ExxonMobil (Norway)

Abstract The greater Utsira High area is located within the southern part of quadrants 24 and 25 and the northern part of quadrants 15 and 16 in the Norwegian North Sea. In this part of the Viking Graben the main exploration play is the submarine fan sands of Paleocene and Eocene age. These sands (Balder, Heimdal, and Ty formations) pinch out to the east in blocks 25/8 (Jotun field) and 25/11 (Balder and Grane fields) and along the western margin of the Utsira High to form a combination of stratigraphic and structural traps. Marine sands of Middle and Late Jurassic age, typically present in rotated fault blocks, constitute another important play. Geochemical analyses show that the Upper Jurassic Draupne Formation has a good potential for oil generation along the entire western margin and northern nose of the Utsira High. Both upper and lower Draupne source intervals along the western graben margin, however, contain more terrigenous kerogen than in the eastern part of the graben. Such change in organic facies within the Draupne source interval naturally results in a higher proportion of gas generation and the possibility for generating a more waxy crude than typically encountered in the Viking Graben. Detection and characterization of oil and gas shows within the Tertiary section permit mapping of migration entry points from the Jurassic source rocks and help delineate secondary and tertiary migration pathways within the Paleocene-Eocene play.

Abstract The South Viking Graben of the North Sea is a prolific oil and gas province that has recoverable reserves of approximately 176 x 109 Sm3 (standard cubic meters) (6.2 tcf) gas, 58 x 106 t (412 million BOE) natural gas liquids, and 12.5 x 106 Sm3 (78 million bbl) of black oil contained in the main fields Sleipner Vest, Sleipner Øst, and Volve. These fields are located primarily within Block 15/9 in the Norwegian sector and extend into neighboring Blocks 15/6 and 16/7. The principal source of black, nonvolatile oil is the Late Jurassic Draupne Formation, which has a predominance of marine algal organic matter. The lower section of the Draupne Formation together with the Heather Formation are organically leaner and contain a mixture of marine algal and terrigenous organic matter, resulting in a potential to generate both oil and gas. The Middle Jurassic Hugin and Sleipner formations contain humic coals and coaly shales with potential to generate gas and some light liquids. These coals contain, on average, 80-90% vitrinitic woody material with occasional enrichment of resinite. High resinite concentrations can lead to an overprediction of oil potential, as they contribute significantly to the hydrogen index (HI) but generate primarily low molecular weight aromatic compounds. All source rock facies types have reached maturities sufficient to generate oil and gas. Basin modeling suggests that onset of oil and gas generation started during the latest Cretaceous-early Paleocene. These source rocks have continued to yield oil and gas to the present day in many parts of the catchment area for the Sleipner fields. Detailed geochemical analyses identified five main oil and condensate families. Family A comprises condensates and oil located in the northernmost part of Sleipner Vest and Dagny, generated from a marine, clastic source with a predominance of type II algal organic matter. Family B is condensates in the middle to southern part of Sleipner Vest, generated from a source, or a contribution from several source facies, with mixed terrigenous higher plant organic matter and marine algal material. Family C consists of condensates reservoired in the Jurassic of Sleipner Øst (except well 15/9-A15), generated from a mixed algal/terrigenous source but with a higher contribution of hydrocarbons from a marine algal source as compared with the Sleipner Vest family B. Family D comprises condensates in the Jurassic-Triassic of Loke and Gungne, in well 15/9-A15 from the crest of the Sleipner Øst structure, as well as condensates within the Paleocene sands of Sleipner Øst. These condensates have a mixed terrigenous higher plant and marine algal signature and are derived from pre-upper Draupne Formation sources. Family E is the black oil present in the Jurassic Volve field, derived from a marine, calcareous shale with type II to II-S organic matter. The source rock for this oil is unique in the greater Sleipner area and is likely located in the isolated subgraben between the northern parts of Sleipner Vest and Sleipner Øst. The hydrocarbon gases are broadly similar and are interpreted to have been generated from coals and coaly shales of the Sleipner and Hugin formations, as well as those parts of the pre-upper Draupne section that have a predominance of terrigenous higher plant organic matter.

