SPE-170852-MS

Development of a Stranded Tight Gas Field in the UK Southern North SeaUsing Hydraulic Fracturing Within a Subsea Horizontal Well: A Case Study

Marc Langford and Douglas Westera, SPE; Brian Holland, Centrica Energy; Bogdan Bocaneala, SPE;Mark Norris, Schlumberger

Copyright 2014, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in Amsterdam, The Netherlands, 2729 October 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

There are more than 100 accumulations in the southern North Sea that are flagged as stranded fields. Tightreservoirs, distant infrastructure, small volumes, and anomalous gas qualities are amongst the mainreasons why these resources have not yet been developed. One of these stranded tight gas fields has beensuccessfully developed with the use of a subsea well, horizontal drilling, and hydraulic fracturing.

The Kew structure is a northwest/southeast trending horst straddling licenses 49/4c, 49/4a, 49/5a, and49/5b of the UK sector approximately 2 km east of the Chiswick field. The primary reservoir objectivesare the Carboniferous sandstones of the Caister formation (Westphalian A). This gas field has now beendeveloped with a singlewell that employs a combination of horizontal drilling and multistage hydraulicfracturing to achieve maximum reservoir contact in this low-permeability and interbedded structure.

The absence of data and analogue wells for the design and execution of the fracturing treatmentsnecessitated extended injection tests prior to the execution of the stimulation treatments. To maximize thedata acquired from this well, chemical tracers were injected during the stimulation treatments and returnsevaluated to assess the flowback of each individual hydraulic fracture. As this was a subsea developmentwell, all the hydraulic fracturing operations had to be performed with the rig in place. Hence, the utmostefficiency of the operations was paramount; otherwise, the economics of the project would be negativelyimpacted. Innovative techniques of isolation between each fracturing stage were developed to minimizethe risk and decrease completion time.

The time of massive gas field discoveries has passed, and smaller developments are proving to be thefuture, through tying them to existing assets, to boost gas production in the North Sea and extend the lifeof the existing infrastructure. This challenge was successfully addressed for the Kew field by combiningexisting technologies and developing new techniques.

Stranded Fields in the Southern North SeaA stranded gas reserve is a reserve of natural gas which has been discovered but remains unusable forphysical or economic reasons. In the southern North Sea, there are a number of this type of accumulationswell documented in literature, especially in the Dutch sector of the southern North Sea (Coghlan et al.2013; Schulte et al. 2012).

The Kew field is a gas field, with small volumes of associated condensate, located in blocks 49/4a,49/5a, 49/5b, and 49/4c of the UKCS. It lies some 120 km east of the English coast and 5 km west of theUK/Dutch median line. The field location is pictured in Fig. 1.

The Kew structure had been a proven hydrocarbon accumulation that had not been developed becauseof the poor productivity nature of the tight rock, the distance to infrastructure, the hydrocarbon field sizeand the commercial climate at the time. Kew became commercially interesting to develop due to thetechnical improvements (multiple hydraulic fracturing), the change in economics (tax relief), and theGreater Markham area infrastructure tie-in point via the Chiswick development (Coghlan and Holland2009), as can be seen in Fig. 2.

Figure 1KEW field location in the southern North Sea and proximity to the Dutch sector.

Figure 2Kew field location within the Greater Markham area

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The solutions applied for the KEW accumulation development, such as subsea completions, horizontaldrilling, and efficient multistage hydraulic fracturing using a dedicated stimulation vessel, position Kewas a classic success story in the development of stranded fields.

Geological and GeophysicalThe southern flank of the Kew field was penetrated in 1988 by the Kew discovery well 49/5-4, whichproved the presence of Carboniferous sandstone units C1, D2, E2, and E4. This well encountered 42 mof sand with a net pay of 9.5 m from which gas flowed at 0.42 MMscf/D from poor-quality unstimulatedCarboniferous sandstones.

