high-pressure, high-temperature well logging, perforating...
TRANSCRIPT
50 Oilfield Review
High-Pressure, High-Temperature Well Logging, Perforating and Testing
Tom BairdTroy FieldsAberdeen, Scotland
Robert DrummondDave MathisonSugar Land, Texas, USA
Bjorn LangsethAndrew MartinRosharon, Texas
Lisa SilipignoBelle Chasse, Louisiana, USA
For help in preparation of this article, thanks to Tom Allen, Schlumberger Wireline & Testing, Songkhla,Thailand; Charlie Cosad, Sam Gomersall and Brian Scott,Solutions Services, Aberdeen, Scotland; Dhani Kannan and Sam Musachia, Schlumberger Wireline & Testing,Rosharon, Texas, USA; Harold Darling, Hugh Scott andChris Stoller, Schlumberger Wireline & Testing, Sugar Land,Texas; Graham Elliot and Robert McCombie, Texaco North Sea UK Company, Aberdeen, Scotland; Brian Imrie,Schlumberger Wireline & Testing, Stavanger, Norway; Stuart Murchie, Schlumberger Wireline & Testing,Montrouge, France; Neil Legendre, SchlumbergerWireline & Testing, New Orleans, Louisiana, USA; Kofi Quansah, Schlumberger Wireline & Testing, Kuala Lumpur, Malaysia; and Don Sweet, Schlumberger Wireline & Testing, Aberdeen, Scotland.
AIT (Array Induction Imager Tool), APT (AcceleratorPorosity Tool), CBT (Cement Bond Tool), CQG (CrystalQuartz Gauge), CSI (Combinable Seismic Imager), CST(Chronological Sample Taker), DSI (Dipole Shear SonicImager), Enerjet, FPIT (Free Point Indicator Tool),GunStack, HLDT (Hostile Litho-Density Tool), HSD(High Shot Density), HTX, InterACT, IPL (IntegratedPorosity Lithology), Litho-Density, MAXIS (MultitaskAcquisition and Imaging System), MDT (ModularFormation Dynamics Tester), PCT (Pressure ControlTester), PLATFORM EXPRESS, PLT (Production Logging Tool),PosiSet, Sapphire, SLIMACCESS, SRFT (Slimhole RepeatFormation Tester), TLC (Tough Logging Conditions), USI (UltraSonic Imager), Variable Density, WFL (WaterFlow Log) and Xtreme are marks of Schlumberger.
As the search for oil and gas leads to deeper reservoirs, extreme pressures and temperatures
have become key considerations in reservoir development. Innovative technologies are
being developed to meet the challenges of evaluating and completing
HPHT wells and bringing these fields on-stream.
Summer 1998 51
Wells completed in high-pressure and high-temperature (HPHT) environments are bytheir nature expensive undertakings. Therisks associated with evaluating and com-pleting a well are intensified as boreholepressures and temperatures rise. However,regardless of the dangers and expense, thenumber of HPHT wells is increasing in manyareas of the world, including the North Sea,the Gulf of Mexico and China (right).
Several factors are responsible for driving thesearch for hydrocarbons to these hostile envi-ronments. Existing fields are becomingdepleted and easier targets are scarce. The highpressure means that relatively more hydrocar-bon is contained in these fields compared withnormally pressured fields. Moreover, as longas the fields are large enough (as with theErskine, Elgin, Franklin and Shearwater in theNorth Sea), they make commercially attractivetargets even with the technical difficulties ofdrilling and producing.
Improved seismic techniques have enabledcompanies operating in the deepwater Gulfof Mexico to identify geologic structures thatare much deeper and hotter than those previ-ously drilled. Changes in the UK PetroleumRevenue Tax and the deregulation of gas salesare promoting the development of HPHTwells in the North Sea. The Erskine fieldjointly developed by Texaco and BP is oneexample.1 Discovered in 1981 and located160 miles [256 km] east of Aberdeen,Scotland, UK, this field was not seriouslyconsidered for development until 1994mainly because of the expense and difficultyof dealing with the extreme conditions foundin the reservoirs.