This paper briefly summarizes the ERMS project and presents the developed model by showing results from environmental fates and risk calculations of a discharge from offshore drilling operations. The developed model calculates environmental risks for the water column and sediments resulting from exposure to toxic stressors (e.g., chemicals) and nontoxic stressors (e.g., suspended particles, sediment burial). The approach is based on existing risk assessment techniques described in the European Union technical guidance document on risk assessment and species sensitivity distributions. The model calculates an environmental impact factor, which characterizes the overall potential impact on the marine environment in terms of potentially impacted water volume and sediment area. The ERMS project started in 2003 and was finalized in 2007. In total, 28 scientific reports and 9 scientific papers have been delivered from the ERMS project (http://www.sintef.no/erms).

The Balder and Jotun fields are located on the western flank of the Utsira High, close to the eastern pinch-out of a Tertiary submarine fan system. Although similar in many aspects, the fields display important depositional, structural and stratigraphic differences which influence the choice of development strategy. The subsurface development strategy for the fields has been designed to optimize oil capture and minimize risk based on the interpreted reservoir geology. Therefore, differences between the exploration histories and reservoir geology are reflected in the development strategy of the two fields. Both fields comprise Tertiary reservoir sands shed from the East Shetland Platform and transported across the Viking Graben area onto the Utsira High by sandy debris flows and turbidites. These distal gravity flow deposits display both thin-bedded sands and thicker more massive sandstones (>100 m). In the Balder Field, an intricate interaction between deposition and soft sediment deformation processes generated a complex network of reservoir compartments with common fluid contacts. In the Jotun Field, the oil–water contact is also common between all three structures, but a gas cap is restricted to one of the structures.

Abstract During the Messinian salinity crisis (5.96–5.33 Ma), the Mediterranean Sea was disconnected from the Atlantic Ocean. As a consequence, a dramatic sea-level fall occurred during part of the crisis and deep erosion has been observed on the Mediterranean margins as well as on the continent. Here, we demonstrate that the erosion and the large sea-level fall generated a significant uplift along the Nile River delta valley, due to isostatic rebound. Based on a quantitative analysis, our results suggest that the uplift of the Egyptian margin and of the Nile valley flanks may have triggered an enclosed environment during the Messinian salinity crisis (MSC). We estimated a mean rate of regressive erosion of −2.5 m/y along the River Nile during the MSC and of 1.25 and 0.4 m/y for the smaller rivers. The water discharge of the River Nile necessary to trigger this erosion rate was at least 5 to 25 times superior than the water discharge of the smaller one’s.

Abstract A review is given of the development of the understanding of the structure and stratigraphy of a classic petroleum province through 35 years of NW European Petroleum Geology Conferences, using new examples to illustrate the interplay between tectonics and sedimentation in the development of some of the major hydrocarbon plays. Cimmerian tectonics is discussed, with regard to the evidence for regional-scale truncation beneath the Mid Cimmerian unconformity, and the stratal motifs characteristic of rifting associated with the Early and Late Cimmerian events. New data revealing the structural geometries associated with polyphase rifting in the East Shetland Basin are presented. The seismic and sequence stratigraphy of Jurassic and Cenozoic sequences are reviewed and new data presented, with a discussion of generic play controls in North Sea Jurassic deepwater reservoirs. The development of integrated hydrocarbon system studies is reviewed, and the remaining challenges to predictive capabilities discussed. The impact of advances in geoscience and technology on North Sea creaming curves is discussed.

