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D rilling I nnovations V ol ume 2 , No. 2 , 2 0 1 4

A sp e rry D RILL ING Tec h nology Jour nal

In This Issue

Advancements in Powered Rotary Steerable Technologies Result in Record-Breaking Runs See pages 4-9 Optimized Platform Placement to Cover All Geological Targets in Baronia Field See pages 35-40

Executive Steering Committee Eric Carre Senior Vice President, Drilling and Evaluation Ahmed Kenawi Vice President, Sperry Drilling

A Message from Ahmed Kenawi

Greg Powers Vice President, Technology

Editorial Advisory Committee Welcome to the fourth issue of Drilling Innovations – a technical journal that focuses on Halliburton solutions and technical successes. Halliburton is uniquely positioned to solve increasingly complex drilling challenges by utilizing the expertise offered by Drilling Engineering Solutions (DES) – an integration between Sperry Drilling, Baroid and Drills Bits and Services. DES strengthens Halliburton’s ability to offer customers risk mitigation, optimized well bore placement for increased reserve recovery, and maximized drilling performance. An integrated performance drilling systems approach has helped our customers in challenging environments. In this issue, several papers illustrate how an integrated solutions-based approach been successful. For example, a through motor telemetry (TMT) powered rotary steerable system combined with early planning, risk assessment and global experience set new records, and exceeded benchmarks in difficult formations. Another paper explains how careful planning and collaboration among subject matter experts resulted in high production levels in two multilateral wells due to the effective execution of the drilling and completion phases. These examples, along with the rest of the papers in this issue, highlight the tangible benefits of drilling optimization. By using cutting edge technology and collaborating with the right technical experts, Sperry can provide customers with the solutions needed to drill safe, faster and on target every time. Additionally, you can find more in-depth information about Sperry’s drilling expertise in the Drilling Engineer Solutions and Applications Handbook, which I encourage you to ask your Halliburton contact about. Please enjoy this issue of Drilling Innovations, and as always, feel free to contact me if you have any questions.

Kind regards,

Mac Upshall Akshay Sagar Andreas Grossmann Derrick Lewis

Managing Editor Roselle Mohle

Circulation Steven Thrift

Design Griffin Creative Company This magazine is published biannually by Halliburton Sperry Drilling. For comments and suggestions, please contact: [email protected].

Sperry Drilling’s DrillDOC® collars provide the measurements necessary to fully understand downhole drilling dynamics. They deliver real-time measurement of torsion, weight, bending and vibration measurements. Directly measuring tension, torsion, bending and vibration identifies the actual drilling parameters that are being applied to the bottomhole assembly (BHA) and the bit. These measurements, utilized by our experts can give operators greater insight into the wellbore to reduce uncertainty, minimize unplanned events and optimize the drilling performance.

Ahmed Kenawi Sperry Drilling Vice President

© Copyright 2014 Halliburton All rights reserved.

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Contents

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4  Advancements in Powered Rotary Steerable Technologies Result in Record-Breaking Runs

Geo-Pilot® GXT Rotary Steerable System Fit-For-Purpose Solution

9 Planning Managed Pressure Drilling With Two-Phase Fluid in a Depleted Reservoir

Managed Pressure Drilling Bergermeer Gas Storage Project

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17 Multilateral TAML Level 4 Junction Provides Maximum Flexibility for Drilling and Intelligent Completions

Planning and Executing an Intelligent Multilateral Well

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23 Challenges and Successes in Horizontal Drilling Shallow 3D Unconventional Turbidite Reservoir, Mexico E xploiting Vast Oil Resources in Mexico’s Chicontepec Basin 31 Instrumented Motors Prove Crucial in Unconventional Well Placement

Real-Time Geosteering with Gabi™ Motor

34 Optimized Platform Placement to Cover All Geological Targets in Baronia Field

Enhanced Oil Recovery Project Malaysia

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40 Overcoming Extreme Weather Conditions by Drilling with Mpd Offshore in the Arctic

Alaska Field Improves Drilling Economics with MPD

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45 Are You on the Right Track with Casing Milling? Innovative Precision-Milled Windows Offer Improved Casing Exit Reliability for Sidetracking and Multilateral Completions

MillRite® System Premium Replacement for Conventional Milling

34 40 45

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Advancements in Powered Rotary Steerable Technologies Result in Record-Breaking Runs

drilling applications. Operators drilling extendedreach wells do not want to cause excessive wear on casing strings; additionally, operators want a solution to mitigate stick-slip. TMT powered RSS is bringing these and other important benefits to the drilling process.

Hernando Jerez, SPE, and Jim Tilley, SPE, Halliburton

Applications

Copyright 2014, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Latin American and Caribbean Petroleum Engineering Conference held in Maracaibo, Venezuela, 21–23 May 2014. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, 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 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 copyright. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission.

Abstract Drilling operators continually experience increasing pressure to achieve all objectives safely and at the lowest cost. Powered rotary steerable systems (RSS), applied within the correct drilling environment, can improve rate of penetration (ROP), lower risks, and reduce non-productive time (NPT), which can decrease drilling costs. Using through motor telemetry (TMT) technology, a wired motor with a hollow rotor and flex shaft, allows a connection between rotary steerable systems (RSS) and logging while drilling (LWD) downhole tools. A conductor passes power and communication through the motor to operate and steer the RSS. The wired power section uses a uniform wall thickness stator design that reduces heat production and retention. It also delivers higher rev/min and torque directly to the RSS and bit. Using the TMT powered RSS not only has improved ROP, but has also mitigated stick-slip vibration and reduced NPT. The NPT improvements have been identified in areas, such as slip-stick vibration, drill string failures, drill string torque variations, casing wear, and rig equipment failures. Early planning and risk assessment have also been key. Experience across the globe, both on and offshore, are presented to show the benefits of integrating advanced drilling technologies, such as TMT powered RSS and real-time downhole measurements with effective planning, to reap tangible benefits from drilling optimization. With improved performance as a result of increased torque capacity and bit speed, and reduction of the stick-slip mechanism, this new motor-driven rotary steerable technology has delivered superior performance and improved ROP in challenging medium and hard formations. After more than 10,000 drilling hours and nearly half a million feet drilled, TMT powered RSS technology is setting new records and exceeding benchmarks by bringing greater horsepower to the rock destruction process with longer runs and higher ROPs.

Introduction

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Optimized drilling systems include not only matched drilling tools, but also the integration of technology, processes, and people across all stages of the drilling process1. This is important as the industry places emphasis on improvement to drilling programs to reduce NPT, improve safety and efficiency, and optimize production.

drilling tools have greatly improved drilling efficiency and allowed much higher ROPs. Choosing the proper drilling system is critical to boosting the well construction process and pushing the drilling limit. The proper BHA design and modeling is critical to drilling the well and contributes to the optimization of drilling efficiency.

Fit-for-purpose bottomhole assemblies (BHAs) together with a wide array of advanced downhole

Delivering power downhole without increasing the rotary speed of the drillstring is a demand in some

TMT powered RSS has a broad range of applications, focused mainly on performance drilling and mitigating certain drilling phenomena, such as vibration. Because of the wired connection and the modular design, drilling optimization or formation evaluation sensors can be incorporated in front of the wired motor, providing great versatility to the BHA configuration. From a performance point of view, TMT powered RSS increases ROP, decreases vibration, and decreases casing wear by delivering the torque directly to the bit. The power section decouples the drilling string from the RSS, eliminating torsional vibration common in RSS applications. This benefit increases reliability not only for the RSS but also for all of the electronic sensors in the string including optimization and formation evaluation sensors. In addition, the drill bit lasts longer and can deliver better ROPs. An important application for TMT powered RSS is in instances when the drilling rig experiences limit capacity related to top drive power to rotate the drilling string or drillpipe torque limitations. Using a TMT powered RSS can reduce stress on the rig and reduces wear on topdrive and drill pipe. Extended-reach drilling (ERD) and complex well profiles are classic applications for TMT powered RSS by reducing surface torque and increasing reach capabilities. A TMT powered RSS allows a variety of sensor combinations for multiple applications, including geosteering, performance drilling, and reduced stick-out in casing while drilling applications.

Benefits • More energy is directly applied to the bit, improving cutting efficiency and ROP while also overcoming stick-slip and torsional related dysfunctions. • Decoupling of the bit from the drillstring reduces transmission of vibrations to LWD and other BHA components, improving life. • Drill string rotary speed can be reduced

to minimize casing wear while bit speed is optimized for the best drilling performance. • When applied in the proper drilling environment, TMT powered RSS improves ROP and reduces NPT, leveraging to drill faster and with less risk, resulting in decreased costs. • Improved ERD capabilities and exposure of the payzone, which can greatly reduce capital expenditure. • The TMT powered RSS shows capability of significantly increasing ROP in conditions where rig topdrive does not provide adequate torque and surface rev/min.

TMT Motor Design RSS’s generally require communication with the measurement while drilling (MWD) system to transmit directional control information to the surface and to transmit directional commands from the surface to the RSS. Directional information from the RSS is critical information for the directional driller to help ensure the well path is being drilled according to the directional plan. Communication between the RSS and MWD is also required to send formation evaluation information from sensors located in the RSS to the surface. An example is the azimuthal gamma ray sensor located in the RSS. Wiring the RSS motor allows transmission of power and high speed communications between the RSS and the MWD. The power section is designed for high torque low speed operation. Fig. 1 shows a schematic of the main components of TMT. The main challenges in the wired motor design include compensating for the eccentric motion of the rotor in the power section, passing the transmission section and the bearing pack and compensating for different rotational speeds between the rotor and upper housing.

TMT Motor Design Features The rotor in a power section has an eccentric and axial motion that is a function of the lobe

Figure 1. – TMT main components.

configuration, the fewer the lobes, the higher degree of eccentric motion. When passing a conductor from the top of the rotor to the top of the motor housing, this eccentric and axial motion must be compensated for. The method employed is to use a mechanical compensator that compensates for movement in the axial and radial directions while providing a bidirectional continuous conductor for power and communications transmission. Rotation must also be compensated for because the rotor is decoupled from the upper housing in the rotational sense. A slip ring is employed to allow for the differential rotation while, at the same time, providing a conductor for stable power transmission and for high frequency, high speed communications. The TMT motor design employs a titanium flex shaft to transmit rotation from the power section to the driveshaft. The flex shaft design allows incorporation of a solid conductor through a bore in the center. In addition, the titanium flex shaft provides high torque capability to drive higher loading below the wired motor. The TMT motor has flexibility to use virtually any conventional power section provided the torque and rev/min specification is within the tool limits and application requirements. The preferred power section type is uniform wall thickness. The uniform wall thickness power section provides higher torque output and a higher temperature rating. Higher torque capability will allow for smoother rotation of the RSS and drill at a higher ROP. In addition, the uniform wall thickness expands with temperature at a constant rate. Thinner rubber thickness that expands at a constant rate means that the rotor and stator can be fit precisely for high temperature application. This allows application of the TMT technology at temperatures up to 175°C.

Wired Motor— RSS BHA Design The placement of a motor in an RSS assembly requires consideration of the impact on the MWD, RSS, and BHA performance. The system described here is modular in design, which allows flexibility in placement of the motor in the BHA. The motor can be placed between the RSS and MWD or within the modular MWD components. The optimum placement of the power section is normally directly on top of the RSS and below the MWD. This placement allows torque to be delivered directly to the RSS, allows higher bit speed without over-rotating the MWD, minimizes the amount of string below the power section, and decouples vibration to the MWD and upper string. The BHA can also be designed with drilling optimization sensors or LWD sensors located below the motor. Placement of the drilling optimization sensor below the motor and above the RSS can be used to measure torque, weight on bit (WOB), and bending on bit, for example, directly above the RSS for drilling optimization. LWD sensors can be placed directly above the RSS and below the motor to obtain measurements closer to the bit. The wired motor can also be configured with a bent housing for conventional motor applications, allowing power and communication to the bottom of the motor and placement of sensors directly on top of the bit. Typical applications include ranging sensors for intersection wells and LWD sensors for near bit formation evaluation. Fig. 2. shows some BHA configurations depending on the application.

Figure 2. – Modular BHA configuration using a TMT powered RSS.

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Geological proposal, however, identified a hard/ abrasive drilling environment, multilayered dipping, and folded formations with dips in the range 40 to 70°. The stratigraphy of this area corresponds to the old Mesozoic and Paleozoic geological eras starting with the Cretaceous period, subjacent by Jurassic, Devonian, Silurian, and Cambric. On top of the hardness and abrasiveness, the geological cross-section shows important discontinuities with highly faulty events.

Figure 3. – TMT RSS application with vibration data above and below the motor.

Case History 1— Offshore Deepwater UK TMT powered RSS technology was used for an operator in a high-pressure/high-temperature (HP/ HT) development well in the UK Central North Sea. The challenge included maximizing ROP through hard chalk / limestone formations in the 12 1/4-in. section and then drilling the 8-in. hole section through the HP/HT reservoir using LWD, eliminating the need for wireline. In the 12 1/4-in. section, the TMT RSS assembly was used to drill from 5,276 to 13,938 ft (1,608 to 4,248 m) measured depth (MD). Average penetration rate was 78.6 ft/hr (24 m/hr), a 62% improvement over conventional rotary steerable system performance in an offset well. Total footage drilled was 8,662 ft (2,640 m) with zero NPT. In the 8 1/2-in. section, The HP/HT TMT RSS BHA with HP/HT LWD quad combo delivered the entire 2,323-ft (708-m) section in a single run, intersecting all geological targets with zero NPT. In what was the fourth longest section in the UK for drilling hours on bottom since records began, the LWD quad combo was downhole for 355 hr (14.8 days) with 296 circulating hr (12.3 days). Successful LWD performance eliminated the need for wireline logging, and the well reached total depth (TD) at 16,232 ft (4,948 m) 25 days ahead of plan. A major benefit of TMT technology is this case was decoupling the BHA to reduce vibration on the LWD and upper string. This reduces damage and potential NPT while, at the same time, improving ROP and drilling performance. Fig. 3. (a time based 6

log) shows that, while some torsional resonance vibration exists below the motor, it is not transmitted to the LWD tool and drillstring above. In this particular case, two downhole vibration sensors were part of the drill string, the first between the RSS and the TMT motor and a second one behind the TMT motor within the LWD. The left graph in figure 3 is the data from the sensor below the TMT, it shows in the track #4 high average values of vibrations both in Y and X axis; on the other hand, the right graph in the same track (sensor above the TMT) shows minimum or null average vibration values both X and Y axis. This is the decoupling effect from the TMT motor, which reduces transmission of vibrations.

The first well was drilled with a rotary BHA including a straight mud motor. Low ROP was experienced, and the hole inclination drifted until reaching an equilibrium angle around 20º. The drilling continued with the hole deviation moving in the 10 to 20º range of inclination. The equilibrium angle is dependent on various factors, including formation dip angle, drillability anisotropy, and drilling parameters in use. The well was TD with 13º of inclination and a vertical section of 270 m. For the second well, a drilling motor was used with both sliding and rotating drilling modes in both intervals (12 1/4- and 8 1/2-in. hole sizes), ROP was lower compared to the first well because of the directional work to keep the well close to vertical. The abrasiveness of the formation required performing several trips to drill each interval. Another well used a push the bit vertical seeking tool powered with a motor above it; this approach managed to drill the well vertical and improve ROP.

The vibration measured below the TMT motor was -5.0 g average x-y delta torsional resonance. The vibration measured above the TMT motor was -0.5 g average x-y delta torsional resonance, indicating a reduction due to the decoupling effect.

Case History 2—Continental Europe Exploratory Campaign In this vertical drilling application, the TMT powered RSS delivered maximum performance, outperforming the benchmark well in the area with RSS or performance motors. During a four-well exploratory campaign, different drilling systems were used aiming to maximize ROP. The structural setting in this continental Europe project corresponds to ancient Paleozoic and Mesozoic depositions. Because of limited drilling, not much information was known at the beginning of the project.

Figure 4. – (left) drilling time curve for the four wells campaign; (right) inclination data for the four wells.

Still, some drilling inefficiencies were experienced, including vibration that reduces the life of the bit. The last well incorporated a point the bit RSS together with a wired power section to drill both the 12 1/4- and 8 1/2-in. intervals. The TMT powered RSS system not only managed to keep the well close to 0º inclination but, because of the vertical cruise control mode in use, the drilling time was optimized by drilling the well in automatic vertical mode, maximizing ROP. Fig. 4. (left) shows the time drilling curve for the four exploratory wells. The TMT powered RSS also shows value to keep the well vertical. Fig. 4. (right) shows the deviation survey for the four wells. During the entire run, the TMT powered RSS observed a strong build tendency caused by the steeply dipping formation. The TMT powered RSS was operated with bit deflection over 60% and mainly at 80 to 90% to keep the wellbore vertical. Vibration mitigation measures were employed at the direction of real-time engineering monitoring; however, low to medium vibration severity was still present while drilling in the presence of interbedded formations; medium to high vibration was also present when picking up the bit off bottom.

secondary reservoir by dropping angle to 84° and steering inside that zone for approximately 900 ft. With an average ROP of 36.4 ft/hr in the 6 1/8-in. lateral section, this run also established a field record. Fig. 5. shows the trajectory created. In the build section alone, a field record average ROP of 59.60 ft/hr saved the operator 2days, or approximately USD 100,000, while in the 6 1/8-in. section. The geosteering assembly achieved a field record average ROP of 36.4 ft/hr to save the operator another 3 1/2 days, or about USD 175,000.

Case History 4 Unconventional Play Drilling efficiency requires attention to a variety of key indicators. Modeling BHAs together with advanced drilling technologies contributes to the stability of the drilling system, optimum performance, and ultimately improvement to efficiency. The fourth case history was in an unconventional play in which a TMT powered RSS was used to drill a long lateral section, performing better than the best well previously drilled using mud motors.

The lateral hole intervals had been traditionally drilled with motors, achieving ROP of 50 to 70 ft/ hr. Lately, however, rotary steerable systems were introduced to drill long lateral complex trajectories, which has resulted in increased ROP. The objective of this well was to use a TMT powered RSS to navigate in the best quality of rock while matching/exceeding the established benchmark ROP as a minimum. A TMT powered RSS assembly was used to drill the 8 1/2-in. lateral section of the well; total footage drilled with was 4,074ft MD in one run. Table 1 shows relevant data of the powered RSS application and presents run data, comparing a TMT powered RSS to a motor. The TMT powered RSS drilled in total 4,074 ft along the shale formation while geosteering and achieving good quality rock based on formation evaluation data in real-time. The effective ROP was more than fourfold compared with the ROP experienced in offset wells. The improvement of ROP by using the TMT powered RSS saved 24 hr of rig time. Fig. 6. shows thecomparison of TMT powered RSS and best offset mud motor run.

Case History 3— Middle East Hard Formation A mature field application in Kuwait required TMT technology to improve ROP in a hard formation. The well consisted of build and land sections in an 8 1/2-in. hole sizes, followed by a lateral section in 6 1/8-in. hole size. At the same time, a high degree of steerability was required because of geologic uncertainty. TMT technology, along with high build rate RSS, was chosen for this application.

Figure 5. – Realtime Geological Model Interpretation

In the 8 1/2-in. section, high build rate was required at landing because of formation tops coming in high. The required trajectory was achieved with record ROP in this field, 60 ft/hr average, including connections and reaming times. A total of 2,500 ft was drilled building angle from 4 to 88° inclination in 32.5 drilling hours versus the 3.5 days planned for the section. In the 6 1/8-in. lateral section, the assembly included a TMT powered RSS and LWD tools including geosteering service to navigate through the reservoir. The assembly successfully drilled the reservoir for 1,500 ft, and then steered into the

Figure 6. – Footage and ROP Comparison

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The matched uniform wall thickness power section powering a point the bit RSS improved steerability and reduced inefficiencies. Producing the power and speed as well as torque closer to the bit results in better steerability and a better wellbore quality. This led to a record lateral in terms of ROP. Drilling efficiency improved as vibration-related damage was reduced by minimizing stick-slip and by decoupling the LWD tools from damaging shocks and torsional vibration. Some vibration was experienced with the TMT powered RSS, mainly during circulation out of bottom. Fig. 7 shows a comparison of vibration experienced with both systems. The TMT powered RSS has been a drilling efficiency stepchange2. The proper planning in the right application can deliver great benefits for the well construction. Fig. 8 shows 2013 footage and drilling time using TMT technology.

Figure 7. – Stick-slip vibration comparison (TMT powered RSS vs. downhole motor).

Conclusions • The TMT powered RSS with improved performance as a result of increased torque capacity and bit speed and reduction of the stick-slip mechanism has delivered superior performance and improved ROP in challenging medium and in hard formations. • TMT wire technology is the most reliable way for a high speed and power communications between the RSS and the MWD, allowing for BHA design flexibility to accommodate placement of downhole sensors ahead of the power section. • A benefit of the TMT powered RSS is that it decouples the BHA, reducing vibration on the LWD and upper string. This reduces damage and potential NPT while, at the same time, improving ROP and drilling performance. • In a vertical drilling application, the TMT powered RSS has delivered maximum performance, outperforming the benchmark well in the area in comparison to RSS alone or performance motors. • The matched uniform wall thickness power section powering a point the bit RSS improves performance significantly in hard formations and HP/HT applications.

Acknowledgements

Authors

The authors thank the management of Halliburton for their support of this project and encouragement to publish this work.

Hernando Jerez has 21 years of experience working with Halliburton. He has served in multiple positions including field hand, operations, engineering and management. Hernando led Sperry Drilling operations in Venezuela and Mexico before moving to Houston where he is now the Drilling Tools product manager for Sperry.

References Alvord, C., Noel, B., Galiunas, L. et al. 2007. RSS Application From Onshore Extended-ReachDevelopment Wells Shows Higher Offshore Potential. Paper OTC 18975-MS presented at the Offshore Technology Conference, Houston, Texas, USA. 30 April–3 May. http://dx.doi. org/10.4043/18975-MS.

Figure 8. – TMT Powered RSS cumulative footage and drilling hours.

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Zimmer, C., Pearson, J., Richter, D. et al. 2010. Drilling a Better Pair: New Technologies in SAGD Directional Drilling. Paper SPE/ CSUG 137137 presented at the CSUG/SPE Canadian Unconventional Resources & International Petroleum Conference, Calgary, Alberta, Canada, 19–21 October. http://dx.doi. org/10.2118/137137-MS.

