system over traditional ROV CP systems is the speed with which these surveys can be undertaken, coupled with the dramatic increase in sensitivity which is approaching 100 times the sensitivity of the traditional ROV CP survey systems. Ocean Floor Geophysics (OFG) has a successful history of developing numerous magnetic and electric field instruments for ROVs, AUVs and deep-tow systems. Based on the success of these programs, and in collaboration with ISES Technical Services (ISES), OFG & ISES have developed an electric field measurement system which mounts onto a pipeline inspection AUV. Initial testing of the system in 2017 on OFG's 3000m depth rated Hugin AUV "Chercheur" demonstrated that the intrinsic electrical noise of the "Chercheur" with motors and all survey sensors running, was well below the threshold needed to successfully measure CP signals from the AUV. This was further supported through the development of a first principles model of the electrical fields generated around a generic cathodically protected pipeline. These supporting measurements and calculations led to the first operational field test of the system on a North Sea pipeline in April 2018. During these trials we were able to demonstrate the responsiveness of the system to the cathodic protection currents in the pipe at a variety of ranges and orientations up to 10 meters distance from the pipe. Furthermore, by performing repeated surveys of sections of the pipeline in both directions, we were able to confirm the repeatable detection of extremely small electric field gradient signals (less than 0.025μVrms/cm difference). The results show levels of sensitivity and detection hitherto unattainable using any other currently available CP survey method. These measurements were taken concurrently with all the other onboard survey sensors running, including the HISAS, Sub-bottom, Multi-beam, Camera system, and USBL, while running at the nominal survey speed of the vehicle of 3-4 knots.

Objective/Scope This paper examines an environmental weighting tool developed for site assessment of New York offshore wind development and discusses future applications of sensitivity weighting for site identification and assessment as part of the development of other renewable energy projects across different geographic locations. As part of New York State's Offshore Wind Master Plan, Ecology and Environment, Inc. (E & E), with direction from New York State Energy Research and Development Authority (NYSERDA), developed a weighted sensitivity model to evaluate the relative risk of developing offshore wind infrastructure. This relative risk assessment compared the potential impacts, or "stressors," to selected biological marine resources, or "receptors," from activities that may occur during the pre-construction, construction, and post-construction phases of offshore wind energy development off the coast of New York. Methods, Procedures, Process The overall approach was to first establish relative risk matrices by conducting a literature synthesis and risk assessment. These matrices characterized risk and potential impacts to each selected marine resource, incorporating vulnerability of the marine resource and probability of the impact. This approach differs from density-based risk assessments and allows for the comparison of risk associated with different phases of development. Based on the resultant risk assessment matrices, regulatory context, permitting requirements, Bureau of Ocean Energy Management recommendations, seasonality, and other relevant factors, sensitivity weight values were determined for the identified receptor groups for each phase of offshore wind development and applied using a weighted sum geospatial analysis model to produce maps of relative sensitivity throughout the state's area of analysis. Results, Observations, Conclusions The high-level sensitivity mapping analysis identified seasonal shifts in regions of relatively higher or lower sensitivity although certain regions showed consistent environmental sensitivity, such as the continental shelf slope and Hudson Canyon. Since the sensitivity weighting is a high-level analysis, it can be adapted to other types of projects, such as marine hydrokinetic turbines and wave generators. Novel/Additive Information This paper will discuss how changes in anticipated development activities and geographic shifts to other regions could affect the presence of stressors on marine resources and subsequent risk weighting assignments. It will also discuss how to add or remove other biological resources from the analysis and how to incorporate certain human resource data while presenting the potential outcomes of these changes. Due to the granularity of the input data, this analysis is not appropriate for fine scale site selection. It is also important to note that areas of higher sensitivity do not preclude development, but merely indicate higher sensitivity and greater risk for developers. Therefore, discussion will conclude with recommendations for generating the most meaningful results to project development and using these outputs for efficiently siting projects in a cost-effective way.

