HPHT

Chris Avant Saifon Daungkaew Bangkok, Thailand Bijaya K. Behera Pandit Deendayal Petroleum University Gandhinagar, Gujarat, India Supamittra Danpanich Waranon Laprabang PTT Exploration and Production Public Company Limited Bangkok, Thailand Ilaria De Santo Aberdeen, Scotland Greg Heath Kamal Osman Chevron Thailand Exploration and Production Ltd Bangkok, Thailand Zuber A. Khan Gujarat State Petroleum Corporation Ltd Gandhinagar, Gujarat, India Jay Russell Houston, Texas, USA Paul Sims Dar es Salaam, Tanzania Miroslav Slapal Moscow, Russia Chris Tevis Sugar Land, Texas Oilfield Review Autumn 2012: 24, no. 3. Copyright © 2012 Schlumberger. For help in preparation of this article, thanks to Renato Barbedo, Ravenna, Italy; Larry Bernard, Jean-Marc Follini, David Harrison and Steve Young, Houston; Libby Covington, Simmons & Company International, Houston; Alan Dick, Simmons & Company International, Aberdeen; Eduardo Granados, Richmond, California, USA; Khedher Mellah, Chevron, Houston; and Sophie Salvadori Velu, Clamart, France. InSitu Density, MDT, MDT Forte, MDT Forte-HT, PressureXpress, PressureXpress-HT, Quicksilver Probe, Signature, SRFT and Xtreme are marks of Schlumberger. INCONEL is a registered trademark of Special Metals Corporation. Quartzdyne is a registered trademark of Dover Corporation.

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Testing the Limits in Extreme Well Conditions High borehole temperatures and pressures pose design challenges for engineers developing formation evaluation tools. Pressure and sampling tools that use motors and pumps require high power to operate and often generate considerably more heat than tools used for basic petrophysical measurements. Traditional solutions to combat temperature and pressure are insufficient for these types of tools. Recent innovations make it possible to obtain downhole pressure measurements and samples and to perform extended well tests in extreme conditions.

Many E&P companies are drilling wells in environments that push the limits of equipment and services as they search for new sources of oil and gas. Operators are looking in places where few have ventured or that not so long ago were considered impractical. The depths they are now probing tend to be hotter and higher pressured than ever before and often exhibit extreme well conditions that test the limits of downhole tools and equipment. Service companies continue developing solutions to contend with extreme well conditions; however, certain situations present particular problems for downhole tool developers.1 For instance, applications such as acquiring formation pressures and fluid samples and performing extended downhole pressure tests require tools that are designed to overcome more than heat and pressure, which is a difficult feat. These tools must also deal with time as it relates to internally generated heat and the challenges of long exposure to potentially destructive conditions. Pressure and sampling tools utilize motors that require high power; these motors generate heat that is trapped inside the tool. To acquire pressure measurements and formation fluid samples, these tools may have to remain stationary for long periods of exposure to heat and pressure. These tools have pressure gauges and sensors that must remain stable at high operating temperatures while retaining their measurement precision. Other uses for pressure gauges may require

that they remain downhole for hours, even days, constantly exposed to extreme conditions. Many methods traditionally employed to withstand high wellbore temperatures are ineffective in these instances. This article reviews two pressure and sampling tools that require high power to operate and were engineered to withstand high-pressure, high-temperature (HPHT) operating environments. In addition, a recently introduced downhole pressure gauge has been proved to operate for many hours at high temperature. Case studies from the North Sea, Thailand and India demonstrate the application of these advances. A Niche Market That Matters Hostile environments are typically characterized as having HPHT conditions. HPHT wells will generally cross thresholds of either temperature or pressure, but few wells cross both. However, the term HPHT is applied to any well that is considered hot or high pressured. Various criteria are used within the oil and gas industry to define “high,” although there is no widely accepted industry standard. Whichever criteria are used, the majority of wells drilled today are not extreme, being neither high pressure nor high temperature. Approximately 107,000 oil and gas wells will be drilled worldwide in 2012.2 A study conducted by engineers at Schlumberger estimates approximately 1,600 of these wells will be

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1. For solutions available in extreme operating conditions: DeBruijn G, Skeates C, Greenaway R, Harrison D, Parris M, James S, Mueller F, Ray S, Riding M, Temple L and Wutherich K: “High-Pressure, High-Temperature Technologies,” Oilfield Review 20, no. 3 (Autumn 2008): 46–60. Chan KS, Choudhary S, Mohsen AHA, Samuel M, Delabroy L, Flores JC, Fraser G, Fu D, Gurmen MN, Kandle JR, Madsen SM, Mueller F, Mullen KT, Nasr-El-Din HA, O’Leary J, Xiao Z and Yamilov RR:

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“Oilfield Chemistry at Thermal Extremes,” Oilfield Review 18, no. 3 (Autumn 2006): 4–17. Adamson K, Birch G, Gao E, Hand S, Macdonald C, Mack D and Quadri A: “High-Pressure, High-Temperature Well Construction,” Oilfield Review 10, no. 2 (Summer 1998): 36–49. Baird T, Fields T, Drummond R, Mathison D, Langseth B, Martin A and Silipigno L: “High-Pressure, HighTemperature Well Logging, Perforating and Testing,” Oilfield Review 10, no. 2 (Summer 1998): 50–67.

2. “Special Focus: 2012 Forecast—International Drilling and Production. Global Drilling Remains Consistently Strong,” World Oil 233, no. 2 (February 2012): 43–46. “Special Focus: 2012 Forecast—U.S. Drilling. Growth Amidst Economic and Regulatory Turbulence,” World Oil 233, no. 2 (February 2012): 67–72.

