testing the limits in extreme well conditions
TRANSCRIPT
4 Oilfield Review
Testing the Limits in ExtremeWell 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.
Chris AvantSaifon DaungkaewBangkok, Thailand
Bijaya K. BeheraPandit Deendayal Petroleum UniversityGandhinagar, Gujarat, India
Supamittra DanpanichWaranon LaprabangPTT Exploration and ProductionPublic Company LimitedBangkok, Thailand
Ilaria De SantoAberdeen, Scotland
Greg HeathKamal OsmanChevron Thailand Exploration and Production LtdBangkok, Thailand
Zuber A. KhanGujarat State Petroleum Corporation LtdGandhinagar, Gujarat, India
Jay RussellHouston, Texas, USA
Paul SimsDar es Salaam, Tanzania
Miroslav SlapalMoscow, Russia
Chris TevisSugar 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.
Many E&P companies are drilling wells in envi-ronments 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 con-sidered 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 solu-tions to contend with extreme well conditions; however, certain situations present particular problems for downhole tool developers.1 For instance, applications such as acquiring forma-tion 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 expo-sure 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 sam-ples, 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 tempera-tures while retaining their measurement preci-sion. 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 sam-pling tools that require high power to operate and were engineered to withstand high-pressure, high-temperature (HPHT) operating environ-ments. In addition, a recently introduced down-hole pressure gauge has been proved to operate for many hours at high temperature. Case studies from the North Sea, Thailand and India demon-strate the application of these advances.
A Niche Market That MattersHostile environments are typically character-ized as having HPHT conditions. HPHT wells will generally cross thresholds of either tem-perature 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 esti-mates approximately 1,600 of these wells will be
Autumn 2012 55
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:
“Oilfield Chemistry at Thermal Extremes,” Oilfield Review18, 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, High-Temperature 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.
6 Oilfield Review
Rese
rvoi
r tem
pera
ture
, °F
Reservoir pressure, psi
HPHT Wells Drilled 2007 to 2010 Worldwide
Well
High temperature
High pressure
250
1500 5,000 10,000 20,000 30,000 35,00015,000 25,000
350
450
550
650
classified as HPHT wells, representing about 1.5%of the worldwide total. Most of the wells consid-ered HPHT exceed established temperaturelimits; only a few wells exhibit truly extremepressures (left). The study also indicated that theHPHT market is heavily dominated by two coun-tries: the US (60%) and Thailand (20%) (below).
One caveat to consider in this analysis is thatgeothermal wells are not included in the totals.Because of their extremely high bottomhole tem-peratures, geothermal wells present operationalcomplexities rarely encountered in oil and gasexploration.3 Moreover, the number of geother-mal wells is small compared with the number oftheir oil and gas counterparts.
The HPHT market may currently be relativelysmall, but there is an industry-recognized accel-eration in the number of extreme wells beingdrilled and planned. For example, according toone report covering extreme wells drilled off-shore, during the 30-year period from 1982 to2012, operators drilled 415 HPHT offshore wells
> Extreme temperature or pressure. Schlumberger engineers conducted an internal study oftemperature and pressure data from wells worldwide. Over a four-year period, no wells exceededboth high-temperature (350°F [177°C]) and high-pressure (20,000 psi [138 MPa]) limits, which arecommonly used for wireline logging tools. Many wells exhibiting extremely high pressure do notexhibit high temperature, and vice versa. In addition, more wells exceeded the 350°F temperature thanexceeded 20,000 psi.
Significant high-temperature activityPotential for high-temperature activityGeothermal activity
> Drilling activity in high-temperature environments. Exploration and development drilling in high-temperature environments is regionally isolated. Themajority of extreme wells are located on land, although there is significant activity in the Gulf of Mexico, the North Sea and offshore India and SoutheastAsia. The number of geothermal wells, which represent the high end of extreme temperatures, is not statistically significant.
Autumn 2012 7
worldwide (above).4 The forecast for the four-yearperiod ending in 2016 anticipates that the totalwill be doubled, with the region off the coast ofBrazil alone adding more than 238 deep wells by2016. By 2020, the total number of offshore HPHTwells is projected to exceed 1,200—tripling thetotal number of extreme offshore wells in just10 years. The analysis highlights the need in thecoming decade for equipment to address theseHPHT operating conditions. The problem withsuch analyses, however, is that the results dependon the user’s definition of HPHT.
A Matter of SemanticsOperators and service companies often use vary-ing criteria for classification of HPHT wells.Operators contend with the effects of pressureand temperature on drilling, well constructionand surface equipment; service companies oftenfocus on how those conditions affect their prod-ucts, equipment and services. Although the dis-tinction may appear subtle, the engineeringdesign approach often differs.