Jim Tilley is the global product manager for rotary steerable systems based in Houston, Texas. He received his BSc in petroleum engineering from Texas A&M University. Jim has been with Sperry Drilling since 1984 starting in field operations in the Gulf of Mexico and progressing through technology and management positions. He has been involved with rotary steerable systems operations and management since 2002. Jim is a long-term active member of SPE.

M A N A G E D PRESSURE D RI LLING B ERG ERMEER GA S S T OR A G E PRO J ECT

Planning Managed Pressure Drilling With Two-Phase Fluid in a Depleted Reservoir

operation. This paper documents the key planning considerations required to drill and complete a highly depleted reservoir using two-phase MPD techniques.

Martyn Parker, Jelle Wielenga, and Vladimir Bochkarev, TAQA; Isabel Poletzky, SPE, Mark Juskiw, and Saad Saeed, Halliburton

Introduction

Copyright 2014, SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition This paper was prepared for presentation at the SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition held in Madrid, Spain, 8-9 April 2014. 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. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission.

Abstract The Bergermeer Rotliegend sandstone reservoir has been depleted by production. This has substantially reduced reservoir pore pressure and well deliverability. Pressure depletion has been accompanied by an expected decrease in minimum in-situ stress, resulting in a substantially sub-hydrostatic drilling fluid density being required to enable drilling. As a result, Managed Pressure Drilling (MPD) using two-phase fluid has been chosen as the enabling technology for drilling and completing initial wells for the Gas Storage Bergermeer Project. MPD for the Bergermeer wells is defined as the use of two-phase flow of drilling fluid including nitrogen injection via a tieback casing to maintain bottom hole pressure (BHP) below the anticipated reservoir minimum in-situ stress at a long hole depth. Application of MPD technology in the Gas Storage Bergermeer Project will allow drilling the planned boreholes without exceeding minimum in-situ stress, minimizing the risks of differential sticking and drilling fluid losses if natural fractures are present. Reservoir pressure in the Rotliegendes reservoir was originally 238 bar (3451 psi) at 2100 m (6890 ft) subsea. By mid-2009, gas reinjection was started to bring the reservoir up to an operating pressure of 133 bar for gas storage operations. By May 2013, the time of drilling the 1st of the new gas storage wells into the Bergermeer reservoir, the formation pressure had been brought up to 81 bar in block 1 and 35 bar in the adjacent block 2. Due to permitting restrictions, it was not possible to drill a test/pilot well before drilling the first gas injection/production wells to physically determine formation rock strength. Therefore a decision was made to drill into the 81 bar reservoir with a target BHP of 117 to 127 bar; this equated to an equivalent circulating density (ECD) of 0.57 to 0.63 SG. Two wells were drilled during May–June 2013, one S-shaped vertical well in block 1 and one horizontal well into block 2. This was achieved maintaining a constant BHP within the predetermined window using MPD with gasified fluid; in reality it was possible to drill the wells with a very stable BHP with a 0.6 SG ECD. Dynamic formation integrity tests (FIT) were performed to determine the formation rock strength in a controlled manner using two-phase MPD techniques at predetermined depths in the reservoir; results indicated that rock strength was adequate for using conventional drilling techniques. Despite the successful implementation of MPD, future wells will be drilled conventionally although MPD could deliver the wells should the formations turned out to be weak, and it remains as an important contingency in case formation strength turns out to be weak in future wells. For the Gas Storage Bergermeer project, significant planning into the overall system design, equipment selection, techniques, procedures and training lead to an operation where precise control of the annular pressure profile was achieved and maintained throughout the

The Rotliegendes reservoir is Permian, and consists of well-sorted, fine-grained Aeolian sandstones. The average thickness of the reservoir is approximately 200 m. Porosity is generally high, ranging from 15 to 30%, and averaging 23%. Vertically, the best porosities occur in the middle part of the reservoir, with generally lower porosity in the upper portion in the Weissliegendes facies. Horizontal and vertical permeability is generally high, with 300 and 200 MD, respectively. A number of thin low-porosity streaks occur throughout the reservoir. The upper and side reservoir seals are provided by Zechstein evaporites. The Weissliegend, the upper formation of the reservoir, is better cemented but is less permeable than the Rotliegend, which attributes to greater rock strength. The formation permeability also favors the horizontal plane over the vertical. There are two sections of the reservoir that slant, therefore the water cut level is below both formations in the 1st section but traverses up into the bottom formation Rotliegend in the 2nd section. With these factors in mind, the 1st section wells are planned to be S-shaped and the wells in the 2nd section will be horizontal in the stronger Weissliegend. The Bergermeer Rotliegend sandstone reservoir has been depleted by production. This has substantially reduced reservoir pore pressure and well deliverability. Independent studies into

Figure 1. – Geographic Location (Source: Google Maps).

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the field depletion indicated that there was a high potential for a decline in the minimum insitu (fracture closure) stress in the Rotliegendes reservoir, requiring sub-hydrostatic ECD fluids to be used to avoid drilling fluid losses to the formation. Uncontrollable mud losses resulting from a mud with a density such that it cannot adapt to MPD techniques could result in consequences ranging from compromising sand face completions, to complete loss of an expensive wellbore. FITs were performed, to prove or disprove the possibility of reservoir stress rebound, and plans for drilling future wells can be made accordingly. The location of the wells was in a semi-urban setting between the towns of Bergen and Alkmaar requiring extra precautions with regards noise and light to accommodate the proximity to the local population and limit disruption to the environment (Fig. 1).

so that no nitrogen would be pumped down the drill pipe string. This design also allowed the use of a Pressure While Drilling (PWD) tool, which aided in providing early detection of fluid losses. To achieve stable BHP conditions in a two-phase MPD system, it was clear that the overall system would benefit significantly from uninterrupted injection of both nitrogen and drilling mud. Thus, a continuous circulation system was used making it possible to maintain continuous mud pump rates for the drilling operations from start of reservoir to TD. The continuous circulating system also allowed for trips while pumping back into the shoe with nitrogen injection.

Defining the MPD Parameters Normally, MPD is thought of as a singlephase system and many would argue that the introduction of nitrogen, a compressible gas, to the system reduces the level of control. Past operations similar to this have been termed as Low-Head Drilling operations.

Background The MPD objectives were to drill into the depleted Bergermeer formations (2100 m to 2200 m TVD) with a sub-hydrostatic ECD fluid and to maintain a desired bottom-hole pressure (BHP) between 117 to 127 bar (the fracture reopening pressure). This required a two-phase mud system, nitrogen and oil-based mud system, which yielded an ECD of 0.54 to 0.63 SG.

However for the Gas Storage Bergermeer project, significant planning into the overall system design, equipment selection, techniques, procedures and training lead to an operation where precise control of the annular pressure profile was achieved and maintained through out the operation. This paper details this planning process in the following sections.

It is worth noting that an ultra-low density mud system using hollow glass spheres had been evaluated for this project, however field trials in nearby wells found that a 0.90 SG OBM system could be reduced to a 0.78 SG density. However, as a dynamic system, the achievable ECD was 0.90 SG as proven by a field trial in similar nearby well.

While MPD drilling the 8 1/2-in. reservoir sections in Block 1, or the 6 1/8-in. reservoir laterals in Block 2, nitrogen was added primarily by tieback annulus injection. Addition of nitrogen resulted in fluid density reduction such that BHP did not exceed reservoir minimum in-situ stress. Mud pump rate, nitrogen injection and the geometry of the bottom hole assembly (BHA), drill string and ‘A’ annulus (drill string x liner-tieback annulus or the drill string x production casing annulus), determined BHP and hole cleaning parameters.To determine whether it was possible to use a single-phase fluid, it was necessary to quantify the change in reservoir stress. This was most useful if there were natural fractures in the reservoir—if no fractures existed, test pressures were not high enough to initiate fracturing.

Regarding the drilling fluids selected for drilling the reservoir sections, the drilling mud that appeared likely to offer the best overall performance was synthetic oil-based mud (SOBM). It appeared to have the least impact on formation damage, and minimized the risk of foaming in a nitrified mud system. Formation evaluation was critical for the project, and historically, two-phase flow has been detrimental to conventional Measurement While Drilling (MWD). To maintain a viable MWD system, a parasitic injection string was designed 10

determine flow combinations of drilling fluids (both SOBM and water-based mud (WBM)) and nitrogen gas, in the various possible hole sizes, with a variety of drill strings, but all aimed at achieving a maximum BHP of 127.6 bar (1850 psi). Fluid levels were carefully managed during tripping, since they were substantially below surface. Briefly, it was proposed to use a 97 to 131 bar (1400-1900 psi) BHP operational envelope, as periodic unloading of the ‘A’ annulus was required on trips in the hole. This 97-131 bar BHP operational window was also the target for sand face completion operations. Note initial assumption was formation pressure of 81bar (1175 psi). It was conventional practice to include a 13.8 bar (200 psi) trip margin. In order to drill and trip as recommended, the designed MPD operations cannot proceed past the point where reservoir pressure rises to 103.4 bar (1500 psi). Performing FITs was recommended to determine whether reservoir stresses were changing. With significant improvement, determinations could be made as to when use of a single-phase SOBM would be appropriate. If there is no rebound, planning should commence for consideration of stress cage or other drilling fluids, which contain additives to seal porosity and fractures, which may allow drilling and other operations at higher bottom hole pressures.

Basis for MPD Well Design Optimization

Repressurization will bring the reservoir pressure into the recommended BHP operational envelope towards the end of the current drilling schedule. Multiphase simulation runs were made to

MPD design for Bergermeer was based primarily on the requirement for a maximum of 127.6 bar (1850 psi) bottomhole circulating pressure and adequate bottomhole hole cleaning to remove drilled cuttings from the wellbore. Initial multiphase simulator runs aimed at simply achieving the target maximum BHP of 127.6 bar (1850 psi). Once a combination of mud pump rate and nitrogen injection arrived at a satisfactory BHP solution, annular liquid velocity was next considered. Minimum acceptable annular liquid velocities of 45.7 m/min (150 ft/min) in vertical and low-inclination holes, and 54.9 m/min (180 ft/min) in high-angle and horizontal wellbores are used. Injecting additional nitrogen had a minor effect on liquid velocity. Nitrogen’s main influence was in reducing the effective density of the drilling fluid. With the low BHP, these wells could not accommodate higher liquid rates without exceeding the design pressure limit.

For a constant mud pump rate, annular BHP at the bit initially decreased as nitrogen gas was introduced into the system. This hydrostatic pressure reduction was gradually offset by increasing fluid flow friction and decreasing liquid fraction in the fluid. This portion of the curve is referred to as being ‘hydrostatically dominated’, and is prone to slug flow. Computer modelling for Bergermeer indicated slug flow was going to prevail in most situations, with (typically) discrete flows of liquid with lower wellhead pressures, followed by discrete gas flow and higher wellhead pressures. The MPD manifold had a programmable choke, which assisted in maintaining a stabilized wellhead pressure. Liquid pumping rate was an important factor in the control and magnitude of the two-phase BHP. Small changes in pump rate resulted in significant changes in BHP specifically for the 6.125" hole section in the horizontal wells. It was also found that the 8.5" sections had a greater tolerance to change of the mud flow rates. The effect of a single phase flow on the BHP clearly demonstrated the importance of using a continuous circulation system. Other factors that were considered with respect to the annular BHP of a circulating system using tieback nitrogen injection were the drill string connections. Normal connections involve stopping circulation, which interrupts the steady state flow of a two-phase system and cause significant pressure transients or pressure ‘spikes’. If conventional connections were made, nitrogen and the liquid drilling fluid would phase-separate in the ‘A’ annulus, and a period of circulation would be required to re-stabilize flows and BHPs prior to resuming drilling. To avoid this issue and its associated non-productive time, use of in-string continuous circulation subs were included into the plan.

of the injected nitrogen in the circulation fluid. To account for this complexity, a computer simulator must be used. For Bergermeer, two-phase hydraulics modelling simulations were run using steady state software and the results were then verified using a transient two-phase hydraulics simulator. To validate results of the modelling, data was collected from two-phase flow during a familiarization period, and this data was analyzed and used to calibrate the computer modelling. The steady state multiphase simulator predicts flow conditions for extended flows at the nominated rates and the described geometric and fluid situations. It can predict changes which may occur in a wellbore if circulation conditions are changed, but could not predict the dynamic changes between one circulation condition and another. A transient wellbore hydraulics simulator that has been extensively used for Underbalanced Drilling (UBD) operations was used, since it is also a valuable tool when used for MPD operations when gas injection is required. The physical and mathematical basis of the transient simulator enables the user to investigate a wide variety of problems (both static and dynamic) related to UBD operations. In summary, the two-phase hydraulics modelling simulations indicated that it would be possible to reduce the hydrostatic of the fluid system by introducing nitrogen to achieve the desired operating window. There was an initial slug related to the start of gas injection in all the different hole sections for both wells but the effect

on BHP was minimal. While the simulator took into account this initial start-up condition, the actual drilling program included a staged pumping schedule to minimize slugging and pressure spikes at start up.

Dynamic Simulation of Different Drilling Events The modeling performed with the transient simulator for the 8 1/2-in. hole sections verifies the operating envelope of the modeling performed with the steady state software. Again the main difference between the static modelling and the more comprehensive dynamic flow modeling is that effects on flow parameters and pressures can be seen vs. time rather than just as a snap shot at a given flow period as per the steady state. These results were interesting as the slug flow condition can be reviewed in more detail. These results showed that after the initial two-phase MPD start up, the dynamic conditions stabilized in a short time, thus having the ability to maintain both nitrogen and mud returns as separate discreet flow regimes led to a very stable two-phase system where the effects of slug flow conditions could be minimized. Transient wellbore hydraulics software was used to simulate the entire drilling process, especially the main events that could result in a BHP being outside the required operating window. Fig. 2 shows some of the transient simulation results for one of the two wells, where events such as start of nitrogen injection, simulated connections with different times for pump offs to get the surface survey, and dynamic FIT can be observed.

Use of continuous circulation subs maintained circulation during connections, keeping BHP constant. They also avoided pressure variations associated with re-establishing two-phase circulation. This also assisted in not worsening any hole instability which could have developed.

Two-phase Hydraulics Flow Modeling Two-phase circulation for MPD is complex with no linear relationships, due to the compressive nature Figure 2. – Results from the Transient Simulator.

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Concentric Nitrogen Injection The decision was made early in the planning phase to use concentric nitrogen injection (injection of nitrogen between the outer casing and a preinstalled drilling liner) in favor of drill string nitrogen injection. Drill string nitrogen injection is considerably more efficient than injection of nitrogen higher up the well via concentric casing and although this technique would have required less nitrogen there are simply too many disadvantages for using drill string nitrogen injection. Due to the Bergermeer wells being designed as large bore with 9 5/8-in. completions for the high flow rate gas wells with the need for injection and production capability, the Bergermeer wells required the use of a drilling liner to achieve suitable hole cleaning velocities regardless of nitrogen injection location. The disadvantages for drill string injection can be summarized as follows: • Injection of nitrogen via the drill string would have led to the requirement for specialized MWD tools, EM-MWD (electromagnetic measurement whilst drilling). •N  itrogen injection via the drill string would have complicated the use of continuous circulating subs. • Nitrogen injection comingled down the drill string with drilling mud would have led to high velocities in the drill string with the potential for localized erosion of drill string/BHA components. • Nitrogen injection would have required a change out of the rotary drilling hose to a nitrogen compatible one. The use of concentric nitrogen injection had the following additional benefits: • Provided a suitable conduit to inject nitrogen on a continuous uninterrupted basis. • Allowed for the installation of a purpose-built nitrogen injection downhole choke assembly to ensure that the nitrogen injection point was always maintained at a suitable differential pressure to prevent U-tubing from the drilling annulus to the concentric casing annulus during MPD operations. • Allowed for installation of a surface read out real-time downhole pressure gauge to control BHP. • Ensured that the two fluid streams where separated thus allowing for use of the continuous circulation subs. 12

The nitrogen injection requirements and availability were a critical factor in defining the two-phase MPD requirements. As a part of an overall system, it was found from the hydraulics modelling that rates up to 4000 to 5000 scf/min would be required for concentric nitrogen injection.

Measurement Whilst Drilling (MWD) BHA Configuration As previously stated, the MWD section of the BHA was not subjected to nitrogen flow either from the inside or the outside of the tools as the MWD tools were always below the nitrogen injection point whilst drilling. The main considerations therefore for MWD/BHA selection essentially centered on the following points: • MWD tool selection for reduced mud flow rates. • MWD tool selection/configuration for minimal drilling pump rate changes for communication and downlinks. • MWD tool porting/restricted orifice to achieve suitable standpipe pressure and minimize the effects of U-tubing drill pipe to drilling annulus.

Suitably Applied Surface Back Pressure To have a suitable degree of control on the BHP, it was necessary to manipulate the annular pressure profile (operating window) and this could only be achieved with a suitably applied surface back pressure (ASBP). All adjustable choking devices have a control range which is referred to as the Cv range (flow coefficient or flow capacity range). For the twophase MPD planning on Bergermeer, the flow capacity of the choking devices was a critical issue that had to be reviewed using specialized process engineering software. Simply put, the combined flow of comingled drilling mud and nitrogen returns had to be controlled by the MPD automated choke manifolds at very low pressures of 4 to 14 bar (60 to 200 psi): • Drilling mud rates required for suitable hole cleaning and the BHA 950 to 1000 lpm (250 to 260gpm) • Nitrogen rates required 4000 to 5000scf/min • Drilling mud density of 0.9 SG • Two-phase hydraulics modelling indicated that the desired ASBP range required would be 4 to 14bar (60 to 200psi). • A typical 3" MPD drilling choke has a Cv max. range of 120 The above combination is the worst possible situation: relatively high comingled flow rate with

a relatively low operating pressure to be controlled by a proportionally small Cv operating window. The specialized process engineering software identified that to control the ASBP with the required MPD parameters then the throughput of the system had to be designed so as not to create surface flowline restriction that would create a very high surface pressure, yet allow the required ASBP to achieve the desired MPD BHP drilling window of 117 to 127 bar. The process engineering software also identified that the surface flowlines upstream of the MPD choke manifolds would have to be 8" flow lines, and that to use standard 3". MPD chokes, at least 3". MPD chokes in parallel would be needed to drill 8-1/2" hole section with an ASBP of 4 bar (60 psi); above 7 bar (100 psi), 2 X 3". MPD chokes would be required. The large ID flow lines also remained important to the separation system to be able to run the MPD 1st stage separator at a minimum operating pressure of 2 bar (30 psi), required to ship drilling mud the distance from the separation package to the rigs header box at an elevation of 4.5 m. With the contractual requirement for 100% system redundancy in the MPD chokes this meant that two full automated MPD choke systems were required.

Description and Application of Equipment and Processes In principle, the theory is simple enough. The drilling hydrostatic is reduced by introducing nitrogen into the drilling annulus, the volume of drilling mud removed by the nitrogen is then controlled by application of ASBP (choking the return flow from the drilling annulus), to precisely control the annular pressure profile. A full underbalanced separation system downstream of the MPD choke manifolds was used to remove and safely vent the nitrogen from the drilling mud. The drilling mud with all nitrogen removed from solution was then returned back to the rigs header box for processing as normal i.e., over the shakers, centrifuges, and then back to the active mud pits. Fig. 3 shows a simplified MPD twophase equipment overview, and Fig. 4 shows the rig location. Some of the main considerations during the up front planning and engineering were: • Since MPD drilling procedures deviate

Figure 3. – Two-phase MPD System Overview

significantly from conventional methods, it was required to perform detailed equipment design reviews, Hazard Identification (HAZID), and Hazard and Operability (HAZOP) to develop MPD procedures specific to the MPD equipment being supplied and the MPD operating window available for the Bergermeer project. These procedures required activities in addition to conventional procedures to properly manage a dynamic twophase circulation system. • Development of MPD training courses to familiarize the operator, drilling contractor, mud loggers, and MWD/DD personnel was performed in the months leading up to the 1st MPD operation. • Additionally there was an equipment commissioning, familiarization, and calibration process scheduled prior to entering the reservoir to allow function testing of MPD equipment, including a surface control and separation package, the Rotating Control Device (RCD), and nitrogen generation unit, to establish baseline monitoring trends and to train crews. • An auditable process (NORSOK Z-MC-007) was used to check the MPD piping, electrical, and instrumentation of the RCD, RCD, separator, nitrogen, and continuous circulation subs. Each item had an individual Mechanical Completion Certificate (MCC) used to ensure the equipment was rigged up, installed, and functioned correctly. All MPD equipment was signed off as per the MCCs and included all relevant pressure tests. • The process return lines from the RCD to the MPD manifold were exposed to flow of a mixed gas-liquid system containing drilled solids. To monitor for erosion, it was recommended to use an Ultrasonic Thickness (UT) meter to survey the flow lines periodically. A baseline UT survey was conducted once the equipment was rigged in, and additional surveys were performed periodically to monitor for changes in the system.

MPD Equipment

Figure 4. – Rig Location.

The MPD equipment rigged up for the wells included (see Fig. 5): • Cryogenic Nitrogen Pumping Package • RCD • Emergency Shut Down (ESD) valve skids for primary and secondary flowlines • 2 x MPD choke manifolds run in parallel • 1st stage separator c/w pump and piping skid and spare pump • 2nd stage pressurized knockout vessel • Coriolis metering skid • Silenced safe vent • Data Acquisition System (DAS) for automated ASBP control • Surface Readout Downhole Gauge (DHG)

Other critical equipment was: • Continuous circulation sub allowing for continuous circulation on connections • Downhole PWD sensor to provide real time at the bit BHP readings • Downhole nitrogen casing injection valve

Environmental Considerations During MPD operations, gases from the separation package were conducted to a vertical vent stack equipped with noise silencer. A fit-for-purpose silenced, safe nitrogen vent system was designed to specifically meet the requirement for the Bergermeer MPD project. Figure 5. – MPD Equipment Set Up.

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Well Control

reach TD safely; have no recordable accidents, no incidents; no major spills;maintain the BHP within a certain window as per requirements; test the fracture gradient of the Weissliegend formation with a dynamic FIT to determine if the fracture gradient was high enough for future wells drilled with one less casing string; test the fracture gradient of the Rotliegend formation with a dynamic FIT to determine if the formation was suitable for single-phase drilling; successfully install the completion assembly while remaining below fracture pressure and minimize NPT by reducing drilling problems such as losses and stuck pipe events.

