Bergslien et al. 2005

8/3/2019 Bergslien et al. 2005

1/13

Petroleum Geology Conference series

doi: 10.1144/00600992005; v. 6; p. 99-110Petroleum Geology Conference series

D. BERGSLIEN, G. KYLLINGSTAD, A. SOLBERG, et al.discovery and successful development

key toknowledge, multidisciplinary teams and partner co-operationJotun Field reservoir geology and development strategy: pioneering play

serviceEmail alerting to receive free e-mail alerts when new articles cite this articlehereclick

requestPermission to seek permission to re-use all or part of this articlehereclick

SubscribeConference series or the Lyell Collection

to subscribe to Geological Society, London, Petroleum Geologyhereclick

Notes

Darrell Wayne Harrison on May 4, 2011Downloaded by

2005 Petroleum Geology Conferences Ltd
http://pgc.lyellcollection.org/cgi/alertshttp://pgc.lyellcollection.org/cgi/alertshttp://www.geolsoc.org.uk/gsl/publications/page417.htmlhttp://www.geolsoc.org.uk/gsl/publications/page417.htmlhttp://pgc.lyellcollection.org/site/subscriptions/http://pgc.lyellcollection.org/site/subscriptions/http://pgc.lyellcollection.org/site/subscriptions/http://www.geolsoc.org.uk/gsl/publications/page417.htmlhttp://pgc.lyellcollection.org/cgi/alerts


2/13
http://../core/G4/G4.pdf


3/13

accumulations both in the Mesozoic and Tertiary (Mure 1987;stvedt 1987). The accumulated knowledge from 30 years ofinvolvement in Utsira High exploration and development of the

Sleipner and Balder fields was used in a focused exploration

programme that led to a number of discoveries in the 1990s:Grane, Hanz, Jotun and Ringhorne.

The Elli prospect was first identified as a lead in 1984 anddeveloped into a drillable prospect in the early 1990s based on 2D

seismic structural mapping. Flat spots in thePaleocene section were

mapped as potential direct hydrocarbon indicators (DHIs) andhighlighted the risk for gas versus oil in the area. However, based on

the oil water contact seen on seismic data in the Balder Field, the

prospect was given a fair chance for oil. In addition, a larger

potential trap was defined in a Jurassic horst block beneath thePaleocene Elli closure. In 1994 the Jotun discovery well 25/8-5S

was drilled as a deviated well to penetrate both the Paleocene andJurassic component of the Elli prospect. Oil was discovered inPaleocene massive sands, whereas the high risk Jurassic closure

Fig. 1. North Sea structural elements and Paleocene deposition. The Jotun Field is located on the western margin of the Utsira High. Paleocene and

Eocene sands are derived from the East Shetland Platform 50100 km to the west-northwest. Jotun, Balder, Grane and Sleipner East are all located near

the eastern limit of sand deposition.

D. BERGSLIEN ET AL.100


4/13

proved to be dry. 3D seismicdata were acquired coincident with thedrilling of25/8-5S. Detailed UtsiraHighPaleocene play knowledgeand information learned from the Sleipner and Balder fielddevelopments were utilized to fast track the Jotun Fielddevelopment. Appraisal drilling was planned and executedsuccessfully in parallel with development planning to shorten thetime from discovery to first oil.

Field history and development strategyThe Jotun Field development is an example of a fast trackdevelopment that took only five years from discovery in 1994 to

first oil in October 1999. A total of four wells and three side-trackswere drilled in the exploration and appraisal phase. The Jotun Unitpartners are Esso, Norske Shell on behalf of Enterprise Oil, DetNorske Oljeselskap (DNO) and Petoro. The field is mainly locatedin Block 25/8 (PL 027B) and a smaller part of the field stretcheswestward onto licence PL 103 on Block 25/7 (Fig. 2). The JotunField was discovered in 1994 by well 25/8-5S penetrating an oilcolumn in the Elli structure (Figs 2 and 5). A 3D seismic surveywas acquired while the discovery well was being drilled. In 1995

well 25/7-3 proved oil in Elli South. The same year 25/8-8S, withits side-tracks 8A and 8B, demonstrated that the Tau structurecontains both oil and a gas cap (Fig. 2). The appraisal programme

Fig. 2. Jotun Field development.

Fig. 3. Jotun Field top Heimdal Formation depth structure map.

JOTUN FIELD GEOLOGY AND DEVELOPMENT 101


5/13

was carefully designed based on regional Tertiary play controls,the 3D seismic interpretation and available wells in the area.