Since then, many technical challenges such as bottomhole temperatures (BHT) of350°F [175°C] and pressures of 14,000 psi[97 MPa], wellhead shut-in pressures of10,600 psi [73 MPa] and flowing surfacetemperatures of up to 300°F [150°C] wereovercome. The first gas production in theErskine field was in December 1997, and thefield is expected to yield 330 Bscf [9.4 Bscm]of gas and 75 million barrels [12 million m3]of condensate. Although it was considered amarginal discovery for many years, Erskineled the way to HPHT development in the North Sea, and set the standard for otherhotter and higher pressure Central Grabenprojects including the Shearwater, Puffin,Elgin and Franklin fields.
Five years ago the Oilfield Review dis-cussed HPHT drilling safety, testing proce-dures, casing and cementing technology.2 In
that article, wells with bottomhole tempera-tures above 300°F were considered as hightemperature. Those requiring pressure con-trol equipment rated in excess of 10,000 psi [69 MPa] or a maximum anticipated down-hole pore pressure exceeding an 0.8 psi/ft[18 kPa/m] hydrostatic gradient were con-sidered high pressure. We will adopt thosedefinitions for this article. However, muchprogress in technology has been made since then.
This article looks at some of the latestdevelopments in three key areas: logging,perforating and testing. First we will look atthe latest logging tool technology designedfor wells that are hotter and have higherpressures than the technical limits of “stan-dard” HPHT tools. Then, we discuss HPHTperforating techniques and a new explosivedesigned to meet the needs of longer expo-sures at higher temperatures. Finally, we pre-sent examples of new developments indrillstem testing (DST).
HPHT Wells Although they are a small but growingpercentage of the total number of new wellsdrilled, HPHT wells require downholeevaluation, testing and completion servicesthat push the limits of instrument and tooltechnology. For example, the high tempera-tures in HPHT wells cause conventional log-ging tool electronics to fail. Extremetemperatures and pressures are also knownto affect tool sensor responses.
One solution, putting conventional log-ging tool electronics in dewar flasks, hashelped meet the early challenges of HPHTenvironments. But as operators drill wellsinto ever hotter environments that pushbeyond the safe operating envelopeachieved with flasks, new technology isneeded to meet the ever increasing demandsof these hostile environments.
Perforating deeper and hotter wells isanother difficult challenge. New perforatingtools and procedures are being developedfor traditional wireline, the more complextubing-conveyed and completion-conveyedoperations. The introduction of a new high-temperature explosive has led to improvedperformance of shaped charges; this, in turn,has resulted in greater oil and gas produc-tion, making these expensive wells econom-ically viable.
HPHT wells are equally hard on mechani-cal tools and devices used in downhole pro-duction testing. Any operational failurecould potentially compromise wellsite safetyand lead to high environmental and financialcosts. New developments in seal technologyhave resulted in safer and more reliable toolsfor testing such wells.
230
320
275
365
455
410
500
Arun
Marnock
Initial reservoir pressure, MPa
Initial reservoir pressure, psi
HPHT wells
Ultra-HPHT wells
40 50 60 70 80 90 100 110 120
5760
110
160
135
185
235
210
260
Tem
pera
ture
, ˚F
Tem
pera
ture
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7200 8640 10,080 11,520 12,960 14,400 15,840 17,280
Kotelnevsko
North Ossum
F15Laco
Lille Frigg
Mary Ann
Embla
WestCameron
Mobile Bay South Texas
Shearwater Thomasville
Eugene Island
FranklinElgin
Trecate
Puffin
Malossa
Villa/Trecate
Erskine
■HPHT fields. The number of HPHT wells is growing worldwide. Wells with undisturbedbottomhole temperatures above 150°C [302°F] are classed as high temperature. Thosewith wellhead pressure greater than 10,000 psi [69 MPa] or a maximum anticipateddownhole pore pressure exceeding an 0.8 psi/ft [18 kPa/m] hydrostatic gradient are con-sidered high pressure. Wells with bottomhole temperatures above 425°F and pressuresabove 15,000 psi [103 MPa] are generally regarded as ultra-HPHT.