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HPHT Wells Drilled 2007 to 2010 Worldwide 650

Well High temperature

Reservoir temperature, °F

550

High pressure

450

350

250

150 0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

Reservoir pressure, psi

> Extreme temperature or pressure. Schlumberger engineers conducted an internal study of temperature and pressure data from wells worldwide. Over a four-year period, no wells exceeded both high-temperature (350°F [177°C]) and high-pressure (20,000 psi [138 MPa]) limits, which are commonly used for wireline logging tools. Many wells exhibiting extremely high pressure do not exhibit high temperature, and vice versa. In addition, more wells exceeded the 350°F temperature than exceeded 20,000 psi.

classified as HPHT wells, representing about 1.5% of the worldwide total. Most of the wells considered HPHT exceed established temperature limits; only a few wells exhibit truly extreme pressures (left). The study also indicated that the HPHT market is heavily dominated by two countries: the US (60%) and Thailand (20%) (below). One caveat to consider in this analysis is that geothermal wells are not included in the totals. Because of their extremely high bottomhole temperatures, geothermal wells present operational complexities rarely encountered in oil and gas exploration.3 Moreover, the number of geothermal wells is small compared with the number of their oil and gas counterparts. The HPHT market may currently be relatively small, but there is an industry-recognized acceleration in the number of extreme wells being drilled and planned. For example, according to one report covering extreme wells drilled offshore, during the 30-year period from 1982 to 2012, operators drilled 415 HPHT offshore wells

Significant high-temperature activity Potential for high-temperature activity Geothermal activity

> Drilling activity in high-temperature environments. Exploration and development drilling in high-temperature environments is regionally isolated. The majority of extreme wells are located on land, although there is significant activity in the Gulf of Mexico, the North Sea and offshore India and Southeast Asia. The number of geothermal wells, which represent the high end of extreme temperatures, is not statistically significant.

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Offshore HPHT Wells Norwegian North Sea 14 16

118

North Sea 13 23 3

Mediterranean Sea

Gulf of Mexico

17 4 10

97 133

Caspian Sea

0 0 26

90 Southeast Asia

West Africa

0 0 16

18 52 10 Brazil 238 75

290 36 10 22

Australia

Wells 415 Drilled through 2011 433 Projected from 2012 through 2015 483 Projected from 2016 through 2020

> Offshore HPHT activity. HPHT drilling activity is projected to accelerate in the coming years, especially offshore. In the next four years, the number of offshore HPHT wells (green) is expected to be more than double the total drilled in the preceding three decades (blue). By the year 2020 (pink), the well count is projected to triple. (Adapted from Simmons & Company International Limited, reference 4. Used with permission.)

worldwide (above).4 The forecast for the four-year period ending in 2016 anticipates that the total will be doubled, with the region off the coast of Brazil alone adding more than 238 deep wells by 2016. By 2020, the total number of offshore HPHT wells is projected to exceed 1,200—tripling the total number of extreme offshore wells in just 10 years. The analysis highlights the need in the coming decade for equipment to address these HPHT operating conditions. The problem with such analyses, however, is that the results depend on the user’s definition of HPHT. A Matter of Semantics Operators and service companies often use varying criteria for classification of HPHT wells. Operators contend with the effects of pressure and temperature on drilling, well construction and surface equipment; service companies often focus on how those conditions affect their products, equipment and services. Although the distinction may appear subtle, the engineering design approach often differs.

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In an effort to resolve some of the confusion, the API recently published recommendations for equipment used in HPHT wells, which were defined as those with pressure greater than 15,000 psi [103 MPa] and temperature above 350°F.5 The recommendations apply primarily to engineering standards related to design specifications of equipment, acceptable materials and testing of well control equipment and completion hardware. The report includes design verification and validation, material selection and manufacturing process controls, which are intended to ensure that equipment used in the oil and gas industry is fit for service in HPHT environments. The three criteria for HPHT classification are the following: • anticipated surface conditions that dictate completion and well control equipment rated above 15,000 psi • anticipated shut-in surface pressure in excess of 15,000 psi • flowing temperature at the surface in excess of 350°F.

If any one of these conditions is met, the well is considered an HPHT well. Although the report establishes specific guidelines for defining HPHT and provides protocols for certifying equipment, it does not specifically address downhole electronics or certification of downhole tools. In an attempt to define thresholds that reflect physical and technological limitations, Schlumberger developed an HPHT classification system representing stability limits of common 3. A recent study estimates that approximately 4,000 geothermal wells had been drilled through 2011. Sanyal SK and Morrow JW: “Success and the Learning Curve Effect in Geothermal Well Drilling—A Worldwide Survey,” paper SGP-TR-194, presented at the 37th Workshop on Geothermal Reservoir Engineering, Stanford, California, USA, January 30–February 1, 2012. 4. These findings were noted in the Simmons & Company International Limited 2012 analysis prepared for Quest Energy. For the report, HPHT was defined as conditions greater than 10,000 psi [69 MPa] and 300°F [150°C]. The number of land-based HPHT wells drilled during the period was much higher than that of those drilled offshore. 5. API: “Protocol for Verification and Validation of HPHT Equipment,” Washington, DC: API, Technical Report PER15K-1, 1st ed., 2012.

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HPHT-hc 260°C

500

Ultra-HPHT 205°C

400

HPHT 150°C

300

100

241 MPa

138 MPa

200

69 MPa

Static reservoir temperature, °F

600

0 0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

Static reservoir pressure, psi

> HPHT classification system. This classification system was proposed by Schlumberger engineers and is based on pressure and temperature boundaries that represent stability limits of common components used by service companies. These include electronic devices and sealing elements. The HPHT-hc classification defines environments that are unlikely to be seen in oil and gas wells, although there are geothermal wells that exceed 500°F.

components such as elastomeric seals and electronics (above).6 Other service companies and operators use their own definitions, which are similar to the Schlumberger guidelines. A Niche in Design The well type—HP or HT—dictates the engineering design approach because techniques used for contending with pressure differ from those for temperature. For pressure, the solution is often to design equipment with sealing elements capable of withstanding extreme forces. Exposed surfaces may be at risk, but internal

electronics are protected, barring a seal failure, which would be catastrophic should failure occur (below left). Protecting sensitive downhole electronics from extreme temperatures, however, usually relies on sheltering sensitive components from the cumulative effects of exposure to heat. This is most often accomplished using thermal barriers in the form of flasks—double-insulated metal housings—that protect electronic components long enough for data acquisition and other operations to be performed (below right). Flasks are constructed to have extremely low thermal

conductivity and thermal diffusivity to ensure that the temperature inside the housing rises very slowly. Flasks have become an integral component in tools such as the Schlumberger suite of Xtreme tools, designed for HPHT environments.7 The Xtreme platform includes common measurements for petrophysical analysis. Unfortunately, the solution for keeping electronics protected from wellbore heat traps self-generated heat inside the tool housings. This heat can push internal temperatures well beyond a tool’s thermal rating. Logging engineers monitor both time and temperature to avoid potentially catastrophic tool failure related to temperature when using flasks in HPHT environments. Tools that employ high-powered downhole motors and pumps, such as pressure and sampling tools, are examples of tools that generate considerable heat—much greater than most other evaluation tools. The thermal loads generated by these tools can quickly raise the temperature inside a flask above the rating of the electronic components. Thus, flasking alone may not provide sufficient operating time to complete the required task when these high-power, high heat–generating tools are used. Tools that do not generate excessive heat and have low power consumption, such as downhole pressure gauges, may be used to collect data for many hours, even days, in extreme conditions.

