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Copyright 2007, SPE/IADC Drilling Conference

This paper was prepared for presentation at the 2007 SPE/IADC Drilling Conference held in Amsterdam, The Netherlands, 20–22 February 2007.

This paper was selected for presentation by an SPE/IADC Program Committee followingreview of information contained in an abstract submitted by the author(s). Contents of thepaper, as presented, have not been reviewed by the Society of Petroleum Engineers orInternational Association of Drilling Contractors and are subject to correction by the author(s).The material, as presented, does not necessarily reflect any position of the SPE, IADC, theirofficers, or members. Electronic reproduction, distribution, or storage of any part of this paper

for commercial purposes without the written consent of the Society of Petroleum Engineersand International Association of Drilling Contractors is prohibited. Permission to reproduce inprint is restricted to an abstract of not more than 300 words; illustrations may not be copied.The abstract must contain conspicuous acknowledgment of where and by whom the paper waspresented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836 U.S.A.,fax 1.972.952.9435.

Abstract

The Beryl field in UK Block 9/13 was discovered in 1972.The 40-slot, twin drilling rig, Beryl Alpha platform (see

photograph Fig. 1) installed in July 1975 was the first concreteCondeep structure installed in the North Sea. The field isheavily faulted and stratigraphically complex, generatingnumerous drilling opportunities with associated geologicaluncertainties. Extended reach wells are planned to develop

resources beyond the reach of the current platform rigcapabilities.

In the current industry environment where costs of semi-submersible rigs have risen dramatically and rig availability isan issue, the traditional concept of subsea satellitedevelopment is now problematic in terms of economicviability and control of schedule. The Beryl field has anumber of satellite and in-field development opportunities

beyond the platform’s drilling reach. The concept ofupgrading the Alpha drilling rigs to enable these resources to

be developed by means of extended reach drilling (ERD) wasconceived. The approach taken was to maximize ERD whileremaining within the constraints of the existing derrick

structures. This involved an innovative approach to retrofittingenhanced drilling capabilities on a 30-year old rig extendinghorizontal displacement from 15,000 to 25,000 ft (see fieldmap on Fig. 2).

This paper will address project planning from inceptionthrough the development of a rig upgrade execution plan andaddress the well design issues for the ERD program envisaged,including potential new drilling technology applications toreduce torque and enable multiple casing strings below9-5/8-in. casing. Beryl celebrated its 30th year of productionon 11 June 2006. The field life was initially estimated to be20 years. At the time the Alpha platform was installed, BerylField reserves were estimated to be approximately 400 million

barrels of oil equivalent, to date over 1.3 billion barrels of oil

equivalent have been produced from the Beryl field andassociated satellite developments (28% from subsea wells) farin excess of the original Alpha platform funding basis.Innovative approaches to field development characterised the

beginning of Beryl's productive life and are being appliedtoday to continue the process of extending field life byreaching out to recover and discover new resources previouslythought beyond reach.

ERD Project Planning

When drilling commenced from the Beryl Alpha in 1976, theeffective drilling reach, using the drilling technology of thatera, was approximately 8,000 ft. Today, with advances indrilling technology including top-drive systems (installed onAlpha in 1995) and rotary steerable drilling systems, the reachhas been extended to about 15,000 ft. This increased capabilityhas been instrumental in supporting a campaign of drilling todevelop reserves not foreseen in the original field development

plan, with the result that to date 81 wells have been drilled

from the original 40 slots (see Fig. 3).In fourth quarter 2005, a study was undertaken to assessthe potential benefits of further increasing the drilling reachfrom the Alpha platform by a small multi-disciplinary team ofdrilling and reservoir engineers and geoscientists. The

background to this study was the sharply increasing trend ofsemi-submersible rig day rates, and due to the tight North Seamarket situation, their lack of availability. The Beryl area hasa number of subsea satellite field developments that produceto and are supported from the Alpha platform, including the

Nevis, Ness, Buckland, and Skene fields. In addition, there area number of accumulations thus far not developed that wereconsidered to be potential future satellite development

opportunities. Since near term access to an economicallyacceptable semi-submersible rig for drilling satellite subseawells was not foreseen, it was decided to consider the potentialfor ERD wells to develop these opportunities. A number of

potential ERD drilling prospects lay out with the reach of theexisting Beryl Alpha platform rigs, and these are shown interms of drilling reach requirements on the worldwide ERDwells “nose plot” (see Fig. 4). The longest reach requirementwas 30,000 ft. A “bubble plot” showing relative reserve sizefor potential drilling opportunities is also shown as Fig. 5 andthis was used to help prioritise drilling candidates.

The question could have been asked, "What capabilitiesare necessary to drill all of these opportunities from the Alpha

platform?" However, it was quickly realised to do so would

SPE/IADC 105782

Beryl Alpha—Reaching Out To Recover : An Extended-Reach Drilling Upgrade Projecton a 30-Year -Old RigRichard N. Cutt, ExxonMobil Development Co.



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involve the complete replacement of the drilling rig equipmentsets, including the two derrick structures, a project that couldcost in the region of USD $100M and take a minimum of twoyears of planning and construction time. This was ruled out asan option early in the proceedings. Instead, focus was put onthe question, "What capability can be delivered within theconstraints of the existing twin derrick structures and drilling

modules configuration?" This focused efforts significantly. Asa result of this analysis, it was estimated it would be possibleto reach a number of potential ERD targets with a limited rigupgrade within the constraints specified above. In effect, itwas possible to extend drilling reach from 15,000 to 25,000 ftwithin the constraints imposed by utilising the existing derrickstructures. A remarkable fact is the project moved from aninitial “rig upgrade concept” to full project approval withinfour months, and the commencement of offshore work withinsix months of an initial meeting where the rig upgrade conceptwas outlined on a “flip chart” (see Fig. 6).

The identification of the rig upgrade scope and suitabilityto drill the program of ERD wells envisaged required

preliminary well designs to be carried out, including estimatesof hole sizes, casing seat depths, directional plans,calculations of surface torque, hook load, and hydraulicsrequirements for the individual wells. Although presented heresequentially, the well design requirements and rig upgradecapabilities were both worked together interactively anditeratively to derive the most cost-effective rig upgradesolution. Before covering the well design aspects in detail, theERD well rig upgrades scope will be discussed.