1. Young T: “Erskine HPHT Field Development,” SPEReview (September 1997): 6-7.
2. MacAndrew R, Parry N, Prieur J-M, Wiggelman J,Diggins E, Guicheney P, Cameron D and Stewart A:“Drilling and Testing Hot, High-Pressure Wells,”Oilfield Review 5, no. 2/3 (April/July 1993): 15-32.
52 Oilfield Review
Logging HPHT WellsElectronic components such as integrated cir-cuits are frequently the weakest link in a log-ging tool’s operational performance at hightemperature. Typically, most electronic sys-tems in logging tools are built from commer-cially available high-temperature US militaryspecified components.
Increasing tool ratings—These commercialelectronic systems are rated to 350°F for con-tinuous operation. The temperature increaseinside a logging tool depends on two factors:the heat flow from the outside environmentand the heat dissipated by the power con-sumption of the internal components.Therefore, the use of low-power componentsand efficient circuit design helps reduce theinternal temperature increase coming fromthe heat generated inside the tool.
Conventional logging tools (rated to 350°Fand 20,000 psi [140 MPa]) are upgraded tohigh-temperature specifications by installingall sensitive electronic components in a20,000-psi pressure-rated dewar flask housing(above). The dewar flasks protect the electroniccircuits from excessive borehole temperatures.However, weight becomes a concern in HPHTwells because the flasks add weight to longcombinations of tools. In deep HPHT wells theadded cable tension from the additionalweight of the flasked tools reduces the amountof pull that can be made on the cable beforethe limits of the weak point are reached.3
Electrical continuity between flasked tools is provided by selecting various thermalplug inserts, which also move electroniccomponents away from housing-to-housingor tool connection joints—serving as further
thermal isolation. Mechanical systems canbe sensitive to high temperatures simply byvirtue of dimensional changes caused bythermal expansion, and special attentionneeds to be paid to selecting and matchingthe size and fit of flask inserts.
The IPL Integrated Porosity Lithology tool isan example of a high-technology tool that,when flasked, can be upgraded to the hostileenvironments of HPHT logging operations.The APT Accelerator Porosity Tool sonde andIPL tool’s common electronic cartridge arecompletely enclosed in a flask, as are theLitho-Density sonde detectors and electron-ics. The flasked Hostile Natural Gamma RaySpectrometry (HNGS) tool has been com-mercially available for many years.
Other tools, such as the Hostile Environ-ment Array Induction Tool (HAIT), areupgraded by flasking the electronics from thelatest generation Slim Array Induction Tool(SAIT) and combining these with a newinduction antenna coil array sonde designedto withstand extreme environmental condi-tions. By their nature, induction tools requirethe use of nonconductive materials. ForHPHT versions, high-temperature compos-ites—developed for the aerospace industry—were adapted for use downhole. All tools andcomponents are heat qualified to tempera-tures expected in the HPHT wells before theyare sent out for logging.
For conventional wells, the use ofunspooled cable lengths of 14,000 to30,000 ft [4300 to 9100 m] causes no sig-nificant degradation to electrical operationof the logging cable. However, in HPHTwells, the increased temperature results inan increased cable resistance and thus
higher power loss, a consideration whenprejob operation checks are carried out. Insome wells logged in the North Sea,Schlumberger uses a special downholetransformer to allow a higher voltage to beapplied with less power loss on the cable. Atelevated temperatures, special loggingcables are required. High-strength cablewith electrical-release logging heads mini-mizes the risk of sticking, because thoseheads permit higher tension and more con-trol on the cables.