Abstract At Ringhorne field, in the North Sea, judicious well placement and high quality 3D seismic data allow good control over stratigraphic and structural frameworks. In particular, two near-horizontal producing wells about 150 m apart on both sides of a critical normal fault are key for deciphering the fault effects on flow. These elements make this field ideal for using production data to constrain a range of process-based fault permeability predictions in a siliciclastic reservoir. A high resolution (50 m×50 m×1.8 m) faulted geological model, constructed in Petrel™, was used as input to process-based fault permeability predictions. Subsequent multiphase simulation and testing identified critical stratigraphic connections across shale layers and structural connections along a faulted relay around an isolated fault block. The simulations were used systematically as a probe to investigate both these and other controls on production and determine the likely range for permeability of fault zone materials, which are inferred to include deformed shales, sands, and minor cements. This study leverages the most pertinent observations and best constrained interpretations in the field to attempt to extract accurate, quantitative information on fault properties. A range of predicted fault permeability cases, linked to particular fault movement timing scenarios, were tested. The middle case, from a fault timing perspective, was determined to provide the best overall flow simulation match to all actual production information, providing valuable feedback for our process-based fault property prediction approach. Establishing the link between predicted and actual flow, and pressure history in response to critical reservoir plumbing elements, is paramount for evaluating and improving fault permeability predictions.

Summary The development of modeling methods to characterize the relative vibration tendency of alternative bottomhole assemblies (BHAs) has enabled deliberate tool redesign to reduce vibrations. To achieve the greatest benefit, tool redesign is most effective if applied early in the tool-design cycle in which important configuration parameters are most easily adjusted. This paper outlines several design issues to resolve so that future generations of tools have inherently lower vibration levels. The use of multiple special-purpose tools [such as logging tools, rotary-steerable assemblies, and ream-while-drilling (RWD) tools] generates significant constraints on BHA-configuration options. A redesign methodology to achieve lower vibration indices can be used to investigate modified components, dimensions, and configurations to select the best BHA configuration for specific drilling-operating conditions. Case studies are used to investigate BHA designs with flex stabilizers above rotary-steerable tools. The flex stabilizer is composed of a stabilizer with a smaller-diameter connecting flex sub to facilitate rotary-steerable directional objectives. It is typically wired for tool signals and is frequently run by vendors. In one case study, the spacing below a reamer is evaluated, and drilling data are compared with other assemblies in the same formation. In this example, the spacer provides an increase in the distance between contact points, to allow both the stabilizer and the reamer to seek the centerline with less interference. Another case study evaluates changing contact locations in the BHA by swapping the order of logging tools, resulting in different borehole-contact positions. Finally, a theoretical modeling study illustrates how changing BHA components and dimensions affects the vibration indices. The operator has field experience with BHA redesign that has directly led to significant improvement in drilling performance. The benefits include a higher rate of penetration (ROP), a longer time on the bottom, less wear of drilling-tool components, and a reduced frequency of trips.

Abstract This paper presents field results from scale squeeze treatments carried out on platform wells from two high temperature (143C to 150C) fields in the Norwegian sector of the North Sea. Scale control and the resulting squeeze treatments to production wells were highlighted as one of the most expensive items in the production chemical budget. The development of a cost-effective squeeze policy was critical to reduce the operating cost of these assets as the produced water cut rose. Computer simulation software was utilised to allow economic and practical evaluation to be carried out prior to deployment of inhibitor treatments in the field. The use of this software allowed optimization of the squeeze treatments in terms of volume of water treated, cost of chemical and duration of injection. The associated costs such as deffered oil/artificial lift were all be taken into account based on the computer simulation results. This paper will outline the practical difficulties encountered when selecting and deploying scale inhibitors in this type of asset and how some of these practical problems can be overcome. Field data from the scale squeeze treatments will be presented and compared to the computer simulation predicted lifetimes. Possible cost savings will be presented by using software as part of an integrated total cost scale management (TCSM) solution where cost of scale control/removal is critical to the economic feasibility of the assets as they mature.