ERD Rig Upgrades Scope

Early studies indicated upgrades would be required in thefollowing areas:

• Riq Torque Capacity

• Pump Hydraulics Capacity

• Pipe Handling and Storage

The scale of the challenge faced to increase drilling reach can be seen in Fig. 7, which superimposes one of the two 1970'sera derrick structures on Beryl Alpha against the modernRinghorne platform derrick. The Ringhorne field operated byEsso Norge AS lies in the Norwegian sector and the single rigsteel structure platform was installed in 2002. The derrickstructure has a total drill pipe setback capacity of 31,000 ft and

supports a top drive system with a 59,000 ft-lbs continuoussurface torque, an automated pipe racking and pipe handlingsystem, and is designed to drill the types of ERD wells thatwere envisaged for Beryl Alpha. However, a solution had to

be found that lived within the constraints of the 1970's eraderrick structures.

The main rig upgrade requirements for the two BerylAlpha rigs are summarised in Table 1. The detailed scope ofthe upgrades is discussed below.

Rig Torque Capacity and Associated Upgrades

The minimalist, kelly-oriented derricks could not support aconventional dolly-mounted top drive and were retrofitted

with a DC top drive 34,000 ft-lbs hanging torque-tube devicein the mid 1990's.

All of the planned ERD wells required a higher torquecapability than the top drive systems retrofitted previously.However, without replacing the derrick structures any upgradewas limited to using a similar torque-tube mounted device.Only two top drive systems meeting these requirements were

in process of manufacture, and with top drive and otherequipment deliveries growing quickly at the time, only onesystem could be delivered within the six months from

purchase order required to support the project schedule. Thisnew AC top drive device delivers 44,000 ft-lbs of continuoussurface torque and our ERD well plans were required to workwithin this limiting factor. The existing torque-tube,intermediate tiebacks, travelling blocks and Beckett will berefurbished and re-used.

A containerised top drive system control room will besupplied as part of the package that will house the variablefrequency drive (located on the pipe deck) and the entire topdrive system will be interchangeable between the two derricks,

as it is envisaged only one rig at a time will operate. The topdrive driller’s control panel in the driller's cabin will also bereplaced to be compatible with the new system.

The drawworks is currently fitted with manually-actuated band brakes and an eddy current auxiliary brake system. Theexisting system is very noisy and is manually controlled by thedriller. To improve drilling efficiency, an automatic feed disc

brake will be installed. This comprises a control cabinetlocated on the mezzanine deck within the switch gear roomand an air-actuated, multi-plate disc brake assembly with a

brake pneumatic control unit, which will replace the existingeddy current brake.

The existing band brakes will be retained as an emergency back-up and parking brake. A brake control joystick will belocated within the driller's cabin and the associated pneumaticcontrol system will be located on the drill floor. This type ofautomatic feed disc brake system has been fitted on the Bravo

platform drilling rig for over one year. The system has beenhighly instrumental in reducing drilling torque and assemblyvibrations by maintaining constant WOB, thus minimising akey source of induced bit/BHA agitation, and has assisted thesetting of new field ROP and bit run lengths, which have morethan doubled prior Beryl Field records. In addition, a devicewill be fitted to modulate variations in surface drilling torqueto assist in the mitigation of slip-stick and whirl-inducedvibrations of the drilling assembly.

Pump Hydraulics Capacity Upgrades

A similar approach was used to maximise pump hydraulicswithin the constraints of the existing mud pump facilities. To acertain extent, the legacy of having two rigs with two mud

pumps each on Alpha was beneficial to the upgrade project asthe intention for future Alpha drilling is to operate only one rigat a time. Sufficient total horsepower was therefore available

but the pressure rating of the pumps had to be increased.Analysis indicated it would be possible to increase thecirculating system pressure rating from 5,000 to 7,500 psiwithout replacing the existing four pumps. The pumps wereonly required to have the fluid end modules upgraded tohandle the 7,500-psi working pressure, in conjunction with the



SPE/IADC 105782 3

installation of 4½-in. liners and plungers. The following mud pump ancilliaries were required to be upgraded to 7,500 psiworking pressure:

• High pressure pulsation dampeners

• Pressure indicators and transmitters

• Pressure gauges

• High-pressure mud pump pressure relief valves

In addition, the entire high-pressure mud system pipe workthroughout both rigs was required to be replaced and upgradedfrom 5,000- to 7,500-psi working pressure from the mud

pumps to the top drive including stand pipes, rotary hoses, andinterconnecting pipe work between pumps. This was asignificant undertaking to retrofit on existing rigs.

Associated with the pump upgrades, the existing shaleshakers will not have the capacity to handle the increased mudreturns envisaged (up to 2,000 gpm should a 17½-in. hole bedrilled in future) and will be replaced with shakers withimproved separation capabilities and increased flexibility/ability to recycle loss control material (LCM).

The question of cuttings handling when using non-aqueousfluid (NAF) was also addressed, particularly the Beryloperations traditional approach of transporting non-aqueousfluid cuttings in skips onshore for disposal. Due to theincreasing trend in logistics and onshore disposal costs

predicted, it was determined that for future drilling operationsit would be economical to install a cuttings cleaning anddisposal system offshore. This system operates bymechanically compressing the cuttings into a powder and theheat generated in this process also vaporises the oil present inthe cuttings. The base oil is recovered and re-used. The

process achieves less than 0.1% oil in cuttings (by weight),and the powder is disposed overboard well within theregulatory limits of 1% oil on cuttings.

Pipe Handling and Storage Upgrades

The current racking capacity of the Beryl Alpha derricks is19,000 ft of 5-in. drillpipe, and due to the design of the derrickstructures, this cannot be increased without completelyreplacing the derricks. Engineering studies indicated thatassuming the torque and hydraulic upgrades described abovehorizontal drilling reach could be extended to 25,000 ft withtotal well-measured depths of up to 30,000 ft.