Thermal insulators

Electronics

Vacuum layer Dewar flask 0 cm 2.5

> The results of failure. This tool failed when exposed to pressures only slightly above its rating. The failure was initiated at the threaded-ring connection, where the pressure seal was most vulnerable. The result was a catastrophic loss of the tools above and below the failure caused by the sudden inrush of drilling mud from the wellbore.

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> Flasks for thermal barriers. The most common method of protecting sensitive electronics from extreme heat is to use a Dewar flask (top). The flask (bottom) consists of a glass liner inside a metal housing that serves as a vacuum layer; the glass and air are poor heat conductors. Thermal insulators at each end isolate the electronics section. Internally generated heat from the electronic components is trapped inside the tool and can cause the tool to overheat.

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Thermal Hot Spots

Unbalanced Loading

24

26

28

30

32

34

36

38

40

42

44

46

48

Temperature, °C

> Thermal imaging. Infrared images reveal localized hot spots and overloaded electronic components (left). Identical components on a circuit board (right) may not have the same loading. Large loading differences may be identified using thermal imaging and may require circuit board redesign. Solutions include changing the layout to redistribute the load or installing heat sinks to draw heat away from target areas.

For long-duration measurements in HPHT wells, flasks are not a solution for these types of tools. For solutions to address self-generated heat or extended operations in high-temperature environments, design engineers often focus on the circuit boards. By maximizing efficiency, analyzing the heat generated by electronic components and, wherever possible, employing components that have above-average temperature ratings, engineers can extend the time available for tools to operate and acquire data downhole (above). Sourcing components that withstand high

temperatures has become increasingly difficult. The electronics industry is driven by consumer products that use plastic electronic components that are not rated for use in even moderately high-temperature conditions, for instance above 125°C [257°F]. Plastic components are often composed of silicon chips, or dies, enveloped in a plastic overpack. These components cannot withstand the rigors of extreme environments because the overpack fails first from temperature effects, although the underlying electronic component may not have failed. In addition, manufacturers treat plastic electronic components with flame retardant chemicals, which

contain volatile compounds that are released at elevated temperatures. These chemicals are highly corrosive. For high-temperature environments, design engineers at Schlumberger have learned to eliminate plastic overpacks and use only the silicon chips. These chips and other components are attached directly to heat-tolerant ceramic multilayered circuit boards; the connecting wires have the diameter of a human hair (below). In some cases, engineers have created proprietary 6. DeBruijn et al, reference 1. 7. For more on Xtreme logging tools: DeBruijn et al, reference 1.

× 65

> Designed for extremes. To ensure tools are able to operate under extreme temperatures, engineers use components that rely on the underlying ceramic and metal (center) without the plastic overwrap commonly used in consumer electronics. Ceramic components may be combined in multichip modules (MCMs) (left). Component reliability can also be improved with manufacturing techniques such as the use of low-mass connections (right), some of which are similar in thickness to a human hair.

Autumn 2012

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Seven Days at 150°C Without Desiccant

Cracked wedge

× 1,000

Seven Days at 150°C with Desiccant Broken wedge × 200

× 50

> Electronic component failure mode. When electronic components fail, the mode can often be traced to mechanical failure from shock and vibration. Cracks may form at connections (left) that eventually break under repeated loading. In the sealed environments of logging tools, corrosive chemicals may be released from circuit boards and other components. At elevated temperatures, the corrosivity of these chemicals is accelerated, which causes damage to sensitive electronics (top right). If the tools are opened for maintenance and repair, moisture in the air may also become a problem. When space is available, desiccants can be used inside tool housings, protecting electronics from corrosion by absorbing humidity and volatilized chemicals (bottom right).

dies that are programmed and packaged for specific applications and built to high-temperature specifications that exceed those readily available in the commercial marketplace. Extensive analysis of failed electronic components has resulted in other design innovations. The failure of electronic components may occur at elevated temperatures; however, the actual failure mode is often traced to mechanical breakdowns (above). The two most common causes of mechanical failure are corrosion and vibration. Corrosion can be problematic because high temperatures accelerate chemical corrosivity, especially that resulting from humidity and volatilized gases from products used in the manufacture of circuit boards. Where space permits, desiccants are inserted in tool housings to absorb volatilized chemicals and moisture. Techniques to extend operability time mitigate the effects of high temperature, but such techniques only extend the time available for tools to operate at elevated temperatures. Similarly, shock and vibration cannot be eliminated, but better tool designs can improve the mechanical integrity of connections and components. Attaching circuit boards to specially designed mounting rails and shock absorbers can improve tool reliability. Once the designs are finalized, thorough and rigorous testing, using both thermal and mechanical loads, validates the

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design effectiveness or identifies weaknesses that can then be rectified. Engineered for Extremes The MDT modular formation dynamics tester has been an industry standard for fluid sampling since its introduction in 1989. Through the decades, an extensive array of sampling and downhole analysis tools has been added to the basic platform. Along with new features and services, several modifications have been implemented to improve the tool’s reliability and performance; however, the basic design and layout of the tool electronics and hardware have not changed. In the years since the MDT tool was introduced, Schlumberger engineers have been designing tools to withstand high levels of shock and vibration—the primary sources of most electronic component failures. Much of the impetus for establishing higher standards came from requirements for LWD tools, which operate in extremely harsh conditions. Design engineers have integrated techniques developed for LWD tools in wireline tools, and new designs of wireline tools are qualified to LWD standards whenever possible. To pass these new qualification standards, the MDT tool could not simply be upgraded but required a full redesign. This newly designed tool was introduced as the MDT Forte rugged modular