Time-lapse (4D) seismic data from Ringhorne Field in the North Sea are used to monitor water movement in both Paleocene- and Jurassic-age reservoir sands, improve existing geologic and simulation models, and enable more cost-effective field operations. The structural complexity of the reservoirs, their proximity to the high-impedance Cretaceous chalk, and a relatively small 4D response has required a significant effort in seismic acquisition and processing which resulted in highly repeatable surveys (Johnston et al., 2010). In addition to the 4D interpretation, VP/VS derived from simultaneous elastic inversion is diagnostic of sand and provides additional constraints on Ringhorne subsurface models. Connected volumes based on VP/VS correlate to areas of water sweep seen in the 4D data and reduce uncertainty in 4D interpretation. Relative P-wave impedance changes calculated from inversion are consistent with presurvey 4D predictions. The 4D seismic data and inversion help explain water breakthrough timing, improve our understanding of field production history, and have resulted in the identification of additional infill well opportunities.

Abstract The development of methods to characterize the relative vibration tendency of alternative bottomhole assemblies (BHA) has enabled deliberate tool redesign to reduce vibrations. To achieve the greatest benefit, tool redesign is most effective if applied early in the tool design cycle where important configuration parameters are most easily adjusted. This paper outlines several design issues that need to be resolved so the future generations of tools have inherently lower vibration levels. The use of multiple special-purpose tools (such as logging tools, rotary steerable assemblies, and ream-while-drilling tools) generates significant constraints on BHA configuration options. A redesign methodology to achieve lower vibration indices can be used to investigate modified components, dimensions, and configurations to select the best BHA configuration for specific drilling operating conditions. Case studies are used to investigate BHA designs with flex stabilizers above rotary steerable tools. The flex stabilizer comprises a stabilizer with a smaller diameter connecting flex sub to facilitate rotary steerable directional objectives. It is typically wired for tool signals and is frequently run by vendors. In another case study, the spacing below a reamer is evaluated and drilling data is compared to other assemblies in the same formation. In this example, the spacer provides an increase in the distance between contact points to allow both the stabilizer and reamer to seek the centerline with less interference. The fourth case study evaluates changing contact locations in the BHA by swapping the order of logging tools resulting in different borehole contact positions. Finally, a theoretical study illustrates how changing BHA components and dimensions affect the model vibration indices. The operator has field experience with BHA redesign that has directly led to significant improvement in drilling performance. The benefits include higher rate of penetration (ROP), longer time on bottom, less wear of drilling tool components, and reduced frequency of trips.

Abstract Carbon steel pipelines are being used across the world as a cost effective option for wet gas transportation. When these pipelines operate in a stratified flow regime, top-of-line (TOL) corrosion can occur as a result of water condensation at the top of the pipeline in the presence of corrosive species such as acid gases (CO2, H2S) and volatile organic acids. The ability to predict and control TOL corrosion is necessary to ensure long term integrity of these pipelines. This paper will discuss a TOL corrosion model that can be used to assess the risk of TOL corrosion and optimize the use of carbon steel pipelines. The foundation of this TOL corrosion model is the development of a mechanistic understanding of TOL corrosion based on laboratory testing. The model accounts for the relevant chemistry and physics of the TOL corrosion process, including the effects of condensation rate, temperature, partial pressure of acid gases, detailed water chemistry, and flow characteristics. Case studies are presented that demonstrate how the TOL corrosion modeling in conjunction with laboratory testing can be used to evaluate the use of carbon steel pipe, while ensuring the operational integrity of equipment and facilities.