The above mentioned pipe racking constraint would have

theoretically imposed the picking up and laying down of up to14,000 ft of singles (over 350 singles) during trippingoperations for a 30,000 ft MD well (for example, when

picking up 4-in. drillpipe to drill a planned 6-in. hole sectionto TD). Such operations would also involve dependence uponhighly weather-sensitive platform cranes to pick up and laydown singles, and due to extended trip duration, would haveexposed the drilling operation to unnecessary open hole timeand potential wellbore stability risks, especially during winteroperations (platform cranes cannot operate above 40 knotwinds). Of prime importance were the safety considerationsinvolved in such a large-scale use of manual intervention in

picking up and laying down large numbers of drillpipe singles.

Therefore, a means of handling singles more safely, more

quickly, and with significantly less exposure to weatherrelated downtime had to be found to make the ERD upgrade

project viable. The preferred solution, which envisaged asimple mechanisation of the tripping process rather thanautomation, incorporated three elements as follows:

1. Pipe Deck Machine

2. Pipe Transferring Conveyor with Pipe Tailer3. Power Elevators on Tilt-able Links from Top Drive

The pipe deck machine (PDM) mechanically handles tubularson the pipe deck without physical intervention by the rig crew,is rail mounted, and will sit on the East edge of both pipedecks (see diagram in Fig. 8). The PDM will move in a North-South direction lifting pipe from its stacked location from the

pipe deck onto the conveyor located in line with the wellcentre. A single pipe deck machine will be transferred asrequired between the two pipe decks depending on drillingoperations, requiring each pipe deck to have a permanent railsystem and drag chain assembly. The installation of these

systems will require truncating the wireline unit platforms on both pipe decks.

The pipe transferring conveyor will receive pipe from thePDM and will transfer pipe to the drill floor. The unit will beangled from the pipe deck up to the drill floor level. Theconveyor is hydraulically powered and belt driven, and theconveyor is designed to expand and contract as the rig skids

between well locations. Once the pipe approaches the drillfloor, the pipe tailer at the end of the conveyor picks up theend of the pipe and presents it to the power elevators.

Simultaneously, the power elevators suspended from linkson the top drive tilt upwards to receive pipe from the pipe-tailer. The top drive is then raised and the elevators pull the

pipe completely off the conveyor. These elevators will be provided for interchangeable use on either rig.

The above describes the remotely controlled transfer of pipe from the pipe deck to the drill floor without any physicalintervention by the rig crew. For tripping out of the hole, theoperation works in reverse order. It was estimated suchoperations could be carried out in less than three minutes persingle.

The above systems will mechanise pipe handling from the pipe deck to the rig and vice versa and eliminate the previously mentioned tripping risks by providing a swift andreliable, weather insensitive pipe tripping and handlingsystem.

Finally, the condition of the mud process package roof, previously used for additional lay down space, haddeteriorated to such an extent due to corrosion the supportingsteelwork structural integrity was questionable (see photoFig. 9). Therefore, to provide additional lay down area for theERD programme, it was decided to re-instate the structuralintegrity of the mud process package as a future lay downarea.

The diagram (see Fig. 10) shows a conceptual idea of themajor elements of the upgrades superimposed against a

panoramic view of the existing Beryl Alpha twin derricks.



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ERD Rig Upgrades Cost & Schedule Comparison

The offshore element of the project commenced in July 2006and is anticipated to be completed in December 2006. In total,42,000 offshore manhours will be required. The projectengineering was planned, project managed and executed bythe main drilling contractor (including direct supervision byExxonMobil personnel), using drilling contractor supplied

construction crews and the main equipment elements of theupgrade (top drive, pipe handling systems, mud pumps) were

provided by a single supplier.It is interesting to compare the estimated relative costs of a

program of ERD wells with the cost of a subsea developmentalternative envisaged when the project was funded. While theactual costs of the programs are ExxonMobil proprietaryinformation, relative cost benchmarks can be described.Looking at the cost for the first three wells of the potentialERD program and assuming platform rig upgrade costs asunity, a comparison was made of costs for the same threewells against the equivalent cost of a subsea development.Using today's typical semi-submersible rig rates and excluding

the cost of subsea trees, flowlines and tie-ins to the BerylAlpha, the subsea well cost option is nearly double the ERDoption at today's semi-submersible rig rates.

This is highlighted in Table 2. These costs do not take intoaccount the risked cost of potential future workovers inresponse to unforeseen mechanical or production events whichwould further favour the ERD well option, and adding thesignificant costs of subsea trees and flowline infrastructurewould further favour the platform drill well case.

Similarly, for schedule, the first ERD well is expected tocommence in December 2006. In the current United Kingdomrig market, it would be unlikely to be able to contract a semi--submersible rig at all in 2007, let alone factor in subsea facility

tie-in schedules using a diving support vessel (DSV), whichare also operating in a tight supply versus demand market. Inreality, therefore, the ERD option provides both cost reductionand production acceleration versus the subsea alternative.

ERD Rig Upgrades Construction

The major challenge faced for the construction phase was toretrofit the equipment described above on a 30-year old

producing platform in under one year from project approval.Old equipment and structures had to be torn down andreplaced before the construction phase could begin. Almostnine miles of new electric cabling had to be installed. A keyrequirement in the planning was minimum disruption to theongoing production operations. This latter fact dictated astrategy of minimising hot work in both the destruct andconstruction phases as any hot work would require theconstruction of sealed, positively pressurised habitats tocomply with platform safety regulations, which would betime-consuming, and of course, increase the potentialconsequences of any unplanned gas release.

The photos (see Fig. 11) show examples of the cold workapproach in the destruct phase, avoiding the use of cuttingtorches by using alternative methods involving the use ofhacksaws and drilling to break down corroded steel platingand supporting steelwork, these examples show the mudtreatment skid roof destruct activity. Examples of theextensive high-pressure pipe installation work including

construction of pipe supports are also shown (Fig. 12). Thedifficulty of retrofitting this pipe work with the accessconstraints imposed by the requirement to replace the high-

pressure mud system piping on an existing rig on a producing platform and the extent of pre-planning thereby demandedcannot be under estimated.

