The well discussed in this paper has a history of sand production and has exhibit long cyclic slugging behavior with a frequency of several days and reduced average production. The lower completion has a 2000-ft gap between the mule shoe and the packer that is exposed to the larger diameter of 7-in. liner. It is not fully understood whether the slugging is caused by the gap at the lower completion or by sand transportation or both. Dynamic wellbore modelling with sand particle transport is essential to model the abovementioned complex slugging behavior. A stepwise approach was adopted to allow systematic evaluation of this complex slugging phenomenon. Initially, a lumped inflow with no sand transportation was assumed. In the next stage, sand transportation was included with zonal inflow details added. Several sensitivities on sand particle sizes, particle density, zonal productivity index, etc. were carried out, all of which were aimed at reproducing the long cyclic slugging behavior observed in the field. Transient simulations successfully produced the slugging behavior observed in the field. Cyclic slugging was seen to be caused by the flow dynamics generated by particles of small to medium size. Some of the key findings were complete blockage by porous sand stationary bed at the lower completion gap (with subsequent pressure buildup), transition from stationary bed to moving bed, rate-dependent velocity of a slow-moving particle bed (eventually producing to surface), and fresh sand particle production from the reservoir at increased drawdown. Measured data from the sand detector confirmed the production of sand, particularly around the same period as predicted by simulation. Potential slug mitigation solutions were established that should help to achieve higher and stable production. One solution was to achieve higher flow velocity and therefore enable sand transportation as a continuous moving bed (i.e., no blockage), such as reducing the gap size at the lower completion section together with either tubing size reduction or electric submersible pump (ESP) installation. The other solution was to implement an appropriate sand control/sand consolidation method. Sand production is a common flow assurance issue and sometimes can result in unstable flow behavior causing reduced production. This work is the first attempt to implement particle transport modelling in transient multiphase flow simulation to successfully address a slugging issue in a real well. The analysis helped in understanding the mechanism causing the slugging and arriving at a potential mitigation solution. Further, it provides a step-by-step workflow and a template to address such problems.

Technical Category: “Smarter and More Efficient Field Development” The Culzean field is a high pressure, high temperature (HPHT) gas-condensate field located in block 22/25a in the UK sector of the central North Sea. In order to determine the appropriate well count and facility capacity, it is important to accurately assess the individual well mid and long-term productivity. This paper presents analytical and numerical Pressure Transient Analysis for the Culzean field and several other Skagerrak formation HPHT fields and proposes a method to predict mid-term reser-voir performance from log data. Skagerrak reservoir productivity is shown to be typically tenfold lower than what is estimated from core permeability. It is also shown that the core permeability is not a good predictor of mid-term well performance: whereas the permeability distribution for vari-ous Skagerrak fields is very similar, their field performance is not. The Pressure Transient Analysis of the various Skagerrak fields also shows similar trends, and hence this cannot serve as a good predictor either. What is driving mid-term well performance in Skagerrak is the sand-sand connection far away from the wells, which can be estimated from the well test build-up data using a reservoir simulation box model and automatic history matching. It is then shown that the net to gross estimated from the Neutron/density log forms a reasonable predictor of the sand-sand connectivity and hence mid-term well performance.

Tight gas reservoirs represent a significant portion of natural gas reservoirs worldwide. Production at economical rates from tight gas reservoirs in general is very challenging not only due to the very low intrinsic permeability but also as a consequence of several different forms of formation damage that can occur during drilling, completion, stimulation, and production operations. Tight gas reservoirs generally do not produce gas at commercial rates, unless the well is completed using advanced technologies and efficiently stimulated. Well productivity in tight gas reservoirs is largely controlled by formation damage mechanisms such as liquid invasion damage into the low permeability rock matrix that reduces the near wellbore permeability as a result of temporary or permanent trapping of liquid inside the porous media. In many cases of tight gas reservoirs, the key factors that control well productivity and formation damage mechanisms are not well understood, since it is challenging to characterise them in tight formations. This paper presents evaluation of damage mechanisms and characterization of dynamic parameters in tight gas reservoirs and proposes the methods that can provide improved well productivity by minimizing damage to the tight formation. Numerical reservoir simulation is integrated with tight gas field data analysis and core flooding experiments to better understand the effect of different damage mechanisms on well productivity in order to propose the possible remedial strategies that can help achieve viable gas production rates from tight gas reservoirs.