A consequence of two-phase circulation is a loss in well monitoring sensitivity. The presence of compressible two-phase fluids requires trend monitoring analyses to interpret well status and identify well control events, as instantaneous surface parameter readings cannot be used to interpret well status. Thus, conventional kick detection methods are no longer valid.

A concentric casing string well profile was designed for these wells to inject nitrogen at a fixed point in the annulus in conjunction with a continuous circulating system for liquid injection down the drill pipe, all to provide continuous circulation and maintain a constant BHP throughout the drilling process.

The exhaust stack was designed to accommodate the exhaust flow from two distinct streams, a pressure control valve and a pressure safety valve. Two noise level requirements were specified, namely 70 dB(A) at 5 m and 50 dB(A) at 300 m and the exhaust stack was located at three positions within the site. It was found that a silencer was necessary in the exhaust stack to enable both the noise requirements to be met. It was found that the noise requirement to meet a sound pressure level of 70 dB(A) at 5 m from the vent stack was the governing condition.

nitrogen at a fixed point into the drilling annulus. This ability for continuous nitrogen injection was supported by the ability to continuously circulate drilling mud down the string via subs incorporated into each stand of the drill string giving an uninterrupted/separated circulating system for the two-phases (drilling mud and nitrogen) into the wellbore. This design of uninterrupted/separated two-phase circulation provides the ability to maintain a constant BHP throughout the drilling process. The downhole gauge (DHG) was installed directly above the injection point to provide real-time measurements of the pressure in the drilling annulus. Two wells were drilled using the two-phase MPD techniques: BGM 24 and BGM 29, and the corresponding results are summarized in the next paragraphs.

BGM-24 Fig. 6. details the MPD Operations Matrix and the actions to be taken by the MPD supervisor in communication with the driller who is the designated focal point for all communication.

A tapered 7-in. x 9 5/8-in. concentric casing string was designed to facilitate higher velocities for hole cleaning and as conduit to allow injection of

In a well control situation, no drilling or injecting of mud and nitrogen will immediately occur. If a well control situation develops, then the rig’s flowline and choke manifold, termed the secondary flow path, tested to 345 bar (5000 psi) should be used. The secondary flow path has the rig’s annular preventer closed and well flow is routed via the rig choke manifold. It was recommended to perform an FIT to determine the BHP the well could competently hold for well control purposes.

Prior to MPD operations, a 9 5/8-in. liner was hung and cemented in the 13 3/8-in. casing with a top of liner (TOL) at 1640 m MD. The bottom of the liner was landed in the lower portion of the Weissliegend shale just above the Rotliegend at 2069 m MD. Dynamic FITs were performed at 2090 m MD successfully testing the Weissliegend to 1.1 SG ECD for future casing string requirements.

Results

Dynamic FITs were also performed at 2127 m MD and 2201 m MD in the Rotliegend to 0.87 SG and 1.1 SG respectively. The test that reached 0.87 SG has been determined to be inconclusive as the dynamic FIT was being performed at a faster rate of closure before letting pressures stabilize.

Since the predicted fracture gradient of the reservoir was relatively low, below 0.9SG (7.5 ppg), two-phase MPD was selected to drill with a reduced BHP. FITs were used to determine if the depleted reservoir could withstand a column of conventional drilling fluid. The main objectives of the two-phase MPD were to: drill the wells and 14

BGM-24 was drilled S-shaped with the portion below 1380 m MD continuing vertical. The maximum vertical section from the surface position was 166 m. BGM-24 was drilled vertically with MPD successfully from 2072 m MD to TD at 2201 m MD for a total of 129 meters of open hole.

The well pressures were controlled within 2 bar +/- of the BHP targets, either with Figure 6. – Bergermeer MPD Operations Matrix.

manual choke operations or automated choke pressure settings. The average ECD achieved for drilling this section was 0.61 SG (5.08 ppg).

at 3944 m MD for a total of 567 meters of open hole. The maximum vertical section from surface position was 2411.5 m.

At the end of drilling, the MW was down to 0.92 SG and nitrogen injection rates of 4,000 scf/min were required to maintain BHP in the 117 to 127 bar target window with a mud pump rate of 950 lpm. At this time it was found that 2 of the 3-in. power chokes had to be opened to 80% with a resulting well head pressure of 6-7 bar (87 to 100 psi).

A 9 5/8-in. liner was hung and cemented in the 13 3/8-in. casing with a TOL at 2171 m/MD 1796m TVD. Within the 9-5/8 in. liner a second 7 in. liner was landed at 2897 m MD/2091 m TVD. The bottom of the 7-in. liner was landed in the Weissliegend sandstone at 3376 m MD/2207 m TVD.

Figs. 7 and 8 show the stable MPD parameters for pressure and flow which were maintained through out the reservoir drilling phase. At 13:45 a dynamic FIT was successfully performed to a 1.1 SG equivalent before returning back to MPD parameters.

BGM-29 BGM-29 was the second well drilled with MPD and the first horizontal well of the gas storage project. Prior to MPD the well was kicked off near surface, built to a 68° angle and held f/ 2000 m MD t/3044 m MD between 63 and 68°. The well was kicked off a second time and built to 90° at 3377 m MD. BGM-29 was successfully drilled horizontally with MPD from 3377 m MD to TD

This well differed from BGM-24 by using a dualstring concentric casing consisting of 2153 m MD of 9 5/8-in. casing and 744 m MD of 7 in. casing to stab into the Polished Bore Receptacle PBR at the top of the 7-in. liner at 2897 m MD. This was done to get the nitrogen injection point deeper into the well which was necessary to sufficiently reduce the BHP when circulating in two-phase drilling operations. The nitrogen injection choke had been modified from lessons learnt on well BGM 24 by having the internal sand screen and the check valves removed. Prior to MPD, the well was drilled out conventionally 3m into the Weissliegend and a FIT was conducted to 1.15 SG with 0.9 SG MW. After

the FIT, the concentric casing was partly displaced with nitrogen where a small amount of gas was channeled into the drilling annulus. A bottoms up was circulated to the MPD system to remove the nitrogen and the hole was partly filled to prevent further channeling. The SOBM density peaked at 0.97 SG due to the inability to maintain a 0.9SG OBM with the correct solids profile during the course of operations ; this resulted in an upper pressure limit of the MPD window being extended to 160 bar. Due to the increase in mud weight, the original target BHP of 117-127 bar was changed to 130-135 bar and MPD operations were able to maintain the required BHP. With the CaCO3 profile required for the reservoir, the mud weight could not be maintained at 0.9 SG and steadily increased from the accumulation of fine particles. The mud weight built to 0.94 SG and gradually rose to a 0.965 SG at TD. Fig. 9 shows that stable MPD parameters for pressure and flow were maintained from approximately 2:00 to 12:00; the 6-in. section was TD’d at about 20:00. Fig. 10 shows that a dynamic FIT was successfully performed and the well was subsequently bled off.

Conclusions Two wells were successfully drilled using MPD techniques with twophase fluid. During drilling, the BHP was maintained within the requested limits at all times. No major instances of pressure spiking, loss circulation, or well kicks occurred.

Figure 7. – Pressure Data MPD Two-phase Operations 11-05-13.

Figure 9. – Pressure Data MPD Two-phase Operations 19-06-13.

Figure 8. – Flow Rate Data MPD Two-phase Operations 11-05-13.

Figure 10. – Pressure Data MPD Two-phase Operations 20-06-13.

Due to the strength of the final FIT, MPD was not required for the completion runs. MPD crews and equipment remained on standby until completion of a conventional FIT was successfully performed using the screen deployment fluid. For further dynamic FIT operations prior to the start, the nitrogen rate should be lowered to 15

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increase the hydrostatic pressure and reduce the ASBP on the RCD. Throughout the operation the minimum controllable ASBP was maintained to conserve nitrogen use. Specific monitoring equipment can greatly assist in trend monitoring. Trend monitoring of such variables as surface/down hole annular pressures,

active surface mud volumes, and standpipe pressures allow reasonable predictions of the twophase circulation system and well control events. Computer simulations had been performed to investigate parameters for MPD operations. A DAS was installed to monitor data throughout the MPD operations. Information was also collected by other means, downhole pressures, borehole diameter and directional information

Acknowledgements

Nomenclature

The authors would like to thank TAQA for their participation in this project and for allowing publication of this paper. They would also like to thank the drilling contractor and all other contractors and consultants involved for helping to make this project a success. The authors would also like to thank Halliburton Energy Services, Inc. for their support during the project and for permission to publish this paper.

ASBP = Applied Surface Back Pressure BHA = B  ottom Hole Assembly BHP = Bottom Hole Pressure BOP = B  low Out Preventer CCS = C  ontinuous Circulation Sub Cv = Flow coefficient or flow capacity range DAS = Data Acquisition System DHG = Down Hole Gauge ECD = Equivalent Circulating Density ESD = Emergency Shut Down FIT = Formation Integrity Test HAZID = Hazard Identification HAZOP = H  azard and Operability MCC = M  echanical Completion Certificate

References Gas Storage Bergermeer– MPD Basis of Design. Martyn Parker. 2011 BGM-24 and BGM-29 Drilling Programs. BGM-24 and BGM-29 End Of Well Reports.

was gathered and transmitted by the MWD tool in the BHA. Throughout the operation, data was compared with modelling predictions from the wellbore hydraulics simulators. In this way, operational data could be used to assist in model calibration. Data was also used to generate trend analyses, necessary to replace conventional kick monitoring procedures.

MPD = M  anaged Pressure Drilling MW = M  ud Weight MWD = M  easurement Whilst Drilling NPT = N  on-Productive Time PBR = Polished Bore Receptacle PLC = P  rogrammable Logic Controller PWD = P  ressure While Drilling RCC = R  emote Choke Control Console RCD = Rotating Control Device SG = S pecific Gravity SOBM = Synthetic Oil-based Mud TVD = T  otal Vertical Depth TOL = Top of Liner UBD = Underbalanced Drilling UT = Ultrasonic Thickness WBM = Water-based Mud

Authors Martyn Parker has 25 years of experience in the oil and gas industry. Starting his career with Schlumberger for 12 years working with in DST and well test, he cross trained in slick-line and coiled tubing. In 2000 Martyn joined Precision Drilling as the underbalanced drilling (UBD) operations coordinator looking after the Shell Southern North Sea UBD campaign through to 2005. In 2005 through to 2007 he was seconded full time to Shell Netherlands as the overall UBD project manager. In 2007 Martyn joined Halliburton GeoBalance® services and worked predominantly in Norway on several managed pressure drilling projects and FEED studies before leading the technical development of the DONG South Arne offshore North Sea UBD project. Martyn was involved in the startup and initial development MPO managed pressure operations from 2009 thru to 2011. In 2011 Martyn became a consultant and was employed by TAQA Energy to lead two-phase MPD for the Bergermeer Gas Storage project onshore Netherlands. Since the end of this project in June 2013 he has remained with TAQA Energy as night drilling supervisor.

16

Isabel Poletzky is the underbalanced drilling global product champion for Halliburton Sperry Drilling’s GeoBalance® services. She earned BSc and MSc degrees in petroleum engineering from the Universidad Nacional de Colombia and the University of Houston. Isabel has 15 years of industry experience including drilling and production engineering, directional and horizontal well planning and design, and 10 years of experience in underbalanced and managed pressure drilling applications. She also spent two years working as a drillsite petroleum engineer on the Kuparuk field for ConocoPhillips in Alaska. Isabel’s expertise includes reservoir characterization while drilling, modeling of multi-phase flow, and candidate selection for underbalanced and managed pressure drilling projects. Recent responsibilities have included proposals, well planning, engineering and design, training, and coordination of underbalanced and managed pressure projects worldwide. Isabel has co-instructed several UBD and MPD courses and has also taught wellbore hydraulics modeling. She has written and presented several papers and served on technical program committees for SPE and IADC. Isabel is a member of SPE and IADC.

Mark Juskiw is a managed pressure drilling project manager for Sperry Drilling working worldwide on various types of MPD projects. Mark graduated from the University of Tulsa, Oklahoma in 1982 with a BSc degree in petroleum engineering. Saad Saeed is a global technical advisor for underbalanced and managed pressure drilling for Halliburton. Saad graduated with a degree in petroleum engineering from the University of New South Wales in Sydney, Australia. He initially worked extensively in Well Testing, Data Acquisition, Permanent Gauges and Production Logging both domestically and internationally. Having a keen interest in computer science (artificial intelligence) and its application to the energy industry, Saad returned to university to get his master’s degree in computer science. After graduating, Saad joined Halliburton’s underbalanced and managed pressure drilling group – GeoBalance® services – in Houston, TX. Since joining GeoBalance services (over 11 years ago) he has been involved in all facets of the business from extensive field engineering and operational support to supervision, project management, technology development, business development, and training.

PL A N N I N G A N D EX ECU T ING AN INT ELL IG ENT MUL TIL A T ER AL W ELL

Multilateral TAML Level 4 Junction Provides Maximum Flexibility for Drilling and Intelligent Completions Mohamed Samie, Ahmed Siham and Bruce Gavin/Halliburton Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Kuwait International Petroleum Conference and Exhibition held in Kuwait City, Kuwait, 10–12 December 2012. This paper was selected for presentation by an SPE 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 and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, 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 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 copyright. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission.

Abstract A multilateral (MLT) well with an advanced intelligent completion string was recently completed in the Middle East. The well was designed as a “stacked” dual producer in the upper and lower reservoir, and was drilled using the latest geo-steering techniques to accurately place the wellbore in a highly faulted and geologically complex structure. Rotary-steerable drilling systems (RSS) were used in several of the hole sections, along with advanced logging-while-drilling (LWD) tools including multi-pole acoustic, azimuthal deep resistivity, and resistivity at bit. Encounters with unstable shale and faults made the drilling difficult, but the decisions made in real-time to navigate the well resulted in a very high percentage of net pay in both laterals. This well combined TAML Level 4 multilateral (MLT) technology with passive inflow control devices in the laterals and an advanced intelligent completion system in the mainbore. The TAML Level 4 multilateral junction was cemented to isolate unstable shale above the reservoir and to provide zonal isolation from the lateral completions, which were compartmentalized into stages with proprietary swellable packers and inflow control devices (ICDs). The intelligent completion was run in the mainbore with two interval control valves (ICVs) and isolation ball valve (LV ICV) to manage the production from each of the two

Figure 1. – Well B Pre- and post-well geology models.

laterals independently. The ICVs and LV ICV are controlled hydraulically through four control lines to surface, which were run in a flat-pack with one electric line to control a downhole gauge package for each lateral. Finally, the well was configured to allow the installation of a large electric submersible pump (ESP) to be run inside the upper 9 5 /8-in. production tubing. This project required intensive planning and coordination for more than a year in advance, which made the project successful despite the difficult drilling conditions and resulted in very little NPT for wellbore construction operations. This paper will focus on the planning, execution and lessons learned from the project.

Planning In the existing horizontal wells in the target sand reservoir of the target field, premature water breakthrough caused the water cut trend to increase within months of production. This occurred because the reservoir has a very high permeability sands along with active faults containing high viscous reservoir fluids. New technologies were required to overcome the issue, maximize reservoir contact and enhance a more uniform oil production from a single location. Introducing the smart TAML Level-4 MLT well design to this reservoir along with inflow control device (ICD), inflow control valve (ICV), isolation ball valve (LV ICV) and other downhole gauges proved to be the optimum solution. It also aided in managing the production and the reservoir proactively to achieve maximum oil recovery. Moreover, drilling several laterals from a single wellbore with the ability to control production from both laterals had a great economic advantage because of the optimized cost effective field management. These reservoir improvements encouraged the customer to implement this technology on “Well A” and “Well B” of the target field and consider it for further deployment in other fields. Using the latest in geosteering techniques to accurately place the wellbore in this highly faulted and geologically complex structure was essential. point-the-bit rotary-steerable drilling systems (RSS) were used in several hole sections including the 12 ¼-in. build/tangent hole section, the 8 ½-in. lower lateral L0, the 8 ½-in. build section, and the 6 1/8-in. upper lateral L1, along with several advanced logging-while-drilling (LWD) tools. The RSS enabled continuous rotation for more effective 17

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wellbore cleaning as well as producing smoother hole section due to proprietary point-the-bit design of the RSS systems selected for this project. The added value of advanced geo-steering techniques & practices including pre- and post-well geology models for Well B is shown in Fig. 1. The LWD data acquisition program used for the subject well was designed to cover a broad range of applications, from using basic gamma and resistivity data to evaluate shale quality for the placement of the multilateral junction, to interpreting the advanced quadro-pole bimodal acoustic tool data to provide a permeability curve in near real-time for accurate placement of the passive ICDs in the lateral completion.

An at-bit resistivity tool was used to provide early detection of faults and assist in proactive decision making while geo-steering the wellbore in the sweet-spot of the thin reservoir. The azimuthally focused resistivity tool is a laterolog design that is primarily used to measure the wellbore ring resistivity in conductive mud; however, it was successfully applied here in oil-based mud system to provide a qualitative at-bit resistivity measurement. The anticipation of faults early enough was instrumental to allow for steering decisions to be made at the correct moment by guiding the well path up or down without overcorrection, thus minimizing the doglegs and smoothing the lateral trajectory for easier installation of the sophisticated completion. A

state of the art geo-steering azimuthal deep resistivity (ADR) tool was utilized in drilling the lower 8 ½-in. lateral section and upper 6 1/8-in. lateral section. The tool generates average resistivity curves with multiple depths of investigation (DOI), as well as azimuthally binned resistivity images and geo-steering signal curves and images with multiple frequencies and multiple spacings, resulting in multiple DOI ranging from few inches up to 18 ft into the formation dependent on the true resistivity. The tool output integrated with the use of 3D well placement software provides early geo-steering warning and accurately calculates the distance and direction to adjacent bed boundaries. Estimating the productivity of the laterals presented a unique challenge in these wells because the lateral completion was designed with ICDs that must be adjusted before installation by selecting the correct nozzle size for the reservoir quality in each of the swellable-packer compartments. This required an immediate interpretation of the permeability in each lateral within hours of its being drilled so that the ICDs could be configured accordingly on the rigsite. With the expected reservoir pressures, pressure drop across the ICDs, and flow rate from the ESP, the flow ports in both ICVs were custom designed to suit the life of the well.

Execution

Figure 2. – Pre-completion reservoir characterization.

With the start of the execution phase, and the start of drilling the 16-in. build hole section, the customer held daily meetings in the customer office where the drilling, geology, and geophysics teams met with all service companies and discussed the actual well updates as well finalizing plans for upcoming phases. After the 12 ¼-in. build/tangent hole section was drilled to casing point using dual gamma ray (DGR)–electro-magnetic wave resistivity (EWR)– azimuthal litho-density (ALD) in addition to rotary steerable system with integrated at-bit inclination/at-bit gamma, two proprietary latch couplings were installed with the casing tubulars as shown in Fig. 3.

Figure 3. – Installation schematic for liner and latch couplings.

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Based on logs and surveys, the placement of the primary latch coupling was planned carefully to land just below the Wara formation; this ensured the junction exit was in the shale to offer proper isolation. The other latch coupling was placed

80 ft higher for contingency. The latch coupling is critical to the MLT systems. It is part of a proprietary advanced reservoir drainage services. The latch coupling serves a vital role in MLT applications by providing a consistent, repeatable platform for the depth and orientation of multilateral equipment. It also provides full-bore, unrestricted casing access to the lower mainbore. The latch coupling maintains casing pressure integrity, which allows the well to be completed and produced in any manner, while the option of drilling an additional lateral bore at a later date is maintained. The latch couplings can be installed above or below existing lateral bores to provide access to virtually any productive interval of the reservoir.

Once the main bore was drilled and completed successfully with ICDs and swellable packers, the upper lateral phase was initiated. A retrievable bridge plug was set in the 9 5/8-in. casing just above the lower completion to prevent any debris from milling the lateral from falling into the lower completion and affecting flow from the ICDs as shown in Fig. 4. To accomplish this, a window was milled in the casing by anchoring the milling equipment to the latch coupling, previously installed and integrated with the

The 8 ½-in. build/landing hole section for the upper lateral L1 was then drilled using GammaResistivity-Azimuthal Density tools in addition to at-bit inclination/at-bit gamma integrated on the rotary steerable system. Since one of the main requirements of the well design was to isolate the shale section, the level-4 MLT was the solution. This was accomplished by running the 7-in. liner to cover the open hole up to the whipstock tip and then cementing

The latch coupling orientation was then obtained with measurementwhile-drilling (MWD) in order to offset the milling equipment and whipstock precisely to the planned upper lateral exit at the workshop. The lower 8 1/2-in. lateral hole Figure 4. – Drilling and completing the main lateral. section was then drilled in one run utilizing gamma ray- deep-reading resistivity and geo-steering – azimuthal density casing. A specialized milling machine that allows – compensated thermal neutron – quad bi-modal the creation of a near-rectangular window at a acoustic tool in addition to the proprietary rotary precise depth and azimuth on a repeatable basis steerable system with integrated at-bit inclination/ was used as illustrated in Fig. 5. This control of at-bit gamma. These tools provided real-time the window geometry and position makes this type density and gamma borehole images for accurate of window particularly useful for Level 2 and 4 dip picking, along with directionally sensitive wells, in which lateral re-entry and through-tubing resistivity and geo-signal curves, on top of the re-entry are required. The windows are machined regular formation evaluation real-time curves. with an elongated full-gauge aperture along their Geo-steering specialists watched the real-time entire length and are exactly in line with the axis responses from all tools and fed them into the pre- of the casing. The proprietary system eliminates well model to update the earth model accordingly. problems associated with conventionally milled The customer’s drilling and geology teams were windows in which window geometry is typically actively monitoring the well data in real-time using elliptical and spiraled. Magnets are also included a real-time operations (RTO) online connection in the bottomhole assembly (BHA) for well which allowed a faster and more comprehensive cleaning and to capture any metal shavings that decision making process. Several sub-seismic the mud was unable to lift to surface. This helps faults were encountered and picked on the images ensure integrity of the screens in the mainbore. After the milling as illustrated in Fig. 6 was in real-time along with fracture zones. These faults were not readily visible on seismic images finished, the milling machine was then pulled out prior to the start of the drilling operations, due of the hole. Another dedicated cleanout trip was to the non-conclusive resolution of the seismic made with magnets and junk subs for better hole images. However, these encountered faults did not condition and cleaning. cause severe challenges in the well placement, as the lower reservoir unit was thicker than the The retrievable whipstock was then run and calculated fault throw which prevented exiting the seated onto the latch coupling for further drilling reservoir unit after passing the fault plane. operations in the upper lateral.