One further aspect is that in order to maintain these two

30-year old rigs at the desired level of operability and safety,there is a significant ongoing capital maintenance annual workscope of typically 15,000 offshore manhours of constructionactivity. For year 2006, these activities included five-yearmaintenance on both rigs, including drawworks and crown

block removal/refurbishment, Koomey line repairs,installation of man-riding secondary retention systems,replacement of a rig skidding panel on Rig 1, and installationof a system for NAF cuttings handling. These activities had to

be managed in conjunction with the ERD upgrades and werelargely carried out at the same time. The familiarity of theKCA Deutag Drilling management, supervision, and rig crewswith this continuous capital maintenance activity assisted

efforts to execute these activities in harmony with the ERD project work scope and supported the base judgment that forwork of this kind, use of an external construction organization,unfamiliar with drilling operations, would be counter

productive.

ERD Well Design

A key enabler of the ability to drill 25,000 ft reach ERD wellsfrom a highly limited set of constraints, using 30 year old platform rigs, with a 900,000 lbs hook load capacity, and amodest maximum surface torque of 44,000 ft-lbs, is theinherent design of the wells. Normally, much bigger and morecapable rigs with higher torque capability (such as the

Ringhorne design) are required to drill these types of ERDwells.

The first ERD well to be drilled from Beryl Alpha inDecember 2006 will be the 82nd well drilled from a 40-slot

platform. While this poses problems related to costs of re-entry and well abandonment/preparation, it also provides anopportunity, if donor wells are carefully selected, to avoiddrilling long, deviated top hole sections in large hole sizes inunstable formations by utilizing deep kick-offs from existingwells. This allows the possibility of designing the ERD wellsto drill most of the horizontal reach required in deeper, morestable formations in smaller hole sizes compared to a moreconventional surface spud design from a new well slot.

A proprietary ExxonMobil process which maximises drillrates with real-time surveillance of mechanical specific energy(MSE) will be used to constantly identify and remove bitfounder points and also allows drilling individual hole sectionsmore efficiently, reducing downhole vibrations, and theadditional surface torque generated by inefficient, energywasting drilling techniques4.

A typical ERD well design is shown as Fig. 13. In factthis is the plan for the first ERD well. Future ERD wells in the

programme will use a similar design concept. This well with atotal MD of 24,546 ft targets an upper Jurassic accumulation

Northwest of the Alpha platform. The well targets the entry point at the top reservoir of a now abandoned exploration wellin order to minimise the effect of well placement uncertainty



SPE/IADC 105782 5

and to avoid the need for a pilot hole to confirm position. Thedesign incorporates a deep kick-off from an existing donorwell (A66, slot 15 on Rig 1) at 6,633 ft MD below the current13-3/8-in. casing shoe in the Tertiary Sele claystone

formation, with well angle already built to 46°. A 12¼-in. holeis then drilled to 11,000 ft MD, drilling through the highly

porous and weak Tertiary Heimdal sandstone and reaching

section TD in the Danian Maureen formation (which consistsof limestone, calcareously cemented sandstones and

claystones). Inclination is maintained at 46° in this section.This hole section is drilled with an unweighted 9.5 ppgewater-based mud system, and this allows both reactive Seleclaystone and the weak Heimdal formation (a potential losszone for mud weights at or above 10.0 ppge) to be drilled inone hole section. The WBM system allows dispersal of theclaystone when hole enlargement occurs in the claystonesections, which allows management of potential wellboreinstability in the shale while avoiding catastrophic whole mudlosses in the Heimdal. Such uncontrollable losses would occurin the Heimdal if a weighted inhibitive mud system such as

NAF was used to fully stabilize the overlying shale intervals inthis hole section. A casing shoe in the Maureen formation isrequired to allow mud weights to be increased for deeperdrilling.

Modelling indicates that maximum torque required for thisinterval is 29,000 ft-lbs and a surface pump pressure of4,864 psi to deliver a 1,100-gpm pump rate for effective holecleaning. Mud weight plus ECD is maintained at 9.8 ppge,

below the fracture gradient of the Heimdal 1.With 9-5/8-in. casing run and cemented, and mud weight

increased to 11.0- to 11.5-ppge NAF fully inhibitive mudsystem, the bulk of the horizontal displacement required forthe well can be drilled in 8½-in. hole, with inclination built to

86° using a “point the bit” rotary steerable system. The holesection is drilled initially in the Danian Maureen formationand the underlying and highly stable Cretaceous Shetland

group marls finally dropping to 79° inclination to penetratethe shale overlying the reservoir. The hole section TD is in thetop reservoir interval at 23,727 ft MD. The minimum length ofreservoir will be drilled in order to confirm the presence ofthis formation by means of logging while drilling (LWD) logs.Surface torque required for this hole section is 39,000 ft-lbsand a surface pump pressure of 4,400 psi is required for the600-gpm circulating rate required for effective hole cleaning.ECD at bit is 12.5 ppge at section TD, which is less than the

predicted integrity of the depleted reservoir sandstones.A 7-in. liner is then run and cemented and is designed for burst and collapse loadings for production conditions as thecompletion production packer is set well above the 7-in.casing shoe because a pre-perforated 4½-in. production liner isrun below the 7-in. liner in the target reservoir. This liner isrequired for two reasons. First, to case off the almost 12,727 ftof shale and marls in the open hole to prevent any timedependent wellbore instability problems with such a long openhole interval. Second, to allow mud weight to be reduced to9.0 ppge prior to drilling a 6-in. hole to TD in the depletedreservoir sands (depletion is due to production from nearbyfields drawing down a common acquifer). This approach of

setting the 7-in. liner at the very top reservoir (in a low

permeability and low net to gross reservoir unit) avoids the possibility of fracturing this interval and taking massive wholemud losses, given the uncertainty on the final mud weightrequired to stabilize the 8½-in. hole interval, and the preciselevel of pore pressure depletion. It is intended to utilise aresistivity tool near the bit to quickly identify the reservoirmember and avoid drilling too far into this depleted zone in

8½-in. hole.A 6-in. hole is then drilled to TD in the target reservoir,

building inclination back up to 89° to maximise completionlength while maintaining adequate standoff from the

prognosed oil water contact (OWC) and reaching a final TD of24,546 ft MD with a horizontal reach of 18,600 ft. A mudweight of 9.0 ppge is planned using NAF. Surface torque inthis hole section is reduced to 29,000 ft-lbs due to the reducedfriction factors from the extensive cased hole section. Surface

pump pressure reduces to 3,690 psi at the reduced circulatingrate of 250 gpm required for effective hole cleaning in 6-in.hole, with ECD at 10.3 ppge, significantly below the predictedreservoir rock integrity. A 4½-in. pre-perforated liner is then

run to TD with a sacrificial motor and inner circulating stringto ensure the liner can be run to TD without difficulties.