In an effort to resolve some of the confusion,the API recently published recommendations forequipment used in HPHT wells, which weredefined as those with pressure greater than15,000 psi [103 MPa] and temperature above350°F.5 The recommendations apply primarily toengineering standards related to design speci-fications of equipment, acceptable materialsand testing of well control equipment and com-pletion hardware.
The report includes design verification andvalidation, material selection and manufacturingprocess controls, which are intended to ensurethat equipment used in the oil and gas industry isfit for service in HPHT environments. The threecriteria for HPHT classification are the following:• anticipated surface conditions that dictate
completion and well control equipment ratedabove 15,000 psi
• anticipated shut-in surface pressure in excessof 15,000 psi
• flowing temperature at the surface in excess of350°F.
If any one of these conditions is met, the wellis considered an HPHT well. Although the reportestablishes specific guidelines for defining HPHTand provides protocols for certifying equipment,it does not specifically address downhole elec-tronics or certification of downhole tools.
In an attempt to define thresholds thatreflect physical and technological limitations,Schlumberger developed an HPHT classificationsystem representing stability limits of common
3. A recent study estimates that approximately 4,000geothermal wells had been drilled through 2011.Sanyal SK and Morrow JW: “Success and the LearningCurve Effect in Geothermal Well Drilling—A WorldwideSurvey,” paper SGP-TR-194, presented at the 37thWorkshop on Geothermal Reservoir Engineering,Stanford, California, USA, January 30–February 1, 2012.
4. These findings were noted in the Simmons & CompanyInternational Limited 2012 analysis prepared for QuestEnergy. For the report, HPHT was defined as conditionsgreater than 10,000 psi [69 MPa] and 300°F [150°C].The number of land-based HPHT wells drilled duringthe period was much higher than that of thosedrilled offshore.
5. API: “Protocol for Verification and Validation of HPHTEquipment,” Washington, DC: API, Technical ReportPER15K-1, 1st ed., 2012.
97
238
18
14
13
17
0
0
36
90
290
10
16
3
10
26
16
22
133
75
52
118
23
10
0
4
0
415 Drilled through 2011
Projected from 2012 through 2015433
Projected from 2016 through 2020483
Gulf of Mexico
West AfricaSoutheast Asia
Australia
Norwegian North Sea
Mediterranean Sea
North Sea
Caspian Sea
Brazil
Offshore HPHT Wells
Wells
> Offshore HPHT activity. HPHT drilling activity is projected to accelerate in the coming years, especially offshore. In the next four years, the number ofoffshore 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 wellcount is projected to triple. (Adapted from Simmons & Company International Limited, reference 4. Used with permission.)
8 Oilfield Review
components such as elastomeric seals and elec-tronics (above).6 Other service companies andoperators use their own definitions, which aresimilar to the Schlumberger guidelines.
A Niche in DesignThe well type—HP or HT—dictates the engi-neering design approach because techniquesused for contending with pressure differ fromthose for temperature. For pressure, the solutionis often to design equipment with sealing ele-ments 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 electronicsfrom extreme temperatures, however, usuallyrelies on sheltering sensitive components fromthe cumulative effects of exposure to heat. This ismost often accomplished using thermal barriersin the form of flasks—double-insulated metalhousings—that protect electronic componentslong enough for data acquisition and otheroperations to be performed (below right). Flasksare constructed to have extremely low thermal
conductivity and thermal diffusivity to ensurethat the temperature inside the housing risesvery slowly.
Flasks have become an integral component intools such as the Schlumberger suite of Xtremetools, designed for HPHT environments.7 TheXtreme platform includes common measure-ments for petrophysical analysis. Unfortunately,the solution for keeping electronics protectedfrom wellbore heat traps self-generated heatinside the tool housings. This heat can pushinternal temperatures well beyond a tool’s ther-mal rating. Logging engineers monitor both timeand temperature to avoid potentially catastrophictool failure related to temperature when usingflasks in HPHT environments.
Tools that employ high-powered downholemotors and pumps, such as pressure and sam-pling tools, are examples of tools that generateconsiderable heat—much greater than mostother evaluation tools. The thermal loads gener-ated by these tools can quickly raise the tempera-ture inside a flask above the rating of theelectronic components. Thus, flasking alone maynot provide sufficient operating time to completethe required task when these high-power, highheat–generating tools are used.
Tools that do not generate excessive heat andhave low power consumption, such as downholepressure gauges, may be used to collect data formany hours, even days, in extreme conditions.
> HPHT classification system. This classification system was proposed bySchlumberger engineers and is based on pressure and temperatureboundaries that represent stability limits of common components used byservice companies. These include electronic devices and sealingelements. The HPHT-hc classification defines environments that areunlikely to be seen in oil and gas wells, although there are geothermalwells that exceed 500°F.
