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Copyright 2005, Society of Petroleum Engineers

This paper was prepared for presentation at Offshore Europe 2005 held in Aberdeen,Scotland, U.K., 6–9 September 2005.

This paper was selected for presentation by an SPE Program Committee following reviewof information contained in a proposal submitted by the author(s). Contents of the paper, aspresented, have not been reviewed by the Society of Petroleum Engineers and are subjectto correction by the author(s). The material, as presented, does not necessarily reflect anyposition of the Society of Petroleum Engineers, its officers, or members. Papers presentedat SPE meetings are subject to publication review by Editorial Committees of the Society ofPetroleum Engineers. Electronic reproduction, distribution, or storage of any part of thispaper for commercial purposes without the written consent of the Society of PetroleumEngineers is prohibited. Permission to reproduce in print is restricted to a proposal of notmore than 300 words; illustrations may not be copied. The proposal must containconspicuous acknowledgment of where and by whom the paper was presented. WriteLibrarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435. 

AbstractThe Forties field was discovered in 1970 and at its peak produced 500,000 bbl of oil per day (bopd). To re-startmajor drilling operations using oil-based drilling fluids onsome of the field’s old platforms would have requiredsignificant capital expenditure (CAPEX) to ensure totalcontainment of both the fluid and cuttings. An alternativeapproach on three of the field’s platforms has beensuccessfully employed. The first utilisation in the North Seaof a high-performance, environmentally friendly, water- based drilling fluid has helped the operator achieve early oil

with much lower CAPEX. It has also proved possible to drillside-track wells through the Eocene overburden and throughthe reservoir in one hole section. This was not previouslyconsidered possible - historically intermediate casing wasset and the reservoir drilled with a smaller hole size.Expensive retrofitting of aging platforms to meetenvironmental obligations for total containment may beunnecessary when a high-performance, water-based fluid isutilised.

This paper describes the characteristics and field performance of this innovative drilling fluid system. Sixwells have been drilled from three different platforms during2004 and early 2005. This paper describes how the fluid performed drilling reactive formations that have only been

successfully drilled in the past using oil-based muds. The paper presents a cost model of the alternative approaches todeveloping Forties using either oil-based muds with totalcontainment or high-performance, water-based fluids withcuttings discharge. This paper will be of interest toOperator’s of aging assets looking to continue drillingwithout heavy CAPEX investment for Total Containment.

IntroductionApache acquired all of BP’s interests in the Forties field in2003. At its peak the field was a huge producer of oil for both BP and for the UK. At one time production reached500,000 bopd. At the time of the acquisition, productionstood at only 30,000 bopd. For the project to make

economic sense, Apache needed to improve production assoon as possible with a minimum of upfront capitalexpenditure. A significant number of new wells would beneeded from several of the Forties platforms. Legislation inthe UK precludes the use of oil-based drilling fluids withouttotal containment. Upfront modifications to the platforms toallow the use of oil-based drilling fluids would have provednot only very expensive, but would also have required theinvestment before production had generated the cash to pay

for the alterations. This was not an option.Faced with this challenge, Apache investigated the

 possibility of using High-Performance Water-Based DrillingFluids (HPWBF) to help it achieve its primary objective ofearly oil, with minimal capital expenditure. A substantiallaboratory investigation was carried out prior to contractaward. This involved testing the inhibitive properties of theHPWBF, described in this paper, against a competitivesystem, using sized Foss Eikeland shale. The test regimeincluded Slake Durability, Hot Roll Dispersion Testing, andCuttings Hardness tests. A control test was run using nativeAlba shale taken from an offset well. Contamination testswere also carried out on weighted fluid to check the effectsof 10% v/v seawater, 35-lb/bbl Hymod Prima clay

(representing drill solids), 10-lb/bbl cement powder andadditions of sized (2 – 4 mm) Foss Eikeland shale inconcentrations up to 180 lb/bbl. All fluids were hot rolledfor 16 hours at 150 deg F before testing. In addition, thelubricity was assessed using a Falex Lubricity tester on 12lb/gal mud.

The field history, and the fluids-related problems formthe backdrop to the challenges faced by Apacheredeveloping the Forties field. The HPWBF selected by thecompany was originally developed as a water-basedalternative to oil-based fluids (OBM) for wide application,and was first used in the Gulf of Mexico. Its exceptional performance as a real alternative to oil-based drilling fluids,has now led to its use in over 200 wells worldwide. An

overview of the evolution of this system from the firstglycol-based drilling fluids in use at the end of the 1980’sfollows the field history.

