SPE-172858-MS

De-risking a Heavy Oil Development - A Case Study of the Bentley Field,UKCS Block 9/3b

B.H. Brennan, C. Lucas-Clements, S. Kew, and P.F. Dempsey, Xcite Energy Resources plcs

Copyright 2014, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE International Heavy Oil Conference and Exhibition held in Mangaf, Kuwait, 810 December 2014.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contentsof the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflectany position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the writtenconsent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations maynot be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract

The Bentley Field, located on the UK continental shelf in block 9/3b in 110 m of water, containsapproximately 900 MMstb in-place of heavy (10 to 12 oAPI) viscous (1500 cP) crude. The field isfour-way dip closed at uppermost Palaeocene, lowermost Eocene, Dornoch sandstone level, and covers anarea of about 16 Km by 5 Km.

An appraisal programme culminating in the 2012, 9/03b-7, 7Z extended well test (EWT), has addressedthe key technical concerns associated with developing the viscous crude in an offshore environment. Theprogramme demonstrated how sustainable commercial flow-rates can be achieved through the selectionof a suitable completion design, including a downhole electrical submersible pump (ESP), a downholediluent injection strategy, and through keeping within an appropriate operating pressure and temperatureenvelope. It further demonstrated that the movement of water from the underlying aquifer into theproduction bore proceeds in a predictable and manageable way, that produced water and oil can beseparated even though emulsions are created in the ESP, and that water can act as a carrier fluid withinthe export pipeline.

The information from the EWT has been used to define and de-risk the field development design whichis currently estimated to deliver 257 MMstb of 2P Reserves over a 35 year production period. In additionit is estimated that 48 MMstb of 2C Contingent Resources could be commercially extracted beyond theend of the currently planned facilities life. Investigations are underway to accelerate this tail-endproduction, with initial studies indicating that a polymer flood, enhanced oil recovery scheme, could beattractive.

This paper describes the appraisal programme, the lessons learnt and how these have been applied indesigning the field development plan.

IntroductionDevelopment of Heavy OilWith many basins reaching a late stage of maturity and with much of the production to date being fromconventional oil fields, an increasing percentage of the yet-to-be-developed oil can be classified as heavyoil with a gravity of less than 20 oAPI (Jayasekera & Goodyear 1999; Morton et al 2005). Some of thebarriers that have prevented development of heavy oil compared to conventional oil are:

Discounted sales price; Increased per barrel production cost; Lower recovery per well; Requirement for artificial lift.

On a like-for-like basis, a reservoir containing conventional oil will always look more commerciallyattractive than one with heavy oil but the relative lack of development of heavy oil to date means that thereare more opportunities for sizeable developments in the heavy oil arena. Advances in technology, inparticular in the areas of horizontal drilling, multi-lateral technology and artificial lift has helped narrowthe gap between heavy oil and conventional fields from a production perspective. This, coupled with acontinuing high oil price, makes development of heavy oil fields increasingly attractive. Furthermoremany heavy oil fields are located in shallow, relatively well-imaged reservoirs, with relatively lowappraisal costs, thereby generally resulting in relatively low geological uncertainty.

The majority of producing heavy oil comes from onshore settings. Development of heavy oil inoffshore environments presents additional challenges, most notably that higher well productivity isrequired to offset increased unit costs.

The Bentley field provides a good example of a giant, offshore, low geological risk field that has beenundeveloped for nearly forty years due to the challenges outlined above. An appraisal programme carriedout by Xcite Energy Resources plc (Xcite) between 2008 and 2012 has demonstrated how these challengescan be overcome with new technology and favourable oil prices.