One of the primary recommendations of the Wood Review is for Government and Industry to develop and commit to a new strategy for Maximising Economic Recovery from the United Kingdom Continental Shelf (UKCS). To achieve this recommendation several strategies are proposed. These cover the key UKCS areas which require enhanced development to ensure that the UK maximises the production of its assets. As part of the Technology Strategy, there is push to apply better reservoir management techniques on a cost effective basis. In order to manage a reservoir appropriately, the produced fluids have to be measured accurately. Typically in the UK, this is accomplished through the use of Well Tests and associated equipment – namely test separators supported by single-phase flow measurement technologies. Well test data is critical to operations in the offshore industry and covers a wide variety of applications. The data can be used to allocate produced fluids to particular wells either directly, or through verification of multiphase flowmeters. The data can also be used in the determination of reservoir size and in the positioning of new wells and installations. Another key use of well test data is in the optimisation of well production where well stream parameters can be altered to maximise hydrocarbon production levels. However, recent first-hand audit experience by DECC suggests that well test measurement systems may not be operating at their optimal levels. For instance, primary measurement elements (flowmeters) are often not removed and recalibrated on a routine basis. There is also evidence of flowmeters being exposed to two phase flows resulting in meter degradation. In addition, the interval between the testing of individual wells may extend to several weeks, with the flow rates between tests inferred by interpolation. The risk is therefore that these measurements may result in a measurement bias. This paper will present work completed on behalf of DECC into the current state of the art for well testing in the UKCS. North Sea operators have been questioned and their responses used to calculate typical uncertainties achieved during well testing. The significance of the uncertainty in measurement is highlighted through case studies into the impact on the applications that use well test data. Finally, alternative methods to current well testing practice are discussed with their expected impact on the UK offshore oil & gas industry. The submitted paper provides evidence and recommendations in line with the ethos of the Wood Review, as well as assisting industry to achieve the goals and step-wise improvement in performance, which the Review demands.

This paper describes the first known offshore application of distributed horizontal pulse testing. This technique appraises the deliverability of naturally fractured resource, using only a single penetration and Drill Stem Test (DST) string run. Central to the design is the ability to collect near real-time interference data at a known minimum length from a drawdown interval. The pulse test is distributed in that the signal and observation zones can be swapped on demand from surface, acoustically via sleeve. BP successfully applied this technique to two appraisal wells in their 2014 offshore drilling operations. The dual zone DST pulse testing method is a new approach to the appraisal of naturally fractured reservoirs. It was developed to create a real-time interference dataset outwith the active production interval, i.e. within a passive zone. The formation is produced (and rate data are measured) in two spatial locations and across two known length-scales (by swapping the active and passive zones prior to commingling). Pressure diffusivity can thus be calibrated to data measured in two spatial locations of the same reservoir, and not just one, as per a conventional test design, i.e. enabling a history match of the pressure response of two lateral zones from a pulse signal in one. The horizontal aspect is achieved via high-angle well, drilled sub-parallel to unit bedding ( Figure 1 ). With the double staging approach (upper and lower zones), which has been developed for fractured reservoir appraisal studies, three tests were successfully performed in each appraisal well: two partial penetration tests on discrete short intervals (DST#1a, DST#1b), and one final test on a longer interval that included both of the short intervals (DST#1c). Results of this application have demonstrated that pressure diffusivity can be derived from pressure data that are measured simultaneously in two spatial locations, within and outwith an active production interval. This has proved particularly useful for reducing the degrees of freedom in reservoir model identification. The paper concludes that appraisal of naturally fractured reservoir might be sub-optimal in a DST design where drawdown and observation data are limited to a singular inflow zone only. This is the first known application in the industry where one DST run has successfully yielded six unique appraisal data types, gathered simultaneously at both intra/inter zone and commingled length-scales. These data are conventionally not gathered in a single zone design, i.e. without the ability to selectively inflow and monitor pressure in each discrete lateral zone. Consequently this technique has significantly improved the description of both static and dynamic reservoir properties and reduced development uncertainty, all at a relatively low incremental cost.

The East Brae platform is located in UK Block 16/3a and is operated by Marathon Oil U.K. LLC. The platform has a high pressure (HP) separator 406 psig (28 barg) and a test separator operating as a low pressure (LP) production separator 217 psig (15 barg). There are currently 12 producing gas wells; varying water-gas ratios and low gas rates result in liquid loading being a major flow assurance issue. This paper discusses the use of clamp-on sonar flow meters to minimize losses associated with well testing and the subsequent benefits that were seen with respect to production optimization and well deliquification. Clamp-on sonar flow metering is a non-intrusive technology which measures the flow velocity of the fluid stream. Sonar meters have been deployed every two months to facilitate routine production well testing of all wells to meet allocation and field management requirements. Prior to sonar metering, wells capable of only flowing to the LP separator needed to be shut-in to allow individual well tests. Wells can now be individually sonar well tested without production interruption. Different methods have been adopted to optimize production and combat liquid loading. ‘Swing’ wells use the LP separator to unload liquids and thus improve their subsequent performance in the HP separator. Sonar metering determined the optimal cycle frequency for individual wells, allowing Marathon Oil to keep the LP separator full and maintain maximum rates in the HP separator. Wireless wellhead temperature sensors have been recently installed and have been correlated to sonar measured gas rates in the well bore, providing a real-time trend of liquid loading and well performance. Currently 75% of the well stock is cycled every 4 hours in order to optimize production. This intensive well management has assisted in reducing the production decline of the East Brae field.