formation dynamics tester. The electronics systems for the MDT Forte tool were completely reconfigured and mounted on a ruggedized chassis (next page, top). Engineers then subjected the new design to a rigorous qualification process. The temperature qualification process of the MDT Forte platform consisted of thermal aging of components, thermal cycling from –40°C to 200°C [–40°F to 392°F] and cold storage at –55°C [–67°F]. Shock and vibration qualification included thousands of shocks on individual circuit boards, which were administered on different axes by rotating the boards in the test facility. Vibration testing of the boards included 10- to 450-Hz sweeps. Engineers also performed pressure cycling, vibration transmissibility and transverse shock transmissibility testing. After qualifying the boards, they conducted temperature and shock qualification on full tool assemblies. They also performed extended low- and high-temperature operations, including operation at 210°C [410°F] for 100 h while administering shocks to the tool assembly (next page, bottom). These tests confirmed the new design could withstand mechanical shock and vibration in addition to thermal shocks, thereby meeting qualification standards that previous-generation tools could not. The temperature and pressure ratings of the MDT Forte tool are 177°C [350°F] and 172 MPa [25,000 psi].

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Original Design

Redesign

> Making tools stronger and better. Older tool designs, like those of early generation MDT tools (left), used discrete components and circuit boards attached to a central mandrel. These designs have been replaced by boards rigidly mounted to solid rails, such as those used in the MDT Forte tool (right). This approach isolates sensitive electronics from shock and vibration and also helps dissipate heat. Many of the design changes have been introduced from lessons learned developing LWD tools; newer generation tools are designed to pass LWD shock and vibration standards whenever possible.

Design engineers next focused on developing a tool with the improved reliability of the MDT Forte tool that could also withstand higher temperatures and pressures. The result is the MDT Forte-HT rugged high-temperature version, which is rated to 204°C [400°F] and 207 MPa [30,000 psi]. To meet the 207-MPa pressure rating of the MDT Forte-HT tools, engineers employed innovative sealing technology that incorporates carbon

nanotubes in the O-ring seals. The structure of these sealing elements provides strength to withstand downhole effects such as temperature degradation and rapid gas decompression during operations. The seals, which provide sample assurance that is not possible with conventional elastomers, retain full high-pressure capability even at low subsea temperatures routinely experienced in deepwater environments while running in the well.

50 h

50 h

400°F

45 h 75% power load

75% power load Ambient temperature

Engineers also upgraded the pressure gauge used for the MDT tool by adding a new-generation quartz gauge qualified to 207 MPa and 200°C for 100 h. A high-temperature InSitu Density reservoir fluid density sensor, which monitors fluid density and helps improve fluid sample quality, was developed and placed in the flowline. The fluid density measurement provides the ability to identify compositional grading and fluid gradients at HPHT conditions—the first time

Shock test

50 h 5h 100% power load

45 h 75% power load Shock test

5h 100% power load Shock test

> Proof of concept. The MDT Forte tool platform (bottom) was designed to pass shock and vibration standards similar to those for LWD tools. Tool qualification using the laboratory equipment shown (top left) cycles the tool through temperature variations while subjecting the tool to repeated mechanical shocks. The test cycle (top right), which is just one of many, elevates the temperature to the tool limit and holds it for 50 h. The tool is allowed to return to ambient conditions and subjected to fifty 250-gn shocks on four axes. The cycle is then repeated. These tests help identify design weaknesses as well as validate design concepts.

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Upgraded Inflatable Packer

these measurements have been available in these environments. For the MDT Forte-HT version, the dual-packer module was also upgraded to 210°C. This module uses sealing elements above and below the zone of interest to isolate formations for sampling (left). The inflatable packer elements isolate an interval from 1 to 3.4 m [3.3 to 11.2 ft] in length. The pumpout module presented one of the most challenging aspects of upgrading the MDT tools to the higher temperature and pressure ratings. The pumpout module is important for ensuring a reliable sample of formation fluid. It uses a positive displacement pump to transfer formation fluids that may be contaminated with drilling mud filtrate into the wellbore until the sample stream is free of impurities. When the quality of the stream is acceptable, samples are taken and recovered for analysis. Four new pumpout displacement units are now available to meet a range of specifications, from a standard version to an extra, extra highpressure version (below left). Engineers designed the new pump to operate more efficiently—to generate less heat, resist plugging and handle mud solids more effectively. The increased flow area of the new pump decreases O-ring erosion and delivers better sand-handling capabilities. The pumpout modules are compatible with the Quicksilver Probe device.8

> MDT Forte-HT tool additions. Engineers designed modules and tools to complement the new higher temperature rating of the MDT Forte-HT toolstring. This inflatable fullbore packer withstands temperatures up to 210°C.

Pumpout Module Displacement Units Standard tool

Extra high-pressure tool

Extra, extra highpressure tool

Volume/stroke, cm3 [in.3]

485 [30]

366 [22]

177 [11]

115 [7]

Maximum differential pressure, MPa [psi]

32 [4,641]

42 [6,092]

58 [8,412]

81 [11,748]

Pump flow rate, cm3/s [in.3/s]

8.2 to 32.8 [0.5 to 2]

6.3 to 24.6 [0.4 to 1.5]

4.4 to 18.3 [0.3 to 1.1]

0.8 to 16 [0.05 to 1]

> MDT pumpout module options.

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High-pressure tool

Meeting the Sampling Challenge The challenge of taking samples and pressures in HPHT conditions extends beyond simply being able to acquire fluids or pressure data. The sampling time must be minimized to avoid tool damage from both internally generated heat and external heat exposure; however, the sample must be as free of contamination as possible to ensure that the fluids collected by the tool and analyzed in the laboratory are representative of the formation fluids. In a recent test, a North Sea operator successfully ran an MDT Forte-HT toolstring that included two pumpout tools, a Quicksilver Probe assembly and downhole fluid analysis modules. The well was drilled with oil-base mud (OBM) into a reservoir with pressures in excess of 17,000 psi [117 MPa]. Along with high downhole pressures, the operator faced bottomhole temperatures ranging from 347°F to 370°F [175°C to 188°C]. Sample quality was crucial for accurately characterizing the reservoir fluids, but the high temperatures limited the time available for sampling. Samples had to be taken quickly, yet fluids needed to flow long enough to minimize OBM filtrate contamination.