The 25/8-8 well with its three deviated penetrations of thereservoir interval was planned to cost-effectively complete theappraisal drilling while, in parallel, planning the field develop-ment. The objectives of the 3 branch 25/8-8 well were to: (1)prove and define the hydrocarbon column at Tau; (2) investigatehydrocarbon type; (3) confirm the regionally mapped eastwardPaleocene sand pinchout; and (4) define depositional facies andinvestigate local variability in the reservoir quality along the sandpinchout. All the objectives with these three penetrations weremet: oil and gas were found; the pinchout was confirmed; and localvariability in reservoir quality and distribution were revealed (Figs2 and 5). A Jotun field-wide oil water contact of 2091mTVDSSwas initially defined through averaging contacts observed inindividual wells. Further data from pilot wells in the initial phase

of development drilling supported the interpretation that there areonly a few metres difference in the oil water contacts betweenand, in part, within the three structures.

The initial development plan comprised 14 wells: 11horizontal oil producers and three water injectors. However,

based on reservoir simulations and early production data, theprogramme was altered to include two more producers andonly one injector was drilled in the initial phase. Of the initial14 wells, 12 are completed as horizontal producers, and one asa vertical water injector. The B-12 well in northern Tau, drilledto test the resolution of seismic attributes, was completed as awater disposal well because it failed to find sufficient reservoirfor completion in the oil zone. During the 2002/2003 infilldrilling campaign another five wells were drilled. All five wellswere drilled with designated pilots, to optimize location of thehorizontal producer. Two producers, B-23A and B-21A, weredrilled prior to the time-lapse seismic data becoming available.The B-23 pilot found that the oil water contact had movedand was now several metres shallower than predicted by

simulation. The well demonstrated lateral change of faciesfrom thick massive into thinner sands interbedded with shaleon the eastern flanks of Elli. In the B-21 pilot the oil water

Fig. 4. Generalized stratigraphical column, composite log and seismic horizons.

Fig. 5. Jotun Field structural/stratigraphical well-log cross-section.



6/13

contact was close to prediction but the net reservoir sand

was lower than expected. The B-21A producer was notcompleted due to insufficient net sand. All three wells drilled

subsequen t t o the time-lapse seismic interpretation have met

prognosis and been completed successfully. One example of

this is illustrated by the positioning of the 25/8-B21C wellon the northeastern side of Elli (Figs 2, 3, 7 and 8). In the

pilot (25/8-B21B) the position of current oil water contact

mapped by time-lapse seismic data was correctly predicted

within 1 m and the horizontal producer was deviated laterally

to maximize the distance to the mapped waterfront (Fig. 8).

The depositional facies in the B21C area was predicted

successfully based on well data tied to seismic attributes tobe channel margin to off axis, fairly thin, interbedded

turbiditic sand and shale with net:gross in the range 0.5 0.6.

The producer was placed along the top surface of the

uppermost sand and the well has performed as predicted andinitially raised oil production from about 40 000 to 60 000BOPD. The B-29 pilot well, drilled into a fairly small low

relief structure between the three main structures, found oildown to the level of the original oil water contact as predicted

from simulation and time-lapse seismic data. The westernmost

well, B-28, required two pilots to constrain the well path of a

horizontal producer with only 7 8 m stand-off from the moved

oil water contact.The horizontal producers are completed with open-hole

screens and a typical completion length is 800 1000 m.Initially, the wells were produced at rates of around 20 000

BOPD. Water coning started within the first year and water cut

steadily increased towards 70 90% by 2002. The latter issomewhat earlier than anticipated pre-start-up of the field and

ascribed mainly to be a result of production at higher rates than

originally planned. Consequently, infill drilling commenced

earlier than originally planned. Seven of the wells have been

production logged in order to establish distribution of fluid flowinto the wells and evaluate well-intervention opportunities.Coiled tubing clean-up was performed in two of the producers.Unfortunately, no water shut-in opportunities have beenidentified and currently some wells are choked back and

periodically shut in due to the high water cut. The use of time-

lapse seismic data, combined with production logging, provedcritical in defining drilling opportunities during the second

drilling phase.