Abstract This paper describes a history match study carried out on a deep water reservoir with roughly a year of production history, consisting of flowing bottom hole pressure (FBHP) and oil rate measurements. This study demonstrates a procedure that can be used to integrate geologic concepts with the history match process to find a range of geologically realistic reservoir descriptions that are all consistent with production history to date for evaluating uncertainty in predictions. The process has three steps: 1) determine, based on geologic and engineering data, what model inputs will be tested in history matching; 2) develop an experimental design(s) and use it(them) to test the impact of those inputs on reservoir performance; and 3) select models for further history match work or prediction of future performance. Two geologic features were selected for study: The degree to which the boundaries between stratigraphic elements seal. Analysis of seismic data identified three levels of stratigraphic elements - channel complex sets, channel complexes, and channel complex remnants. Degree of sealing represents the presence of sub-seismic shale drapes at each level. The degree to which faults are sealed, which depends on the net-to-gross ratio and the throw of each fault. The degree to which a given fault seals is uncertain because it depends on the detailed spatial arrangement of sand and shale in the fault zone, which is not measured directly. The impact of shale drapes was evaluated first. Four shale drape scenarios were chosen to represent a range of behavior including the best match, and seven fault seal scenarios were used to further evaluate the impact of fault seal. Our analysis in this case revealed that the pressure depends on both fault seal and shale drape continuity, with the best matches observed when either faults or stratigraphic boundaries are partially closed and the other geologic feature is open. This allowed selection of seven reservoir descriptions for use in predictions.

Accumulated knowledge from the early pioneering wells and subsequent exploration history led to the discovery of several fields in the Utsira High area during the 1990s. One of these, the Jotun Field, was discovered in 1994. The Jotun Field consists of three structures and is located on the western flank of the Utsira High, close to the eastern pinchout of the Tertiary submarine fan system. The reservoir at Jotun comprises Paleocene Heimdal Formation sands shed from the East Shetland Platform and transported across the Viking Graben area onto the Utsira High by high density gravity flow processes dominated by sandy turbidites. These distal gravity flow deposits display both thin-bedded sands alternating with shales and thicker, more massive sandstones (tens of metres thick). Minor sand injections occur throughout the field but are volumetrically insignificant. The production wells in one of the structures are completed in a slump and injection complex above thick massive reservoir sands. The Jotun Field development strategy was designed to optimize oil capture and minimize risk based on the interpreted reservoir geology. The initial development comprised 14 development wells: 12 horizontal producers, 1 water injector and 1 water disposal well. Production from the Jotun Field started in October 1999 and reached peak production in June 2000, with 140 000 BOPD. After exceeding initial expectations, declining production and rising water cut prompted an infill well programme, time-lapse seismic data acquisition and production logging in 2002. The first two wells were disappointing due to facies transition to interbedded sands and shales on the flanks of the structure and underprediction of oil–water contact movement. The newly available time-lapse seismic data were then integrated with production logging and updated depositional facies studies to evaluate additional drilling opportunities. The discovery, appraisal and development history of the Jotun Field serves as a good example of the key challenges in the Tertiary Utsira High play and the strength of applying multidisciplinary team efforts, partner co-operation and involvement to optimize asset value through tailored drilling and data acquisition programmes.

Time-lapse (4D) seismic data from the Ringhorne field in the North Sea are used to monitor water movement in both Paleocene and Jurassic age reservoir sands, improve existing geologic and simulation models, and enable more cost-effective field operations. The structural complexity of the reservoirs, their proximity to the high-impedance Cretaceous chalk, and a relatively small 4D response required a significant effort in seismic acquisition and processing which resulted in a highly repeatable survey. In addition to the 4D interpretation, Vp/Vs derived from simultaneous elastic inversion is diagnostic of sand and provides additional constraints on Ringhorne subsurface models. Connected volumes based on Vp/Vs correlate to areas of water sweep seen in the 4D data and reduce uncertainty in 4D interpretation. Relative P-wave impedance changes calculated from 4D inversion are consistent with pre-survey predictions. The 4D seismic and inversion results help explain water breakthrough timing, improve our understanding of field production history, and were critical inputs to an updated geologic model used for reservoir simulation. The data have resulted in an increase in the reserves base and the identification of additional infill well opportunities.