The alternative to wireline conveyance isthe TLC Tough Logging Conditions system.The TLC system uses drillpipe to convey thelogging tools, which are attached to the endof the pipe and pushed to the desired loggingdepth. The logging cable—providing powerfor the logging tools and telemetry commu-nications—is attached to the logging tools bypumping a TLC docking sub down throughthe pipe to connect with a special dockinghead at the top of the tool string. Thedrillpipe is then used to pull the tool out ofthe well while logging.
Sensors for HPHT environments—Many dif-ferent sensors are used for wireline logging:antenna arrays, gamma ray detectors, neutrondetectors, pressure and temperature sensors aswell as ultrasonic and sonic transmitters andreceivers. The extreme conditions in HPHTwells have a variety of effects on these sensorsand each must be dealt with in a different way.
An example is the development of specialpressure gauges for HPHT environments.Accurate pressure determination inherentlyrequires the sensor to be exposed to the well temperature. There is a trade-off
Time, min0 200 400 600
450
400
350
300
250
200
150
100
50
0
210
180
150
120
90
60
30
0
Outside flask
Inside flask
Tem
pera
ture
, ˚F
Tem
pera
ture
, ˚C
■Barriers to extreme temperatures. Dewar flask housings work on the same principle as vacuum flasks. When a flasked tool is inserted in atest oven (left), external temperature rises rapidly (red curve). However, temperature of the electronic circuits inside a flask under the sameconditions rises at a much slower rate (blue curve), allowing time for logging operations to be completed. Temperatures from variouslogging tools on a recent HPHT operation at greater than 380°F show a gradual increase throughout the job (middle and right). The rate ofincrease for each tool depends on the power dissipated by internal electronics and insulation provided by the individual flask. PrecooledHNGS detector temperatures are lowest and rise slowly because of low heat-generating components inside the flask. The power dissipatedby the neutron generator in the Hostile Accelerator Porosity Sonde (HAPS) contributes to a high rate of temperature increase.
HNGS 1
HNGS 2
Nuclear toolcartridge
Nuclear toolcartridge
Telemetrycartridge
Telemetrycartridge
Inte
rnal
tem
pera
ture
, ˚F
HLDSdensity
HAPSneutron
20
40
60
80
100
120
140
160
180
200
80
60
40
20
0
Down logging, min0 20 40 60 80 0 20 40 60 80
HNGS 1
HNGS 2
Up logging, min
HLDSdensity
HAPSneutron
Inte
rnal
tem
pera
ture
, ˚C
Summer 1998 53
between accurate pressure measurementsand elevated temperatures. Hydrostatic pres-sures—typically 16,000 to 18,000 psi [110 to124 MPa]—are above the safe operating rangeof the CQG Crystal Quartz Gauge sensor.Currently, other pressure gauges with varyingdegrees of resolution, accuracy and cost areavailable for a variety of HPHT operations.The Well Testing Sapphire Recorder (WTSR)Sapphire gauge is rated to 200°C [393°F] and20,000 psi and has been run in memorymode with a specially fitted and modifiedMDT Modular Formation Dynamics Testertool.4 Its resolution is similar to that of the con-ventional strain gauge (0.03 psi), but itsdynamic response-speed and stability aremuch improved. Real-time readout is avail-able for well testing applications, but not forwireline pressure readings.
The HPHT environment has always been achallenge for thermal neutron porosity log-ging measurements. Temperature and pres-sure corrections are extremely large and ofopposite sense—high temperature makes thethermal neutron tools read low, and highpressure makes them read high. Increasedtemperature raises average neutron energysuch that its cross section is diminished,leading to lower neutron absorption in theformation, which mimics lower porosity inthe tool response. Increasing pressure causesthe opposite effect on neutron responsebecause of the compressibility effect on thehydrogen indices of the fluids.