0
100
200
300
400
500
600
40,00035,00030,00025,00020,000
Static reservoir pressure, psi15,00010,0005,0000
Stat
ic re
serv
oir t
empe
ratu
re, °
F
150°C
69 M
Pa
138
MPa
241
MPa
HPHT
Ultra-HPHT
HPHT-hc
205°C
260°C
> The results of failure. This tool failed when exposed to pressures onlyslightly above its rating. The failure was initiated at the threaded-ringconnection, where the pressure seal was most vulnerable. The result was acatastrophic loss of the tools above and below the failure caused by thesudden inrush of drilling mud from the wellbore.
2.50 cm > Flasks for thermal barriers. The most common method of protectingsensitive electronics from extreme heat is to use a Dewar flask (top). Theflask (bottom) consists of a glass liner inside a metal housing that serves asa vacuum layer; the glass and air are poor heat conductors. Thermalinsulators at each end isolate the electronics section. Internally generatedheat from the electronic components is trapped inside the tool and cancause the tool to overheat.
Electronics
Vacuum layer
Thermal insulators
Dewar flask
Autumn 2012 9
For long-duration measurements in HPHT wells,flasks are not a solution for these typesof tools.
For solutions to address self-generated heator extended operations in high-temperatureenvironments, design engineers often focus onthe circuit boards. By maximizing efficiency, ana-lyzing the heat generated by electronic compo-nents and, wherever possible, employingcomponents that have above-average tempera-ture ratings, engineers can extend the time avail-able for tools to operate and acquire datadownhole (above).
Sourcing components that withstand high
temperatures has become increasingly difficult.The electronics industry is driven by consumerproducts that use plastic electronic componentsthat are not rated for use in even moderatelyhigh-temperature conditions, for instance above125°C [257°F]. Plastic components are oftencomposed of silicon chips, or dies, enveloped in aplastic overpack. These components cannotwithstand the rigors of extreme environmentsbecause the overpack fails first from tempera-ture effects, although the underlying electroniccomponent may not have failed. In addition,manufacturers treat plastic electronic compo-nents with flame retardant chemicals, which
6. DeBruijn et al, reference 1.7. For more on Xtreme logging tools: DeBruijn et al,
reference 1.
contain volatile compounds that are released atelevated temperatures. These chemicals arehighly corrosive.
For high-temperature environments, designengineers at Schlumberger have learned to elim-inate plastic overpacks and use only the siliconchips. These chips and other components areattached directly to heat-tolerant ceramic multi-layered circuit boards; the connecting wireshave the diameter of a human hair (below). Insome cases, engineers have created proprietary
> 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.
Thermal Hot Spots Unbalanced Loading
Temperature, °C24 26 28 30 32 34 36 38 40 42 44 46 48
> 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.
×65
10 Oilfield Review
dies that are programmed and packaged for spe-cific applications and built to high-temperaturespecifications that exceed those readily availablein the commercial marketplace.
Extensive analysis of failed electronic compo-nents has resulted in other design innovations.The failure of electronic components may occurat elevated temperatures; however, the actualfailure mode is often traced to mechanical break-downs (above). The two most common causes ofmechanical failure are corrosion and vibration.
Corrosion can be problematic because hightemperatures accelerate chemical corrosivity,especially that resulting from humidity and vola-tilized gases from products used in the manufac-ture of circuit boards. Where space permits,desiccants are inserted in tool housings to absorbvolatilized chemicals and moisture.
Techniques to extend operability time miti-gate the effects of high temperature, but suchtechniques only extend the time available fortools to operate at elevated temperatures.Similarly, shock and vibration cannot be elimi-nated, but better tool designs can improve themechanical integrity of connections and compo-nents. Attaching circuit boards to speciallydesigned mounting rails and shock absorbers canimprove tool reliability. Once the designs arefinalized, thorough and rigorous testing, usingboth thermal and mechanical loads, validates the
design effectiveness or identifies weaknessesthat can then be rectified.
Engineered for ExtremesThe MDT modular formation dynamics tester hasbeen an industry standard for fluid sampling sinceits introduction in 1989. Through the decades, anextensive array of sampling and downhole analy-sis tools has been added to the basic platform.Along with new features and services, severalmodifications have been implemented to improvethe tool’s reliability and performance; however,the basic design and layout of the tool electronicsand hardware have not changed.