Several hundred of Intelligent wells well that combine downhole flow control and monitoring have been installed over the last decade in a wide range of reservoir production scenarios. Numerous publications have reported the successful use of the technology to reduce the number of well interventions, improve sweep efficiency, reduce risk, mitigate production problems, etc. A number of zonal inflow and outflow control methodologies have been proposed to meet a wide range of different well objectives as well as different production or injection conditions. Research still continues in the areas of simple reactive or predefined passive control methods employed by Intelligent wells. This is even more true if it is planned to use proactive control which requires optimisation of a complex multivariable problem. Efficient downhole flow control comes at the cost of adding an additional pressure loss. Such losses can be significant, jeopardizing the well productivity and sometimes carrying the risk of a reduced well performance of the intelligent well when compared to the corresponding conventional well. Installing artificial lift can compensate for this reduced well performance; not only extending the well life, but also adding additional well control flexibility. However, it also poses two extra problems: how to (a) optimally design the artificial lift equipment and (b) avoid interference between the I-well’s control of the zonal inflow and control of the artificial lift. This paper sets out how to(1) Add control flexibility to downhole flow control by artificial lift and (2) Design an electric submersible pump that operates flexibly with down hole, multi-zone inflow control actions. Improved active and passive downhole flow control will be discussed in a rigorous, mathematical manner that allows the conclusion that the combination of artificial lift and downhole flow control provides greater zonal flow control flexibility and reduces the inflow imbalance. Also, two conceptual, electric submersible pump design options, employing (1) a variable wellhead choke and (2) a variable pump operating frequency, are proposed and illustrated. Both of these proposed pump design options could cope with the changing well inflow performance created by downhole flow control devices in situations where the standard pump design workflow was ineffective.

Shell aspires to maximize unattended operations for all upstream E&P "green" and "brown" field assets using the appropriate level of automation. The benefits associated with down manned operations include the following: Reducing staff exposure to travel hazards e.g., driving, sailing and flying Reduce staff exposure to process hazards at the well site and drill floor Increased production due to continuous monitoring and optimization by expert staff CAPEX saving due to elimination of unnecessary facilities such as process simplifications and reduced number of offshore beds OPEX savings due reduced travel and reduced logistics Increased staff productivity due to less time spent travelling Reduced GHG emissions as a consequence of reduced travel and improved process efficiency The underlying premise is that the E&P process should as much as possible be monitored and controlled from a remote monitoring/control room staffed by the most experienced and capable people. For "green field" facilities the basic design concept that we aspire to is unattended as the norm and attended as an exception that has to be clearly justified. For "brown fields" we aspire towards as much as possible reducing attendance, again by monitoring and controlling from remote control centers. This paper will describe the following: Shell's overall remote operations strategy Technologies associated with remote operations, inclusive of production deferment reducing techniques such as data analytics and well/reservoir surveillance Shell guidelines associated with remote operations EP remote operations experiences in a number of different assets in Europe, USA and Africa This paper demonstrates that, for Shell, remote operations is not a remote possibility, but is in the process of becoming a reality across our global upstream operations.

In the 1990s, the wells drilled in the Dan field, located in the Danish sector of the North Sea, were primarily completed with sand fracture treatments separated with packers and pipe, which include sliding sleeves [ Ref 1 ]. The zones were stimulated with normal 20/40 mesh sand with a tail of resin coated sand to keep the sand in the fracture. As water injection was introduced in the Dan field, some water induced fracturing of the chalk reservoir occurred. In the production well DFE-05, a fracture created by a water injector hit the sand fractured zone in the well. Most likely causing damage to the resin coated seal in the zone and loose sand formed erosion holes in the tubing. Maersk Oil investigated the possible options to isolate the damaged zone without restricting the access to the well below the damaged zone. The investigation revealed that one option was to pump an environmental friendly colloidal silica gel into the zone to lock the sand in place. Several onshore tests with frac sand and colloidal silica gel showed that it was possible to displace the uncured gel into a sand/water mixture and get the gel to set up. The resulting leak rate through a gel/sand plug at high differential pressure was low, and the sand was successfully held in place by the gel. During the course of the intervention job the primary target zone of the gel was treated with good results. The neighbouring zone above the treated zone was also found to be producing sand. This zone was therefore treated as well. After the gel had cured, the inflatable bridge plugs used to place the gel correctly were removed and the well cleaned up and production restored from the remaining zones. Six months after the treatment, the well is still producing at a stable rate with only minor traces of sand. The successful job has created valuable learning about the colloidal gel technology and the way it can work in sand fractures.