The Kew appraisal well (49/4c-7z) was drilled in Q4 2008 in block 49/4c as a commitment well forUKCS exploration licence P1186. After drilling difficulties through the Chalk and Zechstein formationsthe well was sidetracked in Q1 2009. The Top Rotliegend came in 15 m high to prognosis and the TopCarboniferous 24 m high to prognosis. The well encountered more net sand (50 m as opposed to 36 m asprognosed) and higher gas saturation (54% as opposed to 45% as prognosed). Pressures indicated modestdepletion (40 psi) and no flow test was performed.

Reservoir SynopsisBecause of the existing two well penetrations there was a good understanding of the reservoir facies. Theprimary reservoir objectives are the Carboniferous sandstone units of the Caister formation (WestphalianA age). The reservoir interval comprises fluvial channel sandstones up to approximately 15 m thickinterbedded with nonreservoir floodplain, interdistributary bay and swamp siltstones, shales, and coals.The sandstone grain size ranges from very fine to very coarse and has poor to moderate porosity (~10 to12%) and expected permeability (0.01 to 90 mD). Reservoir quality is affected primarily by deposition,with higher-energy braided channel deposits being cleaner and coarse grained, whereas lower-energymeandering fluvial deposits are finer grained and shalier. Deep burial has resulted in significant reservoircompaction. Kaolinite and dolomite form the dominant cements as observed in the cores from wells49/5-4 and 49/4c-7z. Because of erosion at the base Hercynian unconformity, there was uncertainty as towhich of the Westphalian units subcrop away from the wells.

Higher up, in the overlying Rotliegend sequence, the Silverpit Layer B contains a number of thinsandstone interbeds. These represent thin lake margin sabkha deposits. Additionally, Lower Lemansandstones had the potential to occur at Kew, as suggested by the 49/5-4 well to the southeast. However,the 49/4c-7z appraisal well encountered only 1.3 m of net sand in the Silverpit (gas bearing) and no netsand in the Leman. The 49/4c-7z well encountered a gross Carboniferous section of ~140 m with ~41 mof net sand.

Well OverviewThe planned Kew 49/04c-7Y subhorizontal development well was drilled along the crest of the Kewstructure and is a sidetrack of the existing (suspended) Kew appraisal well, 49/4c-7z. The well trajectoryis presented in Appendix A.

The planned sidetrack 49/04c-7Y was initially intended to target the Lower Carboniferous units (C1,D2, E2, and E4). To maximize reservoir contact, the well was initially planned to be completed with fourto five hydraulic fractures, with a minimum of one per target unit.

Because of the proximity to the gas/water contact, the decision was made to complete the well usinga cased and cemented liner and plug-and-perf technique for placement and isolation of the hydraulicfractures. This was an agreed decision by the whole project group as it had a direct impact on theefficiency of the operations; previous experiences using open-hole un-cemented multistage systems havepositively impacted the efficiency of hydraulic fracturing execution offshore in the North Sea, reducing

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execution time to one fracture per day (Bocaneala et al. 2013). Also, previous experience of spalling andout-of-gauge hole was another driver towards a cemented system.

Difficulties encountered during the drilling phase cause total depth (TD) to be called early at 5225 m,meaning a stimulation treatment could not be placed as planned in the E2 sand in the southern section atthe other side of the main fault. This resulted in a change in fracture placement, with only one fractureplaced in the E2 sand in the northern section.

Completion DesignThe design of the well was for a subsea completion that could be hydraulically fractured and cleaned upand would allow for the installation of a downhole pressure/temperature gauge (DHPG) to provide anaccurate understanding during the stimulation treatment. The tubing hanger could not be used whilstfracturing as the tubing hanger/subsea production tree design did not allow a through-port for the DHPGcable. As such, the proposed design, excluding the surface frac rig up, was

7-in. (JFE Bear, 32ppf, 110ksi 13Cr) liner 4-1/2-in. (JFE Bear, 15.1ppf, 110ksi 13Cr) production liner 7-in. production packer set below the 7-in. liner packer/hanger Polished bore receptacle (PBR) above the production packer DHPG positioned close to but above the PBR 4-1/2-in. (15.1ppf, 110ksi 13Cr) by 5-1/2-in. (20ppf, 80ksi 13Cr) completion string DHSV at a depth in line with other wells in the area (i.e., Centrica-operated Chiswick field)