PreviousNext You have accessPractical Applications of Time-lapse Seismic DataA. Jotun 4D: Characterization of fluid contact movement from time-lapse seismic and production logging tool dataAuthors: Wences P. GouveiaDavid H. JohnstonArne SolbergMorten LauritzenWences P. GouveiaExxonMobil Exploration Co, Houston, TX, USAExxonMobil Exploration Co, Houston, TX, USAEsso Norge AS, Stavanger, NorwayEsso Norge AS, Stavanger, Norway, David H. JohnstonExxonMobil Exploration Co, Houston, TX, USAExxonMobil Exploration Co, Houston, TX, USAEsso Norge AS, Stavanger, NorwayEsso Norge AS, Stavanger, Norway, Arne SolbergExxonMobil Exploration Co, Houston, TX, USAExxonMobil Exploration Co, Houston, TX, USAEsso Norge AS, Stavanger, NorwayEsso Norge AS, Stavanger, Norway, and Morten LauritzenExxonMobil Exploration Co, Houston, TX, USAExxonMobil Exploration Co, Houston, TX, USAEsso Norge AS, Stavanger, NorwayEsso Norge AS, Stavanger, Norwayhttps://doi.org/10.1190/1.9781560803126.appendixA SectionsAboutPDF/ePub ToolsAdd to favoritesDownload CitationsTrack CitationsPermissions ShareFacebookTwitterLinked InRedditEmail Abstract This paper is reformatted and slightly modified from the original publication in The Leading Edge, 2004, 23, no. 11, 1187–1194. Permalink: https://doi.org/10.1190/1.9781560803126.appendixAFiguresReferencesRelatedDetails Practical Applications of Time-lapse Seismic DataISBN (print):978-1-56080-307-2ISBN (online):978-1-56080-312-6Copyright: 2013 Pages: 289 publication data© 2013 All rights reserved. No part of this publication may be reproduced or distributed in any form or by any means without written permission of the publisherPublisher:Society of Exploration Geophysicists HistoryPublished in print: 01 Jan 2013 CITATION INFORMATION Wences P. Gouveia, David H. Johnston, Arne Solberg, and Morten Lauritzen, (2013), "A. Jotun 4D: Characterization of fluid contact movement from time-lapse seismic and production logging tool data," Distinguished Instructor Series : 195-202. https://doi.org/10.1190/1.9781560803126.appendixA Plain-Language Summary PDF DownloadLoading ...

Abstract A regionally extensive tight-gas accumulation in the Cretaeous age Mesa Verde Group of the Piceance Basin, Colorado, USA has been actively developed for over a decade. Daily production has increased from under 200 MMCFD in the year 2000 to over 1 BCFD currently. However, in some parts of the basin, the commercial development of the asset is challenged by water production. The tight gas reserves occur in a stacked, multi-sand system. It includes over 100 stacked reservoir targets distributed over approximately 5,000ft of formation vertically. Water can be produced from any of these targets geographically. Produced water can cause serious wellbore hydraulic issues and also increase water disposal cost. Therefore, recognizing and avoiding high water production zones before hydraulically fracturing is critical. A workflow for evaluating water-production risk has been developed. The workflow includes 1) deriving reservoir properties (porosity, water saturation, etc.) from open-hole and/or cased-hole logs, 2) calibrating the log measurements with a robust core-based, grain-size-dependent permeability prediction model, and 3) using water saturation in conjunction with permeability to evaluate the likelihood of low capillary or imbibed water for individual sands. This gives a qualitative analysis of water risk on a cross-plot of permeability versus permeability-water-saturation separation (k-Sw screening) with no water production risk (bound water) to high water production risk. The k-Sw screening concept has been verified with logs and production data from over 50 wells in the northern part of the basin. The workflow helped decrease water production thereby improving the economics of the tight gas play.