Figure 5. – Run milling machine and mill window.

Figure 6. – Mill-off whipstock.

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it. The pressure integrity of this junction is mostly dependent on the cement; therefore the cementing company introduced specialized cement which proved to be very efficient in isolation of the junction zone. It is vital for the successful completion of the multilateral well that the liner lands exactly on the whipstock in order to be able to retrieve the latter. On “Well A”, there were serious problems getting the liner all the way to bottom because of the nature of the reactive shale. The shale was swelling and the liner was dragging with minimum circulation. This issue was addressed and a new high torque liner running tool was introduced on “Well B” in order to have more tolerance for rotation. After setting and cementing the liner successfully and cleaning out cement as illustrated in Fig. 7 & Fig. 8, normal drilling operations in the upper lateral were continued. The upper 6 1/8-in. lateral hole section was then drilled in one run utilizing the same suite of tools

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run in the lower 8 ½-in. lateral in addition to the azimuthal focused resistivity AFR tool which was run in oil-based mud for acquiring at-bit resistivity measurements. These tools provided the same real-time formation evaluation curves utilized in the lower lateral. The upper reservoir unit posed various challenges to the drilling operations due to the complex geology of the structure. Several sub-seismic faults were encountered which were not previously visible on the seismic image prior to drilling the well. The nature of the upper reservoir unit being thinner than the calculated fault throws, caused multiple exits from the target zone resulting in a couple of geological side-tracks after plugging back the zones beyond the fault planes. Drilling in multiple units before and after fault planes also imposed further challenges due to mud weight incompatibility with the non-producing shaly intervals throughout the borehole, which caused some tight hole and stuck pipe incidents in Well “A”. These occurrences were properly

overcome by utilizing different solutions proposed by the drilling team so that the lateral section reached the planned geological targets. The lessons learned were carried over to Well “B” where stuck pipe incidents were kept to a minimum. After the upper 6 1/8-in. lateral was drilled to total depth (TD) successfully, the ICD completion was run in lateral as shown in Fig. 9, and the whipstock with the cemented liner sitting on it was then retrieved in one run using washover pipe as shown in Fig. 10. This provided the option of completing the well with no restriction in the main bore. To prove the reliability of the Level-4 multilateral junction, the client required access to the lateral to perform stimulation via coiled tubing. A workover whipstock was run in and latched into the latch coupling without the need to orient it

Figure 7. – Setting the 7 in. liner.

Figure 8. – Drilling out cement and the 6 1/8-in. lateral.

Figure 9. – Installing the upper lateral completion.

Figure 10. – Whipstock washover and retrieval.

or the use of MWD tools to locate the window. After successfully exiting through the window, the workover whipstock was then pulled out again. The advanced LWD petrophysical data gathered while drilling the horizontal hole sections of the MLT well contained several important and informative indicators that helped engineer the smart completions design. Permeability from Stoneley wave energy loss was made quantitative by calibrating with core permeability data from the same field (using the Stoneley-perm module in proprietary analysis software), in addition to using the sonic compressional and shear slowness in cross plots with density and resistivity as well as Compressional/Shear velocities VPVS ratios to indicate rock quality and deduce any secondary porosity from the difference in sonic porosity vs. density porosity. A borehole profile and inferred hole caliper were provided using the azimuthal stand-off correction data from the ALD density image. LWD recorded data was then processed and analyzed using petrophysical software packages to finalize the completion string design as illustrated in Fig. 2. The significant input for QBAT here was using the Stoneley-derived permeability to identify zonal permeability profiles so that the ICD screens could be nozzled accordingly to achieve uniform production from all zones across the lateral over the life span of the well. This was performed on both the 8 ½-in. lower lateral (L0) and the 6 1/8-in. upper lateral (L1). Both ALD and CTN were run in the lower lateral while ALD only (no CTN) was run in the upper lateral. By direct comparison, it was found that Stoneleyderived permeability values more closely followed the chemostratigraphic analysis for cleaner sand units, in which other permeability empirical calculations/indications were showing abnormal behavior. Having several cores cut previously in the same reservoir/field helped ensure quantitative permeability figures that are calibrated to core permeabilities at the applicable intervals throughout both laterals. Density porosity was the primary porosity indicator. Sonic porosity was also provided (Wiley Calculated) for redundancy and to verify any effect of secondary porosity not seen by the sonic. In this case, no apparent secondary porosity was

captured, as all fractures seen were apparently closed fractures (as seen on density image). After analyzing the complete formation evaluation data gathered by the LWD suite in both laterals, the preliminary completion string design was agreed among geology, drilling, and completion specialists to arrive at the best reservoir profiling and compartmentalization. The design was then modeled using a simulated BHA that included collars and stabilizers gauged to match the final swellable-packers, ICD screens and blank pipes sequences to ensure that the hole condition and DLS compatibility allowed the completion strings to be run successfully to bottom.

Installation of Intelligent Completion The retrievable bridge plug was retrieved from the 9 5/8-in casing, and well clean-up operations were conducted in preparation for running the intelligent completion. The intelligent completion consisted of the following assembly: • 2 retrievable feed-through production packers • 2 dual sensor permanent downhole gauge systems (tubing and annulus) • 2 single sensor permanent downhole gauge systems (tubing) • 2 multi-position interval control valves (ICV) • 1 isolation ball valve (LV ICV) • 1 perforated sub • 1 ratch latch / seal assembly • 5 control lines a) 4 hydraulic b) 1 electric • control line protector clamps

were positioned such that the production flow rate through the upper and lower ICVs could be estimated through calculation. Above the uppermost feed-through production packer, the production tubing was crossed over from 4 1/2-in. to 9 5/8-in. The four-line hydraulic control lines, contained in one flatpack, and the single electric gauge line were held against the outside of the 4 1/2-in. and 9 5/8-in. tubing using cross coupling protection clamps. All five lines were fed through and isolated at the tubing hanger. The isolation ball valve and both ICVs were functioned to prove the integrity of the hydraulic system. The electric gauge line was tested to confirm the pressure and temperature readings from all four gauge systems. The ESP was run inside the 9 5/8-in. production tubing. Surface control lines connected to the well head were run below ground level approx 100 m to the area where the automated control panel and data acquisition unit are to be located. The automated control panel is used to control the ICVs and ball valve, through field communications system, from the software in the field control room. Pressure and temperature data from the permanent downhole gauges will be viewed in the data acquisition unit and in the field control room. Final completion string is illustrated in Fig. 11.

The ratch latch/seal assembly was tied into the top of the lower completion in the mother bore. The retrievable feedthrough production packers were positioned above and below the lateral to isolate the production from the mother bore and the lateral. The perforated sub and closed isolation ball valve allowed produced fluids from the mother bore to be controlled through the lower ICV. Production from the lateral was controlled though the upper ICV. The permanent downhole gauge systems in each zone

Figure 11. – Final completion string design.

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Lessons Learned The below captured practices and lessons were developed during the process of drilling and completing well “A” and were later carried over to ensure seamless well delivery in well “B”: 1. Depending on the well profile, the back-up latch coupling to be placed two casing joints above/ below the planned junction depth. 2. Well clean-up was critical to the success of the MLT and the completion. A very high percentage of milled casing was recovered (~150kgs) 3. Drilling off the whipstock with 8 1/2-in. motor BHA, adjust motor to minimum bend angle and try to rotate to drill at least 30 ft. Avoid sliding if possible to minimize dogleg as whipstock provides ~ 8 deg localized DLS. 4. Running the 7-in. liner through the Wara shale sections can be problematic. This was solved on the next well using the high-torque liner running tool to allow rotation and circulate the liner to bottom. 5. Latex cement provided excellent junction quality. Cement volume was good.

6. Fluid loss device/solution required for upper lateral completions to avoid losses during washover and clean-out operations. Recommend a flapper-type of device to be incorporated into proprietary hydraulic-set seal-bore retrievable 7-in hanging packer assembly.

Conclusion With careful planning, comprehensive technical knowledge and collaboration among subject matter experts, and the effective execution of the drilling and completions phases of both MLTs, the final outcome proved to be a huge success for the client and everyone involved. Both wells have shown exceedingly high production levels after the installation of smart completions strings and confirmed after actual production verification testing (PVT) logs, ranging from 50% to 150% improvement in each individual lateral over regular production in near-by horizontal wells.

The asset managers as well as the field development team indicated huge enhancement in the production levels, and indicated that the inclusion of smart completions and reservoir compartmentalization techniques would help stabilize the saturation levels within the economical values for an improved recovery curve and less water cut/water coning effect over a longer well life span. This would eventually bring a huge increase in the net present value of the asset and result in more efficient/economic reservoir drainage. It is worth mentioning that the two subject wells and the promising results achieved have encouraged the customer to plan many of its upcoming horizontal wells to be completed using smart completion strings, as well as to expand MLT technology usage in all applicable fields.

Authors Mohamed Samie is the business development manager for Sperry Drilling in Northern Gulf, currently focused on business acquisition and growth efforts for Sperry’s DD, LWD, MLT and SDL sub-product services lines in Kuwait, Qatar and Jordan. Mohamed joined Halliburton in 2005 as an LWD field professional in Saudi Arabia. He progressed through field ranks and held several supervisory and operational roles in Saudi Arabia, Libya and Kuwait. Mohamed earned his BSc in computer science with a minor in business administration from the American University in Cairo. He is a published SPE author and a contributing member to the Society of Petrophysicists and Well Log Analysts (SPWLA).

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Ahmed Siham was a Sperry Drilling multilateral technology field professional in Saudi Arabia from 2004 to 2012. He is a graduate of Ain Shams University in Cairo with a BSc in mechanical engineering.

Bruce Gavin is the senior product manager for Flow Control Products, Intelligent Completions, based in Houston, Texas. He received his HND in mechanical engineering from Aberdeen Technical College. Bruce has been with Halliburton since 1993 starting in the Technology group in Aberdeen, developing Intervention and Completions equipment. Most recently, he was based in Dubai as Region BD/Technology manager for Intelligent Completions, supporting MENA and Eurasia regions for Intelligent Completions and has recently relocated to Houston. Bruce is a long-term member of SPE.

E X PLO I T I N G V A S T OI L RESOURCES IN ME XI CO ’ S CH ICO NT EPEC B A SIN

Challenges and Successes in Horizontal Drilling Shallow 3D Unconventional Turbidite Reservoir, Mexico G. Gutierrez Murillo, PEMEX; G. Villanueva Zapata, and E. Medina, Halliburton; J. Salguero Centeno, CBM E&P Copyright 2014, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Latin American and Caribbean Petroleum Engineering Conference held in Maracaibo, Venezuela, 21–23 May 2014. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, 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 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 copyright. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission.

Abstract Aggressive plans for exploiting vast oil resources within the Chicontepec basin (Mexico-Poza Rica) are currently underway. One of the most complex deposits in the world, this basin is qualified as an unconventional turbidite reservoir, and one of its characteristics is the existence of hydrocarbon resources in shallow regions. Horizontal wells within this basin are extended three-dimensional (3D) wells in parallel arrangement, suitable for termination techniques, such as simultaneous multi-fracturing. Commercially developing these resources requires the construction of wells that present major challenges. These challenges can be attributed to low depth, required dog leg severities close to 8°/30 m, 3D geometry necessary for construction and horizontal navigation uphill “boomerang” within the target unconsolidated sand formations (which are thin and unstable with mechanical hydraulic limitations), superficial limitation of space, the use of conventional drilling equipment, and required exhausting analysis.

Based on this scenario, there is a massive plan for increasing the recovery of unconventional hydrocarbons in the Chicontepec basin, which is characterized for having one of the most complex reservoirs in the world. The average production per well before applying unconventional techniques was 28 BOPD, with an average cumulative production of 30,000 bbl. Currently, production is up 2,000 BOPD, with cumulative production of 630,000 bbl. The Paleochanel of Chicontepec is apaleophisiographic elongated unit with a NW-SE orientation and extends to the subsoil, from Cerro Azul to Tecolutla cities in Veracruz State, Mexico. It has an approximate length of 123 km with a variable width of 25 km to the north and 12 km to the south, with a surface of approximately 3100 km2 (Fig. 1). Geologically, it belongs to the province of Tampico-Misantla and is part of the Chicontepec basin.

Figure 1. – Chicontepec Paleochanel location.

The successful exploitation of these wells was achieved with thorough planning simulation, detailed engineering analysis, and the selection of appropriate tools for each operational stage. Monitoring key factors during drilling was essential to helping prevent problems with uncompacted sands and gas migration. The use of advanced technology helped reduce deviation from the plan designed for the well and helped achieve a successful completion using a rotary steerable system (RSS), in some cases from the first casing, to prevent collapse and initiate the construction of the kickoff point (KOP).

Introduction The operating company faces significant short and mid-term challenges within the Chicontepec basin, such as efficient management of primary reservoirs, which are declining, and the substitution of this declination with unconventional hydrocarbon to sustain production; this requires unconventional drilling and completion techniques.

The lithological sequence ofthe target zone includes several interbedded formations from the top, with approximately 350 m of consolidated conglomerates associated with light-gray calcareous soft shales, which also contain freshwater aquifiers followed by shale layers that work as seals overlying oil-bearing sandstones (Fig. 2). The target sand for the well is the C-50 unit, this unit is located at a shallow depth. The vertical depth is approximately of 1091 m, which was reached and crossed in previousvertical wells. Potential for exploitation exists despite its low depth because of narrow thickness and 23

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Figure 2. – (Left) geologic column and 3D horizontal well path image in geological sequence.

inside the target at 1000 m, in a parallel position, with 150 m of distance between them in the horizontal section. The effective construction time per well was 35 operating days with 1.69 days of non-production time (NPT), which represented 4.8% of the days employed positioning one of the first unconventional wells with the best performance in the region. This success allowed increasing the recovery factor and maximizing production by reducing drilling of vertical wells in the region, leading to an overall cost reduction to the project.

Development

Figure 3. – 3D horizontal path profile of both wells.

unconsolidated sands, although the previous information gathered suggested uncertainty and challenges related to drilling horizontal wells. The wells were designed using 3D displacement with parallel projection between them, meeting zipper frac completion requirements (Fig. 3). During planning, doubts regarding the feasibility of drilling in such conditions arose related tothe target depth being low and generation of high severities reaching 8˚/30 m in an unconsolidated formation with an unstable background and constant gasification. Another consideration was lowering the production liner successfully with 24

sleeves and swellable packer arrangements, which is key during multifrac completions. A rigorous engineering procedure was planned, prioritizing the completions, an accurate selection of suitable tools for each stage, and data gathering before drilling. The project had to be completed on time and within budget. This was accomplished successfully and the wells were drilled and completed. The A and B wells reached a vertical depth of 1091 m true vertical depth (TVD) and 2407 m measured depth (MD). The construction KOP began at 435 m, with a lateral displacement of 1400 m, maintaining an effective horizontal section

Problem Definition. There were several challenges during planning of the first two 3D unconventional horizontal wells, some of which are listed below. • Construction severities were demanding (8°/30 m) in these unconsolidated shale formations affected by a high deviation degree. • Achieving a successful run into a wellbore with 4 1/2-in. liner, packed with 15 sleeves and 25 swellable packers, with an external diameter of 6.45 in., in a hole of 6 3/4-in. crossing high dog leg severities (DLSs). • Running the production liner across unstable shale formations of the reservoir with constant gasification prone to fluid loss in a TVD. • With respect to the path, it was necessary to keep the tangent with vertical drilling for the proper adaptation of the artificial lift system (pneumatic or hydraulic). This led to more severities.

• Selection of a compatible fluid with the formations, which were prone to damages during drilling of the target zone. • Maintaining optimum stability of the walls in the horizontal section. • The achievement of a horizontal section of 1000 m developed in a target sand with a thickness of 12 mV, 150 m away from its parallel well, which crossed through and navigated inside the production target. Complications with maintaining the “uphill” trend were expected because this would impede the effective transmission of drilling parameters, mainly on the weight of the bit and in the severity of high torques and poor cleaning of the hole, among others. • The conventional core of the horizontal section was recovered because it was vital information for wells that were multifractured. • Another challenge was the little or practically no experience drilling 3D horizontal wells with targets displaced from their axis. Such challenges generated significant uncertainty related to the technical feasibility of drilling. In this scenario, the vertical wells that were drilled were verified and, with the experience gained, a plan was structured for horizontal wells as follows: • The target zone is “C-50” located inside the Tertiary top of Chicontepec formation. There are high leakoff test values (2 gr/cc) close to the overburden values in vertical wells -+crossed through. Although this sandstone with argillaceous matrix exhibits natural softness, it tends to close fractures very quickly, which was experienced during many leakoff tests in nearby wells. The fracture’s gradient value is 1.99 gr/cc, therefore events with total lost circulation are almost non-existent. • Stuck events caused by differential pressure are not present at this depth and unlikely to happen. • The gas delivery behavior in this zone is constant because the reservoir has light oil associated with gas; for this reason, the probability for gasification and/or blowouts during drilling is high, further maximizing the horizontal section. • Stuck events for mechanical effects are possible because of unconsolidated sands and a threat of collapsing against the drilling string exists. • It was determined that the maximum stress for this zone was oriented to the NE-SW 30°. The wells were oriented to the minimum stress with a maximum of 90; this optimized the expected hydraulic fracturing completion.

Figure 4. – Planning flowchart.

Planning During this phase, several changes were made. Previous wells drilled and international experiences in similar conditions were taken into consideration for planning the construction of the well. This scheme was structured with simulations. The plan for the well was implemented into an integral drilling program, which was approved and executed. The planning process involved a traditional and standard flow chart, shown in Fig. 4.

the stage and the weight. It was also possible to define the preliminary arrangement of a completion with a liner with sleeves and swellable packers. These results were based on information from vertical wells including geophysical logs, diagnostic fracture injection tests (DFITs) and/ or leakoff tests (LOTs), background information on shales hydration, “breakout” studies, core analysis, and production tests, etc. The same analysis was modeled and adapted for the target zone.

Hole Stability Analysis

Parameters for this Phase

A geomechanical analysis of multiple hydraulic fracturing and a hole stability study was performed (Fig. 5). This analysis was vital to defining an optimum path with a trend favoring the fractures. This included the selection of drilling fluid per

• The target formation properties are a sand body with quite argillaceous interbedded with an average thickness of 40 mV; nevertheless, the best quality of the rock extends to a limited thickness of 12 mV, 1.25 gr/cc pore pressure,

Figure 5. – (Left) stress estimation—shear fault “Sh” and safe operational window for mud weight; (right) minimum mud weight to reach the hole stability in different directions of the well.

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TVD of 1090 mV, with the presence of natural microfractures per zone, with good oil saturation. • The formation compressibility ranges from approximately 5,000 to 10,000 psi, with an overburden gradient of 2 gr/cc; the difference between the minimum and maximum horizontal stress is 0.1 gr/cc and exhibits little influence on hole stability. • Inhibition of reactive shales studies showed that water-based fluid systems (based on polymers) avoided clay hydration and maintained the pH within a range of 9.5 to 10.5, minimizing clay dispersion, and creating optimal polymer development, which was encapsulated in a concentration that ranged from 0.5 to 3.5 lts/m3 potassium chloride (KCl). • For the intermediate and production segments, an oil-based mud was used to provide better ROPs and a reliable cleaning tool for the well and for drilling solids suspension. With this, the content of solids was reduced from 2 to 4% in the system and allowed the creation of a “crosslink” system that gels at low speeds, disperses at high speeds, and can bear water contamination. This fluid also offers maximum lubrication, reducing the torque and drag, and providing exceptional protection against corrosion. Additionally, it is thermally energy efficient, stable, and resistant to bacteria.

Well Direction Several engineering designs were created for the 3D horizontal wells, meeting at least the three drilling stages of the completion expected. A combination of hole diameters and well directions were analyzed, focusing mainly on the severity required to reach the target and navigate in the same uphill trend without generating tortuosities and microtortuosities to help ensure introduction of the liner. From the beginning, it was required to generate high severities with minimum weight because the extended horizontal section was 1000m with a limited thickness of 12 mV, in which the directional work would consume time and technical resources. Based on this, the best drilling direction was chosen with a hole combination and coat tubing 14 1/2- × 10 3/4-in., 9 1/2- × 7 5/8-in., and 6 3/4- × 4 1/2-in., obtaining a successful result. This last stage was for the extended horizontal well. There was a requirement for landing the well at a TVD of 1090 m; it implied the construction of a shallow KOP of 435m in the first stage of 14 1/2 in. This led to a 26

constant construction that ranged from 4°/30 m to a 9 1/2-in. severity stage with a 50°inclination at 1000 md and 947 mV. The increase of severity reached 8°/30 m during the lateral displacement in construction and a drilling at 6 3/4 in. on the stage where it should land at 90° in a TVD of 1090 m (1577 md) with 12 mV penetration inside the reservoir. The drilling progress continued with a horizontal tangent, generating a horizontal section, an uphill “boomerang,” above 1000 md, which reached a final depth of 2407 md. The azimuth of the well was projected at 150°SE. It was based on a geomechanical model, the same designed to favor the multi-fracturing programmed for these wells, in addition to safeguarding the anti-collision with wells close to the sludge. The directional path planned versus the actual one has a phase displacement of 2.65 with a distance from center to center (Fig. 6). This shows almost perfect navigation inside the target zone with high-quality construction of a hole, eliminating the microtortuosity, almost to a null value, attributed to the rotatory systems. Superficial Stage 14 1/2 in. at 410 md The plan for this stage was to cross the entire conglomerate, cover the aquifers, and isolate the high level of vibration of the formation in the drilling column. The verticality control allowed an effective directional job during the second stage; for the vertical control, a conventional motor of 8 in. with high torque, a rotor configuration/stator of 6/7 × 4 stages was used in slick mode with an AKO graduation of 1.5° equipped with measurement while drilling (MWD) (inclination and direction sensors). The settling point was at 410m with a 0º inclination and an azimuth of 171°. The navigable drilling system was chosen to control and avoid collision incidents with nearby wells and to minimize the vibration in the

conglomerate associated with basalt (300m) and for improving the penetration rate. The bottomhole assembly (BHA) (Fig. 7) was made up for the first run with a tricone bit with chiseled inserts of aggressive cutoff, protecting the caliber because it was designed to cross through the conglomerate. For the second run, a replacement was used with a polycrystalline diamond compact (PDC) bit of 14 1/2 in. with seven blades and cutters of 13 mm. According to the model, this BHA would be constructed every 30 sliding m with a 9.4° of rotation; the tendency was to decrease at 1.2° approximately 30 m each; nevertheless, it would vary according to the formation index. This section was drilled with water-based mud (KCL polymeric 3.5%) that ranged from 1.17 to 1.30 gr/cc, with a minimum flow of 400 gal/min and an optimum of 700 gal/min. The total flow area (TFA) of the bit with 0.92 in2 was 1.37 hydraulic power (HSI). The plan was to minimize “washing” and channeling in the conglomerates; meanwhile, the cleaning was improved with viscous sludge. Toward the base zone and the settling point, a lithological change was expected. Shales would change from a semihard to a hard state with high hydration; so a 10 3/4 in. J55, 40.5 lbm/ft casing was placed. The casing was built up with 28 centralizers and a 100% standoff, which helped achieve excellent centralization in the hole. It was cemented with a slurry of 1.90 gr/cc with gas control because of the existence of input superficial gas in neighboring wells.