Specific components in the string include, from the bottom up:

Mule shoe, c/w shearable centraliser (WEG) AF nipple 3.437-in. Hydrostatic set production packer Packer bore receptacle (20-ft seal assembly and 90, 000 lbf shear ring) Pressure/temperature gauge mandrel Sliding side door c/w AF nipple 3.562-in. 4-1/2-in. tubing (15.1ppf, 110ksi 13Cr) 4-1/2-in . 0078 5-1/2-in. tubing crossover Downhole safety valve (TSME-8) 5-1/2-in. tubing (20ppf, 80ksi 13Cr) Tubing hanger

A detailed completion schematic is presented in Appendix B.As per Centrica Energy standards, a full triaxial tubing stress analysis was completed with the above

string. This would confirm all anticipated load cases during both the fracture stimulation and long-termproduction scenarios. All safety factors were to be below the Centrica Energy design safety factors forcollapse, burst, tension, compression, and triaxial stress, confirming sufficient well integrity during thefracturing operation.

Perforation DesignThe number and size of perforations are critical factors in the execution of the hydraulic fracturingoperations. Pressure drop through the perforations can represent a significant part of the total near-wellbore pressure drop experienced in the flow system. The design basis for Kew was to engineer amaximum of 200 psi pressure drop during the injection phase. This pressure drop number was thegoverning factor to determine charge design, both for the required entrance hole in the tunnel and the shotsper foot.

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The design basis used in the perforating was to assume a discharge coefficient of 0.75 (i.e., newlycreated perforations in the liner). The charge design was also validated using the selected contractorsin-house perforating design tool to ensure the required entrance hole met the requirement to preventproppant bridging and ultimately early near-wellbore screen out with the planned 16/30 resin coatedceramic based proppant. Fig. 3 presents the results of the analysis.

Hydraulic Fracturing: The Key for Maximum Reservoir CoverageThe planned fracture placement, subject to the final LWD data and dedicated repeat formation testerpoints, was to initiate fractures along the wellbore in all of the Carboniferous sandstone units to providemaximum reservoir coverage. The original planned first fracture in the E2 sand had to be canceled becauseTD of the well was called early, resulting in a reduced number of fractures being placed along thewellbore, as presented in Error! Reference source not found.

Hydraulic Fracturing DesignHydraulic fracturing was seen as one of the key elements to ensure the success of the Kew project. Thecreated fractures would help maximize contact to the reservoir, increasing production rates and enhancethe ultimate gas recovery.

Figure 3Perforation design for various flow rates

Table 1PLANNED VERSUS ACTUAL HYDRAULIC FRACTURE LOCATIONS

Planned fracture location Actual fracture location

Target reservoir unit Notes Target reservoir unit Notes

Frac 1 E2 sst Placed in southern segment Unable to place fracture due to early TD

Frac 2 E2 sst Placed in northern segment Frac 1 E2 sst Placed in northern segment

Frac 3 D2 & E4 sst Frac 2 D2 & E4 sst

Frac 4 C1 sst Frac 3 C1 sst

Frac 5 Lower Leman Frac 4 Lower Leman

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The initial well design contained five hydraulic fractures pumped at rates of up to 40 bbl/min. Afracture gradient of 0.7 psi/ft was forecasted, which indicated an expected maximum effective stress ofjust over 5, 000 psi. The proppant was then selected based on the determined minimum horizontal stress,cyclic stress loading, and proppant pack permeability considerations.

As Kew was to be developed as a subsea well, proppant flowback was seen as a significant risk for theoverall project, and to mitigate this risk, resin-coated proppant (RCP) was used. An encapsulating stresscoating applied on a traditional curable resin-coated proppant protects the proppant from premature curinguntil both the right temperature and closure stresses are applied. This technology makes certain that theproppant can be properly placed before the curable coating layer is activated for flowback control, and iteliminates the potential consolidation of proppant in the wellbore, thus allowing for an easy proppantcleanout. Centrica has adopted a policy of using resin-coated proppant on all North Sea fracture-stimulated wells given the good success in previous projects.