The environmental corrections required forthese logging measurements are the mostsignificant source of uncertainty and inaccu-racy in HPHT porosity logging. In a high-porosity formation at 350°F, the temperaturecorrection to the thermal neutron porosityreading is nearly a factor of two. The pressurecorrection is also sensitive to the type andcompressibility of the mud system. Pressurecorrections can be more than a factor of twoat 25,000 psi [172 MPa] in oil-base mud.
Problems encountered when measuringneutron porosity in HPHT environments canbe avoided by using an epithermal neutrontool such as the APT sonde. Epithermal neu-trons are far less sensitive to temperatureeffects. The net pressure-temperature chart-book corrections to epithermal neutronporosity measurements are significantlysmaller—a factor of 6 at high porosity—thanthose for conventional thermal neutronmeasurements. The APT sonde, with itsbackshielded neutron detectors focusedtowards the formation, is also much lesssensitive to variations in the mud system. Inaddition, it provides an openhole formationneutron absorption cross section ∑ measure-ment, which helps identify shale beds andsaline water-saturated zones in HPHT wells.
This measurement is useful to correlate withgamma ray and resistivity measurements.
Elements of SuccessExperience shows that advance planning andpreparation are vital to the successful comple-tion of wireline and testing operations.
Planning—Wireline and testing operationshave been carried out in extremely hostileenvironments, where high downhole temper-atures, frequently in combination with highpressure and the presence of hydrogen sulfide[H2S], demanded the use of tools and loggingequipment specifically designed for suchenvironments. One location that has success-fully met these challenges for more than 15 years is the Schlumberger base Songkhla,in southern Thailand. The hostile high-temper-ature environment encountered in wells atthis location requires particular care andattention to detail in each job.
As with HPHT logging jobs performed inother parts of the world, early consultationwith the operator is essential. All aspects of
the job must be discussed, includingrequirements, solutions and the capabilitiesand limitations of the logging tools.Excellent wellsite communication is essen-tial. Each phase of the operation is exam-ined, including hole conditions, mudparameters and the proposed logging sched-ule. Logging engineers review strategies andoptions that may be implemented if the log-ging program cannot continue as planneddue to operational circumstances.
Prejob planning and careful consultationalso save valuable time. First, it is essentialthat the planned logging program be final-ized well in advance of the actual operation(above). Three weeks or more are needed toensure sufficient preparation for the logging
Well sketch Proposed logging program
103/4-in. hole, 97/8-in. casing
1. Sondex–CBT–VDL–GR–CCL
81/2-in. openhole
2. HAIT–HDSI–HNGS–LEHV
3. HLDS–HAPS–HNGS–LEHV
4. HOBDT–HGR–AMS
5. MDT–HGR–LEHV
DSI tool to 133/8-in. casing point
Bowspring to reduce rotation
Sapphire gauge, pressures only
7-in. cased hole
6. CBT–VDL–GR–CCL
7. Gyro
8. VSP
9. Sondex caliper
Combine with CBT string
97/8-in. and 103/4-in. casing
55/8-in. openhole
10. HAIT–HDSI–HNGS–LEHV
11. HLDS–HAPS–HNGS–LEHV
12. HOBDT–HGR–AMS
13. SRFT–HGR–LEHV
5-in. cased hole
14. CBT–VDL–GR–CCL
15. Gyro
16. Sondex caliper
Combine with CBT string
97/8-in. and 103/4-in. casing
Special issues
225˚F
Boreholetemperature
360˚F
380˚F
107˚C
182˚C
193˚C
■Prejob planning. Detailed plans for logging each phase of a drilling program allow theunit operator and client to get vital information for formation evaluation, while minimizingthe risk of tool failure due to environmental exposure. Each logging tool provides criticalinformation about the well and formation: induction measurements (HAIT) are used forfluid saturation; shear and compressional sonic velocities (HDSI) are used for formationporosity and determining rock properties; epithermal neutron (HAPS) and density (HLDS)are used for porosity evaluation; gamma ray (GR) helps correlate beds; and spectralgamma ray (HNGS) is used for shale corrections. Dipmeter (HOBDT) helps identify fracturesand formation bedding properties, and formation pressures and fluid samples are takenwith a formation tester (SRFT) and (MDT). Other tools are used for borehole navigation(Gyro), and fluid properties (AMS). A CCL identifies casing collars for depth correlation andcement integrity is evaluated with a sonic Variable Density log (VDL). Electrical releaselogging heads (LEHV) permit higher tension on logging cables with heavier tool strings.