This paper discusses steel catenary riser (SCR) design challenges subject to complex bi-modal and bi-directional seastates offshore West Africa in ultra-deepwater (2,600m). Metocean data is key to determining the design of SCRs. As offshore exploration continues in remote regions and deeper water depths, it is very important to obtain accurate and comprehensive environmental data for the field. Different locations around the world have distinct offshore environments such as hurricanes, typhoons, swells and squalls with seastates exhibiting a varying range of frequency content. The work in this paper describes effects of multiple seastate modes on the riser’s performance. The risers evaluated are 10 inch production and 18 inch export SCRs connected to a spread moored FPSO. Riser fatigue was particularly challenging given the unique environment consisting of up to four wave modes in a single sea-state. Several sensitivities were performed to improve the fatigue performance of the risers. Finally a feasible riser concept was selected which met all of the project design requirements. Work showcased in this paper will address the challenges of placing steel catenary risers in remote deep water fields with relatively unfamiliar metocean conditions. Several sensitivities are performed with the riser properties, platform motions and environmental data which help to reduce design conservatism and better understand the fatigue response of SCRs connected to a spread moored FPSO.

There is a need to accurately measure the density of drilling mud and well flow rate at downhole locations in the wellbore. Mud density can be determined by measuring the differential pressure between two locations in the well. The most common manner of measuring flow rate is also through the use of a differential pressure sensor. The development of a true differential pressure (DP) sensor for downhole measurement at HP/HT conditions (500 Deg F and at 15,000 psi) was presented at the 2015 OTC (paper #25772-MS). The excellent performance of the initial two DP sensors led to the fabrication and testing of additional DP and absolute pressure cells to verify the design. Since the performance of the DP sensors showed a maximum error at each of the HP/HT extremes of less than 0.02% of the upper-range limit, their use with remote diaphragms to measure the density of the drilling mud in the wellbore was considered a possibility. If successful, this measurement could be integrated into a wired drill string to not only indicate the occurrence of a ‘kick’ during drilling, but also provide unprecedented monitoring and control of unwanted changes in mud density throughout the entire length of the drill string annulus. This would provide significantly improved early warning and control of dangerous high-pressure flow into the wellbore. Additional funding by the RPSEA 10121-4304-01 program allowed for the development of a low-differential pressure range sensor cell with a significant increase in sensitivity to a change in density of the wellbore drilling mud. Sensor performance data was obtained: (i) at ambient temperature and various common mode pressures and (ii) at ambient common mode pressure and various sensor temperatures up to 250°C. The calibration results of the HP/HT downhole DP sensor cell with remote diaphragms indicated adequate ‘kick’ detection sensitivity to enhance drilling safety in high-pressure zones. Additionally, possible methodologies to integrate the wellbore density sensor assembly into the drill string will be discussed.

A new logging-while-drilling (LWD) ultrasonic imaging tool was designed and tested to acquire high-resolution borehole surface images in any type of drilling fluid. The LWD ultrasonic imaging tool uses ultrasonic transducers to acquire pulse-echo signals from the borehole wall and pulser/receiver and acquisition electronics to store the ultrasonic image and caliper data. The transducer, pulser/receiver electronics, and acquisition electronics have been successfully tested to meet functional targets. The design of the transducer incorporated ultrasonic modeling to achieve the desired sensitivity and bandwidth using a composite piezoelectric element, two impedance matching layers, and a high-impedance backing. Two designs variants of the transducer were built and tested. The final design was selected by evaluating the performance of each transducer design before and after environmental testing. The pulser/receiver electronics were designed to deliver wideband excitation with optimal damping to reduce transducer ringdown. The acquisition electronics necessitated a low distortion path, variable gain control, a low noise floor, and consistent channel-to-channel performance. Functional testing on the electronics system verified the analog front-end had low channel-to-channel variation with various input signals and with exposure to 165° C. A Digital Signal Processor (DSP) and a Field Programmable Gate Array (FPGA) managed the high-capacity memory to store the high-resolution ultrasonic image and caliper data with a high spatial sampling rate. The FPGA was verified with Universal Verification Methodology (UVM) and with code coverage and functional coverage metrics. UVM increased design reliability and reduced development time by facilitating the creation of many test vectors. The LWD ultrasonic imaging tool has a sufficient spatial sampling rate to fully sample the borehole in the typical ROP and RPM ranges experienced while drilling. Sample downhole images show the LWD ultrasonic imaging tool compares favorably with wireline ultrasonic and resisitivity images and correlates well to LWD resistivity images in water-based mud.