In the years since the MDT tool was intro-duced, Schlumberger engineers have beendesigning tools to withstand high levels of shockand vibration—the primary sources of most elec-tronic component failures. Much of the impetusfor establishing higher standards came fromrequirements for LWD tools, which operate inextremely harsh conditions. Design engineershave integrated techniques developed for LWDtools in wireline tools, and new designs of wire-line tools are qualified to LWD standards when-ever possible.
To pass these new qualification standards, theMDT tool could not simply be upgraded butrequired a full redesign. This newly designed toolwas introduced as the MDT Forte rugged modular
formation dynamics tester. The electronics sys-tems for the MDT Forte tool were completelyreconfigured and mounted on a ruggedized chas-sis (next page, top). Engineers then subjected thenew design to a rigorous qualification process.
The temperature qualification process of theMDT Forte platform consisted of thermal aging ofcomponents, thermal cycling from –40°C to200°C [–40°F to 392°F] and cold storage at–55°C [–67°F]. Shock and vibration qualificationincluded thousands of shocks on individual cir-cuit boards, which were administered on differ-ent axes by rotating the boards in the test facility.Vibration testing of the boards included 10- to450-Hz sweeps. Engineers also performed pres-sure cycling, vibration transmissibility and trans-verse shock transmissibility testing. Afterqualifying the boards, they conducted tempera-ture and shock qualification on full tool assem-blies. They also performed extended low- andhigh-temperature operations, including operationat 210°C [410°F] for 100 h while administeringshocks to the tool assembly (next page, bottom).
These tests confirmed the new design couldwithstand mechanical shock and vibration inaddition to thermal shocks, thereby meeting qual-ification standards that previous-generation toolscould not. The temperature and pressure ratingsof the MDT Forte tool are 177°C [350°F] and172 MPa [25,000 psi].
> 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).
Seven Days at 150°C with Desiccant
Seven Days at 150°C Without Desiccant
×1,000
×200
×50
Cracked wedge
Brokenwedge
Autumn 2012 11
Design engineers next focused on develop-ing 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 innova-tive sealing technology that incorporates carbon
nanotubes in the O-ring seals. The structure of these sealing elements provides strength to with-stand downhole effects such as temperature deg-radation 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 expe-rienced in deepwater environments while run-ning in the well.
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 reser-voir 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
>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.
Original Design Redesign
> 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.
Ambienttemperature
400°F
75% power load
Shock test Shock test Shock test
75%powerload
45 h 5 h 45 h 5 h75%powerload
100%powerload
100%powerload
50 h 50 h 50 h
12 Oilfield Review
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 pres-sure 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 high-pressure 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
Meeting the Sampling ChallengeThe challenge of taking samples and pressures in HPHT conditions extends beyond simply being able to acquire fluids or pressure data. The sam-pling time must be minimized to avoid tool dam-age 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 tool-string 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 tem-peratures 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 sam-pling. Samples had to be taken quickly, yet fluids needed to flow long enough to minimize OBM filtrate contamination.
>MDT Forte-HT tool additions. Engineers designed modules and tools to complement the new higher temperature rating of the MDT Forte-HT tool- string. This inflatable fullbore packer withstands temperatures up to 210°C.
Upgraded Inflatable Packer
>MDT pumpout module options.
Standard tool
Volume/stroke,cm3 [in.3]
485 [30] 366 [22] 177 [11] 115 [7]
32 [4,641] 42 [6,092] 58 [8,412] 81 [11,748]
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]
Pump flow rate,cm3/s [in.3/s]
Maximum differentialpressure, MPa [psi]
High-pressure tool
Pumpout Module Displacement Units
Extra high-pressure tool Extra, extra high-pressure tool
Autumn 2012 13
The presence of OBM filtrate affects labora-tory analysis of reservoir fluids and may distortH2S measurements because the filtrate may scav-enge H2S from reservoir fluids. Sample qualityand reliability of the fluid property measure-ments are improved when engineers, using thepumpout module, first remove fluids contami-nated with filtrate. The Quicksilver Probe device,which uses a focused sampling technique, greatlydecreases the time required to remove contami-nated fluids and reach acceptable purity levels,cutting sampling time by as much as half com-pared with the time required for sampling withconventional probes.
For the well in question, the North Sea opera-tor collected several high-quality PVT samples ina single trip (above). Filtrate contamination forall samples was 2% or lower. Downhole fluid anal-ysis provided fluid composition, CO2 content,GOR and fluorescence.
Because H2S was a concern for the operator,the MDT tool was configured for reverse low-shock sampling. This technique helps minimizethe scavenging of H2S by tool hardware and byOBM filtrate. The low-shock sampling techniqueholds the pressure in the piston chambers of thepumpout module near that of the boreholepressure, minimizing the drawdown pressureduring sampling. The technique produces better
results than those that draw formation fluid intochambers at atmospheric pressure. Reverselow-shock sampling routes fluid directly intosample bottles without passing it through thepumpout module. This technique reduces theopportunity for metal hardware to scavengeH2S, although additional precautions are takento minimize scavenging, including replacingexposed 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.
