SPE/IADC 139623

Drilling Fluid Design Enlarges the Hydraulic Operating Windows of Managed Pressure Drilling Operations Doug Oakley and Lee Conn, SPE, M-I SWACO

Copyright 2011, SPE/IADC Drilling Conference and Exhibition This paper was prepared for presentation at the SPE/IADC Drilling Conference and Exhibition held in Amsterdam, The Netherlands, 1–3 March 2011. This paper was selected for presentation by an SPE/IADC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers or the International Association of Drilling Contractors and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers or the International Association of Drilling Contractors, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers or the International Association of Drilling Contractors is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE/IADC copyright.

Abstract With the increasing use of Managed Pressure Drilling (MPD) to mechanically control bottomhole pressures for drilling narrow mud-weight windows, little consideration has been given until recently to integrating drilling fluid design and MPD operations for a specific application. This paper describes how two converging technologies have emerged in recent years that both converge on more effectively managing narrow hydraulic operating windows in extended reach, horizontal, and through tubing drilling operations.

The performance limitations of drilling fluids are discussed within the context of the drilling fluid requirements needed to drill these more critical well types and how attempts to manipulate the rheological profile have only been partially successful at balancing the need for sufficiently high enough rheology to adequately suspend dense weighting agents and the requirement for low-rheology fluids to manage downhole hydraulic needs (ECD). It is suggested that drilling-grade barite has major limitations when designing fluids for wells with critically narrow hydraulic operating windows, which are overcome by a novel process that produces micronized barite with an average particle size of less than 2 microns. By formulating treated micronized barite (TMB) in drilling fluids instead of API Barite, low-rheology drilling fluids may be formulated that enable downhole frictional pressures to be reduced by 0.5-lb/gal equivalent density with minimal risk of barite sag or settlement.

Managed Pressure Drilling (MPD) is a fast emerging technology that has the ability to reduce ECD’s by applying annular backpressure. The authors suggest that drilling fluids that enlarge hydraulic operating windows should be considered as one of the ‘tools’ of Managed Pressure Drilling as defined by IADC. Case histories from the Gulf of Mexico and the North Sea describe how the combination of TMB drilling fluids and MPD operations provide a powerful synergistic combination of technologies that is capable of drilling the narrowest of hydraulic operating windows. Break-circulation pressures, swab-and-surge pressures are lower and pressure transmission from downhole pressure-while-drilling (PWD) tools are more instantaneous in low-rheology fluids. This allows better control of downhole pressures, further reducing the risk of wellbore instability and lost circulation events during MPD operations. Aspects of software design that predicts ‘in time’ wellbore hydraulics by coupling downhole drilling fluid rheology to annular pressures in the absence of PWD measurements while tripping and casing are also described that further improve the capability to manage bottomhole pressures and wellbore security in critical narrow hydraulic operating windows.

The authors conclude that a combination of MPD techniques and low-rheology TMB drilling fluids have the potential to drill wells that are currently considered ‘hydraulically undrillable’ by enhancing wellbore security and reducing drilling risk in extended reach, horizontal and through tubing drilling applications for development drilling and redevelopment of ‘brownfield’ reservoirs. Introduction Managed Pressure Drilling (MPD) operations have gained widespread acceptance as a means to overcome many of the drilling-related problems associated with the narrow hydraulic operating window between the pore-pressure and fracture-pressure gradient. Stress-related wellbore enlargement or collapse, lost circulation, stuck pipe and other wellbore stability issues are common non-productive time (NPT) events associated with diminishing hydraulic operating windows in long reach and extended reach well profiles, deepwater drilling operations, drilling depleted reservoirs, drilling unstable formations and abnormally pressured formations. All these drilling risks may, to a greater or lesser extent, be mitigated with MPD.

Unlike conventional drilling operations where drilling fluid returns are open to the atmosphere, MPD requires a closed and pressurized drilling fluid system using equipment to apply annular backpressure in order to maintain the wellbore in a stable

2 SPE/IADC 139623

condition, without drilling fluid losses to the formation or the influx of formation fluids into the wellbore. Accordingly, the IADC (2006) has defined MPD as follows:

“MPD is an adaptive drilling process used to more precisely control the annular pressure profile throughout the wellbore. The objectives are to ascertain the downhole pressure environment limits and to manage the annular hydraulic pressure profile accordingly.”