The Bentley FieldThe Bentley Field, located on the UK continental shelf in block 9/3b in 110 m of water, containsapproximately 900 MMstb in-place of heavy (10 to 12 oAPI) viscous (1500 cP) crude (Figure 1). The field

Figure 1Bentley Field Location

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is four-way dip closed at uppermost Palaeocene,lowermost Eocene, Dornoch sandstone level, andcovers an area of about 16 Km by 5 Km at a depthof around 1.1Km TVDss (Figure 2). The reservoir ishigh porosity (33%), net to gross pay (90%) andwith ultra-high apparent horizontal permeabilitiesapproaching 50 Darcies based on flow-test measure-ments, but consistent with unconsolidated sand(Beard & Weyl 1977). The field is licensed to, andoperated by, Xcite at 100% working interest. Fol-lowing an extensive appraisal programme, a devel-opment is planned of which 257 MMstb of 2PReserves are estimated to be recovered over a 35year production period. In addition, it is estimatedthat 48 MMstb of 2C Contingent Resources couldbe commercially extracted beyond the end of thecurrently planned facilities life.

The field was discovered in 1977 with theAmoco 9/3-1 vertical exploration well, which dis-covered an 81ft oil column in high quality Dornochsandstone (Table 1). The field was subsequentlylicensed to Conoco who appraised it with two fur-ther vertical wells (9/3-2A and 9/3-4) in the 1980s.These confirmed the presence of a large accumula-tion, estimated at that time to be similar to todaysfigure at around 900 MMstb in-place. Attempts togas-lift the 9/3-1 well failed due to the viscousnature of the Bentley crude, whilst an attempt toflow 9/3-2A using a downhole pump failed due tomechanical reasons.

With two failed tests and an oil price below$20/bbl Conoco relinquished the license in the mid 1990s. There was no further activity on the block until2003 when Xcite applied for, and were awarded, a Promote License on the block during the UK 21st

Licensing Round. This was the first licensing round in which Promote Licences had been awarded andrepresented an important initiative from the UK licensing authorities to encourage small and new-startcompanies to acquire and promote acreage. The license was converted to a Traditional License in 2005prior to Xcites first appraisal well (9/03b-5) in 2008.

De-risking the Field what was required?When Xcite acquired the license it was already known, based on recovered samples, that the crude washeavy and viscous but the full nature of the crude and its flow properties were poorly understood. TheBentley structure was reasonably well imaged on seismic and it was clear that it was a giant field,approaching 1 billion barrels in-place. This was considered an important factor in making an offshoreheavy oil field viable due to the economies of scale that could be captured. All wells had demonstratedexcellent reservoir quality with high net to gross and there was therefore reasonable confidence inreservoir connectivity and volume. It had been demonstrated that the field had a large underlying aquiferin excess of 400 ft thickness, which was likely to be good for bottom-drive and pressure support but whichalso - due to the adverse oil-water mobility ratio - had the potential to result in large volumes of produced

Figure 2Bentley Depth structure map showing well locations

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water during any development. In summary, although there was reasonable confidence in the geologicaldescription of the field, it was clear that prior to development sanction a number of questions requiredanswering:

1. What is the nature of Bentley fluid and its flowing properties?2. Can Bentley fluid be flowed at commercial rates?3. Can oil-rate be sustained following water break-through?4. Can development plan contact a large area of the field at reasonable cost to ensure good fieldrecovery?

5. Can produced fluids be processed and exported efficiently?6. Can exported fluids be sold at a reasonable market price?

An appraisal programme was instigated between 2008 and 2012 that would address these fundamentalquestions and help confirm Bentley as a viable development.

Recent Appraisal History

Well 9/03b-5Xcites first well on the field (9/03b-5) was a vertical appraisal well, drilled at the end of 2007 andflow-tested in January 2008. This well addressed the first of the questions listed above, in that its primaryaims were to recover oil to surface to determine the nature of the fluid, to demonstrate that flow to surfacecould be achieved with a downhole electrical submersible pump (ESP) and, in so doing, to establish theflow properties of the system. To maximise the chances of achieving these goals the well was drilled asa twin of the earlier 9/3-2A well (Figure 2) which had the best reservoir properties to date.