Geological model

Trap and structural definition

The Jotun Field comprises three structures connected through acommon saddle area (Fig. 3). The oil column is fairly thin: 45 m atElli, 33 m at Tau and only about 15 m at Elli South. Elli and ElliSouth both display four-way structural closure. The eastern Taustructure is a combination structural and stratigraphical trap.The Tau accumulation is limited to the east and southeast bythe pinchout of the fan system and westward by structural dip.A complicating factor for Jotun is that Tau has a gas cap not seen atElli, even though the crest at Elli is above the gas oil contactobserved at Tau. This may indicate lack of effective communi-cation between the two structures, but it can also be explained interms of hydrocarbon migration. The migration path to the struc-tures from the Jurassic source may be through an area where theChalk is eroded south of Tau. The Tau structure will, in this case,befilled first and spill to the western structures. In this scenario Tau isunderfilled with respect to gas and, consequently, the gas nevermigrated to the Elli structure. The gas oil contact in Tauis at 2057 mTVDSS. Evidence for reservoir compartmentalizationis the variation in the oil water contact between and within theJotun Field structures. The oil water contact level only varies by afew metres around 2090mTVDSS, except in northeastern Tau,which is about 10 m shallower (Fig. 2). The definition is, however,not straightforward, as contact definition in part is conflicting,based on evidence from pressure and log data. Uncertainties asso-

ciated with the depth measurements and error cone around the truevertical depth correlations also come into play. A number ofsmallfaults exist throughout the field, with increased density along theflanks (Fig. 3). Some of these are compactional slump faults, butdetached faults triggered by reactivation ofthe Jurassicfaults beloware also present. Clear evidence ofsegmentation is seen in Tau, witha deeper contact in the south (2094.4 mTVDSS defined by well25/8-8B) and the shallower contact(s) in the northern 25/8-B12 area(OWC 2088 mTVDSS in B12A and WUT 2076mTVDSS in theB12 toe pilot). Within the Elli main structure there is also someevidence ofsegmentation. The western exploration wells (25/8-6 &6T2) demonstrate a contact at 2089.8 mTVDSS, whereas pressuremeasurements from the B2 and 5S wells in the east indicate ashallower contact at 2086 mTVDSS.

Top reservoir is mapped directly by the Top Heimdalmarker. This seismic event is tied and correlates with well data.The Base Upper Heimdal is mapped with good confidence

Fig. 6. Jotun Field arbitrary seismic section.



7/13

throughout the field and an intra Upper Heimdal marker canalso be identified in some areas (Figs 4 and 6). These internal

reflectors are used to define overall reservoir geometry, whereasfurther breakdown of the reservoir is based on well data (log

and core) and seismic facies mapping. A DHI, corresponding to

the oil water contact, is present and can be mapped across

most of the field, especially at the Elli structure. The gas cap in

the Tau structure causes a phase reversal at the Top Heimdal

marker level (Fig. 6). Multiple derivative seismic cubes have

been generated from the Jotun 3D seismic volume. These have

been used separately and in combination for attribute studies

utilized in the reservoir mapping.

Fig. 8. 3D depth image of Elli 2002 OWC from time-lapse seismic data. Phase II B-21C producer was positioned by time-lapse seismic data and curved

to maximize the distance from the mapped waterfront. The waterfront reaches the crestal Phase I producers (red). Horizontal well penetration is about

1 km in all the Elli producers.

Fig. 7. Well 25/8-B-21C arbitrary seismic line and B-21B log. Time-lapse seismic data predicted that the moved OWC 2002 would be at 22075 m.

The pilot well B-21B found the contact at 22074 m. The log from B-21B also demonstrates the good sweep at Jotun. Seismic facies change from

transparent at the B-1/B-2 wells to high amplitude continuous reflectors at the B-21 wells. This coincides with a change from channel-axis massive sand

to interbedded channel margin facies, documented by B-1/B-2 and B-21B penetrations.



8/13
http://../core/G4/G4.pdf


9/13

further by the difference in pressure drop across a shale unit in25/8-B29 well and seen between the different structures ofthefield

(Fig. 12). The pressure plot shows that the three structures have

responded differently to the nearby production. Based on the

pressure development it seems clear that the Elli structure is best

connected to the strong regional aquifer, whereas Elli South and

Tau have a similar but slightly poorer connection. These

differences correspond to connectivity predictions that can beinferred from the overall depositional packages (Fig. 10). The only

water injector, well 25/8-B10, is placed between Elli and Tau to

support theTau and eastern Elli production. The strong water drive

from the aquifer has proven sufficient to support production in the

remainder of the field.