Extensive laboratory testing had been performed in the design and preparation phase to ensurecompatibility between the resin-coated proppant and the fracturing fluid. Correct functionality of thecoating in the specific well conditions and with the selected fracturing fluid was tested. All of the testswere successful, with the proppant having little to no effect on the fracturing fluid properties and the fluidnot influencing the ability of the proppant grains to bond together under stress and remain unbonded whenno stress is applied. The proppant sizing was also designed to reduce any non-Darcy effect, which wouldgive rise to an unwanted pressure drop in the near-wellbore region that would impair production.

The fracturing fluid used for the treatments was a freshwater-based borate crosslinked guar with apolymer concentration of 35 pounds of polymer per thousand gallons of fluid.

The 49/04c-7Y wellbore is parallel to the maximum horizontal stress based on the world stress map,indicating fractures will eventually grow longitudinally to align with the principal maximum stressdirection. This is a general trend in most southern North Sea fracture-stimulated wells and is aconsequence of field and platform orientation.

To acquire more information on the reservoir and decide on the fracture initiation points, a formationpressure acquisition tool run was attempted to determine the pressure gradient and to confirm thepermeability in the reservoir section, unfortunately this was canceled due to tool communication failures.Low mobility and tight points were expected to confirm the low permeability Carboniferous sands(Appendix C). This formed the basis for choice of fracture initiation points in combination with thepetrophysical generated CPI (Appendix D). Overall, there was a wide variation of permeability in thetested intervals from less than 0.01mD in the E4 and Markham 2a and the C1 sands and potentially upto 100mD in areas of the D2 sands.

Hydraulic Fracturing ExecutionDuring the execution phase, only four of the five hydraulic fractures initially planned were placed due tothe shorter length of the horizontal section. The four hydraulic fractures were successfully placed in theKew reservoir using over a million pounds of 16/30 resin coated intermediated strength ceramic proppantand over eight hundred thousand gallons of fluid. The isolation in between consecutive stages wasachieved by using soluble-fiber-enhanced sand plugs set at the end of each individual treatment. For theexecution of the fracturing treatments, a purpose built stimulation vessel was used to provided theversatility and storage of the material volumes required for the execution of the Kew stimulationcampaign.

From start to finish, the stimulation operation for the four stages took 18 days, which translates into onehydraulic fracture pumped every four and a half days. This is considered extremely efficient for multistageplug-and-perf fracturing treatments in the southern North Sea considering the interventions required inbetween stages, vessel sailing times, and waiting on weather. This level of efficiency was achieved based

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on Centricas previous multistage horizontal well experience and by ensuring good communication andcoordination between the rig operations and the stimulation vessel team.

The first fracturing treatment from the Kew stimulation campaign targeted the E2 sands. The treatmentwas started on 20 September with an extensive suite of diagnostic injection tests consisting of formationbreakdown, step-rate test (SRT), step-down test (SDT), and calibration injection. The decline from theinitial breakdown was used to perform post-closure analysis (PCA) using the mini-fall-off software.

From the post-closure analysis (see Fig. 4), the reservoir pressure was estimated to be 5, 598 psi(hydrostatic pressure offset from gage to perforations 647 psi). The transmissibility of the reservoir(kh/) is 2, 747 mD.ft/cp, and taking the assumptions that the zone has a net height of 11 m (see Fig. 5)and a reservoir fluid viscosity of 0.023 cp, the permeability can be estimated at 1.75 mD. From the logs,

Figure 4Post closure analysis for zone 1

Figure 5Net height for first hydraulic fracture

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the permeability ranges from 0.1 to 1 mD, which gives a good indication that the analysis provides anaccurate estimate. The above investigation is over a radius of 7.9 m from the wellbore.

The above reservoir pressure estimate of 5, 598 psi matches closely with the Horner plot interpretation,from which the reservoir pressure was estimated to be 5, 721 psi. The lower bound of closure is 6, 450psi, less than the determined pressure from the G-function and SRT analysis, which is expected.