The objective of this paper was to evaluate the sensitivity of the natural frequency for an offshore wind turbine monopile in normally consolidated marine clay to different p-y models being used in practice: API RP 2GEO (2011) , which is the existing Recommended Practice for offshore structures; Matlock (1970) , which formed the basis for the discretized curves presented in API RP 2GEO (2011) ; and Jeanjean (2009) , which was recently developed to model lateral soil resistance for piles at small displacements to predict fatigue life for offshore well conductors. The following conclusions are drawn: Estimates of the natural frequency based on API RP 2GEO (2011) can be significantly lower than those based on the Matlock (1970) due to the poor resolution of the discretized p-y curves (particularly at small displacements) presented in API RP 2GEO (2011) . The Jeanjean (2009) model predicts a stiffer response and higher natural frequency for typical service conditions compared to the API RP 2GEO (2011) and Matlock (1970) models. The pile length for a typical offshore wind turbine founded on a monopile in a normally consolidated marine clay may be governed by the lateral stiffness and not the axial capacity, and the differences between the p-y models can lead to significant differences in the required pile length.

Offshore exploration is a costly endeavor that entails multi-million dollar expenditures to acquire synthetic aperture radar data, electromagnetic data, 2-D seismic data, as well as 3-D seismic data to evaluate subsurface structures and systems. However, while these technologies lend an understanding to the geologic structure of subsea systems, these do not address the critical question of the presence of a petroleum system (i.e. charge). This case study was conducted by Anadarko Petroleum Corporation in their Marco Polo field in the Gulf of Mexico. The project focused on improving the mapping of hydrocarbons from petroleum systems by augmenting seismic with additional technologies such as detailed multibeam bathymetry, side scan sonar, and acoustic backscatter to acquire high-resolution sea floor characterization and ultra-sensitive hydrocarbon detection to provide hydrocarbon detection with a thousand times greater sensitivity than traditional methods. The high resolution geophysical data significantly improved the ability to locate macroseep sites. Additionally, the ultra-sensitive hydrocarbon system was able to identify hydrocarbons from both macroseepage and microseepage. Thus, hydrocarbons were detected in one hundred percent of the core samples, instead of 10% as found with traditional methods. While the Marco Polo site focused on macroseepage acquisition the Red Sea case study focused on microseepage acquisition. The Red Sea area that was overlain by 8,000 ft of evaporitic salt and anhydrite sequences that also contained inter-bedded shale sequences. The field was a fractured sub-salt rift basin producing from the Miocene Kareem and Rudeis formations. The client had drilled two producing wells, but had also drilled three dry wells. The thick salt sequence made seismic data difficult to interpret and the extensive faulting added additional risk to the exploration efforts. Given the complex geologic system and the difficulties associated with the seismic imaging, ultra-sensitive hydrocarbon mapping was employed to add understanding to the geologic structure and add clarity to the boundaries of the hydrocarbon accumulations. Liquid hydrocarbons were detected through the 8,000 ft salt sequence and then mapped across the field indicating areas of high probability of oil locations and areas of low probability. The probability map correctly predicted the previously drilled producing and dry wells. The hydrocarbon survey results also identified two three-way closures in the field as well as a potential fault not identified by seismic data. Subsequent to the study a well was drilled based on the survey results and produced 800 bopd, lending credence to the hydrocarbon probability maps generated by the survey. The result was the use of new technologies to derisk offshore exploration efforts by more effectively determining the presence of an offshore petroleum system through salt sequences. Additionally, it mapped reservoir boundaries and defined reservoir sweet spots with better pressure and porosity thus enhancing improved production.