> 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.
YY,000
XX,000
GOR
20406080
100
0
ft3 /bb
lFlu
id co
mpo
sitio
n, %
Dept
h
CO2 C1 C2 C3–5 C6+
Elapsed time, s2,500 3,500 4,500 5,5003,000 4,000 5,0002,000
Elapsed time, s2,500 3,500 4,500 5,5003,000 4,000 5,0002,000
Fluid Composition Pressure GOR Mobility
psi ft3/bbl mD/cPXX,000 YY,000 0.2 2,000CO2 C1 C2 C3–5 C6+
Station 1
Station 2
Station 3
Station 4
Station 5
14 Oilfield Review
parts with compounds that inhibit H2Sadsorption. Specially designed metal strips—coupons—that detect H2S concentrations wereincluded in the tool flowlines.
The fluid properties, measured downhole inextreme pressure and temperature conditions,
were confirmed by laboratory analysis. Combinedwith a Quicksilver Probe assembly, the MDTForte-HT tool met the operator’s sampling objec-tives of obtaining uncontaminated reservoirfluid, determining CO2 concentration anddetecting H2S.
Reservoir Pressure OnlyOperators cannot always acquire fluid samples orperform complex downhole fluid analyses, nor dothey always need to. These tasks are especiallyproblematic in low-permeability formations inwhich fluid samples may be difficult to obtain orlong sampling times are required. However, accu-rate pressure and fluid mobility data are importantfor understanding these reservoirs.9 These dataare especially crucial for establishing fluid gradi-ents and identifying fluid contacts. Engineers atSchlumberger developed the PressureXpress res-ervoir pressure while logging service, which typi-cally measures downhole pressure and mobility inless than a minute, to address situations in whichpressure data alone may be sufficient.
The speed with which this service deliversmultiple measurements greatly improves the like-lihood of successful operations at elevated tem-peratures, although the original tool is rated foronly 150°C [300°F]. The lower temperature ratingand absence of a flask to protect sensitive compo-nents severely limited the use of the tool in HPHTenvironments. A more robust version was devel-oped to meet the challenge of HPHT operations.
To upgrade the PressureXpress tool design,engineers focused on the electronics and thepressure gauge. Pressure measurements withquartz gauges are highly accurate, but the datamust be corrected for temperature. This tempera-ture correction applies to the measurement elec-tronics rather than the reservoir temperature.
For downhole pressure measurements, thePressureXpress and PressureXpress-HT high-temperature reservoir pressure services use aQuartzdyne gauge, which differs from conven-tional quartz gauges in that it has three separatecrystals: One measures pressure, another mea-sures temperature and a third acts as a reference(above left).10 The measurement is extremelyaccurate when all three crystals are at the sametemperature, and the gauge is reliable at tem-peratures up to 225°C [437°F]. But the gauge issensitive to abrupt pressure and temperaturechanges. When exposed to rapid high-tempera-ture and pressure changes, which can occur whenrunning into the well on wireline, the gauge mustbe allowed to stabilize before acquiring data.
The PressureXpress-HT tool is equipped withtwo flasks—one for the pressure gauge andanother for the electronics—to isolate the pres-sure gauge sensor from the borehole and to isolatethe rest of the tool electronics from the gauge.This configuration has proved to provide more-stable measurements than those taken with toolswithout flasks or when the electronics are housedwith the gauge in the same flask (left). Electronic
> Quartzdyne pressure transducer. Three quartz crystal resonators—a temperature sensor, a pressure sensor and a reference—make up the Quartzdyne transducer. An increase in pressure at the pressure inlet of the bellows assembly causes an increase in frequency of the signal from the pressure crystal. An increase in temperature causes the frequency of the temperature crystal signal to decrease. The signal from the temperature sensor is used to compensate for temperature effects. The reference crystal simplifies frequency counting output from the other two crystals. Its output is mixed with the output of the temperature and pressure sensors, lowering their frequencies from the MHz to the kHz range. The design results in a low power consumption gauge that is highly stable and shock resistant, while providing high-resolution measurements. A pressure resolution of 0.01 psi [70 Pa] and temperature resolution of 0.001°C [0.002°F] can be obtained using this gauge.
Pressureinlet
Bellows
Temperature crystal
Pressure crystal
Reference crystal
Bellows AssemblySensor Assembly
2.50 cm
> Thermal isolation of the PressureXpress tool pressure gauge. The PressureXpress-HT tool isolates the pressure gauge and the rest of the electronics in separate flasks, which protects the gauge from external wellbore temperatures and internally generated heat from the electronics. A comparison of 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 input pressure (3,391.99 psi) after almost 150 s.