With reference to the previously published paper by R. N.Cutt and Mike Niznik, SPE/IADC 92763, “Beryl Field:Extracting Maximum Value from a Mature Asset Through theEvolution of Technology,” it is planned to utilise the samewellsite real-time dialectric constant monitoring (DCM) oncuttings, outlined in that paper, to adjust mud weights toachieve wellbore stability while drilling, particularly in the8½-in. hole section. This technique relates the DCM tosmectite content and shale surface area. Algorithms derivedfrom a field wide shale surface area database and taking intoaccount hole inclination are then used to calculate mudweights required for full wellbore stability.

As outlined in the above referenced paper, a number oftechnologies will continue to be utilised for the future ERDwell campaign, including one trip milling for casing exits,drilling parameter modelling to ensure a stable low vibrationdrilling window, modified/ruggedised rotary steerable systemswith taper gauge PDC bits, and if required, use of “fractureclosure stress” practices to build wellbore integrity should lostcirculation be encountered. In addition, the pre-perforated(4½-in. OD) production liners and sacrificial motorcombination described in the paper is now the standardcompletion technique at Beryl. Cemented/Perforated

production liner options must be proven as economicallysuperior to deviate from this standard. All of this in-housedeveloped technology will be applied to the ERD wellcampaign.

The 79 to 80° approach angle was selected to ensure thetarget reservoir would be fully intersected from top to bottomin the immediate vicinity of a prior (plug and abandoned)exploration well. The combination of reservoir thickness andgeological TVD uncertainty at the target location anddirectional survey uncertainty on TVD depth of the wellborewere such that these uncertainties exceeded the reservoirthickness. It was possible to have taken the approach ofattempting to drill a horizontal well into the reservoir to

maximise reservoir penetration and possibly production rate,



6 SPE/IADC 105782

but the above mentioned TVD uncertainties would haverequired a pilot hole approach due to the high risk of entirelymissing the target reservoir with a horizontal approach path.The final directional solution was a compromise, avoiding thecost and time of drilling a pilot hole, plugging back andsidetracking, but ensuring full penetration of the reservoirstratigraphy and the delivery of the minimum reservoir

penetration required to deliver target production rates. Thisapproach path, in conjunction with the reservoir geometry alsoensured the well could be TD'd sufficiently above the OWC

(by building angle in 6-in. hole to 89°) to allow completionwith a pre-perforated liner as mentioned above, and avoidingthe cost of a cemented and perforated liner, which could haveinvolved very challenging and costly coiled tubing or multiplerun tubing conveyed perforating activities.

Drillpipe Design and Selection

Prior to finalising the scope of the rig upgrade project, it wasnecessary to determine the optimum size of the tapereddrillpipe required to drill the ERD wells, in order to determine

if upgrades to the pipe racking and fingerboards on the rigwere required.

Early modelling indicated the planned ERD wells couldnot be drilled with the current numbered connections (NC) on5-in. drillpipe for the following reasons:

• Torque generated at surface and at top of the 3½-in.drillpipe (in 6-in. hole) exceeded the maximummake-up torque (MUT) of NC50 and NC38connections.

• The 13,000 ft 7-in. liner section would contribute to buckling of the 3½-in. Drillpipe when drilling the6-in. section due to poor lateral restraint within the7-in. casing.

Various pipe combinations were modelled to determine theoptimum drillstring configuration using in-house software andthese results are summarised in Fig. 14 and Fig. 15,respectively, showing torque versus depth for variousdrillstring combinations, torque versus depth for variousfriction factor assumptions. Pump pressure versus flow ratefor various drillpipe configuration and ECD vs. flow rate forvarious drillpipe configurations. The conclusions of theseanalyses, carried out on in-house software, were to select two

pipe grades/sizes. For drilling the 12¼-in. and 8-in. hole

sections, 5-in. 19.50 lb/ft Z140 drillpipe with XT50 doubleshoulder connections with a MUT of 46,200 ft-lbs wasselected as the most suitable for purpose, providing sufficienttorque capacity, high ID, low OD, durability, withcorresponding flow and ECD benefits.

For drilling a 6-in. hole, a combination 5-in. 19.50 lb/ftXT50 (XT=extreme torque) by 4-in. 14.0 lb/ft S135 XT39connection with a MUT of 21,200 ft-lbs was chosen as theoptimum solution. The higher buckling limit on 4-in. drillpipeand minimal ECD increase with the XT39 connection versus3½-in. DP was a key factor. An entire rental string of thisdrillpipe (all range 2) has been procured to drill the wells(27,000 ft of 5 in. and 16,000 ft of 4 in.).

Drilling Fluid Considerations

Formulating drilling fluids in a mature area with a high levelof reservoir depletion and the potential for loss of circulationmake ECD and hole cleaning critical factors. To aggravatethis, high hole angles require high mud weight to counterwellbore instability from stress. Long reach wells, utilising theoriginal kelly drilled high tortuosity surface holes, require

exceptionally low friction fluids. Rotary steerable drillingsystems operated at high rpm grind down cuttings leading tohigh drill solids in the mud.

To combat the above, low-viscosity NAF fluids (for lowECD and to remove cuttings in turbulence) with ultra fine ormicronised barite and both chemical and mechanicallubricants have been evaluated in the field. In addition, thelatest generation very high capacity shale shakers are now

being installed as an integral part of the ERD rig upgrades.These new shakers include a mechanism to retain loss ofcirculation additives or mechanical lubricants withoutcompromising drill solids.

Hole cleaning is monitored manually or automatically at

the shakers utilising sweeps and extended circulation prior totrips to track hole cleaning performance and clean the hole.Wellbore stability is monitored offshore comparing plannedversus actual dielectric constant measurements allowing fineadjustment of mud weight to minimise the risk of losses whilefully stabilising drilled formations.