Airborne imaging spectroscopy has evolved dramatically since the 1980s as a robust remote sensing technique used to generate 2-dimensional maps of surface properties over large spatial areas. Traditional applications for passive airborne imaging spectroscopy include interrogation of surface composition, such as mapping of vegetation diversity and surface geological composition. Two recent applications are particularly relevant to the needs of both the oil and gas as well as government sectors: quantification of surficial hydrocarbon thickness in aquatic environments and mapping atmospheric greenhouse gas components. These techniques provide valuable capabilities for petroleum seepage in addition to detection and quantification of fugitive emissions. New empirical data that provides insight into the source strength of anthropogenic methane will be reviewed, with particular emphasis on the evolving constraints enabled by new methane remote sensing techniques. Contemporary studies attribute high-strength point sources as significantly contributing to the national methane inventory and underscore the need for high performance remote sensing technologies that provide quantitative leak detection. Imaging sensors that map spatial distributions of methane anomalies provide effective techniques to detect, localize, and quantify fugitive leaks. Airborne remote sensing instruments provide the unique combination of high spatial resolution (< 1 m) and large coverage required to directly attribute methane emissions to individual emission sources. This capability cannot currently be achieved using spaceborne sensors. In this study, results from recent NASA remote sensing field experiments focused on point-source leak detection, will be highlighted. This includes existing quantitative capabilities for oil and methane using state-of-the-art airborne remote sensing instruments. While these capabilities are of interest to NASA for assessment of environmental impact and global climate change, industry similarly seeks to detect and localize leaks of both oil and methane across operating fields. In some cases, higher sensitivities desired for upstream and downstream applications can only be provided by new airborne remote sensing instruments tailored specifically for a given application. There exists a unique opportunity for alignment of efforts between commercial and government sectors to advance the next generation of instruments to provide more sensitive leak detection capabilities, including those for quantitative source strength determination.

The increasing global importance of subsea production drives the need for better accuracy in subsea measurements to allow precise reservoir management while ensuring accurate royalty assessment and production allocation. The work described here resulted from the previous RPSEA Project 1301, which showed that flow measurement errors of 10 to 20 percent were possible when meters were subject to scale or erosion. The objective of this work under RPSEA Project 4304 is to identify ways of detecting fouling in multiphase and wet gas meters, so that corrective measures can be taken before large errors occur. The effort consisted of two major parts: An examination of the state of the art in sensor and meter technology was conducted for the purposes of detecting and/or quantifying meter fouling. A number of ideas were considered. Measurement of the wall thickness of the meter, where an increase would indicate a scale deposition and a decrease would indicate erosion. Several methods were considered. Although sand monitors can indicate the presence of sand and possibly give an indication of sand quantity, they cannot detect erosion, but can warn of the possibility. Several sand monitors were examined. The Venturi meter is the most common component in multiphase meters. An additional pressure measurement in the meter was investigated to detect fouling. The possibility of combining a physical meter and a virtual meter was evaluated to detect fouling. Since most multiphase meters have an abundance of diagnostics, the possibility of their being used to detect fouling was considered. An evaluation of these and other technologies was performed to ultimately select the three most promising methods from the technology review. The criteria for choosing the most promising methods are discussed. The chosen methods were: Use of an additional pressure measurement in a Venturi meter. Use of multiphase flow meter diagnostics. Use of virtual metering and data reconciliation. The results of these developments show promise, can be used in parallel and are discussed in the paper.