The field performance of the HPWBF on Forties has been excellent and details of this along with the impact ofthe new wells on hydrocarbons production and a cost modelis presented.

History of the Forties FieldThe Forties field is located in the Central North Sea over

 block 22/10 and 22/6b. The field was discovered in 1970and is the largest ever discovered in the UK sector of the North Sea. After thirty years, and approximately 2.5 billion barrels of production, it is still ranked eighth in the UK for

SPE-96798-PP

High-Performance, Water-Based Drilling Fluid Helps Achieve Early Oil with LowerCapital ExpenditureDerek Reynolds (Apache), Andy Popplestone, SPE, Mike Hodder SPE, Paul Gwynne, Bob Kelly, SPE (M-I SWACO)

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current production and reserves. The principal oil reservoiris the Palaeocene Forties Group Sandstones.

There are several challenges associated with drillingfrom the Forties Platforms, these are both drilling andtopside related. The platforms are old and have only basicdrilling equipment; no top drives, limited pump capacity, basic mixing equipment, low mud-pit capacities and smallsack stores. The decks are also small and have a relatively

limited capacity in terms of loading.Figure 1  shows a generalised lithology for the Forties

field. The Formations penetrated in Block 21 are regionallycontinuous with similar characteristics. The “Red Bed”mudstones are overlain by the Hordaland / Nordland GroupClaystones and Siltstones. Sand stringers may be present inthe first 600m (TVD) presenting the possibility of shallowgas. Below the red beds is the Balder Formation, whichitself overlies the Sele Shales and then the Forties Sands.There are several challenges associated with successfullydrilling these formations:

•  The Tertiary Hordaland / Nordland Group has someextremely sandy sequences which can be identified as potential loss or differential sticking zones. The

 Nordland sequence is also known to have highlyreactive and unstable ‘sticky’ shale sections which cancause potential hole-stability problems

•  The Sele Shale is a weak zone with potential for lossesor hole instability.

•  The Miocene and Eocene Formations are over- pressured up to 1.40 s.g. down to the Balder formationwhere pressures return to a normal gradient of 1.04 s.g.However, the Forties reservoir is now highly depletedand fractured due to the number of wells drilled in close proximity.As Forties is not equipped to date to handle total

containment, nearly all the historical wells have made use ofwater-based mud (WBM), mainly KCl-polymer. Many of

these wells have suffered significant drilling problems(72%) with 10% of the wells being lost as a result. Adetailed review of the wells drilled in the Forties andsurrounding fields with KCl-based systems highlighted thefollowing:

•  The upper (surface) sections, drilled with seawater,were in general trouble-free, with at worst some losses being encountered and occasionally clay swelling.

•  The intermediate sections are potentially problematicdue to the dispersible, unstable mudstone / shaleformations encountered in the Upper Tertiaryformations. Most of the wells drilled with water-baseddrilling fluid suffered similar drilling problems in theMiocene clays, including gumbo and mud ring

 problems. These are consistent with a lack of inhibitionand were avoided on the few wells that were drilledwith oil-based drilling fluids.

•  As the well deepens, the thick Tertiary claystone / shalesequences are interspersed by stringers or lenses ofsandstone and limestone. The drilling problems herehave included swelling claystones and both losses to,and stuck pipe in the exposed limestone and sandstone.The stability of the exposed wellbore tends to be timesensitive due to the swelling claystones. This hascontributed to a number of instances of packing off,hole collapse and stuck pipe and casing.

In contrast, the wells sections that were drilled with oil- based mud (OBM) had very few problems.

The reservoir section is characterised by variablelithologies in a number of formations, which can lead to avariety of drilling problems. The Balder Tuff, Sele andForties Formations are potential loss and wash-out zones.There are differential sticking and seepage concerns in thesand members if the overbalance is too excessive. This isusually the case on Forties, due to the reservoir being highlydepleted. Instability around the casing shoe in the Balder

and Sele formations often leads to hole collapse.Figures 2 and 3  show the occurrence of problems

throughout Block 21 (not just on Forties) for various holesections and drilling fluid systems. Figure 4  then shows asimilar breakdown of problems over fifty of the mostrecently drilled 12¼-inch and 8½-inch sidetracks on Forties before its acquisition by Apache. All the wells in thisanalysis were drilled with KCl-based fluids and hence it isnot further broken down into drilling fluid system type.