It has also been found that while drilling close to or acrossfaults in the Beryl area, two factors are critical to wellborestability. These are 1) the angle of attack of the wellbore to thefault and 2) the well azimuth (see Fig. 16). Analysis of adatabase of over 150 Beryl platform wells has found thatunexplained wellbore instability is more likely to occur when

well path to fault incident angles are 20° or less and/or the

well azimuth is within 20° of a North-South azimuth. To theextent possible, avoiding this well path envelope is aconsideration for future ERD well designs.

The shallow incident angles of 20° or so places the well path in a closely paralleling configuration to the fault andresults in drilling relatively longer sections of the wellborewithin the fault affected zone. The North-South azimuths alsoexpose long sections of the wellbores to the dominant East-West oriented maximum horizontal stress field as evidenced

by the primarily North-South fault trends in the Berylembayment.

ERD Well Contingency DesignsAlthough there is a high level of confidence in executing the base well design described above for the first well, it is prudent to consider contingencies for providing additionalcasing options to respond to unforeseen geological or drillingoperational circumstances to ensure delivery of the wellobjectives particularly for future, potentially more challengingERD wells. Such contingency planning has considered twomain alternatives 1) a slim-hole design, and 2) a casing tie-

back option which will be described in detail below. Theobjectives of each of these designs is to provide one additionalcasing string below the 13-3/8-in. casing shoe present in all ofthe potential Beryl Alpha donor wells, which are typically set



SPE/IADC 105782 7

in a relatively shallow position above 6,000 ft TVD inTertiary shale formations.

Slim-Hole Contingency

Fig. 17 shows the proposed slim hole contingency casingdesign compared to the standard design. This could be used inthe event that the 7-in. liner is committed before the top

reservoir interval, having been unable to drill the 8½-in. holesection to TD, and assuming two further hole sections arerequired (as per base plan) to complete the well. The followingdesign would then be implemented in the sequence described

below:

• Drill out 7-in. (32 lbs/ft, 6-in. ID) liner in 6-in. holeto section TD in top reservoir.

• Run 5-in. (23.2 lbs/ft, 5.75-in. OD, 3.919-in. ID)flush joint liner and cement.

• Drill out 5-in. liner to TD in 3-7/8-in. x 4½-in. hole,drilling to TD with a 3¼-in. rotary steerable system

• Complete with a 3½-in. (9.2 lbs/ft, 3.89-in. OD) pre-drilled liner.

Alternative Casing Programme Contingency

Fig. 18 shows an alternative design concept that adds a casingstring below the existing 13-3/8-in. casing, but retains theability to TD the well in the 6-in. hole. This can be achieved

by using unconventional bit and casing sizes and pushinglarger casing sizes deeper than conventionally used in BerylField operations. The strategy is described below.

• A 12¼-in. hole is drilled conventionally to a sectionTD in the Maureen formation and then underreamed

to 13½ in.• An 11-3/4-in. flush joint liner is then run and

cemented and hung off in the 13-3/8-in. casing.

• A portion of the 13-3/8-in. casing is then cut abovetop of cement (TOC) and recovered.

• The 11-3/4-in. casing is then tied back to thewellhead, crossed over to a 13-3/8-in. casing hangerto utilise the existing casing hanger system. This isachieved using a tie-back packer and seal stemsystem.

• The 9-7/8-in. hole is then drilled to the intermediatecasing point above the target reservoir, and thenunderreamed to 10-5/8 in. (10.625 in.). Note

underreaming necessary due to ID of 11-3/4-in.casing of 10.616-in. due to burst pressure designrequirements.

• The 9-5/8-in. flush joint casing is then run andcemented.

• The 8½-in. hole is drilled to section TD (as per base plan) in top reservoir.

• The 7-in. liner is run and cemented.

• The 6-in. hole is drilled to TD.

• The 4½-in. slotted liner is run.

This option is more time-consuming and costly versus the slimhole option and results in higher surface torque and pump

pressure requirements due to underreaming large hole sizes

and driving large hole sizes (10-5/8 in.) much deeper than the base plan design (still within upgraded rig capabilities).

In comparing these two alternatives, the slim hole design isa more elegant solution, however, it has the disadvantage ofimposing high ECDs on the depleted reservoir section due tothe small hole size. This could be problematic depending onthe level of pore pressure drawdown and resultant rock

integrity. The 11-3/4-in. flush joint casing tie-back optionavoids this drawback as it allows the well to be TD'd in a 6-in.hole size but is more costly particularly due to the extensiveunderreaming activities required.

Solid expandable casing options were considered for thisapplication but are problematic due to concerns aboutsuccessfully expanding casing in a high differential pressureenvironment (potentially above the manufacturer’sspecification) at high well inclinations and at depths exceeding20,000 ft, and in an application previously not attempted inExxonMobil worldwide drilling operations.

Completion Aspects

The type of completion envisaged on Beryl for ERD production wells incorporates a gas lift system, requiring anannular safety valve (ASV). Typically, 4½-in. monobore typecompletions are run with a production packer normally setinside a 7-in. liner above the produced interval. The

production liner planned is a 4½-in. pre-drilled, uncementedliner, run with a sacrificial under-gauge bit and motor, and a2-7/8-in. inner string combination to ensure the liner is reamedto TD. This approach can also provide an opportunity toeliminate a wiper trip after logging operations at TD(depending on hole conditions), and prior to running the pre-drilled liner. This design obviates the need for perforation, asignificant cost and risk reduction for an ERD type well. Atypical completion design is shown (see Fig. 19). A pressureactuated plug is run in the completion string to allow hydraulicsetting of the production packer since a pre-drilled liner, opento the formation is set across the reservoir section below thetubing string tailpipe.

At these extended well lengths, for future wells where acemented and perforated liner is required for reservoir zonalisolation, a coiled tubing conveyed perforating solution wasconsidered but rejected due to the complexity of the operationand the high risk of parting the coiled tubing. Coiled tubing

perforating operations at measured depths approaching25,000 ft is considered a very challenging activity requiringthe connection of multiple coiled tubing reels andtension/compression loads on the coiled tubing, which givesrise to a significant risk of parting the coil tubing. It is likelythat a tubing-conveyed perforating solution, probably a “shootand pull system” on drillpipe requiring multiple perforatingruns will be the preferred option.