In addition, IADC included the following key technical notes to this definition: • MPD processes employ a collection of tools and techniques that may mitigate the risks and costs associated with

drilling wells that have narrow downhole environment limits by proactively managing the annular hydraulic pressure profile.

• MPD may include control of backpressure, fluid density, fluid rheology, annular fluid level, circulating friction, and hole geometry, or combinations thereof.

• MPD may allow faster corrective action to deal with observed pressure variations. The ability to dynamically control annular pressures facilitates drilling of what might otherwise be economically unattainable prospects.

• MPD techniques may be used to avoid formation influx. Any flow incidental to the operation will be safely contained using an appropriate process.

Further description and categorisation of the various MPD processes (Malloy 2007; Armone and Vieira 2009; Nauduri et al. 2009; Malloy et al. 2009; Nauduri et al. 2010; Malloy and Shayegi 2010) and applications in the field (Roes et al. 2006; Foster and Steiner 2007; Chustz et al. 2008; Syltou et al. 2008; Fredericks et al. 2010) are described in the literature, yet every variation of MPD requires the manipulation and management of downhole circulating and static pressure. Effectively managing downhole pressures and annular pressures is one of the key requirements of any drilling fluid for any drilling operation – both MPD and non-MPD drilling operations – and is arguably one of the most important. Engineering drilling fluids is also an adaptive process that applies equally to open circulating systems as it does to closed circulating systems and requires the same critical design factors of wellbore geometry, pump rates, downhole drilling fluid density and rheological behaviour, cuttings concentration, and drill pipe dimension to be considered when managing downhole hydraulics. Whilst the influence of drilling fluid properties to MPD operations is eluded to in the technical notes of IADC, it is often the case that the tools and equipment required for an MPD operations are superimposed on an existing drilling fluid system in order to enlarge the hydraulic operating window between pore pressure and fracture pressure. Whether the drilling fluid design alone can be optimised in such a way to effectively manage downhole hydraulics and negate the need for an ‘MPD equipment solution’ in the first place is not always the first question posed when considering how to drill a well that has particularly narrow hydraulic operating margins. New Drilling Fluid Developments Just as the design and engineering of MPD tools, equipment and techniques have improved over the last 5 years, advances in drilling fluid design and processing engineering software have also been made that similarly converge on the objectives of MPD.

The rheological behaviour of any drilling fluid in an open or closed circulating system is critical to achieving the drilling objectives of that section. Should the drilling fluid rheology be inappropriately engineered to meet these objectives, especially in those drilling operations that carry a high degree of operational risk, there is exists the potential for drilling fluid related non-productive time (NPT). Poor hole cleaning and the build up of cuttings beds on the underside of the hole may result in pack-offs and stuck pipe; settlement or separation of the weight material may cause density variations in the annulus with well control risks; excessively high circulating pressures especially under cold, deepwater conditions could exceed fracture pressure resulting in lost circulation; excessively high and progressive gel strengths after periods on non-circulation will result excessively high swab-and-surge pressures also leading to fluid influxes or losses. A complete description of the downhole rheology of drilling fluids can only be gained by extensive laboratory testing under simulated downhole conditions of pressure and temperature during the planning stage, with the results forming the input data for engineering design software that is able to analyse the rheological affects on the well hydraulics.

The conventional approach to optimising drilling fluids for hydraulically critical wells is to establish, through laboratory testing, the compromise between sufficiently high rheology and gel strengths to adequately suspend high-density weighting agents (usually barite), yet have sufficiently low enough rheology to effect adequate control of downhole hydraulics. With a density of 4.2 g/cm3 and a particle size specified by API of <3% retained on a 75-micron screen, drilling-grade barite is prone to sediment from a drilling fluid in deviated wells. Viscosifiers, gellants and rheological modifiers are added to increase rheology and maintain barite in suspension, which in turn, can lead to higher equivalent circulating densities (ECD) and pump pressures. As well trajectories have become more extreme over the last decade and well geometries more severe, this has pushed the technical limits of drilling fluids to the extreme, to the extent that the rheological compromise between the need for barite suspension with downhole hydraulic performance is, in some cases, irreconcilable.