Figure 4 shows that 28% of the wells evaluated did nothave any significant drilling related problems; by inferencetherefore 72% of them did! 10% of these wells were actuallylost as a result of the problems that arose. The biggestculprit (with the exception of “general poor hole” which

includes such things as tight hole) was pack-off, oftenresulting in stuck pipe.

The Tertiary shale overburden is porly compacted andwith the exception of balled bits, instantaneous ROP of over100 m/hour are easily achievable. The combination of anoverpressured shale with a deviated trajectory results in ahigh potential for instability and an overloaded annulus.With limited flow rate and no top drive, the result is often poor hole cleaning leading to frequent pack offs with loss ofcirculation. Historically the mud weight has been increasedas a response to signs of well bore caving but this hasresulted in unsustainable ECD’s when they exceed theminimum 13⅜-inch window FIT of 1.65 s.g. equivalent.

Positioning of the 9⅝-inch casing shoe appears to be

critical to the success of the well. Due to the change fromover-pressured Miocene to normally pressured formation inthe Balder, this is where the shoe has to be set – the mudweights required to stabilise the Eocene approach thefracture gradient for the Sele formation. This however stillmeans that the Sele shales and possibly some of the Baldershales are left open when drilling the reservoir. Wellborestability and differential sticking then both become issues asthe mud weight required to stabilize the shales is more than2000 psi overbalance on reservoir pressure. This representsa more difficult operating window for WBM as compared toOBM.

As a new entrant into the North Sea, it was essential thatApache made their acquisition of the Forties field an early

success. In order to achieve this, oil production had to beincreased as quickly as possible with minimum capitalexpenditure. It is clear however that this was unlikely to beachieved without changing the way the wells were drilled.The most obvious option would have been to upgrade the platforms for total containment and to make use of an oil- based drilling fluid. However this strategy would haveentailed significant capital outlay at the start of the project.

High-Performance, Water-Based Drilling Fluid(HPWBF) Development

One main driver for the development of improved water- based fluids came when stricter environmental controls were placed on the use and discharge of oil-based fluids. In the

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Gulf of Mexico, synthetic-based muds, (SBM’s) had beenused for some time,1  with good drilling performance andhigh rates of penetration, both important factors in thedeepwater sector where rig rates are very high. The use ofSBM allowed cuttings to be discharged to sea withminimum treatment; however a regulatory change was proposed which might have required total containment ofcontaminated cuttings. Alternative drilling fluids based on

salt/PHPA, glycol and silicates, had historically shown poordrilling performance in this area. In addition, theenvironmental legislation in the Gulf of Mexico does not permit high concentrations of potassium ion to be used,which has a negative impact on the performance of mostglycols. There was therefore a clear need for an improved performance of potassium-free, water-based fluid to providea viable alternative to SBM.

At the same time it was recognised that in the North Seaarea, there were many cases where zero-dischargeoperations with OBM were expensive, impractical orlogistically difficult and that these operations also posedquestions concerning safety and long-term liability for wastedisposal. A successful high-performance, water-based fluid

would thus provide a viable alternative in this area.

Design Objectives. The design objectives for the newwater-based fluid were as follows:

•  Improved wellbore stability and drilling performance

•  Reduced clay dispersion, accretion and bit balling

•  Ability to function without potassium ion

•  Acceptable HSE profile for both Gulf of Mexico and North Sea areas

•  Improved manual handling and logistics

•  Excellent lubricity

•  Compatibility with elastomers and down-hole tools

Evolution and Components. The era of modern water-

 based fluids started in the late 1980’s with the introductionof polyglycerols to improve wellbore stability. Theserelatively low-molecular-weight, mainly water-solubleadditives are able to intercalate between clay platelets,inhibiting the ingress of water and thus minimizinghydration and dispersion of shales. The polyglycerols werereplaced relatively quickly by the more efficient polyalkalene glycols. However most of these productsrequire the presence of the potassium ion to function properly (Figure 5) and hence had limited applicability inthe Gulf of Mexico. A further development led to the cloud- point glycols, where, it is claimed, the emulsion droplets produced when the glycol partially precipitates downhole,further reduce water penetration into the shale.