Abstract We investigate by means of numerical simulation the coupled flow and geomechanical system behavior during gas production from an oceanic hydrate accumulation at the site of a planned field test at the Ulleung basin in the Korean East Sea. We study the system response at two time scales: a short period (14 days) that corresponds to the duration of the planned field test, and a prolonged production period that continues to the point of hydrate exhaustion and/or reservoir abandonment. The data describing the geologic model and the system properties were obtained from earlier geophysical studies and the analysis of cores obtained from experimental wells at several locations in the Ulleung Basin. Gas hydrate accumulations at this site typically occur in deep water (2157 m) but close to the ocean floor (with their tops 140 mbsf), and are usually characterized by alternating mud (nearly hydrate-free) and sand (hydrate-rich) layers. The layered stratigraphy and the presence of mud layers preclude the use of horizontal wells and necessitate vertical wells. The analysis of the short-term production tests focuses on the expected gas production rate and the possibility of subsidence during the limited time of the planned test. The long-term study aims to address the issue of feasibility of long-term production from the hydrates at the test site in terms of production rates and the geomechanical stability of the well assembly and of the reservoir. We investigate several well operation regimes. We evaluate the sensitivity of the system to various flow, thermal, and geomechanical properties, and we account for the interdependence of flow and geomechanical properties. We estimate possible subsidence under production and we determine the conditions that have the potential to lead to wellbore and formation failure, thus defining the envelope of well operations and production conditions that maximize safe gas production.

Abstract As part of the Ormen Lange Northern Field Development, 36 large diameter steel cylinders were used as counter-acts to ensure pipeline stability during pipe-lay along route curves. The Ormen Lange field is situated 120 km off the mid-Norwegian coast of the Norwegian continental shelf at the base of the Storegga landslide. Due to the Storegga landslide, the soil conditions vary significantly with a stratigraphy characterized by very soft Holocene clay overlying very stiff clay till. Locally, the clay till outcrops at seabed level. The water depth is in excess of 800 m and the seabed topography is highly irregular. This makes the development of the Ormen Lange field very challenging. Ormen Lange came on stream in 2007, and the operator is A/S Norske Shell. Ormen Lange is the second biggest offshore gas field and the deepest subsea production facility in Europe. The gas is exported through one of the world's longest pipelines, and the gas-export in peak production equivalents 20% of the UK's gas demand. The chaotic seabed topography and variable stratigraphy presented several unusual geotechnical design challenges. Stability charts were constructed based on a parametric study considering slope gradient, counter-act inclination and penetration of the skirt plate. With use of these design charts, decisions were made offshore to relocate, install additional counter-acts or increase the pre-load the counter-acts with use of a steel clump weight. The counter-acts were designed with an internal lifting mechanism, which allowed for safe installation in the harsh environment. Furthermore, optimization of counter-act locations removed the requirement for a costly subsea rock installation campaign. The methodology proved to be robust and this paper presents lessons learned for design, installation and retrieval of counter-acts in harsh environments on a soft seabed.