Balder Field is located offshore Norway, approximately 180 kilometers from Stavanger and just west of the larger Grane Field (Figure 1). Previous OBC evaluations have shown the utility of PS data for imaging some of the Balder area reservoirs (Daures, et al., 1999; Rape et al., 2005; Fjellanger et al., 2006; Jenkinson et al., 2010). Following the 2009 acquisition of a higher fidelity OBC undershoot of the Balder FPSO, we revisited the question of whether PS data might complement the ever improving P-wave images that are being acquired and processed. Although the OBC cable spacing was too wide to be optimal for the resulting 3D PS data image, we show that S-impedance (IS) inverted from the migrated PS volume provides better illumination of Paleocene reservoir sands than either of the PP-AVA P-impedance (IP) or IS products. However, the IP inversion provides the best illumination of the Eocene pay sands sitting just above the Paleocene targets. Log data and core show the differing impedance contrasts can be anticipated. Recent 4D acquisition and improved P-wave processing techniques have probably reduced the potential impact that a larger PS survey might have. Even so, this is one of the best examples where, due to the mixed impedance responses, we would expect a better reservoir characterization result if a 3D PS data set covering the entire asset were available to utilize as a complement to the P-wave products.

Abstract Time-lapse (4D) seismic data from the Ringhorne field in the North Sea are usedto monitor water movement in both Paleo-cene and Jurassic age reservoir sands, improve existing geologic and simulation models, and enable more cost-effectivefield operations. The structural complexity of the reservoirs, their proximityto the high-impedance Cretaceous chalk, and a rela-tively small 4D responserequired a significant effort in seismic acquisition and processing whichresulted in a highly repeat-able survey. In addition to the 4D interpretation, Vp/Vs derived from simultaneous elastic inversion is diagnostic of sand andprovides additional constraints on Ringhorne subsurface models. Connectedvolumes based on Vp/Vs correlate to areas of water sweep seen in the 4D dataand reduce uncertainty in 4D interpretation. Relative P-wave impedance changescalculated from inversion are consistent with pre-survey 4D predictions. The 4Dseismic and inversion results help explain water break-through timing andimprove our understanding of field production history. The data have resultedin an increase in the re-serves base and the identification of additionalinfill well opportunities. Introduction Time-lapse (4D) seismic data provide an opportunity to identify and quantifychanges in reservoir properties that occur dur-ing hydrocarbon production. 4Dseismic has been extensively used to identify areas of bypassed and undrainedoil, improve the existing geologic model, and enable more cost-effective fieldoperations. The Ringhorne field is located in block PL027 (100% ExxonMobil* interest), offshore Norway in the North Sea. The Ring-horne Jurassic and West (Ty) fieldswere discovered in 1997 and 2003, respectively, with first Jurassic/Westproduction oc-curring in 2003. There are two commercial hydrocarbon units inthe Ringhorne field. The Lower Jurassic fluivial and shallow marine sandStatfjord reservoirs form in a structural horst-block trap on a basement high. The deep water Paleocene Ty sands (Ringhorne West) stratigraphically pinch outonto the Ringhorne high (Figure 1). The Ty sand is a single seismic cycle, sub tuning thickness reservoir whichdirectly overlasy the regionally extensive Creta-ceous chalk. The sands areabout 85% net to gross, an average porosity of 30%, with multi-Darcypermeability. They are being depleted by a strong natural water drive. Thelight oil (API 39) has similar properties and is in pressure communication withthe Jurassic oil reservoirs. The Jurassic sands are found in three fault blocks(Figure 1) underlying the chalk and are depleted primarily by waterinjection. A 4D feasibility study conducted prior to acquiring the monitor surveysuggested that impedance changes resulting from wa-ter displacing oil would be7–8%. While above what is normally considered the detectable limit for 4Dapplication, the prox-imity of the reservoirs to the high-impedance chalk addedcomplications. A relatively low amplitude change of 20% (relative to the chalkreflectivity) and potential side-lobe interference from the chalk reflectionrequired that the 4D data be highly repeatable.