Pres
sure
, psi
3,390
3,389
3,3880 10 20
Time, s
30 40 50 60 70 80 90 100 110 120 130 140 150
3,393
3,392
3,391
3,391.99 psi
3,390.03 psi
Pressure Data Comparison
Autumn 2012 15
components for the PressureXpress-HT tool werealso upgraded based on many of the lessonslearned from the MDT Forte-HT tool design.
The modifications to the PressureXpress-HTtool have extended the temperature specifica-tions of the tool to 232°C [450°F] for 14 h.Pressure and mobility measurements may beobtained with drawdown differential pressuresup to 55 MPa [8,000 psi] and pretest mobility aslow as 0.3 mD/cP may be detected. The toolretains its slim diameter, even with the additionof flasks. The probe section can be as small as10.3 cm [4.05 in.] while the main tool body has adiameter of only 9.8 cm [3.9 in.].
Gulf of Thailand ChallengesBecause of high geothermal gradients, the south-ern regions of the Gulf of Thailand represent someof the world’s harshest environments for hydro-carbon production (right). The Arthit field in theGulf of Thailand is about 230 km [143 mi] off-shore. PTT Exploration and Production Plc(PTTEP) discovered the field in 1999. The field ischaracterized by highly compartmentalized, com-plex reservoirs that have bottomhole tempera-tures between 320°F [160°C] and 500°F [260°C].11
Production is from Late Eocene to LateOligocene formations that are characterized bylow permeability. Low-permeability formationsmay require extended sampling time, even whenonly pressures and mobility data are acquired.
Most boreholes are small, usually drilled witha 61/8-in. bit, which limits the size and selection oftools that can be run at TD. Because of the smallhole size, PTTEP historically acquired pressureand sampling data with an SRFT slimhole repeatformation tester. Although this tool is rated onlyto 177°C [350°F], it was one of the few optionsavailable for the hole size typically drilled in thefield. The measurements needed from the toolincluded formation pressure, fluid gradients andCO2 content. Of these, only CO2 content requiredfluid sampling. The pressure data were used todetermine fluid contacts, fluid mobility, sand-to-sand pressure correlation, reservoir connectivity,compartmentalization and perforation designstrategy. The data were also used to identifydepleted zones.
In 2009, a flasked PressureXpress tool wasintroduced in Thailand. The tool was capable ofobtaining all of the PTTEP objectives exceptone—CO2 content. However, this tool did notinclude a separate flask for the pressure gauge,which caused gauge stability problems becausethe internal temperature rose during operations.
An additional flasked section that isolated thegauge was added next, which resulted in a con-figuration similar to the PressureXpress-HT tool.
The success of the modified PressureXpresstool led design engineers at Schlumberger todevelop a fully upgraded PressureXpress-HT tool,which was field-tested in the Gulf of Thailand.The tool, which incorporated upgraded electron-ics for high-temperature operations and flasksdeveloped specifically for it, is combinable withother evaluation tools and can be included on thefirst trip into the well. The SRFT tool is not com-binable and requires an additional trip when theoperator requires samples.
PTTEP compared PressureXpress-HT opera-tional and measurement performance with thoseof the SRFT tool. Rig time was noticeably reduced.Time savings were realized from improved effi-ciencies and through set and retract times of less
than a minute compared with two to three minuteswith the SRFT tool.
Not only does the PressureXpress-HT tool setand retract more quickly than the previous-generation tool did, but tool performance anddata quality are improved. A direct comparison ofthe 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.
> 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.)
T H A I L A N D
L A O SM Y A N M A R
C A M B O D I A
VIETNAM
Arthitfield
Songkhla
Gulf of Thailand
AndamanSea
180°F to220°F
220°F to320°F
320°F to350°F
350°F to500°F
km0 200
0 mi 200
16 Oilfield Review
data from the SRFT tool demonstrated the stabil-ity and accuracy of the measurements. In a Gulfof Thailand well, the new tool provided fluidgradient data that clearly identified a gas/watercontact, whereas the data from the SRFT toolwere scattered and not definitive (left).
A comparison of pretest data from the firstapplication of the tool demonstrated the higherefficiency and improved performance of thePressureXpress-HT tool (below left). Performancecontinued to improve after a few jobs; on an off-set well, 76% of the attempted pressure testswere successful with no unstable tests and nolost seals.