A totally new approach to drilling fluid design was developed that uncoupled drilling fluid rheology from the risk of barite sag and settlement. By reducing the particle size of API Barite from 97% less than 75 micron to 97% less than 5 micron, the rate of sedimentation in a drilling fluid is significantly reduced. According to Stokes Law, a 10-fold reduction in particle size will reduce settling rates by a factor of 100. A treatment process while grinding ensures that the micronized barite remains

SPE/IADC 139623 3

permanently and fully dispersed, and the effects normally associated with colloidal particles in drilling fluids are not evident. The use of treated micronized barite (TMB) in drilling fluids signifies the first major variation from drilling-grade barite since it was first used to densify drilling fluids 90 years ago and more significantly, solves the apparent irreconcilable requirement for a drilling fluid of low rheology providing low ECD’s, swab and surge and with minimal risk of barite sag.

Low-rheology TMB systems have found increasing use as reservoir drilling fluids in extended reach, horizontal and through tubing wells; HTHP wells and as completion fluids (Frimreite et al. 2004; Massam et al. 2004; Taugbol et al. 2005; Oakley 2006; Bolivar et al. 2007; Matlock and Conn 2007; James et al. 2008; Walker et al. 2009), but only recently have they been coupled to MPD operations with the hydraulic advantages they offer to enlarge the hydraulic operating window and reducing drilling risk. These new elements of drilling fluid design reduce ECD, break-circulation pressures, swab-and-surge pressures beyond that of conventionally formulated drilling fluids. For some applications, these new advances in drilling fluid design not only present an alternative and economical option to the equipment hardware of MPD, but by combining these unique drilling fluid design attributes of reduced annular pressures, together with the equipment, tools and services of MPD allows for even greater control of annular pressures, thus effectively enlarging the hydraulic operating window even further.

Fluids that compliment the drilling objectives of MPD have the potential for operators to economically access drilling targets previously thought unobtainable due to the pressure profiles and geological conditions that have an unacceptable high level of NPT risk. Arguably then, specialized drilling fluids such as low-rheology TMB systems designed to reduce and better manage the downhole hydraulics of critical wellbores may be considered to be part of the MPD ‘tool box’ as defined by the IADC definition. Real-Time Management of Downhole Drilling Fluid Hydraulics Knowledge of downhole drilling fluid hydraulics is critical in order to achieve the desired drilling objectives safely and economically. Downhole pressure is also influenced by downhole temperature and pressure effects on drilling fluid density and rheology, pipe movements, rotational speed, pipe eccentricity, cutting concentration, cuttings bed height and other factors. PWD tools are able to convey real-time downhole hydraulic information from behind the bit to the surface enabling the driller to navigate through narrow pressure margins using MPD choke controls. However, there may be circumstances when PWD data is unavailable, either because the tool has failed, is not installed in the drillstring, bottomhole temperature exceeds the working capability of the PWD tool, or while tripping, running casing or during connections when the PWD tool cannot transmit the necessary information, thus making critical swab/surge and break-circulation pressure data unavailable to the driller. A Wellsite Computer System (WCS) has been developed that models the downhole hydraulic environment in real-time for water- and non-aqueous-based fluids under temperature and pressure, and through suitable hardware interfaces, displays the predicted ECD and other data to the driller. Such a system is designed to compliment, but not replace PWD.

Modelling downhole hydraulics depends on understanding how the rheological properties of the drilling fluid are affected by temperature and pressure. Rheology data from the HTHP viscometers such as the Fann 70/Fann 75 (500°F/20,000 psi) is coupled to PVT (pressure-volume-temperature) data on the different liquid phases of the drilling fluid to calculate downhole Equivalent Static Density (ESD) and Equivalent Circulating Density (ECD) at any point in the well given knowledge of drillstring geometry, hole size, pipe rotation, eccentricity and flow regime. Swab-and-surge pressures may be predicted based on pipe velocity and acceleration, or conversely, pipe running speeds may be limited to within the boundaries of swab/surge pressures predicted by the WCS. Break-circulation pressures are calculated that allow connection practices with respect to pipe rotation and flow rates to be optimised without exceeding downhole fracture pressures. Hole-cleaning efficiency and effects on downhole pressure combine all elements of flow rate, rheological behaviour, and wellbore geometry using analytical and fuzzy logic techniques to predict the location of cutting beds in the wellbore and potential trouble spots. Case History #1 An operator offshore UKCS drilled approximately 1,600-ft long 8½-in. horizontal reservoir section to approximately 12,500-ft MD requiring a non-aqueous based fluid with 10.5-lb/gal surface mud weight. The reservoir sand had an anticipated ECD fracture pressure of 12.8 lb/gal and a possible interbedded shale horizon that required a minimum ESD of 12.0 lb/gal for wellbore stability. Thus the hydraulic operating window was 0.8 lb/gal while drilling. Hydraulic modelling indicated that a drilling fluid system weighted with drilling-grade barite would exceed the fracture pressure if a surface mud weight of 12.0 lb/gal was used at flow rates above 250 gal/min (Table 1).