3. The weak point is a mechanical release at theconnection between the logging tool and wirelinecable. It is designed to prevent overtension frombreaking cable.
4. Vella M, Veneruso T, LeFoll P, McEvoy T and Reiss A:“The Nuts and Bolts of Well Testing,” Oilfield Review4, no. 2 (April 1992): 14-27.
54 Oilfield Review
To meet the increasing demands of HPHT logging,
the new Xtreme tool string is being field tested in
the Gulf of Mexico and the Far East. Developed
using the MAXIS Multitask Acquisition and
Imaging System logging technology, the Xtreme
system is capable of logging in temperatures
to 500°F [260°C] and pressures to 25,000 psi
[172 MPa], providing best-in-class, quad-combo
service to the global HPHT and ultra-HPHT market
(right). The Xtreme platform performs array induc-
tion, digital sonic and some of the latest nuclear
measurements in HPHT wells.
The Hostile Accelerator Porosity Sonde (HAPS)
is an epithermal neutron logging tool that
provides a measurement of the formation hydro-
gen index and ∑, the formation neutron absorption
cross section. These measurements can be used
together with other logging devices to provide
quantitative formation evaluation.
The Hostile Natural Gamma Ray Spectrometry
Sonde (HNGS) measures potassium, thorium and
uranium concentrations and provides borehole
corrections for potassium-based and barite-based
mud systems. The high-efficiency bismuth ger-
manate (BGO) gamma ray detectors in this tool
are internally flasked and can be precooled with
CO2 prior to running in the hole, giving extended
holding time. The spectral matching brings
improved accuracy to the high-precision elemen-
tal outputs. The HNGS is commercial and has
been logging HPHT wells worldwide.
The Hostile Litho-Density Sonde (HLDS) has
new high-speed electronics that are better able to
handle the large count rates experienced in high-
porosity formations.
The HPHT Induction Tool (HIT) features the
latest technology induction measurements with
built-in standoff, a 37⁄8-in. flask housing, robust
electronics, five depths of investigation:
10-in., 20-in., 30-in., 60-in. and 90-in. (at 1-ft,
2-ft and 4-ft vertical resolution), with logging
speeds up to 3600 ft/hr [1100 m/hr]. Spontaneous
potential, mud resistivity and Rt /Rxo computations
are also included.
The Hostile Sonic Logging Tool (HSLT) is a
monopole sonic tool with borehole compensation
at 3-ft and 5-ft spacings. Normal cement eval-
uation data acquisition with CBT Cement Bond
Tool log and Variable Density logging are avail-
able with this tool.
The Xtreme tool string also features improved
thermal management based on state-of-the-art,
low-power electronics, a novel flask stopper
design, hostile-rated materials and an increased
thermal mass to slow down internal temperature
rise. Most of the tools in this new tool string have
shock and vibration specifications conforming to
those of the PLATFORM EXPRESS system, ensuring
Ultra-HPHT Logging
Tension/compression head
119 ft(36.1m)
Hostile Telemetry Gamma RayCartridge (HTGC) and accelerometer
Hostile Natural Gamma Ray Spectrometry Sonde (HNGS)
Hostile Accelerator Porosity Sonde (HAPS)
Hostile Litho-Density Sonde (HLDS)
Knuckle joint
Hostile Sonic Logging Tool (HSLT)
HPHT Induction Tool (HIT)
■Xtreme tool string. A new fully compatible HPHT (25,000 psi, 500°F) MAXIS toolstring offers the latest quad-combo logging service technology for advanced forma-tion evaluation. New lower power electronics, improved thermal isolation designand materials extend the holding times of the state-of-the-art logging tools forincreased reliability in HPHT wells.