Abstract In August 2008, a marine Controlled Source ElectroMagnetic (CSEM) survey was acquired by WesternGeco EM for the previous operator (Encana) of Lady Franklin and Atammik blocks offshore west Greenland. The objective of the project was to rank possible hydrocarbon prospects in the upper Cretaceous section. Therefore, the survey was designed to optimize CSEM responses based on the previous operator's interpretation within a limited budget, resulting in a pseudo-3D survey, sub-optimal to assess actual interpretation updated according to the results of the three exploration wells drilled by Cairn in the block during 2011. Independent 3D inversions of the CSEM data run before the drilling campaign suggest a consistent background resistivity over the different prospects. Drilling results confirmed the resistivity distribution as recovered by 3D CSEM inversions within the data resolution limit. After the drilling campaign, a sensitivity study was carried out in order to assess the limit at which the geological problem can be tuned by the electromagnetic data response. This showed that the resistive anomalies visible on some of the prospects in the block cannot be assessed for hydrocarbon saturation on the basis of electromagnetic data alone as they are below the resolution of the method given the non-uniqueness of the results. The present paper highlights how non-seismic data, such as electromagnetic, can provide additional information which, integrated with other geophysical and geological data, can help exploration during the different phases. The pre-drilling analysis of the resistivity distribution as recovered by 3D inversion of the data identified resistive anomalies that were interpreted as hydrocarbon indicators. The drilling results identified the geological meaning of these anomalies, which were further analyzed to include and extrapolate the new post-drilling interpretation in order to evaluate the non-drilled prospects. The sensitivity study was critical to understand the EM data limitations in this geological context before investing in a new project. Introduction Electromagnetic data are widely applied in the oil industry in order to de-risk exploration, reducing the uncertainty related to reservoir saturation (Hesthammer et al., 2012). Many success stories increased the confidence in electromagnetic data as hydrocarbon detectors: in fact, electromagnetic data provide information exclusively regarding the resistivity distribution of the underlying earth. Resistive anomalies may be related to fluid saturation, but they may also be produced by different geological features not necessarily related to fluid saturation: volcanics, carbonates, and evaporites are only some examples of lithologies characterized by high resistivity values. In addition, inversion of electromagnetic data is a non-unique problem and therefore constraining the inversion with the available geological and geophysical information is critical in order to produce a geologically meaningful model and subsequent interpretations. The limited data and frequency range (~ 0.1 to 10 Hz), the diffusive physics of CSEM, and the necessity (usually) of using a smooth stabilizer for inversion result in low resolution.

Abstract The first deep water geotechnical survey in South China Sea has been performed at Liwan 3–1 Field in Pearl River Mouth Bassin. The investigation comprised Piezocone Penetrometer Tests (PCPT), T-bar, insitu vane tests, pore pressure dissipation tests, jumbo piston cores, box cores, along with advanced laboratory testing. The in-situ and laboratory data results obtained have been used together with the geophysical data (AUV data) to provide the soil design parameters used for the design of the deepest PLEM and Manifold foundations (i.e. between 1300 and 1500m WD). The high quality and variety of in-situ and laboratory tests performed enable a sound comparison with other deep water sediments. Most of the soil properties of the Liwan 3–1 clays are in the range of those encountered in the Gulf of Guinea (Colliat et al. 2010). The use of scanning electron microscopy (SEM) revealed highly structured clay what is in accordance with the relatively high sensitivity of about 5 to 9 obtained from T-bar tests after 30 cycles. However some particularities arise in their mechanical behavior. The shear strength anisotropy (i.e. answer under different modes of shearing) is for example not significant. It can also be noted that the increase of shear strength with time or with the rate of shearing (i.e. respectively the thixotropy and rate effects) are less pronounced. Introduction Located about 300 kilometres southeast of Hong Kong, Liwan field is a major offshore gas discovery. The field contains contingent reserves of between 4 trillion and 6 trillion cubic feet of gas based on the Liwan 3-1-1 discovery well drilled in mid-2006 in Block 29/26. An AUV survey took place in 2009-2010 across five pipeline routes and two sites in the Liwan area. Some gravity cores were also taken at that time. An extensive geotechnical site investigation took then place in 2011 to investigate the deep water structure locations (Liwan 3–1 PLEM, manifolds and SDH), shallower locations (LH 29–1 manifold and SDA) and pipeline routes. This survey also included specific geohazard locations aiming at quantify the susceptibility of soil slope instability along the Liwan 3-1 to CEP pipeline route. The Liwan 3–1 field is located on the lower continental slope of the South China Sea (Figure 1a), in water depths comprised between 1300 and 1500m. Seabed gradients in the vicinity of the proposed seabed structures can be significant. The PLEM Location itself is located on a slope of 2.6°, on the east wall of a submarine canyon (Figure 1b). This large submarine canyon runs from north to south, crossing the LW 3–1 area, and is located between the West Manifold Location and the PLEM Location. A detailed engineering geolocical model together with a slope stability assessment and a debris flow model were developped along the canyon but will not be discussed in this paper. The present paper focuses on the deep water sediments encountered at the Liwan 3–1 structure locations. The soil investigation strategy, the soil physical and geotechnical properties are discussed and compared to the experience gained for deep water projects in the Gulf of Guinea and particularly to the state of the art paper presented at the ISFOG 2010 Conference in Perth (Colliat et al. 2010). The first Chinese deep water field offers many similitudes to other deepwater fields when looking at the shallow sediment properties. Some particularities were however highlighted by the laboratory test results. The impact of the observed differences on future foundation design and installation are discussed in the present paper.