Table 1: ECD and Pump Pressures while Circulating

Treated Micronised Barite System API Barite weighted systemSurface Mud Weight 12.0 lb/gal 12.0 lb/gal Break Circulation 73 (12.05 lb/gal) 313 (12.37 lb/gal) 250-gal/min Flow Rate ECD at TD 12.28 lb/gal 13.07 lb/gal Pump Pressure 1,039 (lb/in2) 1,433 (lb/in2) 500-gal/min Flow Rate ECD at TD 13.21 lb/gal 13.66 lb/gal Pump Pressure 3,334 (lb/in2) 4,068 (lb/in2)

4 SPE/IADC 139623

Though a treated micronised barite system promised to significantly reduced both ECD and break-circulation pressures at TD, due to the unknown pressure profile of the shale and the possibility that future development drilling would require even smaller operating margins, MPD equipment was fitted and a TMB fluid programmed with a surface mud weight of 10.5 lb/gal with MPD applying annular backpressure to 12.0 lb/gal equivalent. For optimum control drilling and tripping, a WCS was synchronised to the mud logging unit and rig system to simulate and pre-empt any hole cleaning issues, provide tripping schedules and to simulate hydraulics in real time including MPD choke pressures. Typical rheological properties of the TMB system and the impact on break-circulation and frictional pressure losses are shown in (Table 2).

Table 2: Typical TMB Drilling Fluid Properties Compared to a Conventionally Weighted System

with a WCS Hydraulic Comparison Case History #1 Treated Micronised Barite System API Barite Weighted System

Density (lb/gal) 10.6 10.6 Plastic Viscosity (cP) 11 23

Yield Point (lb/100 ft2) 6 13 Gel Strength (lb/100 ft2) 4/6 10/14

6-rpm value 3 9 HTHP Fluid Loss (mL/30 min using 35-µ ceramic disc) 4.2 4.2

ESD at TD (lb/gal at 525 gal/min) 11.01 11.00 ECD at TD (lb/gal at 525 gal/min) 12.14 12.28

Total System Pressure (psi at 525 gal/min) 2,252 2,676 Break Circulation (psi & lb/gal eq.) 108 psi or 11.21 lb/gal 317 psi or 11.58 lb/gal

A 10.5 lb/gal TMB system was displaced into the hole with the bit in new formation below the shoe, the MPD and PWD

indicated 11.80 lb/gal, while the WCS was showing 11.77 lb/gal. The average flow rate was 525 gal/min and pump pressure 2,800 psi. 13 lb/gal of the TMB fluid was spotted from surface to approximately 3,800 ft for a trip to replace a failed PWD tool. This density ensured an even 12.0-lb/gal hydrostatic bottomhole pressure which equates to 425 psi equivalent above a 10.55-lb/gal ESD fluid (Figure 1).

Figure 1: ECD, ESD and Applied Backpressure for Case History #1.

Tripping schedules generated by the WCS indicated no restrictions on tripping speeds up to 30 seconds/stand at 9.6- and

10-lb/gal pore pressure and the round trip was completed without incident and 10.5-lb/gal TMB fluid displaced back in the hole simulated by the WCS. With an average flow rate of 525 gal/min and pump pressure 2,800 psi, manually applied backpressure by the MPD equipment varied between 120 and 180 psi while circulating to maintain a minimum ECD of between 12.0 and 12.8 lb/gal (Figure 1). Hole cleaning simulations by the WCS accurately predicted the formation of cuttings beds during under-reaming operations and drilling parameters were optimised accordingly. Typical break-circulation pressures with the 10.55-lb/gal TMB system at 130 gal/min were 12.33-lb/gal equivalent. At connections, the lower break circulation with the TMB system ensured minimal pressure pulsing that might destabilise the wellbore. At TD, a 12-lb/gal TMB fluid was displaced into the well to run openhole sand screens at 358 gal/min exceeding the fracture pressure. Both the PWD and WCS indicated the ECD would be close to the fracture gradient during the displacement, so the pump rate was reduced to 189 gal/min, which is the minimum flow rate necessary for the PWD tool to operate. Screens were then run to TD without incident.