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Fluid Composition CO2

C1

C2

C3–5

Pressure C6+

psi

GOR XX,000

ft3/bbl

Mobility YY,000 0.2

mD/cP

2,000

Station 1

Depth

Station 2

Station 3 Station 4

Fluid composition, %

Station 5

CO2

100 80 60 40 20 0 2,000

C1

C2

2,500

C3–5

3,000

C6+

3,500

4,000

4,500

5,000

5,500

4,500

5,000

5,500

Elapsed time, s YY,000

ft3/bbl

GOR

XX,000 2,000

2,500

3,000

3,500

4,000

Elapsed time, s

> Quality sampling at extreme conditions. Using a reverse low-shock sampling technique, a North Sea operator was able to identify fluid contacts and fluid composition in wellbore conditions approaching 370°F with the MDT Forte-HT tool. Samples were acquired with the Quicksilver Probe assembly, and the filtrate contamination was less than 2%. The operator was interested in CO2 content (Track 1, purple, top), which was available in the fluid composition analysis. A water contact can be identified by the blue color in the composition track at Station 5. During the time interval shown in the sampling plot (center), flow consisted of hydrocarbons with a trace of CO2. The change in GOR (green, bottom) at 2,750 s was associated with a shift in direction of the reverse low-shock sampling. Accurate H2S content was measured in the flowing stream using specially designed coupons. The low levels of OBM filtrate resulted in samples that were unaltered by filtrate contamination, and reverse low-shock sampling minimized scavenging of H2S by metal components of the tool.

The presence of OBM filtrate affects laboratory analysis of reservoir fluids and may distort H2S measurements because the filtrate may scavenge H2S from reservoir fluids. Sample quality and reliability of the fluid property measurements are improved when engineers, using the pumpout module, first remove fluids contaminated with filtrate. The Quicksilver Probe device, which uses a focused sampling technique, greatly decreases the time required to remove contaminated fluids and reach acceptable purity levels, cutting sampling time by as much as half compared with the time required for sampling with conventional probes.

Autumn 2012

For the well in question, the North Sea operator collected several high-quality PVT samples in a single trip (above). Filtrate contamination for all samples was 2% or lower. Downhole fluid analysis provided fluid composition, CO2 content, GOR and fluorescence. Because H2S was a concern for the operator, the MDT tool was configured for reverse lowshock sampling. This technique helps minimize the scavenging of H2S by tool hardware and by OBM filtrate. The low-shock sampling technique holds the pressure in the piston chambers of the pumpout module near that of the borehole pressure, minimizing the drawdown pressure during sampling. The technique produces better

results than those that draw formation fluid into chambers at atmospheric pressure. Reverse low-shock sampling routes fluid directly into sample bottles without passing it through the pumpout module. This technique reduces the opportunity for metal hardware to scavenge H2S, although additional precautions are taken to minimize scavenging, including replacing exposed parts with INCONEL alloys and coating 8. For more on the Quicksilver Probe device: Akkurt R, Bowcock M, Davies J, Del Campo C, Hill B, Joshi S, Kundu D, Kumar S, O’Keefe M, Samir M, Tarvin J, Weinheber P, Williams S and Zeybek M: “Focusing on Downhole Fluid Sampling and Analysis,” Oilfield Review 18, no. 4 (Winter 2006/2007): 4–19.

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Reservoir Pressure Only Operators cannot always acquire fluid samples or perform complex downhole fluid analyses, nor do they always need to. These tasks are especially problematic in low-permeability formations in Pressure which fluid samples may be difficult to obtain or inlet long sampling times are required. However, accurate pressure and fluid mobility data are important for understanding these reservoirs.9 These data Pressure crystal Bellows 0 cm 2.5 are especially crucial for establishing fluid gradiReference crystal ents and identifying fluid contacts. Engineers at Schlumberger developed the PressureXpress reservoir pressure while logging service, which typically measures downhole pressure and mobility in less than a minute, to address situations in which pressure data alone may be sufficient. The speed with which this service delivers > Quartzdyne pressure transducer. Three quartz crystal resonators—a multiple measurements greatly improves the liketemperature sensor, a pressure sensor and a reference—make up the lihood of successful operations at elevated temQuartzdyne transducer. An increase in pressure at the pressure inlet of the peratures, although the original tool is rated for bellows assembly causes an increase in frequency of the signal from the pressure crystal. An increase in temperature causes the frequency of the only 150°C [300°F]. The lower temperature rating temperature crystal signal to decrease. The signal from the temperature and absence of a flask to protect sensitive composensor is used to compensate for temperature effects. The reference nents severely limited the use of the tool in HPHT crystal simplifies frequency counting output from the other two crystals. Its environments. A more robust version was develoutput is mixed with the output of the temperature and pressure sensors, lowering their frequencies from the MHz to the kHz range. The design oped to meet the challenge of HPHT operations. results in a low power consumption gauge that is highly stable and shock To upgrade the PressureXpress tool design, resistant, while providing high-resolution measurements. A pressure engineers focused on the electronics and the resolution of 0.01 psi [70 Pa] and temperature resolution of 0.001°C [0.002°F] pressure gauge. Pressure measurements with can be obtained using this gauge. quartz gauges are highly accurate, but the data must be corrected for temperature. This temperature correction applies to the measurement electronics rather than the reservoir temperature. were confirmed by laboratory analysis. Combined parts with compounds that inhibit H2S For downhole pressure measurements, the adsorption. Specially designed metal strips— with a Quicksilver Probe assembly, the MDT coupons—that detect H2S concentrations were Forte-HT tool met the operator’s sampling objec- PressureXpress and PressureXpress-HT hightives of obtaining uncontaminated reservoir temperature reservoir pressure services use a included in the tool flowlines. The fluid properties, measured downhole in fluid, determining CO2 concentration and Quartzdyne gauge, which differs from conventional quartz gauges in that it has three separate extreme pressure and temperature conditions, detecting H2S. crystals: One measures pressure, another measures temperature and a third acts as a reference (above left).10 The measurement is extremely accurate when all three crystals are at the same Pressure Data Comparison 3,393 temperature, and the gauge is reliable at tem3,391.99 psi peratures up to 225°C [437°F]. But the gauge is 3,392 sensitive to abrupt pressure and temperature changes. When exposed to rapid high-tempera3,391 3,390.03 psi ture and pressure changes, which can occur when running into the well on wireline, the gauge must 3,390 be allowed to stabilize before acquiring data. 3,389 The PressureXpress-HT tool is equipped with two flasks—one for the pressure gauge and 3,388 0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 another for the electronics—to isolate the presTime, s sure gauge sensor from the borehole and to isolate > Thermal isolation of the PressureXpress tool pressure gauge. The PressureXpress-HT tool isolates the the rest of the tool electronics from the gauge. pressure gauge and the rest of the electronics in separate flasks, which protects the gauge from This configuration has proved to provide moreexternal wellbore temperatures and internally generated heat from the electronics. A comparison of stable measurements than those taken with tools measurements from a flasked sensor (red) and an unflasked sensor (blue) demonstrates the higher accuracy and greater stablility of the flasked gauge. The output of the unflasked sensor stabilizes at the without flasks or when the electronics are housed with the gauge in the same flask (left). Electronic input pressure (3,391.99 psi) after almost 150 s. Bellows Assembly