The short (seven hour) flow-test achieved these goals, flowing 10.5 oAPI crude to surface from an 87ft oil column at a rate of 125 stb/d (Table 2). Whilst the rate was far lower than would be required forcommercial flow, sufficient data was gathered to enable a prediction that commercial flow rates could beachieved from horizontal wells with the right completion and right operating parameters. Many importantlessons were learnt relating to this appraisal well that would help to deliver commercial rates in futurewells:

Table 1Early (pre-Xcite) Appraisal Wells

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The sands in the oil-leg are largely uncemented and are highly friable. The mud system and drillingparameters selected for the 9/03b-5 well resulted in significant wash-out in the oil-leg. With thisimproved understanding of the formation and how it reacts during drilling operations a system wasdeveloped for future wells to minimise such wash-outs. This is described as part of the 9/03b-6discussion.

The sandface completion was a cemented and perforated liner. Due to the large washouts thisresulted in poor contact with the reservoir and a high skin of around 30 or more. This was asignificant factor in not achieving high rates. Future completions would aim to maximise sandfaceconnectivity through use of sand screens.

The ability to flow oil to surface at a reasonable rate is closely linked to operating conditions andfluid properties. There was only a limited period in which to achieve a good flow rate before aweather event would shut operations down. The chokes were therefore opened to try and achievethis rate. This however proved detrimental as it dropped the crude below its bubble point. Thisallowed gas to be released, which then occupied much of the production bore and left a liquid witha significantly increased viscosity (Figure 3). The result of this was a well that experiencedsignificant slugging and back-pressure on the ESP. A plan was put in place to design future wellsso that they could be operated whilst maintaining reasonably high pump intake and well-headpressures in excess of 700 psi.

The reservoir itself had a reasonable productivity index and, if a horizontal reservoir section wereto be drilled with a low skin completion, then there should be sufficient reservoir PI to achievecommercial flow rates. Future tests and development wells would therefore utilise horizontaldrilling.

Wells 9/03b-6 and 9/03b-6Z

The 9/03b-6 well was an S shaped pilot hole drilled in November 2010 to identify reservoir structureand to characterise the reservoir properties. An oil column of 113 ft was confirmed and excellent reservoirquality was again identified (Table 2). Immediately following a comprehensive data gathering exercise the9/03b-6Z horizontal sidetrack was drilled, completed and flow-tested. The horizontal reservoir sectionwas successfully geosteered using a deep reading resistivity MWD tool to track the roof of the reservoirthereby delivering 1821 ft of 100% net to gross, high porosity, sandface. The well was completed with

Table 2Recent (Xcite) Appraisal Wells

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a wire-mesh screen run to TD and a downhole ESP. The resultant 36 hour flow-test delivered a surfaceconstrained, final stabilised rate, of 2,900 stb/day. This 9/03b-6 and 6Z wells confirmed many of thelessons learnt from the 9/03b-5 and pointed the way to further improvements for future production wells.In particular:

Despite the unconsolidated nature of the reservoir a reasonably in-gauge wellbore was achievedthrough the reservoir. This was achieved by a combination of low mud flow-rate with jettingfocussed forwards rather than sideways, high drilling speeds with pick-up off bottom andhole-cleaning between stands, and somewhat overbalanced mud containing large bridging agents.

The in-gauge hole resulted in the ability to geosteer close to the reservoir roof whilst avoidingexiting the reservoir or drilling any non-reservoir section.

The resultant reservoir section was 100% net to gross and high porosity with a high productivityindex (PI) and gave a maximum stand-off from the oil-water contact which, for a production well,would lead to delayed water-breakthrough and maximum oil recovery (Figure 4).

With wellhead pressure and pump inlet pressure maintained above 700 psi there was very little gasbreakout within the well, the flow was stable and highly responsive to changes in pump frequencyor surface choke settings (Figure 5) (Brennan et al 2011).

The final flow-rate of 2,900 stb/day was limited by surface offtake which was via tote-tanks. Thewell had the potential to deliver at significantly higher rates.