The key enabling step in the development of improved,(“high-performance”) water-based fluids was thedevelopment of a new shale inhibitor based on diaminechemistry.2 This product is strongly adsorbed onto the basalclay surfaces but is more efficient than the glycols and doesnot require potassium ions. Indeed, significant inhibition isachieved in freshwater, thus opening up possibilities for landdrilling operations where tight restrictions on the salinity ofdischarged water often apply.

The principle components of the high-performancewater-based fluid are summarized in Table 1. The fluid alsocontains an encapsulating polymer to reduce cuttingsdispersion in the annulus (and hence dilution rates) and alsoa rate-of-penetration (ROP) enhancer designed to prevent bit

 balling and accretion. Viscosity and fluid loss are achievedwith regular polymers. All the products used are gold-ratedunder the North Sea environmental risk assessment scheme(CHARM) and pass Gulf of Mexico toxicity testrequirements. A side benefit of the main inhibitor, is that itmaintains a mildly alkaline pH, such that further additionsof caustic soda are not required, thus eliminating the need tohandle this corrosive chemical – a definite HSE bonus.

Laboratory PerformanceThe HPWBF has been comprehensively tested in thelaboratory using a variety of techniques and clay substrates.An excellent overview is given in by Young, et al .2  This paper highlights some recent results. 

Figure 6 shows the results of a cuttings recovery (hot-roll dispersion) test using shale from Bohai Bay, China–Upper & Lower Ming, Guanto, and Dongying formations.The shale is first cleaned and dried then ground to produce particles between 2 and 4 mm. These are hot rolled invarious fluids for 16 hours and the weight recovered on a 2-mm sieve then calculated. This test is a reasonable indicatorof performance but emphasizes the role of encapsulating

 polymers rather then inhibitors in controlling dispersion. Inthis test the HPWBF formulated in seawater gives similar performance to a silicate fluid. Best recovery is obtainedfrom the HPWBF with KCl brine phase.

Figure 7  shows the results of an unconfined swellingtest using a claystone from Bangladesh with a cationexchange capacity of 12 meq/100 g. The graph shows thelinear expansion as a function of exposure time to differentfluids. Freshwater fluids produce significant swelling (30%)within two hours. This is controlled to 10% by KCl/PHPAor freshwater/potassium silicate and to 6% by either theHPWBF or the KCl/silicate fluid.

Figure 8 shows the results of tests designed to measureaccretion and ROP enhancement. Accretion refers to the

 build up of a compacted layer of sticky cuttings on the BHAor bit and often leads to bit balling, reduction in ROP andtight trips. It is caused by poor bit hydraulics combined withhydration effects that make the rock plastic and sticky. This process can be evaluated in the laboratory by rolling a smallquantity of a suitable clay substrate in a cell together with aniron bar for a few minutes and recording the amount ofmaterial that sticks to the bar (right-hand picture).

ROP enhancement is best measured using a small-scaledrilling machine as illustrated on the left-hand picture. The bar charts superimposed on the picture show the ROP’sobtained in Pierre shale with different additives. These testsare expensive to perform but are a reasonable reflection oftrue drilling conditions.

Field Performance. The HPWBF has been used on over a200 wells worldwide to date since its launch in 2001. Recentexperiences from the Gulf of Mexico area are presented byKlein, et al 

3  and Watson, et al.4  This section reviews its

 performance on six wells drilled on the Forties Alpha, Bravoand Delta platforms. The drilling equipment on these platforms had been mothballed for some time with theinevitable detrimental effect on reliability once drilling re-started. It is in this context that the HPWBF performance is presented. The well performance data for six wells issummarised in Tables 2 and 3 and Figures 9 and 10 and issplit depending on either overburden or reservoir lithologyexposure. Average ROP and open hole hours per 100 meters

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were calculated from extracted DIMS (well data base) data.In the case of average ROP, all codes indicating that footagewas being made were used. As these included makingconnections with a Kelly and may have included periodiccirculating time to improve hole condition, on-bottom ROPis hidden. This is reported as a range when it was includedin the DIMS description.