The tool is combinable with other loggingtools. Because it sets and retracts quickly, andbecause the quartz gauge requires little stabiliza-tion time, PTTEP has experienced average timesavings between 157 and 167 min per job. Thistranslates into direct rig cost savings. Fast set-retract cycling has also allowed PTTEP to per-form more tests before the tool heats up andmust be removed from the well.
The success of the PressureXpress-HT tooldemonstrates that the new design meets thechallenge of extreme conditions by protectingsensitive electronics with thermal barriers andminimizing heat generation. Because thePressureXpress tool does not have the capabilityto sample or measure CO2, PTTEP continues touse the SRFT tool for taking fluid samples. Indevelopment wells, where fluid properties areknown, fluid sampling is often unnecessaryand pressure data, from the PressureXpress-HTtool, for example, can be used for reservoir man-agement and modeling. Pressure informationhelps engineers understand dynamic propertiesat the wellbore and across a reservoir.
Time and TemperatureTo understand the reservoir limits and definefield potential, engineers often conduct long-duration pressure transient tests. Shut-in andbuildup tests help accurately define reservoirpotential. These tests provide data on reservoirvolume, permeability thickness and boundaries,along with skin effect in the well being tested.
Critical decisions that affect long-term pro-duction plans require data from long-durationtests. Although some measurements that reflectwell production can be acquired at the surface,for best results, measurements are acquired withgauges positioned downhole, as close to theproducing zone as feasible.
> 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.)
Drawdown Mobility
90-in. Induction
PressureXpress Pressure Data
SRFT Pressure Data
PressureXpressMobility Data
SRFT Mobility Data
Gamma Ray
0.319 psi/ft (gas)
0.401 psi/ft (water)
Gas/water contact
Depth,ft
gAPI
psi
psi
mD/cP0
X,000 Y,000
X,100
X,150
X,000 Y,000
200 0.1 10,000
ohm.m0.2 200
30-in. Induction
ohm.m0.2 200
10-in. Induction
ohm.m0.2 200
Neutron Porosity
Crossover
%
Bulk Density
g/cm31.95 2.95
45 –15
Resistivity
> 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.)
PressureXpress-HTdata
SRFT data
Well A-1
Field Results
Number of attempts Valid Dry Tight Unstable Lost seal Supercharged
37 18 (49%) 2 (5%) 4 (11%) 1 (3%)2 (5%)10 (27%)
10 2 (20%) 2 (20%) 4 (40%) 01 (10%)1 (10%)
PressureXpress-HTdata
Well A-2
Number of attempts Valid Dry Tight Unstable Lost seal Supercharged
29 22 (76%) 6 (21%) 0 001 (3%)
Number of attempts Valid Dry Tight Unstable Lost seal Supercharged
Autumn 2012 17
Quartz gauges are the industry standard for measurement accuracy and precision downhole. These gauges use quartz as the active sensing ele-ment 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 cali-brated to compensate for the effects of tempera-ture 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 envi-ronments—no simple task—but the data acquired meet needed accuracy and stability cri-teria. In developing the Signature gauge, engi-neers 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 tempera-ture extremes for long-duration tests. The major-ity of the electronic functionality for the Signature gauge is incorporated into a high-tem-perature application-specific integrated circuit (ASIC), which minimizes component size and power consumption. Limiting power consump-tion 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 pre-dominant failure mode of electronics is mechani-cal, 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 rigor-ously tested high-temperature electronic com-ponents 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].
> 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.
10 cm
18 Oilfield Review
Electronics that survive long-term exposureat high temperatures still need power to operate.Because the melting point of lithium is 181°C[358°F], conventional lithium batteries—theindustry standard—cannot be used in high-tem-perature wells for long periods. Battery special-ists at Schlumberger developed lithium batteriesthat incorporate magnesium to strengthen thecell structure of the battery, which allows batteryoperation up to 210°C. Although battery liferemains the primary limiting factor in high-temperature operations, batteries with thisdesign can power the tool for 12 days at 210°Cand 37 days at 205°C [400°F].
To maximize test duration and extend batterylife, the electronics are designed to consume min-imal power during operations. Even if the batter-ies are fully discharged, data are recorded innonvolatile memory and stored for the duration ofextended tests with no loss of information.