Although compartmentalization exists as discussed above, logs,

time-lapse seismic data and production data show that the sweep

efficiency is generally good throughout the sands of different

facies. Not surprisingly, the water has risen more quickly through

channel axis sand facies than in the more interbedded parts ofthe field (Fig. 7). Local erosion and fault juxtaposition of sandsalong slump faults may also contribute to the good vertical

Fig. 9. Core sample photos: (a) High density turbidite, vf m grained; (b) high density turbidite with dish structures; (c) low density turbidite vfm

grained; (d) low density turbidite with ripples; (e) muddy debrite, vfm grained with shale clasts; (f) turbiditic shale; (g) hemipelagic shale; (h) sand injectite.

Photographs (b), (e) and (f) are from deviated wells.



10/13

communication experienced in some areas across more laterallycontinuous off axis and hemipelagic shale, as for example

between the Zone 3 massive sand and the thinner and interbeddedZone 4 sand and shale. The interpreted change in depositionalfacies to high density turbidite-dominated facies from sandy

debrite-dominated facies, was an important element in the

evaluation of infill well potential. This understanding, integrated

with the observed compensational stacking patterns, was importantfor the prediction of net sand away from well control. The newinterpretation of facies, linked with seismic facies mapping and the

mapped waterfront (dynamic OWC) from time-lapse seismic data,

reduced the uncertainty in oil sand prediction. The ability to makedetailed reservoir facies predictions influenced the well strategy inthe last three infill locations drilled at Jotun, B21B&C, B29 and

29A, B28 and 28A&B (Figs 2, 3, 7 and 11). Ifthe deposition in the

Elli area had been dominated by sandy debrites it would point

towards a less heterogeneous reservoir architecture. Tested by thedrill bit the predictions held up at all three locations testedafter thechange in depositional facies interpretation.

Work processes and multidisciplinary teams

Appraisal drilling, platform design, development strategy andreservoir management planning is, by and large, performed inparallel in a fast track development. For such a work process tosucceed, good communication between the different parties anddisciplines involved is essential. In the case of the Jotun Fielddevelopment this was successfully achieved by forming task-orientated multidisciplinary teams. The multidisciplinary JotunIntegrated Work Team (JIWT) proved particularly important in theco-operation between the disciplines of geoscience, reservoirengineering, drilling and completion in planning and executing thetwo phases of development drilling. The team also included arepresentative from facilities to ensure an effective communi-cation link for integration between the subsurface work and thefacilities side ofthe field. This was inherited from the Balder Fielddevelopment.

Frequent resource committee meetings ensured communi-cation with, and input from partners. Sharing differences ofopinion on, for example, well strategies, shale distribution and

Fig. 10. Jotun Field channelized depositional pattern.



11/13

reservoir simulation results, was important for describing andunderstanding the field development uncertainties. Collectiveunderstanding of key issues proved especially important in thecritical phase when the 4D seismic data were acquired andinterpreted in parallel with developing and prioritizing drillingopportunities for the second drilling phase. A process involvingresource committee work meetings and inter-company work-shops, besides the formal resource committee meetings, provedparticularly helpful to allow the synergy of the differentcompany experience bases.

3D geological models and reservoir simulation were used inconjunction with well and seismic data to locate and positionoptimally the well trajectories (Bergslien 2002). It has beencommonly experienced in fields with deep-water turbiditic

reservoirs that detailed reservoir geology and production historydiffer considerably from the early simplistic reservoir models(Dromgoole et al. 2000). Modern technology, such as advanced

seismic interpretation techniques from multiple seismic cubes,time-lapse seismic data and 3D visualization, was appliedsuccessfully to mitigate this problem and narrow the uncertaintyranges in the Jotun Field. One of the critical challenges inpredicting the dynamics ofthe field has been bridging the gaps inscale and resolution between the different datasets in constructionofthe 3D geological models. Core was obtained from explorationand appraisal wells and one development pilot. Distancebetween wells is typically several hundreds of metres to over akilometre. Stratigraphical information is somewhat limited as thedevelopment wells are all horizontal. Seismic facies and attributestudies were used to map reservoir facies and architecture ofchannel complex scale (Figs 7, 10 and 11). However, the seismicresolution is only about 20 m vertically, with peak frequency in the

25 35 Hz range. Consequently, this does not allow direct faciesprediction away from well control using seismic attribute analysisat bed-set scale to predict shale geometries. Outcrop analogues

Fig. 11. Elli East random seismic line and structural stratigraphical log cross-section. The original OWC (22086 m) is defined from pressure data in well

25/8-B2 and 25S. The seismically transparent massive sand Channel axis facies in the B2 & 5S area grades laterally into channel margin interbedded

sand and shale with high amplitude continous seismic facies. The depositional facies in the massive sand is interpreted to be mainly high density

turbidites in the B2 and 5S cores.