In summary, and referring back to the De-risking the Field what was required section, the 9/03b-6Zgave a wealth of extra information on the nature of the Bentley fluids and its flow properties (question 1)and it demonstrated that with the right well design and operation commercial flow rates could be achieved(question 2). This gave confidence to move ahead with a further appraisal programme comprising the9/03b-7 and 9/03b-7Z wells, including an extended well test (EWT), which was undertaken in 2012 withthe intention of resolving the remaining pre-development questions.

Figure 3Bentley Crude Viscosity

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Wells 9/03b-7 and 9/03b-7Z

Background and goals Reservoir simulation work prior to 2012 had indicated that the aquifer under-lying Bentley would provide good bottom-drive and an effective vertical sweep, but due to the viscousnature of the crude the lateral sweep was quite limited. Development plans would therefore require closelyspaced horizontal wellbores - in the order of 100m separation - to provide adequate field recovery. Giventhe high cost of drilling in an offshore environment it was decided that a cost effective way of achievingthese closely spaced wellbores would be to utilise multi-lateral drilling technology. Demonstrating thatthis technology could be delivered on Bentley prior to development as part of the next appraisal wouldclearly be essential.

Some uncertainty still remained around the reservoir performance, in particular how long would it bebefore water broke through into the production bore and at what rate would water-cut increase followingthat point in time.

Figure 49/03b-6Z Geosteering data and petrophysical interpretation

Figure 5Final flow period of 9/03b-6Z

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Xcite wanted to design an appraisal programme focused on addressing the remaining reservoiruncertainties and to demonstrate that the key elements of their planned development were valid; ie asmall-development scheme. The appraisal programme also sought to gain valuable data and insights suchthat the development could be optimised. An appraisal programme, including an EWT, was thereforeundertaken with the following goals:

Prove sustainable commercial flow-rates; Prove that water movement through reservoir is predictable and manageable; Demonstrate drilling and completion techniques for multi-lateral development wells; Demonstrate fluid processing and flow assurance techniques; Demonstrate blending, dehydration and export requirements; Demonstrate a marketable crude oil; Provide reservoir and fluid data and surface measurements to better plan the development.

Results and execution The well was drilled from a deep-water jack-up rig on which facilities wereinstalled for degassing of crude and oil and water separation. All liquids were exported via a pipeline toa dynamically positioned shuttle tanker where the oil was blended with gasoil and further dehydration ofthe crude was managed. A 12 motherbore was drilled with a horizontal section above the reservoir andwith a tangential section to contain the planned dual ESP, then completed with a 10 x 9 5/8 liner. An8 section was drilled into the reservoir from the toe of the motherbore to create the 9/03b-7 well, whichhad a total of 2214 ft, 100% net to gross, reservoir that was completed with a premium sandscreen. Thisreservoir section was deliberately placed relatively close to the oil-water contact (OWC) at approximately60 feet above it (Figure 6). At this depth it was anticipated that water would be produced into theproduction bore during the approximate 60 day period planned for the EWT. This would provide thenecessary data to better determine long-term oil and water production. A window was then milled in the9 5/8 liner, a side lateral was created and a multi-lateral junction set, before drilling out a second reservoirsection (9/03b-7Z) of 2042 ft, again with 100% net to gross and completed with a premium sandscreen.This lateral was geosteered to track the roof of the reservoir in a similar manner to that of the 9/03b-6Zand to what is planned for future development wells.

Figure 6Location and trajectory of 9/03b-7 and 9/03b-7Z wells

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The well was completed with a smart control system and dual-pump podded ESP so that either or bothlaterals could be flowed. In addition, a chemical injection line was installed to below the ESP, a heatingcable was placed above the ESP for flow assurance, and a full set of pressure and temperatureinstrumentation, including a fibre optic cable, was positioned downhole (Figure 7).