Pressure relief systems are applied in various installations in the Oil & Gas industry. Especially in upstream applications, the importance of relief systems cannot be underestimated, because failure can lead to release of hydrocarbons to the environment. The upstream production facilities (e.g. subsea production systems, assets on a production platform) are usually protected from overpressurarisation by a HIPPS which shuts in the well when local pressure levels exceed a certain threshold. In addition to this, a pressure relief line is often installed as a last safety barrier when shut-in of the well by means of the HIPPS fails. Especially if gas is produced from a high pressure high temperature reservoir (HPHT), the relief system should be designed such that it can sustain the extreme flow conditions that occur when it is activated. Serious incidents with failing relief lines in the past have raised the attention for the integrity of relief systems and lead to requests for integrity evaluation of newly designed relief systems. Integrity evaluations should address the following dynamic flow phenomena: 1) the generation of shock waves when the relief valve is opened instantly; 2) the occurrence of two-phase flow in the relief line and the corresponding formation of slugs; 3) acoustic fatigue, which is the result of extremely high sound levels in the line generated by the expansion of gas through the relief valve; and 4) possible relief valve instability. This paper addresses how aforementioned phenomena can potentially affect the mechanical integrity of pressure relief systems. A case study of a typical pressure relief system is used to assess the dynamic flow phenomena and how these relate to the mechanical integrity of the relief system. The methods that are discussed in this paper can be directly applied to such mechanical integrity analyses.

Ravenspurn North is a mature gas field forming part of BP’s UKCS portfolio. The field commenced production in 1990 through 42 wells and 3 platforms but by 2006 half of the wells had ceased to flow. Surface pressures suggested limited remaining gas and, with declining production, the field was at risk of abandonment. A surveillance campaign carried out in 2006 suggested a common failure mode for many wells, which postulated that large amounts of proppant had accumulated in the wellbore. Pressures measured downhole above the proppant fill supported a significant increase of the remaining gas potential. A project to rejuvenate this field was initiated in 2007. The key to this project was cleaning out and reinstating non-flowing wells across the field. This would require pushing the boundaries of cleanout techniques and delivering a number of industry firsts, all on normally unmanned installations with complex logistical challenges. Additionally, each individual well intervention would be economically marginal on a standalone basis - the project had to place these interventions into a wider business context before building the case to justify the investment needed to resolve the many challenges presented. This paper details the journey to maximise the potential of the mature Ravenspurn North field. It starts with the acquisition of surveillance in 2006 and covers how the business case was built to justify one of BP’s most complex well intervention programmes in the North Sea (concentric coiled tubing vacuum technology on a small unmanned platform). It culminates in the successful execution of the first phase of wells in 2010. With the first phase of the Ravenspurn North rejuvenation complete, this paper reflects on the lessons learned along the way and identifies the key activities which have contributed to delivering a longer, brighter future for this field.

Routine testing of wells with electric submersible pumps (ESPs) is usually conducted monthly to monitor liquid rates, water cut (WC), and gas/oil ratio (GOR). This monthly testing is the most common form of production and reservoir surveillance and is implemented in even the most mature fields where cost control generally takes precedence over reservoir surveillance. However, this technique has its limitations. The most common limitation is insufficient testing duration to capture a representative sample of reservoir fluids. This testing duration issue is often the case in low-flow rate and deep wells, which require several time-consuming whole or complete liquid holdup periods. Other potential problems include insufficient resolution or repeatability to identify trends in liquid and water-cut rates over short periods of time. To date, the only method for resolving these issues has been to install permanent multiphase meters on each well. Although this method has been implemented in some fields, it is uneconomical for most wells. An analytical method is described for a flow rate calculation that can be implemented in wells produced with ESPs and equipped with downhole gauges and real-time monitoring systems. These downhole gauges and real-time monitoring system provide continuous real-time virtual flow rate measurements and therefore, both liquid and water-cut trends, which deliver the required resolution and repeatability to support both well performance diagnostics and near-wellbore reservoir analysis. This technique, which has the advantage of being valid for both transient and steady-state conditions, provides instantaneous flow rate data when used with real-time data. Case studies presented will illustrate model calibration and its application to back allocation and transient analysis. Examples are provided to show how the data can be used to rapidly identify changes in productivity index and reservoir pressure across the drainage area; thereby, enabling real-time production optimization.