Figure 6. – Well path: plan (mode) vs. real mode.

Intermediate Stage of 9 1/2 in. at 1000 md. The plan for this stage was to reach 1000 md/947 mV and gain integrity for the next stage. This section allowed a construction KOP of 435 m and to continue drilling the well. The severities reached 4.5°/30m, an inclination of 50°, and a trend of 198°, which crossed through the shale layer (Guayabal formation), which works as a seal for the reservoir. For the previous work, a conventional motor with a stabilizing sleeve of 6 3/4 in. was used as well as a configuration of 6/7 a rotor/stator with a 1.5° AKO equipped with MWD. The BHA “navigable system” (Fig. 8) had a 9 1/2-in. PDC bit with five blades with 16-mm cutters with special characteristics as well as “back reaming” cutters. The reason for working with this equipment was the plastic formation, which can rapidly hydrate causing mechanical sticking of the BHA and Drillstring.

Figure 7. – BHA components for the 14 1/2-in. stage.

Figure 8. – BHA components for 9 1/2-in. stage.

According to the model, this BHA construction was of 1.5 at 2°/30m; a rotation in the string ranged from 90 to 110 rev/min to avoid “whirl” vibration. The plan for this section was to drill with an oilbased inverse emulsion mud with 1.35 gr/cc, with a minimum flow of 350 gal/min and an optimum flow of 470 gal/min. A TFA bit of 1.534 in2 with 0.33 HSI was used. It was planned for improving the cleaning of the hole, high penetration regimes, and better directional control with the severities of this stage. The coat tubing configuration of 7 5/8-in. P110, 29.71 bm/ft BCN had 46 centralizers with an 80% standoff, cemented with two types of slurries: 1.60 gr/cc (700 m) and 1.90 gr/cc (300 m) with gas control at 50% and spacer of 1.50 gr/cc, to obtain effective sweep and fluid control.

Production Stage 6 3/4 in. (2407 m). The plan for this final stage was to drill in two segments with two directional systems, the first one used the SlickBore® system with a high performance motor of 4 3/4 in. and 1rev/gal graduated at 1.15° AKO. It was combined with a PDC bit with a gauge length of 6 3/4 in., 13-mm cutters, equipped with MWD and LWD (gamma ray and resistivity in real-time). The plan for this segment was to continue drilling the hole with an inclination that ranged from 50 to 90°, and a 150.30° direction in the azimuth with high severities that can reach 8°/30 m. The behavior of the model for the BHA (Fig. 7) ranges from 1.45 to 2.08°/30 m, with a weight of 6 tons over the bit. This showed that, with 30% of sliding work, the well would land effectively, without affecting the penetration rate and the 70% left would continue with the rotation. Another important factor during this stage was the generation of a high quality hole without microtortuosities for effective navigation in the horizontal section. A general example of the different behaviour of long gauge vs short gauge bit helping to increase the hole quality on the wells is shown in Fig. 9. The drilling parameters for this string ranged from 90 to 120 rev/min, minimizing the “whirl” vibration. The weights on the bit were from 6 to 7 ton; rates above this limit would have generated sinusoidal buckling with an optimum rate ranging of 220 to 250 gal/min. The plan was to pull out the SlickBore system at a depth of 1584 m to take a (9-m) core sample with a conventional tool; this was the first time this procedure was performed in this region, taken from the horizontal section at 90° (Fig. 10). Once landed for the second phase of this stage, dragging and torque simulations showed limitation on the weight of the bit, generating sinusoidal buckling 7 ton over this limit. Additionally, there was deficient directional control because of low penetration rates and high tortuosities. Responding to this situation, the decision was made to use a continuous rotatory system (Fig. 11) with a PDC, a 6 3/4-in. gauge, 13-mm cutters, with a rotatory system equipped with MWD, LWD (gamma rays and resistivity), and a PWD sensor in the annular pressure of the well. This cutting-edge technology arrangement was used to perform the navigation according to geologic and completion requirements. A horizontal navigation 27

E X PLO I T I N G V A S T OI L RESOURCES IN ME XI CO ’ S CH ICO NT EPEC B A SIN

added in case it was necessary to rotate the string for successful positioning. A special hydraulic hanger that allows rotation was ready. For this reason, there was no need of mechanic wedges; it was anchored along 70m and overlapped inside the 7 5/8-in. casing. Once it was introduced, the plan was to leave the inside and the liner annulus with diesel to provide the swellable packers a means to reach a maximum seal of (3, 500psi) (Fig. 12). It was placed on the mouth brine of 1.02gr/cc, leaving it ready for a multistage hydraulic fracturing process.

Lessons Learned During Stage 14 1/2 in. (410 m)

Figure 9. – Better hole quality with the combination of high-performance motor with an extended bit caliber.

• The conglomerate was less thick than expected. • Because this was a highly contrasting formation, directional strings were necessary during this stage to help ensure verticality and avoid collision because of a high deviation tendency. • Reaming should be a regular practice during the drilling of each station. Avoid backreaming as much as possible.

of 1000 m was achieved uphill in a “boomerang,” with a high-quality hole, which nullified tortuosities and microtortuosities without carrying out sliding operations for directional control, optimizing the penetration rate and reducing time necessary to take partial surveys. The plan for this stage was to drill with oilbased mud of 1.38 gr/cc with maximum lubricity, reducing torque and drag with an optimum rate of 220 gal/min, with a TFA of 1.387 in2, to minimize “washouts” and maximize the effectiveness of the cleaning with the help of sludges sent in a tandem; the work in its entirety was monitored using a PWD sensor, which also verified the effectiveness of the cleaning. Completion Stage. The plan was to finish the horizontal section with a production liner of 4 1/2-in. N-80, 13.5 lb/ft, a non-cemented HY513, equipped with sleeves for the multifracturing and for isolating swellable packers of 6.45 in. with a hydraulic hanger of 4 1/2- × 7-in. and 13 centralizers. A torque and drag analysis was performed to lower the arrangement down successfully. Because it was an unconsolidated sand body and because of high severities that appeared in the landing, problems were expected the moment the arrangement was introduced effectively in the horizontal section. For this reason, a rimming shoe with a floating device was 28

Figure 10. – BHA components SlickBore system, loads distribution, and critical rotation simulation in the column.

Figure 11. – Components of the rotatory drill system (RSS).

• Once the stage is finished, the mud weight should immediately be increased to 1.45 gr/ cc to help avoid a lack of stability in the high lithological contrast of this section. • It is possible to have a 10 3/4-in. casing with a suitable centralization at this level. Cement excess should be corrected at 20% values to obtain an acceptable return.

“boomerang” at an uphill angle. The results with the rotatory system were excellent, with a high level of performance behavior in extended horizontal sections. For this reason, the rotatory systems must be used during this stage. • This design provided enough weight for the rotatory system, which might have been extremely complex.

Lessons Learned During Stage 9 1/2 in. (1000 m)

Conclusions

• For this section, the motor graduation of 1.5º AKO was very aggressive, generating an unnecessary torque and severities above what was necessary. • Reaming was not necessary with 1.35 gr/cc of oil-based mud, this stabilized the well walls properly. • At this level, the formation was consistent and did not show major changes or any disturbance in the path; the parameters were in optimal conditions at the end of this section. • This section provided advantages for optimizing drilling times. • Centralization was possible until reaching 70% standoff; adding more centralizers would generate dragging during the running. • An excess of 25% in the slurry design was enough, ensuring its return to the surface.

Lessons learned During Stage 6 3/4 in. (2407 m) • Difficulties for this section were expected associated with sandy shale unconsolidated bodies and constant gasification with a high degree of deviation and difficulty keeping the

• Parallel horizontal wells were designed exclusively for the completion discussed. The operating company was a global pioneer for completion of this type of well. • The planning and execution of these operations were carried out by a multidisciplinary team, and a new working methodology and drilling and completion technique was created for wells in the area. This methodology turned out to be more effective than planned in terms of reducing time and costs associated with unconventional well operations. • Using cutting-edge technology allowed completion of wells with reduced deviation in terms of design and enabled the success of the completion that was expected. • The string and bits designs were specific for these wells and required for this purpose; also, optimum results were achieved with high severities. • The oil-based, solids-free drilling fluid played a crucial role by reducing torque and drag levels by 50% in comparison to an oil-based conventional mud. • For the first time, a conventional core of the horizontal section was taken in the region.

• The success of these wells originated from a detailed simulation planning and detailed engineering analysis combined with suitable tools selection for each stage of operating procedures during drilling. • The procedures allowed optimization of the time necessary for drilling this type of well by 37%. • The wells were completed within the authorized times specified by the authorization of expenditure (AFE), achieving record time in relation to productivity as well as reduction to NPT.

This Information is property of PEMEX, partial or total use are strictly prohibited without authorization.

Nomenclature AFE

authorization for expenditure

AKO graduation bottomhole motor angle BHA

bottom hole assembly

DFIT diagnostic fracture injection test DLS degree length severity every 30m IADC international drilling contractor LOT

leakoff test

LWD logging while drilling MD

measured depth

MWD measurement while drilling NPT non-productive time PWD pressure while drilling ROP rate of penetration RSS

rotatory steerable system

TFA

total flow area

TVD true vertical depth

Figure 12. – Hanger liner, sleeve, and swellable packer.

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Authors Guillermo Gutierrez Murillo is the project implementation leader of the national program of productivity in Ku-Maloob-Zaap asset of PEMEX in Cd. Del Carmen. He has been in charge of high performance multidisciplinary teams to increase well productivity and has provided support and follow-up in strategic projects for the Coordination of Design and for Technical Information Production Management. He has also participated in the creation of standards for well completions and evaluations for pressure tests. Guillermo has 21 years of experience in the oil industry with a specialty in unconventional reservoir evaluation. His work as a project leader has had a high impact in production and best practices documentation in international and national conferences. Guillermo received a master degree in reservoir evaluation and management from Heriot Watt University and a bachelor degree in petroleum engineering from UNAM. He has written and presented more than 20 papers in national and international forums and has participated in the organization committee of several conferences. Guillermo is an active member of the SPE, CIPM, AIPM and the productivity experts’ network of PEMEX.

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Goldy Villanueva Zapata is from Bolivia and currently working as a drilling engineer for Halliburton Consulting and Project Management with responsibilities in the Gulf of Mexico designing and planning HP/ HT ultra-deepwater wells. In Goldy’s previous position he was in charge of an unconventional drilling well campaign for Chicontepec, Mexico, where successful performance increased oil production to a record in this area. Prior to Halliburton, Goldy was a drilling supervisor engineer for Petrobras in Brazil and Bolivia. He has 14 years of drilling and completions experience, including director at YPF Chaco Petroleum, drilling supervisor, head of exploration and drilling for YPF Bolivia. Goldy holds a BSc in petroleum engineering from La Paz-Bolivia USMA University and MS in finance from the CIFF University of Alcala Henares, Madrid Spain.

Eber Medina is Pinnacle technical leader in Mexico and has been involved in the completion of unconventional wells in the Chicontepec basin in Mexico. He has six years of experience in the oil industry mainly in the north region in Mexico. Eber has participated in the design and execution of hydraulic fractures, matrix stimulations and conformance treatments in the Chicontepec basin and the Poza Rica Altamira district and currently is in charge of the stimulation monitoring operations in Mexico with microseismic and fiber optics. He is experienced in completion techniques for multi-fracturing lateral wells. Eber holds a bachelor degree in chemical engineering from ITCM. He is an active member of the SPE.

RE A L - T I ME G EOS T EER ING WIT H GABI™ MO TOR

Instrumented Motors Prove Crucial in Unconventional Well Placement

more than one million feet in lateral sections for smaller hole sizes. However, a lack of nearbit instrumented motors exists for larger than 4 3/4-in wells.

Anthony Wright and John Snyder, Halliburton

The need for larger instrumented motors to precisely geosteer in reservoirs prompted the design of a 6 3/4-in. gamma-at-bit-inclination sensor (Figure 1). This near-bit instrumented downhole drilling system was developed to use not only in the lateral, but also in the curve and vertical sections before reaching the pay zone. In addition, this system can assist reservoir characterization for the most common 6 1/4- to 9 7/8-in production well sizes. The larger-sized tool further enhances the suite of tools available to not only help define the curve, but also for choosing tops in the vertical section. This leads to a shorter curve radius and assists with determining better formations in which to kick off, rather than missing the target formation.

Copyright 2014, IADC/SPE Drilling Conference and Exhibition This paper was prepared for presentation at the 2014 IADC/SPE Drilling Conference and Exhibition held in Fort Worth, Texas, USA, 4–6 March 2014. This paper was selected for presentation by an IADC/SPE 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 International Association of Drilling Contractors or the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the International Association of Drilling Contractors or the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the International Association of Drilling Contractors or the Society of Petroleum Engineers 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 IADC/SPE copyright. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission.

Abstract Near-bit, instrumented motors are a transformative technology used for unconventional well placement. Near-bit sensors are located closer to the bit compared to traditional measurement while drilling (MWD) sensors, which are normally >20 ft behind the bit, thus allowing the opportunity for exiting thin bed formations before a formation change can be observed on the logs. These tools are also instrumental when choosing the formation tops for each new boundary drilled. The gamma-at-bit-inclination sensor system provides at-bit azimuthal gamma ray and inclination measurements for improved geosteering and optimum well placement. This paper describes the geosteering capabilities of a newly released 6 3/4-in. sensor in different formations. In a single run, the gamma-at-bit-inclination sensor system successfully delivered a hole section of 4,952 ft (2,248 to 7,200 ft) in 43.5 drilling hr, with an average rate of penetration (ROP) of 114 ft/hr in depleted shale and sandstone formations on the Gulf of Mexico (GOM) continental shelf, eliminating additional bottomhole assembly (BHA) changes; a 4,043-ft (7,442 to 11,485 ft) lateral in 23.5 drilling hr with an ROP of 172 ft/hr in Oklahoma City (OKC), Oklahoma; and 4,781 ft (479 to 5,260 ft) in 37.75 drilling hr at an ROP of 127 ft/hr in the Woodford shale of the Mississippi Lime, with zero non-productive time (NPT) or health, safety, and environment (HSE) incidents. The use of near-bit, instrumented motors allows remaining in the zone of unconventional plays longer. To date, a total of more than one million feet has been drilled using a smaller near-bit, 4 3/4-in. instrumented motor, and running with larger-sized tools has proven successful. Instrumented motors previously had limited drilling application; however, with the geosteering requirements for unconventional well placement, a greater range of applications for the measurements provided by the near-bit, instrumented motors has been identified.

Introduction Precise geosteering requires high-quality tools with azimuthal sensitivity for optimal well placement. Near-bit, instrumented motors provide near-bit gamma ray with azimuthal sensitivity, and inclination sensor information. This new generation of motors allows drilling to remain in the sweet spot once the formation boundaries are defined. These tools are also instrumental for choosing the formation tops as each new boundary is drilled. Additionally, the benefit created by the capability to azimuthally log gamma ray sections while sliding eliminates the need to relog a section once it has been drilled during a slide operation. A smaller 4 3/4-in. gamma-at-bit-inclination sensor was designed to fulfill the need for near-bit, instrumented motors (Pitcher et al. 2009; Burinda et al. 2009). The 4 3/4-in. gamma-at-bit-inclination sensor was the industry’s first real-time imaging, azimuthal gamma and inclination tool at bit, and has successfully drilled

This paper describes the application of the 6 3/4-in. gamma-at-bit-inclination sensor system in different formations using geosteering application. The 6 3/4-in. gamma-at-bit-inclination sensor system has been run in depleted shale and sandstone formations on the continental shelf in GOM, on a lateral section with no concerns of fault zones in OKC, and the Woodford shale in the Mississippi Lime.

Tool Configuration and Measurements The 6 3/4-in. gamma-at-bit-inclination sensor system consists of two sections. An upper electronics sub located above the power section of the mud motor contains the necessary electronics to support the through motor short-hop telemetry. The upper electronics sub communicates with the logging/measurement while drilling (L/MWD) tool, and provides sufficient memory to store binned data from the lower electronics sensors. This design also requires a mechanical connection to the top of the rotor for signal propagation (Pitcher et al. 2009). The lower electronics sub contains four sodium iodide-thallium [NaI(Tl)] scintillation detectors mounted 90° radially around the circumference of

Figure 1. – 6 3/4-in. gamma-at-bit-inclination sensor system.

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the tool, as well as a triaxial inclinometer package and associated electronics for data acquisition, processing, and short-hop telemetry. Memory is also included for data storage. A driveshaft extension running through the center of the tool transfers torque from the power section to the drill bit (Pitcher et al. 2009).

The 6 3/4-in. gamma-at-bit-inclination sensor is mounted below the power unit of specially configured motors to deliver real-time feedback on directional trends and formation changes. Locating the gamma sensors closer to the bit, and viewing measurements in all four quadrants of the wellbore even while sliding the motor, makes

it possible to detect formation changes sooner, thus eliminating drilling of non-productive footage. Inclination readings from directly behind the bit contribute to flatter, longer horizontals and more accurate well placement. By providing immediate feedback about unexpected trajectory changes due to faults, stringers, changes to dip angle, and

T R B L T

T R B L T

Figure 2. – Top, right, bottom, left, top (T – R – B – L – T) quadrant log image.

Figure 3. – Base approach log image.

T R B L T

Figure 4. – Top approach log image.

T R B L T

Figure 5. – Bottom tag log image.

T R B L T

Figure 6. – Top tag log image.

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T R B L T

Figure 7. – Bottom scrape log image.

other formation related issues, the 6 3/4-in. gammaat-bit-inclination sensor system can ensure the trajectory is corrected immediately so that the well remains on target. Figs. 2 through 7 show log responses of the 6 3/4-in. gamma-at-bit-inclination sensor system.

Woodford Shale (Mississippi Lime). The 6 3/4-in. gamma-at-bit-inclination sensor system was used to find the top of a known formation to accurately core a section in the Woodford shale of the Mississippi Lime for a vertical exploration well. The core was to provide valuable information about this reservoir for use in surrounding wells.

wellbore placement. The 6 3/4-in. gamma-at-bitinclination sensor system is a powerful tool for drilling long horizontal sections and remaining in the pay zone for both conventional and unconventional reservoirs.

In previous wells, the operator drilled passed the coring point and missed a crucial target zone. Therefore, the operator desired to drill within 10 ft of a certain formation and stop to core the section. This information would be used to better plan extended-reach wells for this particular reservoir. To maintain the proper data density to facilitate the identification of certain formation boundaries, ROP was slowed near known zones to accurately select formation identifiers. Once the formations had been accurately identified, ROP was increased to improve overall drilling performance efficiency.

The authors acknowledge Jason Pitcher and Jeremy Greenwood for their insight. The authors additionally thank Jason LeClair for providing log responses.

Geosteering Applications GOM Continental Shelf. A pilot hole in depleted shale and sandstone formations on the GOM continental shelf requiring a high-angle build and hold (>60°) section for a 9 7/8-in. well was drilled. The job required a high-quality, smooth wellbore to improve running of liners and completion strings and avoidance of NPT associated with searching for a good pay zone. In addition, it was critical to avoid nearby wells on the pad while drilling. A 4,952-ft (2,248 to 7,200 ft) hole section was delivered in a single run, eliminating additional BHA changes. The pilot well was drilled in 43.5 drilling hr with an average ROP of 114 ft/hr. The 6 3/4-in. gamma-at-bit-inclination sensor system demonstrated an enhanced capability for landing the curve. Inclination and azimuthal gamma readings from directly behind the bit helped deliver a flatter, longer horizontal and reduced the reaction time for making critical geosteering decisions. A smooth lateral wellbore was precisely positioned in the pay zone, capturing more of the reservoir, and overall drilling efficiency was improved by receiving immediate feedback on any changes in gamma ray and inclination. Time was saved by not having to relog sections that were drilled while sliding. Midcontinent USA (OKC). The 6 3/4-in. gammaat-bit-inclination sensor system was used on a lateral in which there were no fault zone concerns. For this well, the operator did not require the realtime information, but instead desired to evaluate the recorded data after the job to determine future use of the 6 3/4-in. gamma-at-bit-inclination sensor system applications in laterals with known faults. The services provided were the 6 3/4-in. gamma-atbit-inclination sensor, L/MWD sensors, and drilling optimization. All services were used to monitor the drilling performance from the remote operating center (ROC) located in OKC. A 4,043-ft lateral was delivered in a single run in 23.5 drilling hr with an average ROP of 172 ft/hr.

A 4,781-ft (479 to 5,260 ft) lateral was delivered in a single run in 37.75 drilling hr with an average ROP of 127 ft/hr. The 6 3/4-in. gamma-at-bitinclination sensor system was instrumental to finding the top of a zone without drilling too far into the target formation and potentially exiting before it was visible on the logs. It was possible to detect a formation top that had been previously drilled through with other tools. This allowed for drilling precisely to the designated total depth (TD) desired by the operator.