The SDT showed the total near-wellbore friction to be approximately 2, 300 psi. Tortuosity was themain contributor, with 67% of the total near-wellbore (NWB) friction. The remainder was made up ofperforation friction at approximately 759 psi.

Following the SDT, the decision was taken to pump a 1-ppa 100-mesh sand slug; this was pumped priorto the calibration injection test to remove some of the NWB pressure drop. Following the sand slug, theresulting instantaneous shut-in pressure (ISIP) showed a total friction decrease of 900 psi at 35 bbl/min.

Following the diagnostic injections, a redesigned pump schedule was generated with a planned totalproppant of 301, 061 lbm pumped at 35 bbl/min and with a maximum concentration of 8 ppa. Becauseof bottomhole pressure increases in the 6-ppa stage, the decision was taken to extend the 6-ppa stage andnot continue on to the 8-ppa stage. Following this 243, 125 lbm of proppant were placed in zone 1. Theexecution plot of the treatment is presented in Fig. 6, and the estimated conductivity of the executedfracture is presented in Fig. 7.

Similar workflows were applied for the subsequent fractures, and a summary of the diagnosticinjections is presented in Table 2. The hydraulic fracturing execution parameters are presented in Table3.

A special mention needs to be given to the diagnostic injection in zone 4 targeting the Markham 2awhere the leakoff was very low and no fracture closure was seen during the decline period.

A summary of the hydraulic fractures placed within the reservoir structure can be seen in Fig. 8.

Figure 6Execution of the main hydraulic fracturing treatment on zone 1

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Zonal IsolationZonal isolation was successfully achieved by setting sand plugs between the subsequent fracturing stages.To ensure the success of the plugs, the sand-plug slurry mix dissolvable fibers were added to enhance thesuspension and transport of the sand plug in the horizontal section.

Sand plugs as a method of zonal isolation in multistage fractured wells was pioneered in the North Seain the 1990s and was used in high leakoff formations where the dehydration of the slurry and setting of

Figure 7Post job fracture conductivity profile

Table 2DIAGNOSTIC INJECTION PARAMETER SUMMARY

Fracture Pr [psi] kh/ [md.ft/cp] Initial NWB pressure drop [psi]Closure pressure

(SRT) [psi]Leakoff coefficient

[ft/min0.5]

1 5, 498 2, 747 2, 300 7, 500 0.0031

2 5, 233 4, 965 3, 300 6, 200 0.0064

3 5, 360 2, 298 1, 874 7, 800 0.0037

4* - - 2, 699 - 0.0023

* no closure was observed in the decline of the 4th hydraulic fracture.

Table 3HYDRAULIC FRACTURING EXECUTION SUMMARY

Fracture

Totalproppant[lbs]

Total cleanfluid [gal]

Maximumconcentration*

[ppa]

Maximumsurface

pressure [psi]

Maximumbottomholepressure[psi]

Maximumpump rate[bpm] Screen out

1 243, 125 196, 262 6 7, 104 9, 162 35 N

2 213, 526 212, 394 6 8, 010 12, 074 40 N

3 320, 625 229, 846 7 7, 061 10, 076 40 N

4 233, 925 145, 963 7 8, 177 11, 541 36 Y

* Excluding the sand plug setting stage.

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the sand plug occurred very quickly. In the recent years, this method was extended to tight gas reservoirsin the southern North Sea, and because of the low leakoff of the formation compared to the sand settlingrates, the method has experienced a reduced rate of success (see Fig. 9) compared to the high-permeabilityoil wells where the method was initially employed.

A thorough understanding of the proppant transport and settling mechanisms have helped enhancesand-plug setting in horizontal wells with the addition of dissolvable fibers that can help transport the highconcentration slurry and keep the proppant in suspension for extended periods of time until the fracturecloses and the plug can be squeezed (see Fig. 10). The fibers dissolve in time, and the plugs can be easilycleaned using coiled tubing (CT) direct or reverse circulation after all the stages have been placed.