Conclusion

Significant incremental drilling reach capability has beenadded to the Beryl Alpha drilling rigs extending horizontalreach capability from 15,000 to 25,000 ft. This has beenachieved within the constraints applied by utilising the 30-yearold derrick structures and achieved without disturbance toongoing production operations. The additional drilling reachhas provided the potential for a number of ERD wells to be



8 SPE/IADC 105782

drilled to replace previously planned and far more costlysubsea development wells.

The ERD well design process has also taken advantage of both pragmatic and innovative design approaches utilizing theextensive drilling experience the operator has in the BerylField. These well design concepts, building from provendrilling performance improvements in the field, have enabled

maximisation of drilling reach within the constraints of thetorque, circulating system, and hook load restrictions imposed

by the 30-year old derrick structures. This incrementalapproach, innovating on a solid foundation of proventechnology and practices, extracts maximum benefit from theexisting platform infrastructure in order to reach out andrecover hydrocarbon reserves previously consideredunattainable.

Acknowledgments

The author wishes to express his appreciation to ExxonMobil(Mobil North Sea, Ltd.) management for allowing the

publication of this paper along with partners Shell Exploration

and Production, Hess Limited, and OMV Exploration &Production. The author also expresses gratitude to thefollowing ExxonMobil staff and associated contractors fortheir input and assistance in developing this paper: Glen DRichardson, Howard A. Garig, Gregory King, Neil Armstrong,John Freeman, Imran Sheikh, and Chris Liddicott of KCADeutag RDS Division.

Exxon Mobil Corporation has numerous affiliates, many with names that include ExxonMobil, Exxon,Esso and Mobil. For convenience and simplicity in this paper, those terms and terms like corporation,company, our, we and its may sometimes used as abbreviated references to specific affiliates or affiliategroups. Abbreviated references describing global or regional operational organizations and global orregional business lines are also sometimes used for convenience and simplicity.

Nomenclature

AC Alternating CurrentASV Annular Safety ValveDC Direct CurrentDCM Dielectric Constant MeasurementECD Equivalent Circulating DensityERD Extended Reach DrillingID Inside DiameterLWD Logging While DrillingMUT Make-Up Torque

NAF Non-Aqueous FluidOD Outside DiameterOWC Oil Water ContactP&A Plug and Abandon

PDM Pipe Deck MachineTD Total DepthTOC Top of CementTVD True Vertical DepthWBM Water Based Mud

Units

ft Feetft-lbs Foot Poundsgpm Gallons per Minutein. Inch

ppge Pounds per Gallon Equivalent psi Pounds per Square Inch

References

1. Bonnett, N. et al .: “High Angle Drilling in SeverelyDepleted Reservoirs,” paper SPE 49984 presented at the1998 SPE Asia Pacific Oil & Gas Conference andExhibition, Perth, Australia, 12–14 October.

2. Dupriest, F., et al.: “Fracture Closure Stress (FCS) andLost Returns Practices”, paper presented at the 2005

SPE/IADC Drilling Conference, Amsterdam, Netherlands,23-25 February.

3. Cutt, Richard, and Niznik, Mike: "Beryl Field: Extractingmaximum value from a mature asset through the evolutionof technology," paper SPE/IADC 92763. SPE/IADCconference Amsterdam, February 2005.

4. Dupriest, Fred et al.: "Maximising Drill Rates with RealTime Surveillance of Mechanical Specific Energy." PaperSPE/IADC 92194 presented at the SPE/IADC Drillingconference, Amsterdam, Netherlands 23-25 February2005.

5. Knutson, C. A & Munro, I.C. 1991, "The Beryl Field,Block 9/13, UK North Sea", in: Abbotts, I. L. (ed) United

Kingdom Oil and Gas Fields, 25 years CommemorativeVolume. Geological Society, London, Memoir, 14, 33-42.

6. J. R. McDermott, R. A. Viktorin et al ., "Extended ReachDrilling Technology Enables Economical Development ofRemote Offshore Fields in Russia". Paper SPE/IADC92783 presented at the SPE/IADC Drilling Conferenceheld in Amsterdam, The Netherlands, 23-25 February2005.

List of Figures

1. Beryl Alpha Platform2. Beryl Area Field Map/Drilling Reach3. Beryl Alpha Slot Diagram4. Worldwide ERD 'Nose Plot'5. ERD Wells relative reserve size 'bubble plot'6. ERD well design concept 'Flip Chart'7. Beryl Alpha vs. Ringhorne Derricks comparison8. Pipe Deck drawing9. Photo of corrosion of mud process package roof10. Panoramic view of twin Beryl Alpha rigs with pipe

handling upgrades key elements11. Cold Work approach photo12. HP Piping Installation13. 3D wellpath of first ERD well14. Drillpipe Optimisation/Selection-Torque15. Drillpipe Optimisation/Selection-Hydraulics16. Beryl Field Fault proximity Wellbore Stability Plot17. Slim hole contingency casing design18. Alternative casing design19. Completion design

List of Tables

1. Rig Upgrade Scope Table2. ERD vs Subsea well cost comparison



SPE/IADC 105782 9

Fig. 2: Beryl Field map showing upgraded Beryl Alpha drilling reach from 15,000 to 25,000 ft.

Fig. 1: Beryl Alpha Condeep platform installed in 1975 and which now has two 31-year old derrick structures.



10 SPE/IADC 105782

Beryl Alpha: 81 Wells from 40 Slots

Fig. 3: Diagram shows all 81 existing wells in red and potential ERD wells in green.

Fig. 4: Worldwide Nose Plot.



SPE/IADC 105782 11

Numberof wells

Complexity ofupgrades

Fig. 5: Bubble Chart showing drilling reach and relative reserve size of drilling opportunities.

Fig. 6: Flip Chart that initiated the Beryl Apha upgrades.



12 SPE/IADC 105782

Fig. 8: Pipe deck layout plan.

Beryl Alpha Ringhorne

Fig. 7: Derrick comparison between Beryl Alpha and Ringhorne.



SPE/IADC 105782 13

Fig. 9: Mud treatment skid roof corrosion.