Summary and Conclusion The 6 3/4-in. gamma-at-bit-inclination sensor system was successfully used to geosteer different wells in real-time in GOM, OKC, and the Mississippi Lime, USA. In all of the applications, the 6 3/4-in. gamma-at-bit-inclination sensor system demonstrated zero NPT or HSE incidents. In addition, there was no need to relog sections while sliding. The 6 3/4-in. gamma-at-bit-inclination sensor system delivers full wellbore coverage, even in sliding mode, without the need to orient the motor for up, down, left, and right readings by providing four independent gamma ray readings simultaneously in four quadrants around the tool. Locating the sensors close to the bit makes it possible to detect adjacent bed boundaries before exiting the pay zone, and avoid wasting time drilling non-productive footage. Inclination readings from directly behind the bit contribute to flatter, longer horizontals and more accurate

Acknowledgements

References Burinda, C., Pitcher, J., and Lee, D. 2009. Geosteering Techniques in Thin Coal Reservoirs. CSPG CSEG CWLS Convention. Calgary, Alberta, Canada, 9–13 May. Pitcher, J., Schafer, D., and Botterell, P. 2009. A New Azimuthal Gamma at Bit Imaging Tool for Geosteering Thin Reservoirs. Paper SPE 118328 presented at the SPE/IADC Drilling Conference and Exhibition, The Netherlands, 17–19 March. http://dx.doi.org/10.2118/118328-MS.

Authors Anthony “Tony” Wright began his career with Halliburton in 2008 in the Sperry Drilling product service line (PSL) as an L/MWD field engineer in Alaska. He later transferred to Gulf of Mexico and worked offshore. He has work in the Sperry Technology group as a product engineer, in Operations Technology as a technical advisor, and his most current role as a product champion for the Directional Drilling sub-PSL. Tony honorably served in the United States Navy for six years aboard the USS Enterprise (CVN-65) as a nuclear qualified engine room mechanic. He attended Purdue University for both his bachelor and master degrees in mechanical engineering. He is currently working on his professional master of business administration (MBA) at Rice University, and will graduate in May 2015. John Snyder is a Sr. PSL manager for Sperry Drilling’s West Coast operations. John has more than 30 years of industry experience in operations, technical and strategic business leadership roles. A business and technology professional with experience in design, manufacturing and application of complex systems, he is considered a leader in the development of novel drilling technologies and processes. John holds a BSc in technology management from the University of Houston; AS in manufacturing engineering; business management certificate from the University of Texas; and attended Halliburton’s business leadership program at Texas A&M University. He has published and presented a number of technical papers and articles, has numerous patents, and is a member of SPE.

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Optimized Platform Placement to Cover All Geological Targets in Baronia Field M. Anas Sofian, Christophe Leuranguer, and Noor Farhana Musiran, PETRONAS Carigali; Afiqah Fathiah Ahmad Saifuddin, Thomas Wong, and Ilen Kardani, Halliburton Copyright 2014, Offshore Technology Conference This paper was prepared for presentation at the Offshore Technology Conference Asia held in Kuala Lumpur, Malaysia, 25–28 March 2014. This paper was selected for presentation by an OTC 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 Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference 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 OTC copyright. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission.

Abstract Platform placement and sizing are critical steps for enabling subsequent operations, such as well construction, logistics, and facilities installation to be performed efficiently and safely. This paper introduces the most economical, yet efficient, solution for an enhanced oil recovery (EOR) project in which 25 wells were to be drilled in the Baronia field, offshore Sarawak, Malaysia. Collaborative teamwork from drilling, reservoir, facility, geology, and production groups was required to develop the best solutions to minimize construction work, simplify well trajectories, and use all available resources to help minimize the overall budget. In addition, this paper evaluates the drillability of each well based on available drilling technologies and rig capabilities in the market. During the initial design stage, all 25 wells were planned to be drilled from two new wellhead platforms (WHPs) to intercept all geological targets. Major well collision problems were encountered against adjacent wells in the congested Baronia field; however, after several iterations of surface nudging and slots designation, all wells were drillable, with a total footage of 227,527.1 ft drilled.

Introduction The Baronia field is located about 40 km offshore, northwest (NW) of Lutong, Sarawak, Malaysia, in block SK15 of the Baram Delta area (Fig. 1). It was discovered in 1967 (Pratap et al. 2000) by Well BN-1 and production commenced in May 1972 from two isolated appraisal/development wells, BN-4 and BN-5. To date, 72 wells have been drilled in this field. To gain more productivity, horizontal wells were introduced in the Baronia field some 22 years after its first production. During those years, horizontal well drilling technology was just introduced “within the operating company and the Baronia field was the first to be implemented (Jadid and Mustapah 2007). Structurally, the Baronia field is characterized by a simple, internally faulted, relatively flat, low relief domal anticline structure elongated toward the south-southwest (SSW) and the anticline is resulted from a rollover associated with growth

Figure 1. – Location Map of Baronia field.

The first iteration was performed by placing one new single WHP at an optimized location and using spare slots and sidetracking from an existing platform. This optimized design reduced/saved 39,868.61 ft compared to the initial stage and eliminated the requirement for another new platform. The second iteration was performed by shifting the new WHP 300 ft closer to the production platform to enable bridge linking and help reduce construction work on the pipelines. The total footage to be drilled from this location was reduced again by 3,622.63 ft. Finally, the setup was further optimized by equipping the new platform with splitter wells, which reduced the number of conductor pipes required without decreasing the number of wells to be drilled. Overall, the platform placement and sizing optimizations saved USD millions during the planning stage by eliminating one platform, decreasing drilling footage, minimizing construction work, and helping reduce health, safety, and environmental (HSE) risks.

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Figure 2. – Baronia field spider plot shows four drilling platform (BNDP-A, BNDP-B, BNDP-I, and BNDP-J) and five jackets (BNJT-C, BNJT-D, BNJT-E, BNJT-F1, and BNJT-H1).

faulting combined with Pliocene compressional folding. The main prospective sequences are comprised of interbeded sandstones and shales with minor siltstones of Late Miocene (Jadid and Mustapah 2007). There are four drilling platforms in the Baronia field; two 12-slot drilling platforms (BNDP-A and BNDP-B), two 15-slot drilling platforms (BNDP-I and BNDP-J), and five 3-slot jackets (BNJT-C, BNJT-D, BNJT-E, BNJT-F1, and BNJT-H1) (Fig. 2). The first field development started from the drilling platform BNDP-A in 1974, and continued to 1979 from a second drilling platform, BNDP-B.

Drillability Criteria The following criteria are given to ensure that each well is drillable from a given location and reach the geological targets as shown in Fig 11: • Drilling risks • Anti-collision • Dogleg severity • Hydraulic • Torque and drag • Rig capability • Technology availability • Cost efficiency A number of significant drillability criteria were taken into account in the well design for a cost efficient planning and to alleviate any drilling risks. Study from the offset wells will give useful information regarding the drilling problems which may have happened in the past so that the mitigation plans can be clearly defined. All anti-collision risks and mitigation plan should be lay up in detail and communicate to all parties during the planning and execution phase. Correct geographic system, geodetic datum and map zone need to be established and agreed upon in order to have an accurate coordinate system. All anti-collision policies were followed in the planning stage especially on meeting the criteria of clearance factor of more than 1.5 and the sigma value was set to 2.445 as per the operating company’s requirement. The formula for calculating the clearance factor ratio is: Distance between Centres Distance between Centres - Distance between Ellipsoids + Combined Casing & Hole Radii Actual survey and planned trajectories need to be updated in the database before commencing any close approach analysis. The anti-collision scans

were run against all wells with wellheads within 15km of the reference well or as per company’s policy. In this analysis, numbers of iterations were made to come up with optimum wellbore trajectory including shifting the targets after thorough discussions with the subsurface team to meet anti-collision criteria. All the EOR wells in Baronia field were planned with clearance factor of more than 1.5 and anti-collision procedures were generated and must be adhered to by the directional drillers offshore. Dogleg severity (DLS) is defined as the change in the inclination, and/or azimuth of a borehole, usually expressed in degrees per 100 feet of course length. In the metric system, it is usually expressed in degrees per 30 meters or degrees per 10 meters of course length. There are various factors in determining the dogleg severity but the best practice is to keep it as mild as possible. However, since the Baronia field is very congested, some of the wells have to be kept at certain dogleg severities to avoid collision with proximity wells and this scenario is called anti-collision DLS. Excessive DLS will affect the other measurements such as torque, drag, casing wear, buckling limit, drillstring sideforces, cyclic fatigue, hole cleaning efficiency, casing running, and placement of completion tools.

compression and tension. Total value of the hook load during pulling out of hole needs to be calculated and compared against the rig’s hoisting system. Moreover, directional drilling hydraulics plays an important role in determining the drillability of a well for a successful hole cleaning. Failure in hole cleaning can cause excessive overpull on trips, high rotary torque, stuck pipe, hole pack-off, excessive equivalent circulating density (ECD), cuttings accumulation, formation breakdown, slow rate of penetration, and difficulty running logs and casing. Therefore, it was important that the wells were simulated to ensure they met the hydraulics requirements. It was desirable to avoid planning wells with a tangent section within the critical hole inclination range, between 45° to 65°. There were instances that the critical range for hole cleaning was unable to be avoided, the tangent section was planned as short as possible instead. The flow rates were also selected for good hole cleaning for each hole sections for example 10001200 gallons per minute for 17-1/2” and 12-1/4” hole sections. Execution of the hydraulics analysis took into account the rig’s capability in terms of the mud pump efficiency. It was ensured that the total stand pipe pressure was limited to the rig’s liner pump’s availability and the total pressure loss to provide hydraulics energy to downhole tools were below the pop-off pressure.

Besides that, the severity of the mechanical loads imposed on drill string elements namely All these criteria were optimized to come up with the torque and drag, tensile strength reduction the most feasible and cost efficient well designs, due to bending stress in doglegs need to be which supported by the available technology in the considered. The drill string experiences both market as well as the rig’s capability. torque and drag since the drill pipe is in rotational as well as performs linear motion. Drag is the increase in string weight when pulling out of the hole or the reduction in string weight while tripping in the hole while torque is the force required to turn the drill string. More severe doglegs will cause higher torque and drag. Torque and drag simulation was performed to ensure the rig’s drill pipes would not reach the buckling limit and tensile strength Figure 3. – Spider plot shows 25 EOR wells planned from two WHPs, BNIT-A limit due to excessive and BNIT-B.

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depths to avoid collision. It is imperative to kick off the inner slot wells at the shallowest depth first, and then progress to the deepest kickoff for the best option of well dispersion of the outside platform (Fig. 5). Additionally, full use of four spare conductor slots and two wells sidetracking from the existing BNDP-J platform was achieved at this stage. Six wells for targets located southwest of the field were replanned from BNDP-J to replace the eliminated BNIT-B WHP (Fig. 6).

Figure 4. – 3D view of 25 EOR wells planned from BNIT-A and BNIT-B.

Summary and Findings. Because of more stringent constraints of directional planning, this exercise triggered several iterations of optimization cycles between drilling and reservoir engineering, in which “well creaming” was performed thoroughly to eliminate the low economic value wells. In addition, horizontal targets were realigned to simplify the well profile. Five wells were dropped from the initial plan of 25 wells with a very minimum impact on reserves, and hence improved the overall project economic tremendously.

Initial Scenario: Two New WHPs. At the initial stage of the project, the EOR wells were planned from two new wellhead platforms (WHPs), BNIT-A and BNIT-B, to intercept all geological targets given (Fig. 3). A 3D view of the 25 EOR wells from BNIT-A and BNIT-B is shown in Fig. 4. Initially, there were 25 wells planned to be drilled from WHPs BNIT-A and BNIT-B, to consist of the following: • Oil producer: 11 wells. • Gas producer: 7 wells. • Water injector: 6 wells. • Gas injector: 1 well. Although major collision problems were experienced within the proximity wells of this congested Baronia field, after several surface nudging iterations, effective slots designation, and proper planning, all the wells from these two platforms were achievable and the total measured depth (MD) was 227,527.11 ft. Further evaluation with respect to a drillability check (torque and drag, hydraulics, casing, and cementing design) confirmed the feasibility.

Figure 5. – BNIT-A conductor plot shows surface separation by proper nudging at specific gyro azimuth for all the wells.

Optimized Scenario 1: One New WHP and Use of Four Spare Conductor Slots from Existing Platform. The new single WHP, BNIT-A, was placed in one optimized location, which was 2000 ft away. The optimization of the location of BNIT-A was performed on one centralized platform based on placement of horizontal drainage; the two outermost horizontal drainage alignments emphasized two wells to be two-dimensional (2D), while the rest of the horizontal wells were to be mid to quite severe three-dimensional (3D) horizontal profiles. Based on a 2000-ft radius to obtain a maximum of 3°/100 ft dogleg for the horizontal wells, the optimized platform coordinates for BNIT-A were selected. The outer conductors’ well designation was performed effectively to kick off below the shoes at 600 ft MD at 2.3°/100 ft along specific gyro azimuth to disperse the bottomhole location outside the platform to avoid collision. With respect to the inner conductors’ well designation, the planning was performed by true vertical depth (TVD) separation kicking off at different TVD 36

Figure 6. – BNDP-J conductor plot shows four wells are planned from four spare slots (marked in red) and two wells are sidetracking from existing wells.

All of the wells again were proven to be achievable with a total MD of 187,658.50 ft. The optimized location and the use of the spare conductor slots as well as the well creaming exercise saved the total footage by 39,868.61 ft; this is a massive savings with respect to drilling (Fig. 7). The most significant outcome from this, however, was the ability to reduce the number of new WHPs to a single new WHP, hence a significant reduction to facilities costs. This has potentially saved the overall project (Project CAPEX) approximately USD 250 million at the conceptual stage. Optimized Scenario 2: One New WHP at Bridge Linking Location to Existing Platform BNDP-I. Further optimization work was undertaken to achieve greater cost savings for the project. The idea was to place the new platform at a site, which is 300 ft from the existing complex, BNDP-I, to enable bridge linking (Fig. 8). No live wells were ensured underneath the proposed location within a safe radius of 150 ft and the wells were set to kick off deeper, alleviating collision risk. Figure 7. – Spider plot shows 14 wells are planned from an optimized location of BNIT-A, and six wells are planned from existing platform, BNDP-J.

At this stage, there were 20 wells planned to be drilled from platforms BNIT-A and BNDP-J, to consist of the following: • Oil producer: 5 wells. • Gas producer: 7 wells. • Water injector: 7 wells. • Gas injector: 1 well. Summary and Findings. This bridging of the platform enabled the operating company to share platform facilities, such as personnel living quarters, and achieve significant cost reduction on pipelines, which greatly contributed to lowering the budget of the overall project (Project CAPEX) as well as future projects (Project OPEX) (Fig. 9). The total footage to be drilled from this location was 184,035.90 ft. This, again, further shortened the total MD by 3622.63 ft. Additionally, significant reduction to project costs of USD 63 million was achieved through this optimization process.

Figure 8. – Plan view shows the shifting of the platform 2700 ft east-south (ES) for bridgelinking with BNDP-I.

Optimized Scenario 3: Hybrid Platform Design with Splitter Wells at Four Corners. A more optimized platform design was created to incorporate a 36-in. dual splitter system, with 2 × 13 3 /8-in. surface casing, to be deployed with no restriction with regard to the surface casing deviation and kickoff depth (Fig. 10). The selection of wells for splitters was the first kickoff below the conductor shoes for wells with higher dogleg and complexity. The second kickoff was by 200 ft TVD separation. Surface dispersion of wells to be collision-free was important. Therefore, nudging of all wells for the best possible kickoff position was imperative. Summary and Findings. With this hybrid platform design, less conductors were necessary to be installed while retaining the number of wells. This significantly reduced time and cost for conductor installation. Additionally, it left less platform footprint, which enabled the use of a jackup rig instead of a tender assisted rig; hence, a lighter platform could be designed. The platform was then renamed BNDP-K.

Conclusion

Figure 9. – Spider plot shows all 20 EOR wells planned in the Baronia field from BNDP-J and BNIT-A.

The success achieved for this EOR project at the conceptual well planning stage was largely contributed to a synergy of collaboration between all parties involved. Early engagement and technical input from specialized 37

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service providers from conceptual planning was vital to put the project on the correct path during the beginning stage. The optimized outcome was also a clear example of effective interdisciplinary teamwork between sections within the project team, such as drilling, subsurface and surface facilities, for agreement on the best tradeoffs between tapping the maximum hydrocarbon reserves and the “drillability” of the options based on sound engineering considerations. This work involved navigating through a considerable iterative process to optimize well planning that eventually led to the best optimized case with a bridge link to a single WHP option (Fig. 11). Figure 10. – Comparison of the previous platform and splitter wellhead platform design.

In terms of economic savings associated with these solutions, the reduction to the number of new WHPs from two platforms to one central platform as well as enabling a bridge link option demonstrated huge savings to the overall project (Project CAPEX); an estimated value of approximately USD 315 million was saved compared to the original base case scenario (Fig. 12). In addition to all of the risk factors being reduced with all these solutions in place, the net benefits to the operating company have been positive in terms of financial (CAPEX and OPEX) as well as intangible risk reduction benefits. The collaboration between different parties with a single common objective for an economically efficient solution will be the way forward to achieve such success in the future.

Acknowledgements The authors thank the management of Petroliam National Berhad (PETRONAS), PETRONAS Carigali Sdn. Bhd. (PCSB), and Halliburton for support and permission to publish this paper. Figure 11. – EOR project flow chart.

References Pratap, M., Ibrahim, Z.B., and Karim, M.G. 2000. Reservoir Simulation Study of Baronia Field, Offshore Sarawak, Malaysia Indicates Higher Reserves and OIIP. Paper SPE 64442 presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition, Brisbane, Australia, 16–18 October. http://dx.doi. org/10.2118/64442-MS. Jadid, M. and Mustapah, M.F. 2007. A Performance Review of 14 Horizontal Wells in Baronia Field After 12 Years of Production. Paper SPE 107630 presented at the SPE Latin American & Caribbean Petroleum Engineering Conference, Buenos Aires, Argentina, 15–18 April. http://dx.doi.org/10.2118/107630-MS.

Nomenclature EOR = Enhanced oil recovery WHP = Wellhead platform TVD = True vertical depth TVDSS = True vertical depth subsea Figure 12. – Total reduction of Project CAPEX.

CAPEX = Capital expenditure OPEX = Operational expenditure ft = feet in = inch DF = Derrick floor DLS = Dogleg Severity

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Authors Noor Farhana Musiran is a well engineer for Baram Delta & North Sabah EOR Center (EORC), an incorporated joint-venture between PETRONAS and Shell. She graduated from Universiti Teknologi PETRONAS (UTP) in 2011 as a holder of BSc (Hons) of petroleum engineering major in reservoir studies. She has been in the industry for 2.5 years, focusing on the development concept of EOR projects since then. This is her paper of many to come, Inn Syaa Allah. Afiqah Fathiah Ahmad Saifuddin is a drilling engineer for JX Nippon Oil and Gas Exploration (Deepwater Sabah) Limited. She holds a first class honors BSc in chemical engineering from the Universiti Teknologi Malaysia. She has been in the oil and gas industry for three years. She started her career with Halliburton Sperry Drilling services as a well

design engineer where she was involved in a variety of challenging projects such as the congested Baronia brown field. This is her first SPE technical paper and she is looking forward to writing and contributing more to the industry in future. Thomas Wong is a technical advisor for Halliburton Sperry Drilling in Malaysia. An experienced oil rigger, Thomas joined SperrySun International as a borehole survey engineer in 1981, evolving simultaneously with the oil and gas industry in drilling technology applications. He is an expert in gyroscopic and magnetic surveying techniques, passionate in directional well planning and platform site optimization, and possesses invaluable experience in measurement-whiledrilling and directional drilling onshore, offshore and in deep water. He quotes, “Pour into our younger generation the priceless experience we had and constitute them with the knowledge to excel”.

Ilen Kardani graduated in 1994 as a petroleum engineer from Bandung Institute of Technology (ITB), Indonesia. He has been in the oil and gas industry for more than 19 years, starting from field operations as a directional driller (DD). Ilen then moved on to positions of DD coordinator and operations manager, and is now focusing on business development and competency coordinator for Halliburton, Central Asia. One of his philosophies is to add more value to people, so he likes to share his experiences by writing papers. Ilen is published in SPE, OTC, IADC and is becoming a guest lecturer/ speaker for some campuses in Malaysia and Indonesia.

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Overcoming Extreme Weather Conditions by Drilling With MPD Offshore in the Arctic R. Lovorn, D. Lewis, S. Allen, I. Poletzky, Halliburton Energy Services, USA Copyright 2013 RAO/CIS Offshore. This paper was prepared for presentation at the RAO/CIS Offshore 2013 (International Conference and Exhibition for Oil and Gas Resources Development of the Russian Arctic and CIS Continental Shelf) held in St. Petersburg, Russia, 10-13 September 2013. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission.

Abstract

section of the service and engineering company that was assisting in delivery of the well were tasked with finding another drilling method that would improve drilling efficiency in both the intermediate and producing phases where lost circulation and narrow ECD windows were being experienced. Upon award of the contract, the operator wanted to have all associated equipment on this manmade island in the Arctic to meet a tight barge shutdown timeline (Fig. 1). This was imperative due to the weight of the equipment and the fact

Managed Pressure Drilling (MPD) is gaining acceptance as a viable tool for optimizing drilling and managing bottom hole pressure (BHP) in wells with narrow pressure margins, unconventional resources, high pressure/high temperature, and harsh environments. Consequently, an articulate MPD automated system for BHP control during job execution will ensure successful MPD results in such challenging drilling environments. Such a system must include the ability to do pre-job planning, have dependable equipment, and perform with a high level of precision. In this case, wells were initially drilled conventionally but were not successfully completed due to drilling problems such as stuck pipe, lost circulation, and the associated high mud costs which translated into a very costly operation. Initially, the application of MPD in the intermediate holes and laterals started as a technique to solve mainly lost circulation problems and differential sticking when traversing both weak (with high collapse pressures) and highly tectonically stressed formations. The main objective was to optimize drilling especially in narrow margins to minimize drilling problems, reduce Non-Productive Time (NPT), and therefore drilling costs. The automated MPD equipment includes a rotating control device (RCD), a choke manifold, a back pressure pump (BPP), flow meters, associated surface piping, and the automated control and data gathering system.

Figure 1. – Resource basins in the Arctic Circle region (Source: U.S. Geological Survey).