Abstract At the time of project sanction in 1997, Elgin/Franklin was the largest High-Pressure High-Temperature (HP/HT) development in the world. It required innovation across the full range of operator activities, from fluid modeling, through development concept definition, HP/HT drilling and platform design to commercial framework. Eight years after production first began, it is fair to say that Elgin/Franklin has not only achieved the aims of the initial project, it has clearly surpassed them. The increased gas export capacity compared to initial design, the successful development of Glenelg (2006) and West Franklin (2007) satellites using extended reach drilling techniques and the recent drilling of an infill well in highly depleted reservoir are some of the key contributors to the success of Elgin/Franklin. The high level of technical innovation from project conception right through to recent drilling achievements has provided valuable experience, not only for the Total group and Elgin/Franklin partnership, but also for the industry's HP/HT challenges. With hindsight, using this experience, combined with a decade of further progress in technology, some of Elgin/Franklin development features could have been further optimised. This presentation details some of the most significant feedback and provides an insight into the future of Elgin/Franklin as a mature, yet promising asset, which today is at a crossroads for further investments to ensure its continued growth. Introduction The Elgin and Franklin gas condensate fields were discovered respectively in 1991 and 1986 in the Central Graben Area of the North Sea. The reservoirs (shore face sandstones of Late Jurassic age) are 5,500m deep and present abnormally high pressures (1100bar), extreme temperatures (200ºC) and significant levels of CO 2 and H 2 S. Facilities consist of two wellhead platforms, one being normally unattended (Franklin) and the other located over the Elgin field and bridge-linked to an integrated permanently manned Process-Utilities and Quarters platform (PUQ). Glenelg and West Franklin are two HP/HT discoveries made after the initial development of Elgin/Franklin which were put in production in 2006 and 2007 respectively. This paper presents a case history looking back at some of the key decisions taken since the Elgin/Franklin field development was submitted 12 years ago. These decisions are analysed to see what could have been done differently, either from experience and hindsight or because of new technology available today. From Field Development Plan to now Field Development Plan - 1997 The Elgin/Franklin field development plan was approved in 1997. The development was based on 12 wells (7 on Elgin, 5 on Franklin) and included the recovery of two pre-drilled appraisal wells. Provision was included for a second Elgin wellhead platform, also bridge connectable to PUQ to be installed later if warranted. The project included the installation of a normally unmanned wellhead platform on the Franklin field, with Franklin production transferred to Elgin PUQ via a multiphase interfield pipeline system ( Figure 1 ). The total estimated cost for the project was £1.6Bn, which represented a hefty investment, especially in the low hydrocarbon price environment of circa $20/bbl prevailing at the time.

Abstract Advanced well completions (AWC) have shown great benefits not only with respect to production optimization, but also data collection were they provide very useful PLT type information on a zonal basis (ref. 1, 2, 3). However, as many of the wells with advanced completions have matured and more data been acquired over longer production periods, some a better understanding of the production behaviour has been gained. Installing an inner tubing with associated flow control valves in a horizontal liner causes restrictions to the flow, and an increased pressure drop. One the StatoilHydro operated Visund field, one has observed that at certain well conditions (related to combinations of rate, water cut (WC) and gas oil rate (GOR) this pressure drop leads to a noticeable reduced well potential, and thereby a reduced overall robustness of the well design. By increasing the production liner diameter in the reservoir section, one may be able to install advanced completion equipment with bigger dimensions. This allows the benefits of the downhole zonal control to be realised without hindering the well potential. Data from two wells one the Visund field, has been used to demonstrate the benefits related to increasing the diameter of the production liner, and consequently the dimensions of the advanced completion components. A hydraulic well model has been constructed comprising one producer and one gas injector. When the models are matched to actual rates (and well conditions), the effect of varying the flowing diameter (= inner tubing diameter) is studied. The results show that there is an upside with regards to flexibility and well potential with such an optimized completion design. In relation to the model findings, the consequences for the drilling and completion design and processes are outlined. Advanced well completions The term Advanced well completion is a system that includes permanent instrumentation (more than one pressure and temperature gauges) in combination with inflow control devices. In addition further instrumentation may be installed, for example a down hole flowmeter. Such completions give the possibility to control inflow on a zonal basis within the different reservoir layers. See Figure 1for a typical completion design Wells with advanced completion came into general use in the beginning of the 1990's. StatoilHydro installed its first such completion in 1997, and by march 2009 115wells with remote operated Inflow Control Valves (ICV) have been installed in more than twenty StatoilHydro operated fields. Even if an advanced completion leads to increased cost, the well planning process in StatoilHydro has identified great benefits with regards to improved economy with such completions, both on increased recovery, but also on reduced intervention work, as optimal production from different reservoir zones otherwise may only be obtained with sequential production (and several well interventions).