The overburden sections all had similar hole problems

 but the open hole time varied greatly. The deeper thesection, the lower the overall ROP and the longer the openhole time. This is in line with the expectation of reducedhydraulic efficiency and more compacted lithology withdepth. A lower average drilling ROP however did notnecessarily mean a higher open hole time if the impact ofhole problems was less significant. A high percentage of theopen hole time is spent circulating and working pipe in poorhole conditions, exacerbated by waiting time for surfaceequipment repair. Most of the reservoir sections hadoverburden exposure as result of setting the intermediatecasing high but only when the exposure included theTertiary clay did that result in a lost drilling or completiontarget (stuck liner in reservoir). All other reservoir sections

were relatively trouble free even with Balder and Sele shaleexposure using mud weights as low as 1.20 sg.

Among lessons learnt from drilling with the HPWBF isthat the degree of annulus overload has a direct impact oninhibitor consumption in the larger hole sizes. Once the rateof cuttings generation and removal deficit exceeds a certainlevel, the deterioration of mud condition accelerates to pointwhere the specification has to be restored with aggressiveconditioning. If the hole is kept clean and the solidsremoved on the shakers, the chemical consumption is notmanifest to the same degree. Interestingly the hole remainedin good condition for extended periods even when full offluid that was considered well out of specification. In onewell the casing was run after an extended period of waiting-

on-weather with much less trouble than expected. This maywell have been a benefit of the inhibitor chemistry. Bottom-hole assembly accretion and surface clay problems were notexperienced, apart from the beginning of a section withshallow window depth (577-m MD) and was cured byrestoring inhibitor levels.

Recently, sustainable on-bottom penetration rates of over100 meters/hour have been achieved with an OBM on aForties platform using CRI and top drive without hole problems. The ROP penalty of HPWBF compared to OBMis not clear but an assumption was made for the cost modelthat translates to 30% higher open hole time, not consideringtime imported by hole problems. A valid comparison between the two options in terms of drilling performance is

diffcult to make unless they are applied on a similartrajectory using the same mud weight, drilling parametersand upgraded surface equipment.

Fluid Selection – Economic Model.  The use of a water- based fluid was preferred due to the cost and time requiredto upgrade the platform to use OBM. This would haveentailed an upfront capital cost of around $5m and a 90-dayrig refit to install a Cuttings Re-Injection (CRI) unit and atop drive. The former is required for cuttings disposal in azero-discharge environment and the latter to take advantageof the increased drilling performance offered by the OBMand to allow more distant targets to be reached.

The effect of this investment on discounted cash flow isshown in Figure 11, which covers a 12-month, 6-well program. It is assumed that wells would be drilled in 45days with OBM + top drive and 60 days with WBM. CRIand top drive rental were estimated at $8,100/day and mudcosts at $180,000/well for OBM and $400,000/well forHPWBM. Other costs, for example rig rental will be thesame in both cases and so are ignored. Each well is assumed

to produce 1500 bopd.Figure 11 assumes oil at $30/bbl and interest rate of 10%

 p.a. The crossover point, where cash flow with OBM andthe ugraded rig exceeds that with the WBM, would notoccur within 2 years with this model, even if the oil pricewas $50/bbl. If the oil price is increased to $50/bbl, and theinterest rates reduced to 8%, the cross over is reached after24 months.

This model is simplistic, for example, it makes noallowance for decreasing production from the wells drilled. Nevertheless it clearly illustrates the cash flow advantagesof the WBM option in the first year of operations, given allrealistic economic predictions of oil price and interest rates.Given the uncertainties that accompany all enterprises of

this sort, a longer term view would carry additional risk.

AcknowledgmentsThe authors would like to thank M-I SWACO

 and Apache for permission to publish this paper and also manycolleagues in the UK and around the world who havesupplied help and information, especially Ted Hibbert forhis support on the project initially and for his assistance incompiling information for the paper.

SI Metric Conversion Factorsft x 3.048* E-01 = min x 2.54* E-01 = mm

(°F –32) 5/9 = °C

 bbl x 1.589 87 E-01 = m

3

 lb/bbl x 2.85301 = kg/m3

lb/gal x 1.11983 E+02 = kg/m3  bbl/ft/ x 5.21613 E-01 = m3/m

* exact conversion constant

List of acronymsHPWBF High-performance, water-based fluidFIT Formation integrity testOBM Oil-based mudCAPEX Capital expenditurePHPA Partially hydrolysed polyacrylamideROP Rate of penetrationSBM Synthetic-based mudWBM Water-based mudMD Measured depthTVD True vertical depthECD Equivalent circulating densityBHA Bottomhole assembly bopd bbl of oil per dayDIMS Drilling information management systemCRI Cuttings re-injection

References1. Candler, J.E., Rushing, J.H. and Leuterman, A.J.J.:

"Synthetic-Based Mud Systems Offer Environmental BenefitsOver Traditional Mud Systems," SPE 25993, SPE/EPAExploration and Production Environmental Conference, SanAntonio, Mar 7-10, 1993.