Background MPD has been defined by IADC as ‘an adaptive drilling process used to precisely control the annular profile throughout the wellbore. The objectives are to ascertain the downhole pressure environment limits and to manage the annular pressure profile accordingly’.

that the barge was the only form of transportation available to move the equipment to the island. There was also a need to determine what equipment was necessary to perform the job in accordance with the guidelines of the operator and the AOGCC (Alaska Oil and Gas Conservation Commission).

Introduction MPD is considered an enabling technology because of the ability to provide accurate and precise downhole pressure control ‘on demand.’ Nowadays, MPD systems provide the ability to operate in tight operational envelopes, provide dynamic real-time well-event detection, and control capabilities while continuing with drilling operations. These abilities give operators access to assets that were previously considered ‘undrillable’ by either physical or economic limitations. One of the main reasons for the success of MPD is in the automation features which provide levels of dynamic functional control and precision that are difficult, if not impossible, for human operators to achieve and maintain. MPD’s inherent closed-loop setup, coupled with conventional methodology, naturally lends itself to automated applications. Early in this project, a large amount of NPT and excess costs were experienced due to the well conditions. These conditions were affecting the service company’s ability to deliver the proposed wells with conventional drilling methods. The drilling problems centered on the very narrow equivalent circulating density (ECD) window, which was approximately 0.7 ppg. On the low end of the ECD window, hole collapse could result, and on the high end, fluid loss would be a problem. This would negatively impact the economics of the project and delay the recovery of reserves. Thus, the personnel in the MPD 40

The common reservoir structure for the region contains two different sand packages and is highly susceptible to overpressure, under pressure, and skin damage. The entire structure is tectonically stressed and contains several unconformities throughout. This geological scenario has created a drilling environment that is prone to losses, bore hole collapse, and NPT while drilling conventionally. In some formations, there is only a 0.2 ppg drilling window between collapse pressures and fracture gradient. To cross this boundary, a mud weight was designed, which was statically underbalanced to the collapse pressure, and automated chokes were used to maintain a BHP just above the collapse and below the fracture pressure.

When drilling these wells conventionally, there was typically a difference of 1 to 1.5 ppg between the static mud weight (MW) and the ECD. As the MW was increased for wellbore stability, the additional increase in ECD resulted in fluid losses when drilling through the narrowest pressure windows. The objective was to maintain a constant BHP by using a lower MW, usually below collapse pressure, and applying surface back pressure (SBP) to navigate through the different pore/collapse pressures, thus eliminating the pressure cycling experienced during connections. While drilling the intermediate section, there was a maximum SBP that could be imposed to avoid fracturing shallower weaker formations.

installation. Even with all this protection, the lines have to be blown down when no fluid is flowing in the lines, if not they will freeze, thus, all lines must be fitted with blow-down points.

HAZID/HAZOP The initiation of the first winterized MPD project brought forward very specific needs based on the harsh conditions encountered on this manmade island. With the equipment being outside of the enclosed rig, spill containment was one of the highest priorities placed on design and choice of equipment. Since this was to be the first Arctic MPD project, a comprehensive,

Equipment Winterization As this was the first MPD project to be performed in the Arctic where temperatures can drop as low as -70°F, an engineered solution for winterization of the equipment was required and had to be developed. A design consisting of 3 x 20-ft joined containers was developed with the 30,000 lb. choke manifold fitting in the center container. This provided storage and a workshop on opposing sides, and an ample working area for choke Figure 2. – Equipment in winterized containers. maintenance. The RCD with its own winterized container had a door added and attached to the choke area, making the entire step-by-step work method hazard identification MPD system 20-ft long x 32-ft wide (Fig. 2). (HAZID) and hazardous operation (HAZOP) was conducted by a third party. This was to ensure Large items like the choke manifold had to be that all aspects of the project scope were covered placed in the containers so personnel could still with recommendations to safely and efficiently work on the equipment as required without being deliver a successful implementation of the MPD subject to the cold weather. The containers were services in these Arctic conditions. To ensure a installed with two zone-rated air heaters. These successful campaign, it was necessary to perform units were set with a temperature differential simultaneous operations between equipment of only a few degrees, so if one failed, the other transportation and building of winterization would automatically start up to maintain the containers so that project procedures were internal temperature. The walls and the bottom completed prior to the first well scheduled to begin of the container were also insulated since a high drilling one month after the deadline for equipment percentage of the heat would be lost from the mobilization. bottom of the container. The containers were placed on a large skid to facilitate moving around Once a design was agreed upon, a rig visit was the location. The Hydraulic Power Unit (HPU) performed. The rig visit included a review of for the RCD was installed on the same skid and equipment placement and a confirmation of tie-in winterized in the same way. The BPP that fits points. Potential spill scenarios at all stages of under the rig floor sub was also the same design operations were considered with the goal of zero as the rest of the containers. As outside pipework spills. It was determined that blowout prevention also required sufficient protection at all time, flow (BOP) spill-containment equipment would be lines were heat-traced, double-wrapped, and then purchased. A ‘Katch Kan’ spill system was covered with a waterproof jacket to protect the sourced and added to the equipment list. This is a

discharge system for drilling and service rigs that collects fluids for recirculation or proper disposal. During the rig visit, the equipment was in transport, and the winterized equipment was being built by a local vendor; the Anchorage team was developing detailed procedures. As soon as the procedures were developed and agreed upon by both parties, they were integrated into a comprehensive valve numbering diagram (VND). This ensured that all rig personnel would understand the work method and the fluid-flow process during each task. Once the procedures and valve numbering diagram were completed, both the drilling company and the operator signed off on all documentation. Any changes to the procedures required a risk assessment and a ‘Management of Change’ (MOC) form. After the preliminary engineering, drawings, and equipment selection was completed, a meeting was scheduled for all parties involved with the project to conduct the HAZID/HAZOP review. The purpose of this exercise was to thoroughly investigate all operations and ascertain the risk matrix was complete and develop any additional procedures needed. From the risk matrix, a critical path timeline was constructed and items were assigned to relevant companies with close-out dates. The project would not go operational until all outstanding items were closed even though some outstanding items had completion dates up to the day of commissioning the equipment. Once the MPD equipment arrived at the service company yard, a second temporary rig-up was performed with the equipment installed in the winterized containers. Four days were dedicated to equipment testing and all aspects of the MPD system testing were recorded. The testing ensured that the MPD system was ready for Arctic operations. Upon completion of the testing, the equipment was broken down and a third party was brought in to shrink wrap all items in preparation for the transport to Prudhoe Bay. The equipment left in time to meet the barge bound to the island as scheduled. 41

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Initial MPD Installation The compact layout of this manmade island drill site and the specialized nature of the rig presented several challenges as well as some advantages in locating and installing the MPD system. The drilling equipment consists of a mobile drilling rig and a fixed rig support complex (RSC). The rig is a fully enclosed, heated, and self-mobile unit that was specifically modified to cantilever the drill floor over closely spaced wellheads in enclosed well bays, while occupying a minimum footprint. The rig consists of two modules that are mounted on walking-beam moving systems. The sub-base module carries the cantilevered drill floor, draw works, and derrick with an enclosed suspended BOP ‘cellar.’ This basic rig structure is counter-balanced on the off-drill floor side of the walking beams by the rig powered diesel electric generators, air compressors, and heating steam boilers. The three-level service module carries the rig pumps, the mud pits and solids separation equipment, power distribution controls, and the pipe shed. The service module mates to the sub-base on the off-driller side and is connected by an enclosed walkway that houses high- and low-pressure flow lines, power, air, and communications connections. The RSC houses a bulk mud-mixing plant, mud-storage tanks, a cuttings processing mill, and a cement mixing and pumping facility. The RSC is connected to the rig via an enclosed pipe rack, which runs the length of the well bay buildings and carries mud, cement, drill-water, power, and communication connections to and from the rig. Depending on rig placement, the distance of the cement pump to the ROC could be 500 feet. The MPD equipment is comprised of five functionally distinct sub-sets. These are the RCD, the choke manifold, BPP, flow meters with associated piping, and the computerized control system. Consideration of the rig lay out and the need for freeze protection had significant impacts on both the sizing and location of the MPD equipment. For optimum functionality, the RCD is mounted directly to the rig BOP. Locating the BOP in the heated cellar immediately below the drill floor solved the enclosure issue, but less than 5 feet of clearance between the spherical and the rotary table mud box was left. As it was not feasible to lower the BOP or raise the mud box, a singleelement RCD was specified. Associated high- and 42

low-pressure piping for the RCD was installed beneath the floor and in the cellar. A suspended walkway was fabricated to facilitate access to the RCD from a mezzanine in the cellar. The ‘Katch Kan’ system was installed and flow hoses were run from the tray to an overflow container in the well bay. This container was instrumented for fluid-level monitoring. As previously described, the choke manifold was housed in a set of four containers set on the pad next to the sub-base unit on the driller’s side, opposite the service module. Several options for attaching the containers to the sub-base (so that they would move integrally with the rig) were examined. It was decided that these were not as cost effective as simply disconnecting the choke house unit for rig moves. Rig electrical power, air supply, and communications wiring were run to this enclosure from the sub-base module. Both high- and low-pressure flow lines connecting the RCD, the choke, and the mud return flow line were run through the BOP cellar. In the early stages of the project, it became evident that a new remotely controlled BPP could not be manufactured within the barge season time window. Various options for existing pumping units were examined and discarded due to spacing and winterization problems. Use of the existing cement pump in the RSC was then investigated. To maintain the closed loop circulation required for accurate well flow monitoring, it was necessary to feed the cement unit from the rig pits. A review of the existing piping in the rig pits, the pipe rack flow lines and the RSC mud plant revealed that the discharge from an existing, but little used, de-sander pump in the rig pits could be re-routed through a mud return line to carry mud from the active system to the mixing plant manifold. From there, it was possible to rearrange the check valves to allow this flow to feed the cement pump suction. Hydraulic calculations were performed to assure the adequacy of this equipment. Although the equipment was deemed adequate, a remaining concern was the need to man the cement pump. In light of the time constraints and the trial nature of the MPD project, it was decided to use this option. The MPD input circulation flow meter was located upstream of the cement pump suction due to the long distance between the two. This distance also necessitated an upgrade of fiber optical cabling for communications. The pump output was routed back to the rig cellar via the two-inch highpressure cement line. A tee and isolation valve

was inserted to direct the flow to either the RCD inlet or a bypass line. This allowed for flushing and pressure testing of the piping and choke manifold without pressurizing the RCD, BOP, or wellhead. Also housed in the cellar were the RCD outlet, HCR valve, and the low-pressure return mud flow meter. The constraints on equipment placement resulted in a final system piping configuration with several hundred feet of two-, three-, and four-inch highpressure piping and over one hundred feet of six-inch low-pressure flow line. Approximately two-thirds of the pipe work was enclosed since it was inside heated structures and the remaining third was external to the rig and RSC structures. These lines were liberally supplied with blow down ports and electrical heat tracing. They were insulated with several layers of fiberglass bat insulation, which was enclosed in a high strength plastic wind sheath. The final subsystem to be installed was the MPD computer-control system. The configuration selected was to locate the RCD operator’s panel and the main human-machine-interface (HMI) servers in the existing MWD/LWD enclosure located at the rig floor level but external to the drill floor. The design concept for the project was to have fully automated control of the bottomhole pressure. The HMI interacts with the choke and the BPP. External system data is received from the measurement-while-drilling (MWD) log suite and the rig-pit volume sensor. Internal system data is received from the choke transducer, choke position monitor, flow-rate monitor, and other MPD instrumentation sensors. The cement pump was manually operated during connections.

Crew Training and Equipment Functional Check Out Three levels of training were developed to prepare the rig personnel for operations and to ensure seamless conversion from conventional drilling to MPD operations: Interoffice training for officebased engineers and management; classroom training on-rig with equipment walk around; and live training during acceptance test. Initial preparation for MPD on-site began once the major components arrived on the barge. The bulk of the assembly of the MPD choke skid, RCD hydraulics unit, high- and low-pressure four-inch flow piping, two-inch high pressure cement pump

piping from the RSC cementing pump, and the MPD system were accomplished in September, 2008. The equipment was left on standby, when well schedule changes forced a delayed startup. During September and October, the drilling crews and other involved service company personnel were given training in the MPD procedures. Rig-up of the MPD equipment for use on the first well in the MPD program was completed in a week. The 16-in. rig-flow riser air boot was removed and replaced with a 20-in. assembly. The suspension tree and tubing hanger were then removed from the well. The RCD was Table 1. Comparison of Conventional vs. MPD wells. suspended below the floor, and the BOP was put in place beneath it on MPD mode. Minor operational issues were the wellhead riser. The flow lines, Katch Kan, RCD encountered and these lessons were incorporated walkway, split master bushings, and trip nipple in subsequent well procedures. were installed. While the rig picked up five-inch drill pipe and began BOP testing, the MPD piping BPP Installation and Full was completed, and the heat trace and insulation operation continued. The RCD and flow lines inside System Integration Between November 2008 and February 2009, the rig were also pressure tested. Pressure testing MPD was successfully used on several of the choke was completed with no failures. high-angle intermediate and horizontal During this interval, the surface casing shoe was production well sections. Based on continued drilled out, the well was displaced to sea-water improvement in the performance of both MPD mud, and a formation leak-off test was performed. equipment and personnel, and with consequent The MPD chokes were then calibrated. The MPD improvement in project drilling performance, trip nipple was pulled and replaced by the RCD. the operator committed to a more permanent Crew training and MPD acceptance testing was integration of the MPD system into the rig. conducted concurrently. MPD began upon drilling out of the surface casing shoe. Efforts to minimize The tasks identified were replacement of the delays impacted by MPD rig up were successful. cement pump with a permanent, automatically The bulk of the mechanical and electrical rig-up controlled BPP, installation of a dedicated pit was also completed without delays. There were suction and charge pump, and re-orientation of delays setting and testing the RCD and associated the choke manifold and piping to accommodate equipment due to fine-tuning of the spill tray, the new pump. Again, timing was critical as the walkway, and leaks in the RCD piping. A total of 17 winter ice-road season was advancing, and it critical path hours were consumed in these steps. was necessary to mobilize the equipment by An additional 12 hours critical path time was used truck before mid-April. A constant speed pump in hands-on crew training in MPD procedures. with a 200-horse power electric motor and Thus, the total time added to the rig-up on the associated controls and skid was fabricated in first well by the MPD rig-up was 29 hours. Several Texas and mobilized to location. Meanwhile, operational and equipment issues presented in the two 8x24-ft shipping containers were modified rig-up were addressed in subsequent rig-ups and in Anchorage. These containers were joined to critical path time has been reduced to less than house the pump. The initial design concept was to four hours per rig move. place the pump on carriers between the sub-base walking beams. However, this plan was found to The intermediate hole and production intervals be impractical due to the height of the pump skid. of the first well were successfully drilled in Fortunately, it was found that there was sufficient

clearance, adequate structural capacity, and moving-system power to suspend the unit beneath the motor room cantilever. This location was not optimal in terms of pipe routing but provided simple access to the rig power. Analysis of the pit system revealed that an existing 12-in. pit interconnection line could be tapped, and a charge pump could be installed in the existing pump room with little disruption to existing systems. For simplicity in rig inventory management, a 3 x 2 x 13-in. centrifugal pump, identical to others located in the rig mud system, was selected. To accommodate the BPP location with minimized piping runs, the choke manifold was rotated 180° inside its container. The entire 32- by 20-foot building was then rotated 90° and brought closer to the sub base. This reduced the extent of the choke footprint beyond the sub from more than 40 ft to 24 ft. External piping was completed with a combination of fixed and removable sections. It was found that the initial winterization with heat tracing and soft insulation was adequate; thus, plans for permanent hard insulation with metal sheathing were cancelled. The final mobilization and installation of the BPP and full system integration was completed by late March 2009, nine months after the original contract award. 43

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Results and Conclusions One of the initial challenges was to have the equipment winterized and ready for Arctic conditions, and then mobilized in a short period of time due to the tight barge schedule shutdown. High importance was also given to spill containment since the equipment was outside of the enclosed rig. Rigorous and extensive HAZID and HAZOP meetings were conducted to ensure a safe and successful implementation of MPD. The results of using MPD in this project have seen a five-fold decrease in mud cost, and overall improvement in the rate of penetration. More importantly, MPD has made the field economical. The following is a fivewell comparison, two drilled conventionally and three drilled with MPD. Thirty more wells have been completed since the first MPD well was drilled in this manmade island in the Alaskan Arctic and MPD is still in operation to date. The successful implementation of automated MPD has resulted in a substantial reduction of cost-per-foot drilled compared to conventional drilling, by reducing fluid losses, increasing ROP, minimizing NPT, and efficiently navigating through the narrow pressure margins.

Acknowledgements The authors wish to thank the management of Halliburton Energy Services for permission and the encouragement to publish this paper.

References Bernard, C.J., Lovorn, R., Lewis, D. et al. Managed Pressure Drilling – Automation Techniques for Horizontal Applications. 2013 AADE National Technical Conference and Exhibition held at the Cox Convention Center, Oklahoma City, OK, 26-27 February 2013. Finley, D., Ansah, J., Gil, I. et al. Comparisons of Reservoir Knowledge, Drilling Benefits and Economic Advantages for Underbalanced and Managed Pressure Drilling. 2007 IADC/SPE Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition held in Galveston, Texas, 28-29 March 2007. Williams, M., Lewis, D. and Bernard, C.J. A Safe Approach to Drilling Underbalanced Starts with Project Management. 2003 SPE/IADC Middle East Drilling Technology Conference and Exhibition held in Abu Dhabi, UAE, 20-22 October 2003.

Authors Randy Lovorn joined Halliburton in 1978 after graduating from the University of Mississippi with a BA in chemistry. Randy began his career with Baroid Logging Systems, which today is Sperry Drilling, starting as a mud logger and then specializing in drilling optimization. This experience allowed him to work globally while in the field. From the field Randy then worked in the development of products such as Real Time Operation Centers; InSite® and InSite Anywhere® services; and the Applied Drilling Technology service. Today Randy is the product champion for Sperry Drilling’s GeoBalance® service. Derrick Lewis is the strategic business manager for GeoBalance® managed pressure and underbalanced drilling operations for Sperry Drilling. He has published and presented numerous papers, has several patent awards and has co-chaired several IADC/SPE technical forums.

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Stan Allen is MPD coordinator for GeoBalance® managed pressure drilling operations for Sperry Drilling in Alaska. He has been involved in the SPE paper Overcoming Extreme Weather Conditions, Drilling Offshore with Managed Pressure Drilling in Arctic Conditions. Isabel Poletzky is the underbalanced drilling global product champion for Halliburton Sperry Drilling’s GeoBalance® services. She earned BSc and MSc degrees in petroleum engineering from the Universidad Nacional de Colombia and the University of Houston. Isabel has 15 years of industry experience including drilling and production engineering, directional and horizontal well planning and design, and 10 years of experience in underbalanced and managed pressure drilling applications. She also spent two years working as a drillsite petroleum engineer on the Kuparuk field for ConocoPhillips in Alaska.

Isabel’s expertise includes reservoir characterization while drilling, modeling of multi-phase flow, and candidate selection for underbalanced and managed pressure drilling projects. Recent responsibilities have included proposals, well planning, engineering and design, training, and coordination of underbalanced and managed pressure projects worldwide. Isabel has co-instructed several UBD and MPD courses and has also taught wellbore hydraulics modeling. She has written and presented several papers and served on technical program committees for SPE and IADC. Isabel is a member of SPE and IADC.

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Are You on the Right Track with Casing Milling? Innovative Precision-Milled Windows Offer Improved Casing Exit Reliability for Sidetracking and Multilateral Completions Calvin Ponton, Justin Roberts, Steven Fipke and Andy Cuthbert, Halliburton, SPE Copyright 2010, IADC/SPE Drilling Conference and Exhibition This paper was prepared for presentation at the 2010 IADC/SPE Drilling Conference and Exhibition held in New Orleans, Louisiana, USA, 2–4 February 2010. This paper was selected for presentation by an IADC/SPE 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 International Association of Drilling Contractors or the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the International Association of Drilling Contractors or the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the International Association of Drilling Contractors or the Society of Petroleum Engineers 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 IADC/SPE copyright. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission.

Abstract Multilateral wells offer many benefits over conventional wells, including reduced overall drilling costs, lower environmental effect, increased total recovery, greater access to production intervals, and subsequently improved well production rates. However, it can be difficult to achieve a good quality casing window through which an additional lateral branch can be successfully drilled and completed. As bottomhole assemblies (BHAs) become more advanced, involving longer and stiffer strings of tools, and as completion design becomes more intricate, more attention must be given to the way the casing window is created because this is the foundation of multilateral well design. Track-guided milling systems have emerged as effective and accurate methods by which to control casing window geometry, and this paper will focus on recent advances in track-guided, precision window milling technology and its effect on multilateral well design. To avoid potential problems in running drilling assemblies or liner/completion strings, advanced milling technology should be used to create the casing window. During conventional milling, it is commonly difficult to control the action of the mill as it cuts through the casing; poor control creates a casing window that could, as a result of right hand rotation during milling, rolling-off to one side, leading to a skewed or shortened aperture. Uncontrolled and undefined window geometry introduces additional risks when re-entering a lateral wellbore, such as nonproductive time (NPT) and equipment damage. A good quality casing window, with precisely controlled length and width, helps ensure that drilling and completion equipment can exit the aperture without problems and facilitates repeatable re-entry access to both the mainbore and the laterals in future interventions. The quality of the casing window is just as critical in multilateral wells as in conventional sidetracking or whipstock operations. Advances in modern casing milling technology are pioneering improved multilateral well designs. Multilateral wellbore junctions can now be placed in deep, high-angle wells without compromising drilling or completion operations by using a track-guided milling system to create improved casing windows.