Pressure, psi

Sensor Assembly Temperature crystal

14

Oilfield Review

components for the PressureXpress-HT tool were also upgraded based on many of the lessons learned from the MDT Forte-HT tool design. The modifications to the PressureXpress-HT tool have extended the temperature specifications of the tool to 232°C [450°F] for 14 h. Pressure and mobility measurements may be obtained with drawdown differential pressures up to 55 MPa [8,000 psi] and pretest mobility as low as 0.3 mD/cP may be detected. The tool retains its slim diameter, even with the addition of flasks. The probe section can be as small as 10.3 cm [4.05 in.] while the main tool body has a diameter of only 9.8 cm [3.9 in.].

MYANMAR LAOS

180°F to 220°F THAILAND

CAMBODIA

Gulf of Thailand Challenges Because of high geothermal gradients, the southern regions of the Gulf of Thailand represent some of the world’s harshest environments for hydrocarbon production (right). The Arthit field in the Gulf of Thailand is about 230 km [143 mi] offshore. PTT Exploration and Production Plc (PTTEP) discovered the field in 1999. The field is characterized by highly compartmentalized, complex reservoirs that have bottomhole temperatures between 320°F [160°C] and 500°F [260°C].11 Production is from Late Eocene to Late Oligocene formations that are characterized by low permeability. Low-permeability formations may require extended sampling time, even when only pressures and mobility data are acquired. Most boreholes are small, usually drilled with a 61/8-in. bit, which limits the size and selection of tools that can be run at TD. Because of the small hole size, PTTEP historically acquired pressure and sampling data with an SRFT slimhole repeat formation tester. Although this tool is rated only to 177°C [350°F], it was one of the few options available for the hole size typically drilled in the field. The measurements needed from the tool included formation pressure, fluid gradients and CO2 content. Of these, only CO2 content required fluid sampling. The pressure data were used to determine fluid contacts, fluid mobility, sand-tosand pressure correlation, reservoir connectivity, compartmentalization and perforation design strategy. The data were also used to identify depleted zones. In 2009, a flasked PressureXpress tool was introduced in Thailand. The tool was capable of obtaining all of the PTTEP objectives except one—CO2 content. However, this tool did not include a separate flask for the pressure gauge, which caused gauge stability problems because the internal temperature rose during operations.

Autumn 2012

220°F to 320°F

ailand f Th f o G ul

VIETNAM

320°F to 350°F Arthit field

350°F to 500°F Anda man

Songkhla

Sea

0 0

km

200 mi

200

> Gulf of Thailand temperature trend. Reservoir temperatures in the Gulf of Thailand range from relatively benign in the north to extremes of 500°F [260°C] in the south. Field development in the high-temperature reservoirs, such as the Arthit field, presents challenges for equipment used downhole. (Adapted from Daungkaew et al, reference 11.)

An additional flasked section that isolated the gauge was added next, which resulted in a configuration similar to the PressureXpress-HT tool. The success of the modified PressureXpress tool led design engineers at Schlumberger to develop a fully upgraded PressureXpress-HT tool, which was field-tested in the Gulf of Thailand. The tool, which incorporated upgraded electronics for high-temperature operations and flasks developed specifically for it, is combinable with other evaluation tools and can be included on the first trip into the well. The SRFT tool is not combinable and requires an additional trip when the operator requires samples. PTTEP compared PressureXpress-HT operational and measurement performance with those of the SRFT tool. Rig time was noticeably reduced. Time savings were realized from improved efficiencies and through set and retract times of less

than a minute compared with two to three minutes with the SRFT tool. Not only does the PressureXpress-HT tool set and retract more quickly than the previousgeneration tool did, but tool performance and data quality are improved. A direct comparison of the data from the PressureXpress-HT tool with 9. Fluid mobility is a measurement of the ease with which fluids travel through rock. It is the ratio of rock permeability divided by the dynamic viscosity of the fluid. 10. For more on Quartzdyne Technologies: http://www. quartzdyne.com/quartz.php (accessed August 7, 2012). 11. Daungkaew S, Yimyam N, Avant C, Hill J, Sintoovongse K, Nguyen-Thuyet A, Slapal M, Ayan C, Osman K, Wanwises J, Heath G, Salilasiri S, Kongkanoi C, Prapasanobon N, Vattanapakanchai T, Sirimongkolkitti A, Ngo H and Kuntawang K: “Extending Formation Tester Performance to a Higher Temperature Limit,” paper IPTC 14263, presented at the International Petroleum Technology Conference, Bangkok, Thailand, February 7–9, 2012.

15

Resistivity SRFT Pressure Data X,000

Crossover

PressureXpress Pressure Data X,000

PressureXpress Mobility Data

Y,000

psi

Gamma Ray 0

90-in. Induction

SRFT Mobility Data Y,000

psi

gAPI

200

%

45

Depth, ft

mD/cP

10,000 1.95

ohm.m

–15 0.2

g/cm3

200

30-in. Induction

Bulk Density

Drawdown Mobility 0.1

0.2

Neutron Porosity

ohm.m

200

10-in. Induction 2.95 0.2

ohm.m

200

X,100

0.319 psi/ft (gas) Gas/water contact

0.401 psi/ft (water)

X,150

> Stable pressure measurements. Engineers identify fluid contacts from fluid pressure gradients. This information enhances conventional log evaluation. For instance, the rise in resistivity (Track 4) around X,115 ft might be interpreted as a gas/water contact (GWC). The density-neutron porosity data (Track 3) provide little help in determining the fluid contact. However, with pressure data at around X,120 ft from the PressureXpress-HT tool (Track 1, blue circles), a GWC can be identified from the change in slope of a line drawn through pressure measurements. No such trend can be established with the SRFT data (black circles). Engineers also identified permeable zones using fluid mobility measurements from the PressureXpress-HT data (Track 2). (Adapted from Daungkaew et al, reference 11.)