Chemical TracersTo evaluate the clean-out efficiency of the hydraulic fractures in each of the sand bodies and to providean overall contribution, qualitatively, of each stimulated zone, chemical tracers have been used for eachof the four fracturing treatments. Two tracers were used for every stage; one in the pad and one in theslurry stages, which would help in identifying the flowback efficiency and breaker designs for eachfracture post stimulation.

A rigorous sampling schedule was designed at an early stage of the planning phase with a total of 29samples taken during the clean-up phase of the well. The tracers themselves are chemicals found in natureand from the family of fluorobenzoic Acids (i.e. non-radioactive).

The samples showed good breaking of the fracturing fluid with tracers recovered from slurry and padstages of all the fracturing stages. As was expected, a higher volume of tracer was recovered from theslurry stages than from the pad. This is in agreement with the volume and amounts of breaker added tothe fluid. Fig. 11 shows the percentage of tracers recovered during the rig-based cleanup.

Figure 8Summary of hydraulic fracture placement

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Rig-based CleanupOnce all fracturing operations were complete, a rig based cleanup and well test were conducted. As perplatform requirements, there was a maximum limit to both fluids handling and proppant production beforethe well was considered clean and could be handed over to the operations group.

The rig cleanout commenced 19 October 2013. The well was gradually opened to limit the drag forceand prevent proppant production, as shown in Fig. 12. At the end of the cleanout, the choke size was52/64-in. fixed at a flowing wellhead pressure (FWHP) of 3, 370 psi. The final gas rate was~45 MMscf/D,with a condensate rate of 420 bbl/D and 179 bbl/D water/fracture fluid. The proppant rate traces died offat the end, and the basic sediment & water (BSW) was at 38%.

Figure 9Example of a failed sand plug

Figure 10Example of successful sand plug

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Figure 11Tracer return vs flow back time

Figure 12Rig based clean-up parameters

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During the cleanout, the cumulative condensate was 2, 470 bbl, with cumulative water volume of 5,325 bbl. The total proppant that flowed back was 639.3 lbm. In addition, pressure/volume/temperature(PVT) sampling was done.

Based on the overall clean-up and test what can be noted is the minimal amounts of proppant producedduring the test phase. This gave the Centrica team confidence in the resin coating curing process with thehigh drawdowns applied to the well. The Centrica team then had sufficient confidence for the wellhandover phase once the threshold limits were achieved.

The rig based clean-up also showed the deliverability of the well exceeding expectations and flowingon a constrained choke setting of approximately 45 MMscf/D. The tubing performance relationshiputilizing the clean-up data indicated that the Kew well was capable of prolific instantaneous gas rates witha potential AOF ranging 100 - 123 mmscfd (Fig. 13)

Subsea Infrastructure to Place Kew in Production and NormalizedProduction Data to DateThe Kew field has been developed with a single subsea production well that is routed via a 3-km 6-in.flexible pipeline to the Chiswick NUI platform, approximately 3.1 km to the west of the Kew wellhead.Kew hydrocarbons are exported along with those of Chiswick to J6A, for processing via the existingChiswick to Markham 10-in. 18.3-km gas pipeline.

Figure 13AOF well potential plot

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An umbilical provides power, hydraulics, and chemicals to the Kew wellhead. On arrival at theChiswick platform, the produced fluid is routed to the proppant removal facilities before comingling withthe Chiswick fluids and then exported to the compression facilities at Markham. The subsea layout ispresented in Fig. 14.

ConclusionAs the age of the massive gas fields comes to an end in the near future smaller reservoirs will need to bedeveloped to boost gas production in the North Sea and extend the life of the existing infrastructure.

Techniques such as horizontal drilling, subsea completions and hydraulic fracturing have helpeddevelop the Kew reservoir by boosting production and enhancing recovery to enable justification andvalidation of the economics of the project.

The operational execution of hydraulic fracturing in subsea wells is always a challenging undertaking.The lack of data for hydraulic fracturing design was overcome through extensive diagnostic injectionschedules and all the four fractures planned were successful and are contributing to the production of thewell as observed from the chemical tracer analysis and the excellent production results to date. The postclosure analysis has closely matched the results from the log measurements, and this analysis will beemployed during the diagnostic phase of future wells.