Abstract Real time reservoir monitoring is critical for the effective management of any reservoir. Permanently installed reservoir monitoring instrumentation is generally installed as standard practice in the majority of offshore wells and whilst the reliability of such systems has improved significantly over the last decade, there are still many examples of wells around the world where these systems have failed prematurely. The Mungo Platform, located in the UK Central North Sea, has several wells in which the permanently installed monitoring systems failed early on in the life of the wells. In the absence of any real time reservoir pressure / temperature data, a compromise solution has been to install long term memory gauges in the wells so that reservoir monitoring, all be it using historic data, has been possible. Being relatively compact in size and a Normally Unmanned Installation (NUI), well intervention operations on Mungo are logistically challenging, with limited deck space for rig up and with personnel having to shuttle from the Marnock platform located around 24km away. A newly emergent wireless reservoir monitoring technology that can be retrofitted into existing wells and can transmit data to surface in real time was viewed as an attractive alternative to performing regular well interventions to gather historic data using memory gauges. Whilst the wireless gauge technology has a growing track record in the subsea and onshore well environments, signal attenuation in the offshore platform environment presents particular challenges that had previously prevented the technology from being retrofitted into such wells. A concept was developed for offshore platform wells having failed permanent cabled gauge systems, whereby the cable and gauge infrastructure of the failed permanent gauge system should, under the right conditions, act a conduit for the wireless gauge signal to be transferred to surface. To test the theory, a proof of concept trial was performed in Mungo well W160. A wireless gauge system was retrofitted into the well using standard slickline equipment and real time reservoir pressure and temperature data was successfully transmitted to surface using the failed permanent gauge system as a signal pick-up. This world first successful retrofit application of a new wireless monitoring technology into an offshore platform well, marks a milestone achievement in enabling the restoration of real time reservoir data without having to perform a well workover. This technology breakthrough is of significance in many situations where cabled in-well monitoring systems have failed. Collecting real time data from well W160 provided several benefits; the well production could be optimised on a daily basis, pressure build-up analysis could be performed, a new well target location was determined and the reservoir panel water injection response was optimised. Introduction The BP operated Mungo Field is located at the edge of the Eastern Central Graben in the UK sector of the North Sea, about 240km east of Aberdeen and sits in around 90m of water. First discovered in May 1989 it was developed as part of the Eastern Trough Area Project (ETAP) and saw first production in 1998. (See Figure 1 ) Mungo is a large oilfield with a small natural gas cap. The productive Forties, Lista and Maureen formations, which are Palaeocene sandstones, ring a salt diapir. The field has been developed under combined water and gas injection on a NUI located above the field. The Mungo NUI is tied back to the central processing facility (CPF), which is located over the Marnock field. The CPF handles the fluids produced by Mungo and also serves as the accommodation base for personnel shuttling to the Mungo NUI.

Abstract Offshore well testing operations in the North Sea have, for many years, been confined to the shallow areas of UK and Norwegian continental shelf with water depths ranging from 100 to 1,000ft. Rig selection of these operations has been primarily moored vessels. New discoveries in the Frontier areas have moved the operations into the deep water regions north of Ireland and west of Shetland where water depths range from 2,500 to 10,000ft. The under-explored regions of the Barents and Norwegian Seas also provide extreme weather conditions in addition to a wide range of water depths. The deeper water prospects have moved operators to the use of dynamically positioned vessels. The combination of high frequency and severity weather systems, deep water and the potential of rapid vessel movement create unique challenges for well testing subsea safety systems. Subsea safety systems (or as often termed subsea landing strings) are critical to maintaining well integrity during any period were there is the potential to flow hydrocarbons. They typically consist of a lubricator valve to allow in-well tool deployment, a subsea test tree to provide dual-barrier well containment and a disconnect function, and a retainer valve to secure test string contents in the event of a disconnect or shear situation. To ensure all functional goals are achieved in the conditions found in European Frontier regions, several features of available string types need to be taken into consideration. The key features that are desirable in these challenging operating environments are: Rapid disconnect capability through the use of electro-hydraulic controls Disconnect capability under string tension Umbilical protection system Multiple disconnect methods At-tree and below-tree chemical injection Valves capable of cutting coil tubing These features are not commonly available in landing strings provided for the shallower and more benign conditions found elsewhere in Europe. The technologies required can be developed from the experiences from other deep water regions (such as West Africa and Brazil) and the most extreme North Sea conditions.

Abstract Characterizing reservoir architecture and fluid property distributions at the early exploration and appraisal stage are critical for reservoir assessment, planning and management. Particularly for thinly laminated reservoirs, identification of hydrocarbon-bearing zones and determination of the flow unit sizes have profound impact on long term production predictions. In this paper, a case study is presented that integration of reservoir fluid property distribution with other logs leads to accurate reservoir understanding. In this method, downhole fluid analysis (DFA) is used to identify key production parameters of reservoir fluids in real time and at downhole conditions. DFA results are combined with other logs to develop a view of reservoir architecture especially pinpointing thin pay zones with low resistivity, which could be treated as wet by open-hole logs. Indeed, 19 DFA stations were performed in this particular well and represents a typical number of DFA stations per well in this field (another well in this field had significantly more DFA stations that established a world record). The results of the improved interpretation are confirmed by subsequent well test data. The case study indicates that the methodology of integrating DFA with other logs provides a powerful and cost effective approach for reservoir understanding and assessment at the exploration stage, which is invaluable for optimal reservoir management and development planning. Introduction An accurate description of reservoir architecture and fluid properties at the early stage of exploration and development cycle is critically important for reservoir management. Particularly for thinly laminated reservoirs, volumetric and fluid properties of each pay zone may vary significantly. Additionally, lithology effects and highly saline formation water can cause suppression of resistivity log response, and as a result, hydrocarbon-bearing zones may not be identified with confidence from resistivity and CMR logs. Therefore, in thinly laminated and low resistivity reservoirs, an accurate view of each individual flow unit and its fluid properties is the key for drainage volume estimation, production strategy and prediction, as well as completion and surface facility designs. In this circumstance the only way to know what fluid will flow from each lamination is to flow and analyze the fluid from each lamination. Traditional drill stem tests (DST) and well tests have been used to determine formation permeability, detect compartmentalization and boundaries, as well as obtain representative formation fluid samples. However, in deepwater or other high cost wells, traditional DST's becomes extraordinary expensive and environmentally unfriendly. Furthermore, interpretation of traditional well test on highly laminated reservoir can be complicated due to commingled fluid flow from multi zones, especially when the primary goal is to characterize individual pay zones. Formation tester tools prove to be a reliable way of acquiring formation pressures and fluid samples. Particularly with introduction of the focused sampling technique, high quality representative fluid samples can be obtained with less time compared to conventional sampling probes (Dong et al., 2005; Del Campo et al., 2006; O'Keefe et al., 2006). Additionally, development of downhole fluid analysis (DFA) enables formation tester tools to analyze reservoir fluid properties in real time, at downhole conditions and without the need of acquiring fluid samples. DFA provides the capability of scanning reservoir fluids and unveiling fluid property distributions at an unlimited number of station depths. Additionally, a fluid prediction model has been developed to facilitate using fluid property distributions to better understand reservoir architecture and fluid equilibrium. Furthermore, formation tester tools can conduct Interval Pressure Transient Tests (IPTT), also referred as Vertical Interference Tests (VIT) or mini-DST. The IPTT with formation tester tools is similar to traditional DST's in principle but with a smaller investigation depth at tens of feet; by this means permeabilities of individual layers can be obtained (Elshahawi et al., 2008).