Pipe Conveyor

New Mud ProcessPackage includingShakers

AC TopDrive andPower

Elevators

Pipe Deck

Machine

AutomaticFeed DiscBrake and

Power Slips

7500 psi MudPump FluidEnds and HPPiping

Fig. 10: Rig upgrades key elements located on a panoramic view of twin Beryl Alpha rigs.



14 SPE/IADC 105782

Fig. 11: Examples of cold work approach to Mud Treatment Skid destruct by use of hacksaws (left) drilling/cold cutting (centre

and right).

Fig. 12: High-pressure piping and pipe supports installation on mud pump module (left), Rig 1 (centre) and Rig 1 standpipe installation(right)



SPE/IADC 105782 15

Fig. 13: Typical ERD well design.

Fig. 14: Drill Pipe torque requirements/drillpipe selection.

9 5/8-in. Csg shoe11,000 ft MD(csg pt not above100 ft MD into

KO @ 6,633 ft MD(no whipstock - off

plug out existing 133/8-in. shoe)

12 ¼” Section:Length 4,367 ft MDInc 46 deg9.5 ppg WBM

Max torque = 29 kft.lbfSPP = 4,864 psi @ 1100 gpmECD at bit = 9.8 ppg @ 1100 gpm

Typical ERD Well Path Summary

7” Csg shoe23,727 ft MD(Katrine)

8½-in. Section:12,727 ft MDInc 46 - 86 deg11 ppg NAF

TD @ 24,546 ft MD

Typical ERD OptionPrevious longest Alpha Sections:12¼-in. Section (A73Z) = 8,011 ft8½-in. Section (A75Z) = 6,660 ft (B68 = 8,235 ft)6-in. Section (A80Z) = 4,961 ftTotal MD (A80Z) = 20,434 ft

4½-in. pre-drilledlnr

Max torque = 39 kft.lbfSPP = 4,400 psi @ 600 gpm

ECD at bit = 12.5 ppg @ 600 gpm

6-in. Section:819 ft MD, Inc 79 - 89 deg9.0 ppg NAF

Max torque = 29 kft.lbfSPP = 3690 psi @ 250 gpmECD at bit = 10.3 ppg

Plan

Surface Torque (FF OH=0.25 & CH=0.2) Surface Torque (5” XT50 & 3 ½” DP)

NB. Max torque seen at top of4”DP = 12 kftlbf



16 SPE/IADC 105782

Fig. 15: Drill Pipe hydraulic performance.

Per Cato Berg, Erik Sandtorv Pedersen, Ǻshild Lauritsen, Nader Behjat, and Siri Hagerup-Jenssen, Statoil, and Siv Howard,

Gunnar Olsvik, John D. Downs, Mike Harris, and Jim Turner, Cabot Specialty Fluids

Data from all wells within 50m of faults in Jurassic Shale

Plot of well azimuth vs. angle of closest incidence of wellbore to major faults. Wells with unexplained wellbore instability(red points) plot below the dotted line. North-South well azimuths are more likely to suffer wellbore instability.

East-West well azimuths onl tend to suffer instabilit where a fault is crossed with an incidence an le less than 20º.

Pipe Size & Wt: 5” 19.50 lb/fPipe Grade: Z140Tool Joint: 6.50 x 3.75 x XT50MUT: 46,200 ftlbs

Pipe Size & Wt: 4” 14.00 lb/fPipe Grade: S135Tool Joint: 4.875 x 2.688 x XT39MUT: 21,200 ftlbs

Selected DP

Pump Pressure v Flow

rate ECD v Flow Rate

Fig. 16: Wellbore stability relationship to azimuth and angle of incidence to faults.



SPE/IADC 105782 17

Fig. 17: Slim Hole Contingency.

9 5/8” cs

5-in. flush joint lnr

Typical ERD Well Slim-hole Contingency

7” lnr

Existing 13 3/8”csg

3 7/8-in. x 4 ¼-in.

12 ¼-in.

8 ½”

6”

2 7/8-in. Pre-drilled lnr

In the event the 7” liner is committed early not having not drilled the 8½” section toplanned TD, the following slim-hole option could be available to complete the well(assuming 6” hole could not be drilled to TD through Jurassic shales immediatelyabove the reservoir section and the reservoir itself):

• Drill out 7” liner (32 lbs/ft, ID 6”) in 6” hole

• Run 5” (23.2 lbs/ft, OD 5.75, ID 3.919”) flush joint liner

• Drill out 5” liner to TD in 3 7/8” x 4 ¼” hole with PowerDrive Xbow 3 ¼” RSS BHA

• Complete with 2 7/8” (9.5 lbs/ft, OD 3.337”) pre-drilled liner

Existing 13 3/8-in.Casing

11 ¾-in. Flush Joint Liner

11 ¾-in. Tie back to

new13 3/8-in. hanger

9 5/8-in. Flush JointCasin

7-in. Liner

4 ½-in. Liner

12 ¼-in. Hole

10 5/8-in. Hole

8 ½-in. Hole

6-in. Hole

Existing 13 3/8-in. Casing

12 ¼-in.

9 5/8-in. Casing

7-in. Liner

8 ½-in.

6-in. Hole

4 ½-in.

Alternative ERD Well DesignPlanned Casing Program

Alternate design allows 6-in. hole to be drilled throughobjective reservoir section while kicking off from a window

in the 13 3/8-in. casing

Fig. 18: Alternative Casing Programme Contigency



18 SPE/IADC 105782

Fig. 19: Typical Completion Design.

Tables

7-in.

4-1/2-in. Pre-drilled liner@ 24,546 ft MD

4-1/2-in.

5-1/2-in.

ASV @

TRDHSV @

GL

7-in. TOL

9 5/8-in.

13 ⅜-in. @ 6,633 ft

Completion Design

• High angle ERD completion (89º max deviation, 18k+ fthorizontal reach)

• 4 ½-in. slotted liner through reservoir (no conformancerequired)

• 9.0 ppg NaCl brine completion fluid

• 5-1/2’’ x 4-1/2’’ 13%Cr, tubulars

• Pressure Activated Plug to set/test completion

• Permanent DHPT gauge installed above packer

Table 1: Rig Upgrade Scope Table



SPE/IADC 105782 19

Table 2: ERD vs. subsea relative cost comparison excluding subsea facilities costs

beryl alpha spe105782

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