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2. Young, S., Patel, A., Cliffe, S., Stamatakis, E.: “Organo-Amine Chemistry – An Innovative Key to Achieving InvertEmulsion Performance with Water Based Drilling Fluids,”SPE International Symposium on Oilfield Chemistry,Houston, 5–8 February 2003.

3. Klein, A.L., Aldea, C., Bruton, J.R., Dobbs, W.R.: “FieldVerification: Invert Mud Performance from Water-BasedMud in Gulf of Mexico Shelf,” SPE 84314, SPE AnnualTechnical Conference, Denver, 5 – 8 October 2003.

4. Watson, P., Meize, B., Aldea, C., Blackwell, B. “Eastern Gulfof Mexico: Inhibitive Water-Based Drilling Fluid Sets Ultra-Deepwater Records,” IADC/SPE 87131, IADC/SPE DrillingConference, Dallas, 2-4 March 2004.

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Table 2 – Overburden hole sections

Platform Well Hole Size

Casing

size

Sectionlength

meters

Formations

drilled

On bottomROP

m/hr

AverageROP

m/hr

Open holehours/100

m Hole problems

TotalOH

DaysDelta 1 8 1/2" P&A 1138 Tertiary 13-60 11.9 33.4 cavings, pack off 15

casing shoe Balder losses

Delta 2 8 1/2" 7" 340 Tertiary 03 - 35 12.4 2.9 cavings, losses 5

casing shoe Balder pack off

Delta 3 8 1/2" 7" 844 Tertiary 03-30 10.0 19.7 pack off 8

casing shoe top Balder losses

Delta 2 ST 8 1/2" 7" 933Tertiary,

Balder, Sele 13-60 17.5 17.8stuck pipe in

reservoir 9

casing shoe Forties

Bravo 1 12 1/4" 9 5/8" 1144 Tertiary 25-44 22.7 13.3pack off,

sticky clay cuttings 9

casing shoe Hordaland

Alpha 1 12 1/4" 9 5/8" 1409Tertiary,

Balder, Sele 26-32 17.5 18.7fines, cavings,

tight trips 13

casing shoe  top Forties

Table 3 – Reservoir hole sections

Platform Well Hole Size Liner size

Sectionlengthmeters

Formationsdrilled

On bottomROP

meters/hour Average

ROP m/hr Open hole

hours/100m Hole problemsTotal openhole Days

Delta 2 6" P&A 207Balder, Sele,Forties Sand 02-18 6.3 33.4 none 5

Well TD base Forties

Delta 3 6" 4 1/2" 268Balder, Sele,Forties Sand 10 - 20 10.3 29.3 none 3

Well TD base Forties

Delta 2 ST 6" 4 1/2" 148 Forties Sand 08-18 7.3 54.8 none 5

Well TD base Forties

Bravo 1 8 1/2" 7" 1031Tertiary,

Balder, Sele 18-24 14.6 10.7 Liner set off depth 9

Well TD base Forties

Alpha 1 8 1/2" 7" 384 Forties Sand 02-30 9.6 4.2 over pull, torque 5

Well TD  Maureen chalk stringers

Table 1 – High Performance Water-BasedDrilling Fluid Formulation

Component ConcentrationInhibitor 2-4% v/vEncapsulator 1-2 lb/bblROP Enhancer 2-4% v/vBrine Phase As required

Viscosifier (Xanthan) 1-2 lb/bblFluid Loss Additives (PAC,Starches) 3-4 lb/bblBrine phase options are  Freshwater

SeawaterKCl BrineNaCl Brine to Saturation

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Figure 1 – Forties Geological Forecast

Figure 2 - Occurrence of Drilling Hazards in the 12¼-inch Sections

   T   i  g   h   t   H  o   l  e

   O  v  e  r  p  u   l   l   >   5   0   K   l   b

   E  x  c  e  s  s   W   /   O  u   t

   C  a  v   i  n  g  s

   I  n   f   l  u  x

   H   i  g   h   G  a  s

   L  o  s  s  e  s

   G  u  m   b  o

00.050.1

0.150.2

0.250.3

0.350.4

0.450.5

   F  r  e  q  u  e  n  c  y

Common Hazards

Oil-Based Fluids

Gypsum/LignosulphonateKCl/PHPA

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   T   i  g   h   t   H  o   l  e