Abstract A periodic measurement of static bottom-hole pressure to monitor the reservoir depletion is an essential reservoir management practice. In an HP/HT offshore environment, the unavailability of qualified permanent down-hole monitoring technologies and the risks and costs of occasional operations make gradient surveys very difficult to acquire on a routine basis. On Elgin-Franklin (HP/HT gas condensate fields, North Sea, UKCS), the typical approach is to use an average fluid density to estimate the static bottom-hole pressure from the well-head shut-in pressure. This estimation is valid as long as there is only one phase present inside the well-bore. As soon as the pressure drops below dew point in the tubing, the vertical phase distribution changes and the bottom-hole pressure can not be accurately estimated using one single average density. Fluid segregation mechanisms involve complex thermo-convective phenomenon, in association to gravity, which are strongly related to the temperature gradient in the well bore. Segregated phase distribution has been observed on some available static pressure gradient surveys, where three gradients were identified. They correspond to three different phases, i.e. gas at the top, condensate in the middle and supercritical gas at the bottom of the well. This phenomenon of having a low density fluid below a higher density fluid was referred to as "gradient reversals" (Bender and Holden, 1984). At that time, it was assumed to be only due to the increasing temperature with increasing depth, but not explicitly related to the thermo-dynamical behaviour of the critical fluid. In this case, we show that the fluid densities numerically estimated from each phase composition, at the corresponding pressure and temperature in the tubing, are comparable to the densities derived from the measured gradients. Based on this, a robust correlation methodology has been developed to derive the static bottom-hole pressure from the well-head shut-in pressure using thermodynamic modeling. Introduction Elgin and Franklin are deep HP/HT gas condensate fields situated in the Central Graben of the North Sea. Main reservoir is Upper-Jurassic Fulmar sand buried at more than 5000 meters depth and containing a rich fluid in supercritical conditions (1100 bars and 190 degC). The fields have been on-stream since 2001. After eight years of production, the reservoir pressure has declined by approximately 700 bars. HP/HT reservoirs have posed new challenges for field developments and new challenges appear as these fields mature. One of these challenges is dropping below dew point which will impact well performance, field production, measurement limitations and future developments. In terms of well performance, the main related issues are condensate loading in the well and consequently cyclic degradation of well performance, and condensate banking near the well-bore inside the reservoir causing production degradation, compositional changes and GOR increase. The change of the fluid composition and the difficulty to sample regularly introduce inaccuracies in surface measurements, well allocations, and eventually in proper evaluation of further development options.