Other observations related to the WCS and TMB system included: • Modifying connection practices that reduced time without compromising hole conditions and the formation of

cuttings bed. • A continual display of ECD during connections meant that swab and surge induced pressures were minimal. • Verifying PWD measurements with the WCS avoided reliance on the PWD by the MPD operators to manually

control backpressure.

SPE/IADC 139623 5

• No wellbore instability issues with the shale formation in the reservoir section, facilitated by low break-circulation pressures.

• An increase in the rotary speed to improve hole cleaning by the WCS was recommended and accurately predicted. • Hole cleaning deficiencies were accurately predicted and acted upon well in advance of any potential non-productive

time. • Slow circulation rates without exceeding the fracture pressure were achievable without promoting dynamic barite sag. • Fluid properties remained stable throughout the section with the Plastic Viscosity averaging 11 cP and the Yield Point

of 6 lb/100 ft2 with no evidence of barite sag, settlement or mud weight changes. Case History #2 A client operating in nearly 3,000 ft of water in the Gulf of Mexico was drilling a problematic 6-in. diameter well that was hydraulically limited by a fracture pressure of 16.8 lb/gal and pore pressure of 14.8 lb/gal equivalent mud weight at the narrowest point (Figure 2).

Figure 2: Pore Pressure and Fracture Pressure Window for Case History #2.

Table 3: Typical TMB Drilling Fluid Properties Compared to a Conventionally Weighted System Case History #2 Treated Micronised Barite System API Barite Weighted System

Density (lb/gal) 14.2 14.2 Plastic Viscosity (cP) 28 24

Yield Point (lb/100 ft2) 9 20 Gel Strength (lb/100 ft2) 7/8 20/23

6-rpm value 4 8 HTHP Fluid Loss (mL/30 min) 4.2 3.6

ESD at TD (lb/gal at 525 gal/min) 14.87 ECD at TD (lb/gal at 525 gal/min) 15.25

Total System pressure (psi at 525 gal/min) 4,250 The target depth was approximately 22,000 ft at 40° inclination and a low-rheology 14.1-lb/gal TMB system while still

retaining the MPD services. A trip out the hole was initially made at 5 minutes per stand, later reduced to 3 minutes per stand while maintaining annular backpressure of 200 psi. Drilling resumed at 233-gal/min flow rate with PWD showing ECD values of 14.94 lb/gal and ESD of 14.75 lb/gal while maintaining 150 to 200 psi of annular pressure. After a series of staged mud weight increases to 14.5 lb/gal in an attempt to control gas influxes, the well was plugged and sidetracked. The sidetrack section drilled with a 14.2-lb/gal TMB fluid, with the PWD showing an ECD of 15.07 lb/gal and ESD of 14.6 lb/gal at the start of the sidetrack that increased to 15.22 and 14.8 lb/gal respectively by TD as the mud weight increased to 14.5 lb/gal. MPD services maintained 150 psi at connections and on trips. The section was successfully completed. Discussion and Conclusions As the trend towards more complex wellbore geometries, architecture and trajectory increases, so too does the stress placed on the drilling fluid requirements to safely and efficiently drill these well types with the minimum of non-production time.

6 SPE/IADC 139623

Extended Reach Drilling (ERD), Horizontal and Through Tubing Drilling (TTRD) drilling from onshore and offshore drilling locations and in deepwater are just some of the drilling techniques employed to access compartmentalised hydrocarbons at the periphery of reservoirs, or in satellite fields. In many cases the technical limit of drilling fluids is reached and conventional approaches to reconcile the apparent conflicting requirements of sufficiently high rheology for barite suspension and low rheology for effective ECD management does not satisfy the requirements imposed by the well architecture.

Drilling-grade barite, as defined by API Specifications in terms of particle size, density and other chemical criteria has long been used as the weighting agent in drilling fluid since the early 20th century, but it has not fundamentally changed since that time, despite the significant advances in drilling fluid chemistry, systems and drilling technology. It remains the building block of drilling fluids for mud weight control but arguably, it can be viewed as a 90-year-old product still being used in 21st century drilling applications. Other than density control, barite provides little other value to a drilling fluid and may be regarded as a problematic product since gellants and viscosifiers are required to suspend barite and to prevent it from settling out in the wellbore and surface tanks, which in turn can limit the ability to adequately manage downhole ECD and pump pressures in the more critical types of drilling operations.