   O  v  e  r  p  u   l   l   >   5   0   K   l   b

   E  x  c  e  s  s   W   /   O  u   t

   I  n   f   l  u  x

   S   t  u  c   k   P   i  p  e

   H   i  g   h   G  a  s

   L  o  s  s  e  s

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

0.5

   F  r  e  q  u  e  n  c  y

Common Hazards

SBM

KCl/PHPA

Gypsum/Lignosulphonate

 

Figure 3 - Occurrence of Drilling Hazards in 8½-inch Sections

Figure 4 - Occurrence of Drilling Hazards in all Sections in the 50 Most Recent Wells.All Wells Drilled with KCl-Based Drilling Fluids.

Incident Occurence

0

5

10

15

20

25

30

35

NoProblem

Wash-out Holecollapse

Losses Pack-off StuckPipe

StuckLogs

Poor Hole(general)

Hole Fill SectionLost

Incident

   %    O  c  c  u  r  e  n  c  e

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50

55

60

65

70

75

80

85

90

95

100

   R  e  c  o  v  e  r  y   (   %   )

FW Polymer FW Glycol KCl PHPA FW Silicate SW Ultradril KCl Ultradril

Dispersion Results

 

Figure 5 - Glycol adsorption onto clay platelets (schematic)

Figure 6 - Cuttings recovery (hot-roll dispersion test) on Bohai Bay shale

potassium

glycol

glycol

glycol

potassium

glycol

potassium

glycol

glycol

glycol

glycol

glycol

 

HPWBF (SW) HPWBF (KCl)

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0

5

10

15

20

25

30

35

40

0 2 4 6 8 10 12 14 16

Hours

   %    V

  o   l  u  m  e   E  x  p  a  n  s   i  o  n

Fresh Water FW/Lime

KCl/Glydril/Hibtrol/IdcapD

KCl/PHPA

FW/Sildril K

KCl/Sildril

KCl/Ultradril

HPWBM Glycol/ PHPA- CaCl2 /polymer20% NaCl 20% NaCl

91.3

110.5

32.7

7.1

14.1

39.6

18.9

17.8

18.2

49.1

HPWBM Glycol/ PHPA- CaCl2 /polymer20% NaCl 20% NaCl

91.3

110.5

32.7

7.1

14.1

39.6

18.9

17.8

18.2

49.1

91.3

110.5

32.7

7.1

14.1

39.6

18.9

17.8

18.2

49.1

 

Figure 7- Shale Swelling Test on Claystone From Bangladesh

Figure 8 - Accretion and ROP enhancement testing. Bar charts superimposed on theleft hand picture are ROP data in ft/hr with different additives

HPWBF (KCl)

8/19/2019 2 Spe 96798 Hpwbm - Hodder

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96798 11

Overburden Hole Sections

0

5

10

15

20

25

Delta 1 Delta 2 Delta 3 Delta 2

ST

Bravo 1 Alpha 1

   A  v  e  r  a  g  e   R   O   P   (  m   /   h  r

0

5

10

15

20

25

30

35

40

   O  p  e  n   h  o   l  e   T   i  m  e   (   h  r  s   /   1   0   0  m

ROP

Openhole Time

 

Figure 9 – Drilling Performance Summary (overburden section)

Reservoir Hole Sections

0

2

4

6

8

10

12

14

16

Delta 2 Delta 3 Delta 2

ST

Bravo 1 Alpha 1

   A  v  e  r  a  g  e   R   O   P   (  m   /   h  r

0

10

20

30

40

50

60

   O  p  e  n   h  o   l  e   T   i  m  e   (   h  r   /   1   0   0  m

ROP

Openhole Time

 

Figure 10 – Drilling Performance Summary (reservoir section)

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12 96798

Discounted Cash Flow Model

-10.00

-5.00

0.00

5.00

10.00

15.00

20.00

25.00

30.00

35.00

40.00

1 3 5 7 9 11 13 15 17 19 21 23 25

15-Day Periods

   D   i  s  c

  o  u  n   t  e   d   C  a  s   h   F   l  o  w   (   $

OBM

WBM

 

Figure 11 - Discounted Cash Flow Model