The Signature quartz gauges are available inthree models: standard quartz, high-pressure(HP) quartz and HPHT quartz. The physicaldimensions for all three gauges are the same at25 mm [1 in.] outside diameter; however, the
gauges differ in electronics, memory size and bat-teries. The maximum pressure rating of the HPversion is 207 MPa and the temperature rating is177°C. The HPHT model has the same pressurerating but the maximum temperature is 210°C.Because of the limitations imposed by high-tem-perature environments, the HPHT memorycapacity is 12 days of 1-s recordings at maximumtemperature in contrast to 50 days for the othertwo models.13
For the Signature gauge, the accuracy andresolution for both pressure and temperaturemeasurements are some of the best in the indus-try. The HP and HPHT models have pressure accu-racy of 0.015% at full scale—207 MPa—with aresolution better than 70 Pa [0.01 psi]. Fieldresults have demonstrated resolution better than7 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 BengalThe HPHT version of the Signature quartz gaugewas recently put to the test in a well operatedby the Gujarat State Petroleum Corporation(GSPC).14 GSPC, India’s only state-owned oil andgas company, made discoveries of significant
amounts of natural gas in the Krishna-Godavaribasin, which extends into the Bay of Bengal off-shore India. Initial reports by GSPC in 2005 indi-cated a resource potential for 566 billion m3
[20 Tcf] of gas, the largest discovery in India atthat time (above).15
The discovery well encountered 800 m[2,600 ft] of gas-bearing sandstone at around5,500 m [18,050 ft]. Reservoir temperaturesexceed 204°C. The highly faulted horst and gra-ben structures are lower Cretaceous-age sand-stones that have experienced extensive riftingand tectonic faulting. Although seismic data indi-cated potential targets for exploration, the depthand complexity of the reservoir led reservoirengineers to design a drillstem test (DST) to bet-ter 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.
> 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.)
I N D I A
SRILANKA
Pranhita-Godavari Basin
CuddapahBasin
Chennai
Palar-PennarBasin
CauveryBasin
Krishna-Godavari Basin
GSPC lease
Deep explorationtargets
Bay of Bengal
km0 200
0 mi 200
km0 20
0 mi 20
Autumn 2012 19
To establish stable flow within the reservoir,engineers designed the DST to include three suc-cessive drawdowns and buildups conducted over15 days. The estimated downhole pressure wasmore than 95 MPa [13,800 psi] and the tempera-ture was greater than 210°C at TD. Extensivebackup systems included five different electronicrecording devices. The Signature quartz gaugewas the only device that engineers deemed suit-able for deployment at the 210°C level, which wasclose to TD.
For the most accurate data, gauges should bepositioned as close to the producing zone as pos-sible because the compressibility of natural gasmay distort the measurement. Although not opti-mal, but because of temperature and pressurelimitations, three of the five devices were locatedmore than 1,000 m [3,280 ft] above the depth atwhich the Signature gauge was positioned.
The operator ran three pressure transienttests in sequence for the full 15 days. During thefirst two tests, the operator experienced prob-lems that invalidated the tests but were unre-lated to the gauges. The third test sequence,however, was performed as planned.
The test assembly was retrieved and only oneof the gauges was found to be operational, theSignature quartz gauge (above). No usable down-hole electronic data were recorded from the
other gauges because they had all failed prior tothe commencement of the final test. The datafrom the Signature gauge were of sufficientquality—pressure fluctuations of as little as 7 Pawere detected—that a second confirmation testwas considered unnecessary. GSPC engineersestimated that US$ 1 million was saved becauseremedial services to resolve reservoir complexitywere not needed.16
The LimitAt one time, oil and gas service companiesexpressed grave concern about their ability todevelop tools capable of withstanding extremeconditions. Electronics manufacturers shiftedtheir focus from rugged components to those thatconsume little power and operate at ambientconditions, leaving service companies to fend forthemselves. Design engineers, however, are nowmeeting the challenge of extreme operating envi-ronments with innovative pressure and samplingtools and downhole gauges for evaluatingHPHT reservoirs.
Service companies have demonstrated anability to meet the challenge of hostile drillingenvironments. Although the portfolio of offer-ings has expanded in recent years, it is stilllimited to primary evaluation services. Somemeasurements that operators would like to haveto characterize producing wells remain limited
to lower temperatures and pressures. Pressureand sampling tools were once in that class. Nowthat it has been proved that these services canbe performed in extreme conditions, geologists,engineers and geophysicists often consider themeasurements essential to fully characterizeand understand reservoirs.
Extreme wells call for extreme solutions.Although HPHT fields may contain a relativelysmall number of wells, they also may contain sig-nificant sources of hydrocarbons. Thanks to anenormous research and engineering effort, moreand more options are available for operators todrill wells, evaluate formations and properlycharacterize reservoirs. —TS
> 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.)
Pres
sure
, psi
Time, d
Clean buildup
Disturbanceduring buildup
Drawdown
Buildup 1 Buildup 2 Buildup 3
Drawdown
All electronic gauges, exceptthe Signature quartz gauge,
failed to record after this time.
Tem
pera
ture
, °F
TemperaturePressure 425
405
20,000
18,000
16,000
14,000
12,000
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15
10,000
8,000
385
365
345
325
305