It was planned that the majority of the production from the EWT would be from the 9/03b-7 well inorder to establish reservoir parameters and aquifer movement, but that some production would also takeplace from the 9/03b-7Z to demonstrate the functionality of the multi-lateral system and smart controls.At the end of the EWT both wellbores would be temporarily abandoned such that they could be used forearly production in the future development. The 9/03b-7Z wellbore, having been drilled close to thereservoir roof and having had little production during the EWT, was designed to provide significant earlyproduction in the development phase.

The EWT took place between July and September 2012 with approximately 150,000 stb oil producedduring 57 net flow days, at an average flow rate of 2,600 stb/d and with oil rates up to 3,500 stb/d froma single lateral. Prior to production commencing from 9/03b-7, a prediction was made of timing to waterbreakthrough and rate of water-cut build for a P90, P50, P10 range of reservoir, fluid and relativepermeability assumptions (blue, green and brown curves, Figure 8). Initial water broke through close tothe P50 estimate and then water-cut built far slower than had been modelled, such that by the end of theEWT it had reached 20% and was trending towards the P10 pre-EWT assumption. This was an excellentresult to give confidence in the reservoir performance moving forward into development.

Once sufficient water-cut build-up information had been gathered, the 9/03b-7 well was closed to flowand the 9/03b-7Z opened using the downhole control valves. There followed a period where flow wasalternated between the 7 and 7Z wellbores, or comingled, thereby demonstrating that the type of controlsystems intended to be used in the development is viable.

The well was operated in a similar way to the 9/03b-6Z flow-test with wellhead and pump inlet pressuremaintained above 700 psia. However the additional instrumentation in the 7, 7Z well enabled someimportant analysis including:

Figure 79/03b-7, 7Z, completion

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Temperature measurements at the pump inlet and outlet revealed a temperature rise of just over 20oC during typical flow due to heat transfer from the motor and through the pump. This would haveresulted in an approximately five-fold decrease in the viscosity of the fluids above the pump(Figure 3). Managed correctly, with the right pump design, this temperature increase can be usedto improve lift performance for development wells.

Pressure measurements, taken within the flow-stream 1200 ft MD apart, separated by a smoothlength of uniform diameter pipe, were used to monitor pressure drop due to frictional losses duringthe flow-test. Assuming laminar flow (a reasonable assumption for viscous oil in a smooth pipe)and Equation 1 it was possible to have a continuous estimate of viscosity downhole. This enabledanalysis of the impact of changes to apparent viscosity as proportions of oil, water and gas changeddownhole. In addition changes in apparent viscosity could be monitored as different substanceswere introduced through the chemical injection line:

During the EWT demulsifier was added below the pump via the chemical injection line along withbase-oil. The demulsifier helped break emulsions formed in the ESP as water-cut rose. Thebase-oil, whilst only injected at up to 2% by volume of total fluids, had a very positive effect onthe flow below the pump. A 2 day trial was undertaken where base-oil was gradually turned-offprior to being reintroduced. The downhole viscosity measurement described above revealed anapproximate 30% reduction in apparent viscosity on reintroduction of the base-oil (Figure 9) andthere was an accompanying significant boost in flow rate. The viscosity drop and flow-rateimprovement were more than could be accounted for by a dilution effect and it was thereforepostulated that the base-oil was coating the side of the pipe and acting as a lubricant to flow witha core-annular flow regime being created. This postulated effect has subsequently been replicatedin the laboratory.

Figure 89/03b-7 EWT Key Reservoir Findings

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Equation 1

Equation for calculating frictional losses in tubing under laminar flowPrior to the EWT, laboratory studies had demonstrated that the Bentley crude was quite hydrophobic

in nature, with emulsions only formed when severe shear was applied. This was confirmed during theEWT with several important observations:

Following water break-through emulsions were created in the ESP. However the addition ofdemulsifier below the pump made these emulsions unstable. It was observed that brown emulsionsexported from the rig arrived at the shuttle tanker as black oil, the water having largely separatedwithin the export 1.8km pipeline.