Field Results Well A-1 PressureXpress-HT data SRFT data

Number of attempts

Valid

Dry

Tight

Unstable

Lost seal

Supercharged

37

18 (49%)

2 (5%)

10 (27%)

2 (5%)

4 (11%)

1 (3%)

Number of attempts

Valid

Dry

Tight

Unstable

Lost seal

Supercharged

10

2 (20%)

2 (20%)

1 (10%)

1 (10%)

4 (40%)

0

Lost seal

Supercharged

Well A-2 PressureXpress-HT data

Number of attempts

Valid

Dry

Tight

Unstable

29

22 (76%)

6 (21%)

1 (3%)

0

0

0

> Comparison of PressureXpress-HT field results with SRFT data. In the first well test (Well A-1), the PressureXpress-HT tool was able to make more attempts and had a higher success rate than the SRFT tool. In Well A-2, only the PressureXpress-HT tool was run. This test had a 76% success rate for pressure attempts, which engineers considered excellent for the downhole conditions and formation properties. (Adapted from Daungkaew et al, reference 11.)

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data from the SRFT tool demonstrated the stability and accuracy of the measurements. In a Gulf of Thailand well, the new tool provided fluid gradient data that clearly identified a gas/water contact, whereas the data from the SRFT tool were scattered and not definitive (left). A comparison of pretest data from the first application of the tool demonstrated the higher efficiency and improved performance of the PressureXpress-HT tool (below left). Performance continued to improve after a few jobs; on an offset well, 76% of the attempted pressure tests were successful with no unstable tests and no lost seals. The tool is combinable with other logging tools. Because it sets and retracts quickly, and because the quartz gauge requires little stabilization time, PTTEP has experienced average time savings between 157 and 167 min per job. This translates into direct rig cost savings. Fast setretract cycling has also allowed PTTEP to perform more tests before the tool heats up and must be removed from the well. The success of the PressureXpress-HT tool demonstrates that the new design meets the challenge of extreme conditions by protecting sensitive electronics with thermal barriers and minimizing heat generation. Because the PressureXpress tool does not have the capability to sample or measure CO2, PTTEP continues to use the SRFT tool for taking fluid samples. In development wells, where fluid properties are known, fluid sampling is often unnecessary and pressure data, from the PressureXpress-HT tool, for example, can be used for reservoir management and modeling. Pressure information helps engineers understand dynamic properties at the wellbore and across a reservoir. Time and Temperature To understand the reservoir limits and define field potential, engineers often conduct longduration pressure transient tests. Shut-in and buildup tests help accurately define reservoir potential. These tests provide data on reservoir volume, permeability thickness and boundaries, along with skin effect in the well being tested. Critical decisions that affect long-term production plans require data from long-duration tests. Although some measurements that reflect well production can be acquired at the surface, for best results, measurements are acquired with gauges positioned downhole, as close to the producing zone as feasible.

Oilfield Review

Quartz gauges are the industry standard for measurement accuracy and precision downhole. These gauges use quartz as the active sensing element because of its well-defined elasticity. When exposed to a stress, the quartz distorts, or strains, with a precise, repeatable response in reaction to the applied load. The measurement must be calibrated to compensate for the effects of temperature on the sensing element and associated electronics. In HPHT environments, however, operators have had to forgo extended well tests because downhole conditions preclude the use of gauges needed to make the measurements. Engineers at Schlumberger developed the Signature quartz gauge in recognition of the industry’s need for a robust downhole device that provided the accuracy and precision required but could withstand harsh HPHT conditions (right). Not only does the instrument survive HPHT environments—no simple task—but the data acquired meet needed accuracy and stability criteria. In developing the Signature gauge, engineers focused on two main areas of concern: electronics and batteries. For high-temperature applications, engineers chose ceramic electronic components; plastic components would never survive the temperature extremes for long-duration tests. The majority of the electronic functionality for the Signature gauge is incorporated into a high-temperature application-specific integrated circuit (ASIC), which minimizes component size and power consumption. Limiting power consumption is a challenge because consumption increases dramatically at high temperatures, often surpassing the ability of the battery to deliver sufficient current to operate the tool. Condensing the electronics into an ASIC reduces the number of components, connections and potential failure mechanisms. Since the predominant failure mode of electronics is mechanical, this design was developed with reliability and ruggedness in mind. The electronic circuitry is integrated into a multichip module (MCM). There are many types of MCMs but the Signature gauge uses rigorously tested high-temperature electronic components on a single cofired ceramic substrate (right).12 This technology provides mechanical rigidity and hermeticity. 12. Cofiring is a fabrication technique used for creating multilayer ceramic chips.

> Signature gauge. The outside diameter of the Signature gauge is only 25 mm [1 in.] and the tool weighs 1.7 kg [3.8 lbm]. Rated to 207 MPa and 210°C, the gauge is accurate to within 0.015% at full scale and has a resolution of 7 Pa [0.001 psi].

0

cm

1

> Designed for extreme conditions. The electronic components (gold) used in the Signature gauge are applied directly to a ceramic substrate (brown). Conventional tools may use plastic components mounted on circuit boards. The Signature gauge is designed for low power consumption to maximize battery life, which is a chief limiting factor for high-temperature operations that rely on downhole batteries.

Autumn 2012

17

PranhitaGodavari Basin I N D I A

KrishnaGodavari Basin

Cuddapah Basin

Chennai

PalarPennar Basin

GSPC lease

Cauvery Basin Deep exploration targets

engal of B y Ba SRI LANKA

0 0

km

0 0

km

20 mi

20

200 mi

200

> Bay of Bengal basins. In 2005, Gujarat State Petroleum Corporation made a huge natural gas discovery offshore India in the Godavari basin. Well depths here are approximately 5,500 m [18,050 ft], with bottomhole temperatures greater than 200°C. (Adapted from Khan et al, reference 14.)