Abstract Using photons to sense instead of electrons has many advantages, which is why photonic sensing is slowly maturing from a niche into a fully-fledged mature technology. In the O&G business, photonic sensing has gained ground and in some cases is even becoming the standard. Most of these systems are fiber or free space optics based, though. So far, this has been sufficient, but future demands for high information rate at a low cost will make it very difficult for these systems to be competitive on their own. Analogous to the electronics industry, there is also a drive in the fields of photonics for integration of functionality on integrated circuits, the so-called Photonic Integrated Circuits (PIC). In this paper we will present an overview of a novel sensing technology, based on Application Specific Photonic Integrated Circuits (ASPIC) that is suitable and in some cases mature to be deployed for O&G exploration. We will touch on existing and future technologies and also explain the Multi Project Wafer model that is revolutionizing commercial ASPIC development. Introduction Development and exploitation of oil and gas resources must overcome numerous technical challenges that only increase with time. Real-time sensing technologies are critical for optimizing production, increasing ultimate recovery, and improving profitability of these fields. Industry development of real-time sensing technologies began as far back as the 1970's, but the deep water environment presents additional challenges that have resulted in slower uptake of these technologies. The ideal advanced sensing solution will in principle: Facilitate production objectives Simplify completions to improve overall reliability Minimize CAPEX/OPEX Maximize standardization between various well types Facilitate contingency interventions and deployment of selected legacy technologies Apply intervention-less designs, technologies, and procedures to minimize interventions Ensure compatibility with all aspects of sand face completion and interfaces Facilitate corrosion protection (chemically/metallurgically) for H2S and CO2 environment Allow for remedial / post completion operations and work over Ensure contingency service tool compatibility between upper / lower components Provide friendly space out of upper completion/tubing hanger To define which technology or combination of technologies is most appropriate for real-time sensing, one must: Define objectives of the well. Design the well design program to meet the objectives. Deploy the technologies that can provide the data and interpretation that is necessary to meet these objectives.

Abstract This paper presents an overview of wet gas multiphase metering and a new meterdesign to meet future offshore challenges. The design introduces new microwaveelectronics, transmission as well as resonance measurements, a salinitymeasurement system, reduced PVT dependence and a new HP/HT design. Building on the success of wet gas metering in accuracy and reliability, thenew meter increases operators' ability to detect the onset of formation waterproduction and accurately measure flow rates where an increasing amount ofliquid and water is present in the flow (due to gas wells produced over a widerrange of process conditions). The new meter design will have an increased importance for subsea tiebacksapplications. While today's wet gas meters are well suited for subsea tiebacks, current subsea developments require longer horizontal production pipelines, where accurate and sensitive measurement of water is crucial to ensure flowassurance and maintain maximum production capacity of the pipeline. Furthermore, the restrictive and remote nature of subsea fields means that thecosts for subsea interventions and periodic fluid sampling (PVT) are high. Thenew meter is more robust to changes in PVT (fluid composition) and reduces theneed for frequent fluid sampling. The paper will describe the development and technology choices of the newinstrument and how it will meet future subsea field demands. It will explain how the new microwave electronics provides more stable andaccurate measurements; how transmission and resonance measurements extend theoperating range to 80–100% GVF and 0–100% WLR; how two complementarytechnologies - a salinity probe for liquid film measurements at low GVF andFormation Water Detection Function software for droplets measurements at highGVF, provide the first complete salinity measurement system in wet gasapplications. The paper will also show how multivariate analysis and new measurements enablethe meter to compensate automatically for changes in produced fluidcomposition. The paper will be highly significant to oil and gas operators looking toincrease flow assurance and oil & gas production from wet gas fields andmeet the growing offshore challenges of varying process conditions, intervention costs, and subsea tie-backs.