Historical Background What distinguishes a multilateral well from a simple sidetrack is the abilities to access both the mainbore and the lateral and to produce from both, either separately or by co-mingling. The different types of

junction created can be defined by using the TAML categories Levels 1 through 6. The traditional method that was used to open a window in casing has been accepted as an industry standard since the practice began. Improvements in both the design of mills and the whipstocks from which they exit from have improved, but the basic procedure has changed little over the years. The assembly commonly used to mill a casing window consists of a window mill behind which a string or watermelon mill is run. The second mill preferably presents a cross-section that is curved and rectangular, thereby producing a substantially flat center segment and arcuately curved end sections. The assembly is stiff but necessary to ensure that some measure of control is exerted on the assembly and to replicate the drilling BHA which will be subsequently run. The earliest method used a starter mill to initiate the cut in the casing which the window mill exploited in a subsequent run; after improvements in window mill design, however, this technique is no longer required and an additional starter mill run is no longer needed. The operation of milling the window can last from several hours to several days. The early designs suffered through either lack of sufficient cutting structure on the mill or a poorly engineered design, with the result that the whipstock was milled up rather than the steel of the casing that it was supposed to exit. The current round nose and radial ground designs makes it virtually impossible to mill up the whipstock. The current designs incorporate a variety of cutting mediums, from thermally stable 3/8-in. to ¼-in. thick tungsten carbide inserts mounted to a brass matrix by brazing, to diamond impregnated mills. Some mills incorporate a metal-ceramic composition reinforced by alloy plates that enable high-speed milling and single or multiple milling profiles, depending on the application. The geometric disposition of blades on which the cutting structure is mounted has an angular offset with respect to the tool longitudinal axis, usually in the range of 1° to 10° with an abutment of cutters arranged in the direction of rotation of the mill. Because the mill design necessarily relies on sidecutting forces, the concentration of the cutting structure is on the flanks or gauge of the mill. Because the primary function of the mill is to cut through the steel of the casing, very little attention was paid to the cutting structure on the nose of 45

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the mill. The nose was sufficient to begin the cut, but otherwise ineffective when the gauge began to contact the steel. More modern PDC designs have evolved to drill enough openhole (rathole) into the formation to allow for the length of some rotary steerable tools, in particular the push-the-bit systems, to exit far enough into the surrounding formation to function as intended. Whichever milling system is deployed, the aperture is always drifted to ensure that the correct gauge of exit has been constructed; this leads, however, to a false impression that a long enough gauged section has been created.

Maintaining Window and Hole Geometry The side forces imparted to the window mill by the BHA, as it moves along the whipstock ramp from the kickoff point, must remain within reasonable limits throughout the milling operation. If this cannot be achieved by assembly design, then there is a risk that the window mill will suffer early jump-off from the whipstock face at locations along the whipstock ramp. In areas where a positive side force is applied, the window mill is urged against the ramp of the whipstock and may preferentially mill the whipstock face rather than the casing. Conversely, negative side force will divert the mill away from the ramp of the whipstock, causing the mill to exit the casing prematurely. This situation leads to a foreshortened full gauge window which can adversely affect subsequent drilling operations when it becomes problematic to exit the casing aperture with a stiff BHA. After exiting, the drilling assembly is forced to maintain a high trajectory angle immediately outside the window, which rapidly reduces TVD. It also creates a high localized dogleg that is difficult to manage because of increased drilling torque and drag that creates higher concentrated stresses on tool string components as they exit the casing into openhole. Wireline and completion activity is similarly affected, albeit to a lesser extent, as a result of the more limber nature of the assemblies. More specifically, before the gauge OD of the window mill clears the casing, the cutting action will tend to walk or move off the centerline of the whipstock, creating a spiral shape in the direction of the rotation of the mill. This uncontrolled spiraling will create an aperture in the casing that terminates 20 to 30° to the right of the intended path, as indicated in Fig. 1. Because the casing 46

no longer provides a restraining force to the mill and the side forces are maximized, the trajectory of the lateral borehole created in the surrounding formation invariably continues to spiral over the top of the casing if the window is created high side (typically between 0° to 35° left or right from the highest point in the well), or will roll off the whipstock as a result of the force of gravity acting on the mill assembly as the exit approaches a toolface exit of 55°, creating an undesirable drop in angle. Geometrically, the shape of the conventionally milled window is full gauge at the top, but narrows toward the bottom as the mill departs the casing and penetrates into the formation outside the window. This results in a relatively short sweet spot (Sw in Fig. 1) or full bore ID through the opening of the casing. The shape of the lowermost area of the window, as a result of the narrowing at the bottom, is inherently V-shaped and has been referred to as the “wicked V” or “evil V” for its damaging effect on casing centralizers. The combined detrimental effects of the shorter sweet spot result in excessive friction and buckling forces upon longer and stiffer assemblies as they attempt to depart through the window. If sand

control screens are used, then the potential for damage to the surface of the screens is increased proportionately to the drag induced transitioning across the window surface, occasionally resulting in the inability to push the liner to TD, leading to major downtime. External components, such as centralizers (Fig. 2 and Fig. 3), and external or annular casing packers, often hang up, become fragmented, or sliced into pieces (Peterson et al. 2007) when passing across the V-shaped window area, which results in expensive fishing operations and the accumulation of significant NPT. Window geometry, specifically the geometrical precision with which a window is created, becomes increasingly important (Fipke et al. 2003) and critical with regard to the ability to later deploy and recover tools and systems through the opening. Lateral, openhole (TAML Level 2) liner assemblies often incorporate polished bore receptacles or tieback receptacles near the top to accommodate seal assemblies for junction isolation during hydraulic stimulation operations. The ability to create a competent, robust seal at this point in well operations is critical for several reasons: • Effect upon production profile • Isolation of junction from fracture pressure • Cement integrity of mainbore casing Isolation tieback assemblies are typically deployed across the junction window and through a short openhole interval before stinging into a polished bore receptacle at the top of the lateral liner. The

Full gauge ‘sweet spot’ (Sw)

Figure 2. – Centralizer debris. Roll-off effect some 20 to 30 to the right of the intended path.

Figure 1. – Roll-off effect.

Figure 3. – Damaged centralizers. © 2007 SPE

pathway of the seal stinger, when departing the mainbore casing, should ideally be unrestricted and should it encounter a reduced window opening, as in the case of a conventionally milled window with poorly defined geometry, there is every risk that serious damage to the seals may occur as they are dragged across the narrowing aperture. If the isolation tie-back assembly leaks due to damage to the seals then the lateral wellbore cannot be fracture stimulated as required. If the formation is easier to mill than the steel of the casing, which is typically the case, the lead mill will tend to take the line of least resistance, at which point it is subject to the nature of the formation it is milling; strong formation tendency or preferred bedding structure will affect the direction that the mill takes. It becomes increasingly more difficult to retain the lead and string mill against the whipstock ramp and guide them as intended; because an operator has no control other than RPM or weight applied to the mill, the direction the assembly takes becomes more difficult to control the further in to the formation it progresses. With the lengthening of directional drilling BHA designs to include sophisticated logging-whiledrilling equipment (LWD), they invariably become stiffer and include components with a variety of standoffs, all of which tend to hang up across poorly milled apertures. The associated downtime,

sometimes leading to an additional milling run to enlarge the exit, can run into days. Even when a drilling assembly is gently eased over the whipstock and past the casing window opening, the subsequent poor hole quality can lead to slow drilling for some time. The completion technology now applied and deployed across multilateral junctions steadily increases in complexity, composition, and cost each year as new techniques and subsequent solutions evolve. Longer liner sections, including premium screens, packers, stimulation sleeves, and swellable and inflatable isolation tools, in addition to post-completion lateral re-entry requirements, require reliable and repeatable access to the lateral. Some whipstock anchoring tools have been known to either set prematurely or to move after they have been set. In worst case scenarios, the whipstock cannot be recovered and the mainbore is lost, or the whipstock is recovered and the packer itself must be milled out. If the anchoring system fails, the whipstock may slip downhole during the milling procedure and the original depth reference is lost or, just as seriously, the whipstock may turn within the casing as a result of the interference with the mill as it rotates. In this scenario, more steel may be milled away from the casing than designed and other issues then come in to play. In Fig. 4, the CAST images illustrate that the whipstock has become unanchored and the mill has been allowed to rotate, resulting in almost 360° of milled casing.

large volume of material; therefore, milling rates should be kept to between 5 and 10 ft/hr while maintaining high flow rates and interspersing high viscosity sweeps to aid cuttings removal. The ability of the mud system to ensure removal and thereby clean the hole effectively also depends on the shape and size of the cuttings. Cutters typically produce 5-in3 of steel for every cubic inch of steel milled. Consequently, the hole cleaning program must be robust enough to ensure effective cuttings removal. Furthermore, the surface system must be able to effectively separate these cuttings from the drilling fluid so that they do not congest equipment or become recycled into the well. If the milling operation occurs too quickly, the steel tends to be milled away in an ‘orange peel’ fashion, creating long strings of swarf. These tend to coalesce to form nests of steel that are extremely difficult to remove from the well and can create huge problems as the operation proceeds. If the debris from the milling procedure is not properly cleared from the well, enough steel may remain in the vicinity of the window and in the lateral to affect the quality of surveys while drilling

Figure 5. – Track-guided milling tool with milled casing aperture.

Debris Management Advances in mill design have enabled operators to mill windows much faster; a 7- or 8-hour operation was not an uncommon average milling time, excluding the creation of the rathole. Today, those milling times have been reduced by half, yet this comes with a price even if a strict debris management regimen is followed.

Figure 4. – CAST image of unanchored milling operation.

The speed at which the milling operation can proceed depends on the effective removal of the metal cuttings produced. Speeds of up to 40 ft/hr can be obtained, but it is impossible to ensure that cuttings are effectively removed from the wellbore. With a 9 5/8-in. casing weight of 47 lb/ft., 450 lb of metal is produced for the average window length. Enough time must be given to circulating out this

Figure 6. – Track-guided mill with mill guide.

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ahead for some time. This magnetic interference attributable to metal debris in the well could mean that drilling is blind to the actual trajectory of the well, and at best could result in a prolonged period of circulation to clean the well. In the worst case, it could lead to an undesirable well course and lengthy remedial action.

also has a unique feature by which the cuttings are directed by internal barriers and caught in an integral debris basket. The tool can also be fitted with magnets to remove finer steel filings when the tool is recovered from the well, which eliminates the need for additional cleanup trips.

Track-Guided Milling Experience

Innovative PrecisionMilled Casing Exits To contend with the inherent flaws associated with conventional milling, the industry required the advent of a precision milling tool. The MillRite® system was just such a product (Fig. 5) and, at its inception, was readily adopted as the premium replacement for conventional milling for TAML Level 2, 3, and 4 multilateral junction construction. The first issue to be addressed, that of the method used to create the window opening, was solved by ensuring that the milling head is attached to a track (Fig. 6) that precludes the jump-off effect. By securing the mill to a rigid guide that is secured in the well at a set depth and orientation, the mill must follow the line of the rails as it proceeds along the track. Therefore, it cuts a geometrically precise aperture, defined by the length and width of the track and the depth of cut of the mill. The control of milling parameters is far more refined, although the cutting speed is still limited by the ability of the drilling fluid to transport cuttings out of the well. Nevertheless, the milling parameters can be far more easily read and adjusted for optimum milling efficiency. By the same means, the mill cannot spiral along the course of the milling length; instead, the aspect of the cut is maintained precisely parallel to the axis of the casing, resulting in a rectangular aperture of equal width. The sweet spot is sustained along the complete 17 ft length of the guide, eliminating the foreshortening effect produced by conventional milling. Because the mill is locked to the track, it cannot roll off, regardless of the toolface angle of the cut, which eliminates the roll-off issue. The contact of the track-guided mill with the steel casing differs from a conventional mill; instead of being oblique to the casing at the same angle as the whipstock, the mill meets the steel horizontally and cuts square ends to the aperture. This design eliminates the “evil V” effect and renders a completion-friendly aperture geometry 48

Figure 7. – Steel cuttings from track-guided milling system.

that is unlikely to tear away external liner/screen components or damage the screens. To achieve this, the mill design differs radically from the traditional shape and includes the attributes of a flat-bottomed mill and of a section mill. The durable cutting structure incorporates integral circulation paths to effectively remove milled debris and cool the mill. The length of milling machine produces a window that is significantly longer than those achieved with conventional whipstocks. The elongated window enables a far smoother exit by stiff variable OD drilling BHAs, lateral screens, or completion tools. The resultant dogleg is much lower than conventionally milled windows and in one plane, as opposed to a spiral which, by its nature, will always be 3D. The anchoring method, by means of a unique latch coupling that is integral to the casing string, ensures that no inadvertent rotation of the milling assembly occurs within the casing after it has been locked in place. The latch coupling, which has an impressive track record with more than 730 installations worldwide, ensures repeatable depth and orientation of the multilateral assemblies within the casing and provides the means for subsequent lateral re-entry accuracy.

Milled Steel The cutting structure of the track-guided mill is radically different than that of conventional mills which rely on the individual inserts to remain intact to make progress. The cutting action of the track-guided mill produces very thin and narrow slivers of steel (Fig. 7) which are inherently easy to remove from the well with the flow of the drilling fluid and a regime of viscous sweeps. The tool

Recently, track-guided milling systems were implemented in Saudi Arabia as a preferred practice, particularly in the installation of TAML Level 4 junctions. This implementation is primarily because of the requirement of the laterals to be completed with ICD screens and swellable packers, and the mainbore to include intelligent completion functionality. The following section describes the operational steps performed for one particular well. The first step in operation was to install the 9 5/8-in. latch coupling as an integral part of the casing string. The latch coupling was set at a predetermined depth to place the subsequently milled window at the center of the casing joint directly above. After the casing was set, a dual purpose landing tool, combined with MWD equipment in the tool string, was run to depth to jet the latch coupling free of debris and latch into it to obtain a toolface reading. This toolface reading was used to calculate the alignment offset on the milling tools for the window to be milled at the planned exit angle. In accordance with the drilling program, this exit angle was to be 25° right of highside. The track-guided milling tool was then aligned to 25° right of highside on the rig floor and run and set into the latch coupling to begin milling operations. The total milling time was 3 hours and the final result was a 7.2-in. wide cut for approximately 15 ft in length. The removal of milling cuttings is essential for the proper functionality of the mill and future operations through and around the junction. At every 5 ft, a 20-bbl high viscosity sweep was pumped, and tandem 50 bbl high viscosity sweeps were pumped as a final clean before pulling out of hole. To save rig operating time, the running, setting, and retrieving of this track-guided milling tool was designed as part of the assembly. Thus, when milling is complete, and the mill assembly engages back into the tripping position, the assembly is pulled out of hole.

The second step in creating the window was the whipstock run. This assembly was fastened with a shear bolt to a lead and watermelon mill tandem assembly and run in the well as one assembly. After the whipstock was set in the latch coupling, the string was reciprocated to fatigue and shear the bolt, freeing the mill assembly. This milling assembly has three functions: to open the window to full gauge, to dress the rough edges created by the track-guided milling assembly, and to drill a rathole into the formation that is adequate for the subsequent direction drilling BHA to pass. The window was opened to 8 ½ in. and the rathole was drilled 10 ft into the formation in just over 2.5 hours. A 10-bbl high viscosity sweep was pumped every 5 ft of milling and concluded with a 50-bbl high viscosity sweep while final reaming. The 8 ½-in. lateral section was subsequently drilled with a rotary steerable and quad combo. There was no resistance passing in or out of the window throughout the drilling phase. The lateral was landed and a 7-in. liner run and cemented up to the junction. The 6 1/8-in. section was then drilled to TD and ICD; swell packers were run into the openhole and set by a liner hanger in the 7-in. liner. The final mainbore completion consisted of one 9 5/8-in. feed-through packer set below the junction with an interval control valve (ICV) hung below in the tailpipe for mainbore flow control. Above the lower feed-through packer is the ICV to control the lateral flow. The upper 9 5/8-in. feed-through packer is set above the junction and, from that point, production tubing with control lines continue up to surface.

Re-entry for Existing Wells A typical scenario regarding the need for trackguided milling systems is in an existing well. Conventionally milled windows are more suited to openhole laterals that do not need to be accessed in the future. It is primarily when these laterals must be accessed or completed to a higher complexity that a straight and extended window is required (Lowson et al. 1999). In a recent case in Saudi Arabia, the operator requested that an offshore single lateral well be worked over to be a dual lateral, using a TAML Level 4 (cemented) junction. In addition, the mainbore was to be completed with an intelligent completion, using full gauge feed-through packers

above and below the junction. Summarizing the primary requirements, the window had to be milled in the 9 5/8-in. casing that has previously been run and cemented in place. This window required a precise geometry to enable a 7-in. liner and the swellpacker combined with ICD completion string to pass. Finally, the completed TAML Level 4 junction must enable full gauge tools to pass through to the lower mainbore. The solution was provided by a re-entry system that included the track-guided precision milling system. Based on the standard system for new wells, the re-entry system indexed on a packer and latch coupling assembly. After the packer was set, the milling began and the subsequent operations to complete the TAML Level 4 junction were conducted. The junction was completed in accordance with the program, enabling full gauge tools to pass without obstruction. Since the packer and latch coupling assembly remained as a permanent fixture in the well, the upper lateral can be accessed later by pulling the upper completion and running a workover whipstock.

Completions In recent Level 4 junctions in Saudi Arabia, completion strings consisting of swellable packers or external casing packers combined with ICD screens have been installed in a variety of configurations in both mainbore and upper lateral sections; typically, these sections are approximately 3,000 ft long. In addition to the cumbersome length of the completion string, the junction is often placed in a near horizontal section, which increases the difficulty of exiting the window smoothly and landing on depth. Only a precision cut window with notable length is acceptable in these conditions. To date, 100% success has been achieved when running the completion string through a geometrically controlled window.

Case Study Special Application: Multilateral For Shale/Tight Gas The Devonian of west Texas has been producing since the first discovery wells were drilled in the 1950s. Since 1995, there has been considerable success in drilling long horizontal wells though the reservoir, which has increased production in comparison to the vertical wells that were initially drilled into this zone. The return on investment

(ROI) has been realized in a matter of months, rather than years. Even with thousands of feet of reservoir exposure, the natural permeability is still insufficient for economical production without production stimulation treatment. The primary concern about treating a multilateral well is the effect of high pressure on the formation at the junction. If the fracture gradient is exceeded and the formation breaks down, then fluid would be pumped into the vicinity of the junction, rather than the reservoir. Without protection from the acid and pressure, the formation matrix could be dissolved, causing further damage to the integrity of the wellbore. A temporary Level 5 completion was designed to isolate the junction from the stimulation fluids. The junction isolation tool (JIT) was designed to be installed on a hydraulically set, retrievable packer with a very high differential pressure rating of 10,000 psi. The track-guided milling system was used to mill the casing exit window because it creates a long, straight window. A latch coupling, which serves as an anchoring point for the milling and drilling whipstocks, was installed as a part of the mainbore 7-in., 26-lb, P-110 casing string. It was positioned in the casing string at approximately 11,800 ft, in vertical hole, just below the depth at which the casing window was to be milled. The latch coupling was designed to have the same ID as the API drift of the casing string to avoid creating a restriction. In older wells, this latch coupling device can be installed on a permanent anchor packer to latch the multilateral drilling tools on depth and orientation. This well was the world’s first selective, highpressure stimulation of a multilateral well using a junction isolation system. It was finally completed with 2-3/8-in. tubing landed just above the junction on a 7-in. production packer. The well is currently producing commingled gas and gascondensate from two different horizontal legs that drain the northwest and southeast quadrants of the acreage, respectively. Production rates are satisfactory for the reservoir quality in the area, and the combined dual-lateral production is approximately twice that of conventional wells in the region.

Conclusion Despite advances made in mill and whipstock technology, the method by which window 49

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apertures are constructed in multilateral wells is inherently prone to poor geometric outline. Problems exiting such windows have been encountered on a plethora of occasions and have led to significant NPT, as well as irreparable damage to lateral completion and re-entry components. The geometrically well defined casing window produced by a track-guided system will mitigate most, if not all, issues encountered when using a conventional milling system. The ease and accuracy of the window construction and the repeatability provided by means of the latch coupling are unique in the industry, which is constantly striving for this type of high quality solution.

References Peterson, E.M., Greener, M.R., Davis, E.R., and Craig, D.T. 2007. How Much is Left of Your Centralizer After Exiting a Casing Window in an Extended Reach Horizontal Multilateral? Modeling, Yard Tests and Field Results from Alaska’s West Sak Development. Paper SPE 105766 presented at the SPE/IADC Drilling Conference, Amsterdam, The Netherlands, 20-22 February. Fipke, S. 2003. Isolation of a Multilateral Junction for High-Pressure Stimulation - A West Texas Case Study. Paper presented at the HighTech Wells Conference and Exhibition

Multilateral, Intelligent Completions and Expandables, Galveston, Texas, USA, 11-13 February. Lowson, B. 1997. Advanced Window Milling Technology for Multi-Lateral Applications. Paper presented at 6th One-Day Conference on Horizontal Well Technology Organized by the Canadian Section SPE and the Petroleum Society of CIM, HWSIG held in Calgary, Alberta, Canada, 12 November.

Authors Calvin Ponton has a diverse and extensive background in the oilfield service industry. A 34-year Halliburton employee, he is a global technical advisor for Multilateral Technology in Sperry Drilling. Calvin’s technical background ranges from completions, project management, business development and technical support of project executions for multilateral technology. Calvin attended Texas A&I University and the University of Texas. He has co-authored and published numerous technical papers and articles. Justin Roberts is the Artificial Lift manager at Rotating Right Inc. in Calgary, Canada. He has a BSc in mechanical engineering from the University of Alberta and is a registered professional engineer in Canada. From 2003 to 2013 Justin worked in the Multilateral Technology group for Halliburton. He started as a design engineer in Nisku, Canada and moved into operations and management roles based in the Middle East and Asia Pacific regions.

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Steven Fipke is the international business development manager for Tendeka in Houston. He has a BSc in petroleum engineering from the University of Alberta in Edmonton, Canada and for more than 12 years Steven was part of the Halliburton organization specializing in Multilateral Technology (Drilling and Completions). Steven has been assigned to various roles in technology, operations and business development for Halliburton in Canada, Venezuela, Houston, and Dubai, has authored a variety of industry publications, and holds a number of patents on downhole technology.

Andy Cuthbert graduated from the University of London with a BSc (Hons) geology in 1981, and went on to complete an MPhil in geology before joining the oil industry in 1984. He has 30 years of oilfield experience; 10 years with Schlumberger as a directional driller, and then moving to Halliburton where he has been involved in projects of ever increasing complexity concerning the introduction and coordination of new technology. Andy was team lead for the Multilateral Technology group in Norway followed by project management and later as regional manager for Directional Drilling and Multilateral Technology in Southeast Asia operations. He subsequently took on the role of Multilateral global product champion in Houston and was to return to Consulting and Project Management as senior project manager in Iraq before joining Boots & Coots, where he is primarily involved in risk management, well control technology and planning of contingency well measures.

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