Electronics that survive long-term exposure at high temperatures still need power to operate. Because the melting point of lithium is 181°C [358°F], conventional lithium batteries—the industry standard—cannot be used in high-temperature wells for long periods. Battery specialists at Schlumberger developed lithium batteries that incorporate magnesium to strengthen the cell structure of the battery, which allows battery operation up to 210°C. Although battery life remains the primary limiting factor in hightemperature operations, batteries with this design can power the tool for 12 days at 210°C and 37 days at 205°C [400°F]. To maximize test duration and extend battery life, the electronics are designed to consume minimal power during operations. Even if the batteries are fully discharged, data are recorded in nonvolatile memory and stored for the duration of extended tests with no loss of information. The Signature quartz gauges are available in three models: standard quartz, high-pressure (HP) quartz and HPHT quartz. The physical dimensions for all three gauges are the same at 25 mm [1 in.] outside diameter; however, the

18

gauges differ in electronics, memory size and batteries. The maximum pressure rating of the HP version is 207 MPa and the temperature rating is 177°C. The HPHT model has the same pressure rating but the maximum temperature is 210°C. Because of the limitations imposed by high-temperature environments, the HPHT memory capacity is 12 days of 1-s recordings at maximum temperature in contrast to 50 days for the other two models.13 For the Signature gauge, the accuracy and resolution for both pressure and temperature measurements are some of the best in the industry. The HP and HPHT models have pressure accuracy of 0.015% at full scale—207 MPa—with a resolution better than 70 Pa [0.01 psi]. Field results have demonstrated resolution better than 7 Pa [.001 psi]. Temperature accuracy is 0.2°C [0.4°F] with a resolution of 0.001°C [0.002°F]. The Challenge of the Bay of Bengal The HPHT version of the Signature quartz gauge was recently put to the test in a well operated by the Gujarat State Petroleum Corporation (GSPC).14 GSPC, India’s only state-owned oil and gas company, made discoveries of significant

amounts of natural gas in the Krishna-Godavari basin, which extends into the Bay of Bengal offshore India. Initial reports by GSPC in 2005 indicated a resource potential for 566 billion m3 [20 Tcf] of gas, the largest discovery in India at that time (above).15 The discovery well encountered 800 m [2,600 ft] of gas-bearing sandstone at around 5,500 m [18,050 ft]. Reservoir temperatures exceed 204°C. The highly faulted horst and graben structures are lower Cretaceous-age sandstones that have experienced extensive rifting and tectonic faulting. Although seismic data indicated potential targets for exploration, the depth and complexity of the reservoir led reservoir engineers to design a drillstem test (DST) to better understand the reservoir potential. 13. Storage capacity for the standard and HP Signature gauges is 16 MB. It is 4 MB for the HPHT model. 14. Khan ZA, Behera BK, Kumar V and Sims P: “Solving the Challenges of Time, Temperature and Pressure,” World Oil 233, no. 5 (May 2012): 75–78. 15. “India’s Gujarat Petroleum Strikes Record Gas Find,” Spirit of Chennai, http://www.spiritofchennai.com/news/ national-news/a0272.htm (accessed June 6, 2012). 16. Khan et al, reference 14.

Oilfield Review

Temperature Pressure

20,000

425

385

Pressure, psi

16,000

All electronic gauges, except the Signature quartz gauge, failed to record after this time.

Disturbance during buildup

14,000

365

Clean buildup

Drawdown

Drawdown 345

12,000

Temperature, °F

405

18,000

325

10,000

Buildup 1

Buildup 3

Buildup 2

305

8,000 0

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

Time, d

> Extended pressure test. GSPC performed an extended well test that included three buildup and drawdown sequences performed over 15 days. Five gauges were run downhole for redundancy and data security. The first two sequences experienced operational problems, and the tests were compromised by disturbances in the pressure data (blue). The third sequence was performed properly. After the gauges were retrieved, all but one were discovered to have failed prior to the commencement of the third (and only valid) test. The only usable data retrieved were from the HPHT Signature gauge. (Adapted from Khan et al, reference 14.)

To establish stable flow within the reservoir, engineers designed the DST to include three successive drawdowns and buildups conducted over 15 days. The estimated downhole pressure was more than 95 MPa [13,800 psi] and the temperature was greater than 210°C at TD. Extensive backup systems included five different electronic recording devices. The Signature quartz gauge was the only device that engineers deemed suitable for deployment at the 210°C level, which was close to TD. For the most accurate data, gauges should be positioned as close to the producing zone as possible because the compressibility of natural gas may distort the measurement. Although not optimal, but because of temperature and pressure limitations, three of the five devices were located more than 1,000 m [3,280 ft] above the depth at which the Signature gauge was positioned. The operator ran three pressure transient tests in sequence for the full 15 days. During the first two tests, the operator experienced problems that invalidated the tests but were unrelated to the gauges. The third test sequence, however, was performed as planned. The test assembly was retrieved and only one of the gauges was found to be operational, the Signature quartz gauge (above). No usable downhole electronic data were recorded from the

Autumn 2012

other gauges because they had all failed prior to the commencement of the final test. The data from the Signature gauge were of sufficient quality—pressure fluctuations of as little as 7 Pa were detected—that a second confirmation test was considered unnecessary. GSPC engineers estimated that US$ 1 million was saved because remedial services to resolve reservoir complexity were not needed.16 The Limit At one time, oil and gas service companies expressed grave concern about their ability to develop tools capable of withstanding extreme conditions. Electronics manufacturers shifted their focus from rugged components to those that consume little power and operate at ambient conditions, leaving service companies to fend for themselves. Design engineers, however, are now meeting the challenge of extreme operating environments with innovative pressure and sampling tools and downhole gauges for evaluating HPHT reservoirs. Service companies have demonstrated an ability to meet the challenge of hostile drilling environments. Although the portfolio of offerings has expanded in recent years, it is still limited to primary evaluation services. Some measurements that operators would like to have to characterize producing wells remain limited

to lower temperatures and pressures. Pressure and sampling tools were once in that class. Now that it has been proved that these services can be performed in extreme conditions, geologists, engineers and geophysicists often consider the measurements essential to fully characterize and understand reservoirs. Extreme wells call for extreme solutions. Although HPHT fields may contain a relatively small number of wells, they also may contain significant sources of hydrocarbons. Thanks to an enormous research and engineering effort, more and more options are available for operators to drill wells, evaluate formations and properly characterize reservoirs. —TS

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