Managed Pressure Drilling technique is rapidly gaining favour in some of these more complex well types. While the benefits of both the low-rheology TMB drilling fluid system and MPD are to reduce ECD and manage narrow hydraulic operating windows imposed by well design (and pore pressure / fracture pressure gradient), by combining TMB into the ‘basket of technologies’ under the IADC definition for Managed Pressure Drilling and using a bespoke fluid solution and an equipment solution to drill ever decreasing hydraulic windows provides considerable synergies compared to drilling fluids formulated with drilling-grade barite.

The authors conclude that coupling Wellsite Computer Systems to low-rheology TMB drilling fluid systems and MPD operations greatly reduces drilling risk allowing operators to more safely drill and complete wells that are at the limits of current drilling fluid technology.

In summary, many wells that are considered undrillable due to the narrow hydraulic operating margins may now be drillable using the unique synergies of TMB drilling fluids and MPD operations in the following respects:

• ECD’s are up to 50% lower with low-rheology TMB systems compared to a conventionally weighted system and use of low-rheology TMB systems effectively enlarges the hydraulic operating window. This hydraulic window is widened further with MPD operations.

• Flow rates are 15 – 25% higher for the same pump pressure compared to conventionally weighted fluids, thus giving greater flexibility to the MPD operation to navigate the wellbore through depleted zones.

• Break-circulation pressures are an order of magnitude lower with low-rheology TMB drilling fluid systems, thus reducing the risk of downhole losses during MPD operations and excessive NPT. Swab-and-surge pressures are lower due to the lower gels strengths of TMB fluids.

• The use of the Wellsite Computer System adds additional real-time well-control assurance during trips and casing running and during periods when the PWD tool is unable to communicate with the surface.

• Given the lower swab pressures tripping schedules are higher, the efficiency of tripping while applying backpressure is enhanced.

• Dilution factors are lower with TMB system due to the fact finer shaker screens can be deployed, improving solids removal efficiency, reducing dilution and product consumption.

• Barite sag risk, both static and dynamic, is reduced due to the micron sized particles of TMB. • PWD tool response is improved in TMB fluids due to the lower rheological profile providing more rapid and true

PWD pressure transmission of downhole near bit conditions. Acknowledgments The authors would like to thank the many contributors to this paper and the management of M-I SWACO for permission to publish this paper. References Armone, M. and Vieira, P. 2009. Drilling Wells with Narrow Operating Windows Applying the MPD Constant Bottom Hole Pressure

Technology – How Much the Temperature and Pressure Affects the Operation’s Design. SPE 119882, SPE/IADC Drilling Conference, Amsterdam, 17-19 March.

Bolivar, N., Young, J., Dear, S., Massam, J. and Reid, T. 2007. Field Result of Equivalent Circulating Density Reduction with a Low-Rheology Fluid. SPE 105487, SPE Drilling Conference, Amsterdam, 20-22 February.

Chustz, M.J., Smith, L.D. and Dell, D. 2008. Managed Pressure Drilling Success Continues on Auger TLP. SPE 112662, IADC/SPE Drilling Conference, Orlando, Florida, 4-6 March.

Fimreite, G., Asko, A., Massam, J., Taugbol, K., Omland, T.H., Svanes, K., Kroken, W., Andreassen, E and Saasen, A. 2004. Invert Emulsion Fluids for Drilling Through Narrow Hydraulic Windows. SPE 87128, IADC/SPE Drilling Conference, Dallas, 2-4 March.

Foster, J.K. and Steiner, A. 2007. The Use of MPD and an Unweighted Fluid System for Drilling ROP Improvement. SPE 108343, IADC/SPE Managed Pressure Drilling and Underbalanced Operations Conference, Galveston, Texas, 28-29 March.

Fredericks, P., Garcia, G., Sehsah, O. 2010. Managed Pressure Drilling Avoids Losses while Improving Drilling and ECD Management in the Gulf of Thailand. SPE 130316, SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference, Kuala Lumpur, Malaysia, 24-25 February.

SPE/IADC 139623 7

International Association of Drilling Contractors (IADC), Underbalanced Operations and Managed Pressure Drilling Committee. 2006. “UBO & MPD Glossary.” April. Available at: http://www.iadc.org/committees/ubo_mpd/completed_documents.html.