12/13

have, therefore, been helpful in constructing reservoir architec-tures in 3D geological models. Reservoir engineers and geoscien-tists participated in a field seminar at one ofthe outcrop analogues(Annot sandstone Annot, southeast France) to improve thecollective understanding of facies and communication between thedisciplines. This improved the scale-up process and historymatching of the simulation model t o reduce ultimately theuncertainty in predicting the fields production dynamics.Innovative toe pilots in some of the initial producers and regularpilots for all the wells in the second phase were used to narrow thestratigraphical uncertainties during the development of the JotunField (Bergslien 2002). Time-lapse seismic data, PLT logs and 3D

visualization techniques proved to be very valuable tools in theintegration of geological and dynamic data to position welltrajectories for the second phase producers.

Conclusions

. The experience from more than 30 years of exploration anddevelopment in the Utsira High area was the main componentin the definition ofprospects that led to the discovery of Jotunand several other fields during the 1990s. Detailed knowledgefrom the development of the Sleipner East and Balder fieldswas particularl y valuable for a successful fas t trackdevelopment of the Jotun Field.

. The reservoir architecture reflects the compensational stackingof the turbiditic sand facies. Clear evidence of larger-scaleerosion has not been observed. Massive sands from channelaxis deposits grade laterally into interbedded sand/shalechannel margin deposits. Minor syn-sedimentary slump andcompaction faults exist throughout the field and probablycontribute to good vertical connectivity.

. The field is developed with a total of 16 horizontal producersand has pressure support from a strong regional aquifer and asingle water injector. Evidence of compartmentalization isobserved, but the sweep efficiency from the horizontalproducers seems to be very good.

. Time-lapse seismic data used to define the dynamic oil watercontact surface proved to be more accurate than reservoirmodel simulator predictions and was used to define infill well

locations and trajectories.. The application of multidisciplinary teams proved to be

an efficient way to ensure good communication between

the different disciplines in the development phase. It wasparticularly useful during well planning and operations. Goodcommunication with partners through formal and informalwork processes was an important element to the successfuldevelopment ofthe field. Frequent partner resource committeemeetings and focused technical workshops proved particularlyhelpful in capturing the collective experience base in decisionsdefining the infill drilling phase.

The authors thankthe Jotun Field partners, Norske Shell, handling Jotun on

behalfof Enterprise Oil, Det Norske O ljeselskap (DNO), Petoro and Esso

Norge AS, for permission to publish this paper.

Appendix A: Detailed facies description

. High density turbidite is a term used for thick beds ofmassivesand with internal organizationsuch as grading, lamination andimbrication. Generally, they display a delicate homogeneousgrading from medium and occasionally coarse sand at the baseto finer sand upwards. The high density turbidite beds arecommonly several metres thick, but beds less than a metreto a few metres thick occur and commonly grade up into oneof the shale facies. The thicker beds typically containevidence of amalgamation surfaces, revealing the basicdepositional units to be generally of a few metres thickness.Evidence of erosion by truncation of underlying beds is oftenobserved at the basal bed boundaries. The Bouma sequenceterminology can be used to define further these beds in coredescriptions. Ta and Tb units are observed, whereas the lowerflow regime Tc, Td and Te units are generally absent. Theappearance is generally homogeneous, with occasional water-escape dish and pillar structures (Figs 9a and b). Bouma Te andTd units are occasionally observed in association with the highdensity turbidites as interbeds rather than part of continuousfining-upward sequences. The massive Ta/Tb units often gradeup into finer units, with increasing clay, mica and partlyimbricated flaky clasts of shale and organic debris. Wherepresent, this cap, with finer-grained matrix material, oftendisplays characteristics of mass flow deposits such as lack ofinternal organization, floating coarser grains and soft

sediment slump-like flow structures.. Low density turbidite is used to describe units containing

classical Bouma sequence units. Bouma Tb, Td and Te units are

Fig. 12. Pressure data. The pre-Jotun start-up pressure decline from hydrostatic water gradient is caused by production in nearby fields sharing the

regional Tertiary aquifer. The larger pressure decline in the discovery well 25/8-5S versus 25/8-8 and 25/7-3 appraisal wells shows that Elli

is better connected to the regional aquifer than Elli South and Tau.



13/13

Documents

Bergslien et al. 2005