Abstract This paper summarizes leak detection technologies available for use on subseapipelines and the potential role of fiber optic cable (FOC) integritymonitoring systems to improve leak detection capabilities. Available systemswhich monitor offshore pipelines for potential leaks based on internalflowrates and pressures are described along with their limitations for rapidlydetecting small leaks. Alternative pipeline leak detection technologies whichhave been used on some specialized subsea pipeline projects to supplement thecapabilities of these flow-based systems are also described along with theirlimitations. The potential for modern FOC distributed sensing technologies tofill the remaining leak detection capability gaps is then addressed. There is increased interest in improving leak detection system capabilitiesthroughout the pipeline industry. However, the primary application of thispaper is for offshore pipeline projects which may not be adequately covered byconventional flow-based leak detection systems and supplemental monitoring forpotential oil sheens visible on the sea surface. These applications includedeep water pipelines, where potential oil leaks may not reach the surface untilmiles away from the source, and subsea arctic pipelines, which could slowlylose significant oil volumes under the cover of winter sea ice. Other potentialapplications include subsea field developments and pipelines installed inunusually sensitive marine environments. Distributed FOC sensor systems can monitor real-time temperature, acousticnoise/vibration and strain along many miles of pipeline. Changes in any one ofthese monitored parameters can indicate a leak event or other potentialintegrity threats to a pipeline. An overview of FOC systems already installedon offshore pipeline projects and the current testing status of FOC systems forpipeline leak detection are provided. Recommendations for installation andimplementation of the available FOC technologies for subsea pipeline leakdetection are summarized. The limited applications of distributed fiber optic cable (FOC) monitoringsystems on subsea pipelines have not yet been used specifically for leakdetection purposes. The leak detection thresholds defined for FOC systems andthe procedures for design, installation and system repair will facilitate theuse of FOC systems to help ensure leak free pipeline operations. Introduction Internal leak detection systems have historically been used for permanentlyinstalled, long-term leak detection monitoring of subsea pipelines. Thesesystems monitor internal parameters, such as internal pressures and/orflowrates based on internal pressure, temperature, density, and/or flowrateinstrument measurements. Discrepancies between the measured parameters and theoperating trends or calculated operating predictions are used to alert thepipeline operator of a potential leak event. However, the instruments aretypically located only at the ends of a pipeline segment, remote from an actualleak location. This has some effect on sensitivity. Instrument inaccuraciesalso introduce error in the measured parameters. Selecting the alarm settingsof these internal type leak detection systems for very small leaks may resultin an unacceptable number of false alarms (nuisance alarms) due to theirachievable sensitivity and this inherent error. Therefore, alarm settings forthese systems are set-high enough (for large enough leaks) to minimize falsealarms. Leaks that are smaller than the alarm settings (minimum leak detectionthresholds) may continue undetected by these systems. Periodic over-flights orvessel observations from areas with subsea pipelines are then relied upon toobserve oil sheens from potential leaks that fall below a system's minimumdetection threshold. A chronic leak from a deep-water pipeline may manifest as an oil sheen on thewater surface miles away from the leak source due to currents. There may be atime delay in determining the source of the oil sheen, especially if multiplepipelines are located near the observed oil sheen or if there are local subseafield developments.