James, R., Prebensen, O.I. and Randeberg, O. 2008. Reducing Risk by Using a Unique Oil-Based Drilling Fluids for an Offshore Casing Directional Drilling Operation. SPE 112529, IADC/SPE Drilling Conference, Orlando, Florida, 4-6 March.

Malloy, K.P. 2007. Managed Pressure Drilling – What is it Anyway? World Oil (March) p27-34. Malloy, K.P. and Shayegi, S. 2010. UBD or MPD: An Engineering Choice Based on Intent. SPE 130563, SPE/IADC Managed Pressure

Drilling and Underbalanced Operations Conference, Kuala Lumpur, Malaysia, 24-25 February. Malloy, K.P., Stone, C.R., Medley, G.H., Hannegan, D., Coker, O., Reitsma, D., Santos, H., Kinder, J., Eck-Olsen, J., McCaskill, J., May, J.,

Smith, K. and Sonneman, P. 2009. Managed-Pressure Drilling: What it is and What it is Not. SPE 122281, IADC/SPE Managed Pressure Drilling and Underbalanced Operations Conference, San Antonio, Texas, 12-13 February.

Massam, J., Popplestone, A. and Burn, A. 2004. A Unique Technical Solution to Barite Sag in Drilling Fluids. AADE-04-DF-HO-21, AADE Drilling Fluids Conference, Houston, 6-7 April.

Matlock, W. and Conn, L. 2007. Unique Micronized Weight Material Delivers Ultra-Thin NAF to Optimise ERD Drilling. SPE110584, SPE Annual Technical Conference, Annahein, California, 11-14 November.

Nauduri, S., Medley, G.H. and Schubert, J.J. 2009. MPD: Beyond Narrow Pressure Windows. SPE 122276, IADC/SPE Managed Pressure Drilling and Underbalanced Operations Conference, San Antonio, Texas, 12-13 February.

Nauduri, S., Medley, G.H. and Schubert, J.J. 2010. MPD Candidate Identification: To MPD or Not To MPD? SPE 130330, SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference, Kuala Lumpur, Malaysia, 24-25 February.

Oakley, D.J. 2006. Specially Treated Drilling Fluid Weighting Agent Facilitates Development of Maturing Reservoirs. AADE-06-DF-HO-27, AADE Fluid Conference, Houston, 11-12 April.

Roes, V., Reitsma, D., McCaskill, J. and Hefren, F. 2006. First Deepwater Application of Dynamic Annular Pressure Control Succeeds. SPE 98077, IADC/SPE Drilling Conference, Miami, Florida, 21-23 February.

Syltou, S., Eide, E.E., Torvund, S., Berg, P.C., Larsen, T., Fjeldberg, H., Bjorkevoll, K.S., McCaskill, J., Prebensen, O.I. and Low, E. 2008. Highly Advanced Multitechnical MPD Concepts Extends Achievable HPHT Targets in the North Sea. SPE 114484, SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference, Abu Dhabi, 28-29 January.

Taugbol, K., Fimreite, G., Prebensen, O.I., Svanes, K., Omland, T.H. and Svela P.E. 2005. Development and Field Testing of a Unique High-Temperature/High-Pressure (HTHP) Oil-Based Drilling Fluid With Minimum Rheology and Maximum Sag Stability. SPE 96285, SPE Offshore Europe Conference, Aberdeen, 6-9 September.

Van Oort, E., Roy, S., Zamora, M. and Toups B. 2005. Real Time ECD Simulation and Management Using a Remote Operations Center. SPE 92605, SPE/IADC Drilling Conference, Amsterdam, 23-25 February.

Walker, M., Veselka, A. and Harris, S. 2009. Increasing Sakhalin Extended Reach Drilling and Completion Capability. SPE 119373, SPE/IADC Drilling Conference, Amsterdam, 17-19 March.

Zamora, M., Roy, S., Caicedo, H.Y., Froitland, T.S. and Ting, S.T. 2000. Major Advancements in True Real Time Hydraulics. SPE 62960, SPE Annual Technical Conference, Dallas, 1-4 October.

Zamora, M. and Roy, S. 2000. The Top 10 Reasons to Rethink Hydraulics and Rheology. SPE 62731, IADC/SPE Asia Pacific Drilling Technology Conference, Kuala Lumpur, Malaysia, 11-13 September.