Additional water was added to the export pipeline to ensure relatively low residence time for flowassurance purposes. This additional water meant that the water-cut in the pipeline was generallybetween 35% and 50% (Figure 10). This may have helped the separation of the water from theemulsion effectively washing out the water. A further significant effect was that whilst the totalwater-cut was above approximately 20% the export pressure was only around 4 barg. This pressureis consistent with what would have been expected had only water been exported. Only whenwater-cut dropped below 20% did export pressure rise to be more consistent with that expectedfrom the combined viscosity of the oil-water mix. It seems clear that a core-annular flow regimewas set up when water-cut was above 20%, with the added water acting as a carrier fluid for themore viscous oil and emulsion.

Whilst stored on the shuttle tanker the crude continued to dehydrate, reaching better than minimumexport specifications after approximately 8 to 12 days (Figure 11).

In summary the goals of the 9/03b-7 and 7Z EWT were met (Table 3) and the key questions raisedearlier in this paper were all successfully addressed.

Impacts of Appraisal Programme on DevelopmentAs a result of the appraisal programme the development of Bentley can be undertaken with much greaterconfidence. Furthermore, it has enabled an optimised design with reduced cost as certain contingencies are

Figure 9Impact of downhole diluent on apparent viscosity

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not required due to an improved understanding of fluid handling, treatment and export. The EWT was, ineffect, a small scale replica of the planned development, so lessons learnt from that can be carried directlyforward. In summary, the appraisal programme has improved the planned development in the followingways:

Figure 10Effect of water-cut on export pressure

Figure 11Dehydration times for Bentley crude during EWT

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Improved reservoir drilling parameters will help create in-gauge hole and enable geosteering totrack the roof of the reservoir; this in turn will improve recovery and productivity per wellbore.

Optimised well completion design for improved flow performance; in particular, the design andoperation of the well will maintain pressure sufficient to keep most gas within the fluid, willbenefit from heat imparted to the fluids as they pass through the pump, and will minimise frictionlosses by maximising pipe diameter and minimising pipe length for the sections that hold the mostviscous fluids.

Downhole injection strategy for improved flow performance: addition of base-oil or otherlubricant to the flowstream below the pump can significantly reduce frictional pressure lossesthereby resulting in a significant boost to flow-rate.

Simplified dehydration process: based on the results of the EWT, Bentley crude dehydration cantake place on a floating storage and offloading unit (FSO) thereby reducing the required size of theplatform.

Optimised separation process: the equipment can be confidently sized, thus reducing the require-ment for excess capacity and as a result reducing the required size of the platform.

Optimised flow assurance: water can be used as a carrier fluid and this also reduces restart issuesfollowing shut-down. In addition, Bentley crude contains no wax and, whilst it becomes moreviscous when degassed and cooled, it remains a liquid. Analysis from the EWT and subsequentlaboratory work has shown that restart pressures are manageable within the planned developmentdesign.

Table 39/03b-7, 7Z Key Achievements

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The lessons learned from the EWT export pipeline from the rig to the shuttle tanker has enabledsubsea completions to be considered.

The EWT demonstrated that traditional coolers do not work well with Bentley crude and that animproved methodology of cooling produced fluids is to mix the hot oil stream with a cool waterstream. This simplifies the plan.

The reservoir and fluid data gathered during the appraisal programme has enabled early planningfor an enhanced oil recovery (EOR) project, including a pilot at an early stage of the development.

The Development PlanBentley field is planned with a phased development. The first phase development (FPD), focussed on thenorthern area of the field, will be followed by a second phase (SPD) approximately five years later, whichwill provide additional capacity for the FPD wells, as well as accessing the southern area of the field(Figure 12).