Abstract Reservoir connectivity is a key uncertainty when considering field appraisal and development options. Reducing this uncertainty can provide significant benefits in optimising the field development plan. Through the application of new wireless telemetry technology (Expro CaTS TM ), a fully abandoned subsea appraisal well has been cost effectively converted into a valuable reservoir monitoring asset. Clair Ridge appraisal well 206/8–13Y was drilled in 2006 and located some 8km from the existing Clair production platform. The well was the first step in an appraisal programme designed to confirm the next stage of development of the Clair Field. Reservoir connectivity and the risk of compartmentalisation are key uncertainties for development of the Clair reservoir (ref.1). On completion of testing operations, the well would typically have been permanently abandoned and of no further value for reservoir monitoring purposes. By installing a battery powered, wireless pressure monitoring system in the well at the time of final abandonment, it was possible to monitor for any fluctuations in the reservoir pressure in the Clair Ridge resulting from production / injection events on the Clair platform. This newly emerging wireless telemetry technology transmits data from the reservoir to the seabed using the well casing as the communication path and advantageously, the signal is not attenuated by the presence of cement or bridge plugs in the wellbore. The reservoir pressure and temperature data that is transmitted up the casing, is collected and stored by a CaTS subsea receiver located on the seabed. The stored data can be recovered, on demand, by a supply vessel located overhead using well established through seawater acoustic communications. The use of a wireless gauge enabled a downhole well abandonment to be performed. The traditional method for converting subsea appraisal wells for pressure monitoring has utilised a gauge and cable system (ref.2). This approach requires a relatively complex and costly semisub rig workover for final well abandonment. With the CaTS system, the well can be left fully abandoned downhole to UKOOA category 1 at the end of appraisal drilling. The remaining abandonment liability is just for recovery of the seabed receiver and final severance of the wellhead using a diving support vessel. This paper demonstrates that advances in wireless telemetry technology now enables critical reservoir data to be obtained from suspended/abandoned subsea wells or zones, where previously there was no cost effective means to do so. By monitoring the reservoir pressure variations in the abandoned Clair Ridge appraisal well, clear evidence of reservoir connectivity to the existing Clair platform reservoir area was demonstrated. This world first successful application of new wireless telemetry technology in a UKOOA category 1 subsea abandoned well marks a milestone achievement in advancing technologies that can cost effectively reduce uncertainty in reservoir connectivity at the field appraisal and development stages. Introduction The Clair field was discovered in 1977 and is estimated to have >4 billion bbl overall STOIIP, making it one of the largest discovered hydrocarbon resources on the UKCS. The field is located 75 km west of Shetland in water depths of up to 140 m and extends over an area of approximately 220 km 2 . Composed of fractured sandstones of Devonian age, it is the largest naturally fractured reservoir developed in the UK. Production from Clair began in February 2005 through the Phase 1 platform. This is a waterflood development specifically targeting reserves in the Core, Graben and Horst segments in the southern part of the overall Clair reservoir. The undeveloped field area is expected to hold considerable further reserves, but it is relatively un-appraised. The structurally elevated Ridge segments were identified as potentially the most prospective and a multi-well appraisal programme was developed. This programme also included extension of the original ocean bottom cable (OBC) seismic survey that was shot for development of the Phase 1 area.

Abstract In recent years advances in computing and control technology have enabled real time monitoring, surveillance and control of reservoir, well and process; Within the Exploration and Production (E&P) industry these technologies are increasingly being applied throughout all phases of oil and gas field development and production. Arguably least attention has been given to asset operations, where the rewards are actually harvested. "Smart" technologies can significantly increase value here, provided they are properly focused and implemented, and integrated into the facilities daily operations. The successful implementation of smart applications requires new ways of working and different skill sets of the operators and support engineers. This is a particular challenge in mature assets, where the operational style has become embedded through time. Fieldware Production Universe, "PU" is an application developed within the Royal Dutch Shell Group, ("Shell"). Real time signals from individual wells e.g. tubing head pressure, are processed by numerical "data driven" models to estimate three phase flow from individual wells. Total production from the facility is reconciled to individual wells using these estimates. These flow estimates change the traditional process of periodically routing a well's production to a test separator; individual well flow information is available all the time and tests are performed only when necessary to validate or update PU models. A more advanced version of PU, PU-RTO also allows the use of the models for real time production optimisation. To get from research to a fully implemented and sustainably used product is a lengthy and sometimes arduous task. Across the industry most operators can think of at least one system that has been "rolled out" but not been fully adopted and has "died" before it delivered it's full value. Reasons for failure are many, but often centre around support and delivery of true benefit to end users. This paper discusses Shell's experience with, PU, and it's application for real time production optimisation on the Nelson platform in the UK sector of the North Sea . The paper describes PU, how the applications were implemented, some of the challenges faced during the implementation and the changes that have had to be made, resulting in a PU becoming a sustainable part of the "way we do business". Introduction Shell Exploration & Production in Europe operates a wide range of assets from new greenfield developments through to 30 year old brownfield platforms. Technology continually advances and whilst new development may have the latest technology the business case for large investment on brownfield assets is not always clear cut. One such brownfield facility is the Nelson Platform, constructed in 1994 and entering Shell's portfolio in 2002 following the acquisition of Enterprise Oil. Situated 200 km North East of Aberdeen, Nelson wells produce approximately 6,000 m3 Oil and 450 kSm3 gas per day from 33 platform wells and two sub sea tiebacks, approximately 60% of gas production is used to power the platform. All wells produce from the same reservoir and have water cuts of between 10 and 95% with an average of 80%; the approximate Gas Oil ratio is 78 m3/m3. Production is assisted through gas lifting of all the wells. Platform operations staff operate a 14 day two shift system, many operations staff have worked on the platform from commissioning.