The performance of the well has surpassed Centricas expectations and continues to deliver andproduce at a healthy rate to this day, as can be seen in Appendix E.

AcknowledgmentsThe authors would like to thank the operational staff who were involved in the execution of the treatmentand acknowledge the management of both Centrica Energy and Schlumberger, for their kind permissionto publish this paper.

Figure 14Subsea infrastructure layout

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ReferencesBocaneala, B., Holland, B., Langford, M. E. et alet al. 2013. Offshore Horizontal Well Fracturing:

Operational Optimisation in the North Sea. Paper SPE 166550-MS presented at the SPE Offshore EuropeOil and Gas Conference and Exhibition, Aberdeen, UK, 36 September.

Coughlan, G. and Holland, B. 2009. The Chiswick Field: Long Horizontal Wells and InnovativeFracturing Solutions in a Low Permeability Sandstone Gas Reservoir in the North Sea. Paper SPE124067-MS presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana,USA, 47 October.

Coughlan, G., Westera, D., and Ritzeman, K. 2013. The Long Gestation of a Small, Stranded GasDiscovery in the Dutch Sector, North Sea. Paper SPE 166208-MS presented at the SPE Annual TechnicalConference and Exhibition, New Orleans, Louisiana, USA, 30 September2 October.

Schulte, R., Lutgert, J., and Asschert, A. 2012. Stranded Gas in the Netherlands: What is the Potential?Paper SPE 152357-MS presented at the SPE/EAGE European Unconventional Resources Conference andExhibition, Vienna, Austria, 2022 March.

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Appendix A

Well Trajectory

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Appendix B

Completion Design

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Appendix C

Repeat Formation Tester Results for Target Intervals

Point Sand Depth mMDBRT Comments Hydraulic fracture

Lower Leman

0 Markham 2a 4370m MD Very Tight (0.1mD)

1 Markham 2a 4374m MD Very Tight (0.1mD) FIP# 4

Westphalian A

2 C1 4460m MD Extremely Tight (0.01mD) Contingent FIP

3 C1 4467m MD Extremely Tight (0.01mD)

4 D2 (Upper Sand) 4490m MD Fair (1mD - 10mD)

5 D2 (Upper Sand) 4500m MD Fair (1mD - 10mD)

6 D2 (Middle Sand) 4518m MD Good (10mD - 100mD?)

7 D2 (Middle Sand) 4530m MD Good (10mD - 100mD?)

8 D2 (Middle Sand) 4564m MD Good (10mD - 100mD?) FIP# 3

9 D2 (Lower Sand) 4640m MD Very Good (100mD?)

10 D2 (Lower Sand) 4677m MD Very Good (100mD?)

11 D2 (Lower Sand) 4700m MD Very Good (100mD?) FIP# 2

12 D2 (Lower Sand) 4743m MD Very Good (100mD?)

13 D2 (Lower Sand) 4753m MD Very Good (100mD?)

14 D2 (Lower Sand) 4767m MD Very Good (100mD?)

15 E4 4970 m MD Fair/Good (~ 10mD)

16 E4 4998m MD Fair/Good (~ 10mD) FIP# 1

17 E4 5028 m MD Fair (1mD - 10mD)

18 E4 5046 m MD Tight (~ 1mD)

19 E4 5076 m MD Fair (1mD - 10mD)

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Appendix D

Fracture Placement Selection Based on the CPI

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Appendix E

Initial Production Data

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Development of a Stranded Tight Gas Field in the UK Southern North Sea Using Hydraulic Fracturin ...Stranded Fields in the Southern North SeaGeological and GeophysicalReservoir SynopsisWell OverviewCompletion DesignPerforation DesignHydraulic Fracturing: The Key for Maximum Reservoir CoverageHydraulic Fracturing DesignHydraulic Fracturing ExecutionZonal IsolationChemical TracersRig-based CleanupSubsea Infrastructure to Place Kew in Production and Normalized Production Data to DateConclusion

AcknowledgmentsReferences