The FPD comprises a self-elevating platform to accommodate approximately twenty wells which willbe drilled with a deep-water jack-up. Production wells will be drilled initially as dual-laterals, but aredesigned to allow additional laterals to be added at a later date. Production will be via a downhole ESPwith control on individual laterals enabling optimisation of oil-cut. Given the rates achieved in previousflow tests from single laterals and the further optimisation in well design that has been captured since theEWT, it is predicted that the planned multi-lateral development wells will achieve dry oil rates in theregion of 10,000 stb/d. Produced fluids will be degassed, and bulk dewatered, on the platform prior totransfer to a bridge-linked FSU, where further water separation and dehydration will take place. Bentleyfluids will be blended with a diluent on arrival on the FSO in order to assist the dehydration process andto meet optimum marketing criteria. The blended crude will be offloaded to shuttle tankers for shipmentto refineries. All produced water will be re-injected into the Bentley aquifer towards the flanks of the field.

The SPD will also comprise a wellhead platform and degassing facility with produced fluids beingtransferred via subsea pipeline to the FSO via the FPD platform. It is also likely at this time that outlyingareas such as Bentley West will be completed with subsea wells and tied back to the FPD platform.

Figure 12Bentley development plan schematic

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It is estimated that this development can extract 257 MMstb of 2P Reserves during a notional 35 yearfacilities life. It is also estimated that a further 48 MMstb 2C Contingent Resources can be commerciallyextracted beyond this notional period. It is intended to look at acceleration programmes to access thisadditional oil earlier and thus book as 2P reserves. This could include, but not be limited to, an EORproject.

Current EOR trials on polymers are encouraging (Zhitao et al 2014) and if further work continues tobe positive then a pilot is likely during the FPD.

ConclusionsThe Bentley fields contain approximately 900 MMstb in-place, of which it is estimated that 257 MMstb2P Reserves can be extracted over a 35 year notional facilities life. It is also estimated that a further 48MMstb 2C Contingent Resources can be commercially extracted beyond this period, but which will bebrought forward in time through optimisation and EOR techniques.

An extensive appraisal programme between 2008 and 2012 culminating in an EWT has focussed onaddressing the key uncertainties that have, to date, prevented development of the field. The results of thisextensive appraisal programme give a high degree of confidence in the development of the Bentley fieldand enables significant optimisation and simplification of the development design from sandface toexport.

ReferencesBeard D. C. and P. K. Weyl. 1973. Influence of Texture on Porosity and Permeability of Unconsol-

idated Sand. Published in The American Association of Petroleum Geologists Bultetin V, 57, No.2 (February 1973), P. 349369.

Brennan B., Lucas-Clements C., and Kew S., Shumakov Y., Camilleri L., Akuanyionwu O., TunogluA. 2011. Methodologies, Solutions, and Lessons Learned from Heavy Oil Well Testing with anESP, Offshore UK in the Bentley Field, Block 9/3b. Paper SPE-148833 presented at the CanadianUnconventional Resources Conference in Calgary, Alberta, Canafa, 15-17 November 2011

Jayasekera A. and Goodyear S. 1999. The Development of Heavy Oil Fields in the U.K. ContinentalShelf: Past, Present and Future. Paper SPE 54623 presented at the Western Regional Meeting,Anchorage, Alaska, 2628 May.

Morton K., Osman M., Kew S., et alet al. 2005. Heavy-Oil Uncertainties Facing Operators in the NorthSea. Paper SPE 97898 presented at the International Thermal Operations and Heavy Oil Sympo-sium, Alberta, Canada, 13 November.

Zhitao L., Delshad M., Lotfollahi M., Koh H., Luo H., Chang H.L., Zhang J., Dempsey P.,Lucas-Clements C., Brennan B. 2014. Polymer Flooding of a Heavy Oil Reservoir with an ActiveAquifer. Paper SPE-169149

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De-risking a Heavy Oil Development - A Case Study of the Bentley Field, UKCS Block 9/3bIntroductionDevelopment of Heavy Oil

The Bentley FieldDe-risking the Field what was required?Recent Appraisal HistoryWell 9/03b-5Wells 9/03b-6 and 9/03b-6ZWells 9/03b-7 and 9/03b-7ZBackground and goalsResults and execution

Impacts of Appraisal Programme on DevelopmentThe Development PlanConclusions

References