Summer 1998 55
reduced risk of tool failure. The new 25,000 psi
dewars are rated for H2S gas environments. The
500°F-holding times are exceptionally long for
logging tools of this complexity (above).Temperature sensors in each sonde and car-
tridge provide a continuous monitor of internal
temperature build-up during the job. The Hostile
Telemetry Gamma Ray Cartridge (HTGC) is a
flasked version of the SLIMACCESS telemetry
cartridge, which features an accelerometer for
real-time speed correction and a gamma ray
detector. The compatibility of the telemetry sys-
tem with existing high-technology logging tools
allows a variety of tool string combinations
depending on logging requirements. Other HPHT
equipment, rated to 500°F and 25,000 psi, is
available to run with the Xtreme system including
knuckle joints, a slick in-line eccentralizer (ILE-E)
for hole sizes from 8 to 10 in., and slip-on bow
spring eccentralizer (EME-KB), for hole sizes from
10 to 20 in., and a logging head (LEH-HT), which
contains an electrical controlled weak point and
a tension in head measurement.
The benefits of the Xtreme tool string are ele-
vated temperature and pressure ratings, extended
holding times, ability to record a downlog, com-
patibility with the TLC Tough Logging Conditions
system and increased reliability. The new Xtreme
tool string is expected to be deployed in the field
at the end of 1998.
operation, including a thorough examinationof components, upgrading to temperature-qualified sensors, heat qualification, flaskingelectronic components, operational checksand tool master calibrations.
Next, clear contingency plans must beagreed to in advance to minimize the timethat tools are exposed to high temperatures.This is especially important for scenarios inwhich the tool string gets stuck, or an individ-ual tool has a functional failure without affect-ing the other tools. In traditional logging,when tool failure occurs, the tool string ispulled out of the hole and the defective tool isreplaced. In HPHT wells, temperature expo-sure in the borehole is extended by trippingoperations. Pulling out of the hole can takemore than two hours. During this time, thetool is still exposed to borehole temperaturesand the electronics in the flasks cool onlyslightly coming out of the hole. It is, therefore,preferable to continue logging using function-ing tools while in the borehole, with plans toreplace the failed tool in another run, if possi-ble, or to use an equivalent measurement inplace of the missing one.
For example, an operator may consider thegamma ray log as an essential measurementfor depth correlation. In this case, if thegamma ray tool fails, depending on the for-mation character, another measurementsuch as ∑, density or neutron logs could becompared with resistivity or sonic measure-ments on other runs for correlation. Similarscenarios can be envisioned for other com-binations of tools strings and failure modes.Thus, the prejob meeting provides an oppor-tunity to determine strategies for solving
Tool
HTGC
HAPS
HLDS
HSLT
HIT
12
4
5
6
12
Hours
Holding times at 500˚F
■Xtreme holding times. The length of time that eachtool can operate in a high-temperature well dependson the internal power dissipated by the tool electron-ics and the degree of thermal isolation from the hotexternal environment provided by the dewar flask.
problems such as tool failures and tool back-ups, as well as unexpected hole problems.The detrimental effects of temperature canbe seen when the electronics of a new toolare compared with previously used circuitboards (above).
Engineering assistance—The support forSchlumberger HPHT tools comes from anetwork of major research and product cen-ters located in Japan, the USA and France.Upgrades to tools and subsequent HPHTqualifications performed at the product cen-ters and on-site service centers enableSchlumberger to provide the technology andexpertise that clients need.
In certain locations, extreme well condi-tions require the use of specially designedtools. In Aberdeen, Scotland, special supportfor the Hostile Oil-Base Dipmeter Tool(HOBDT) and SRFT Slimhole RepeatFormation Tester tool was required, since theconditions expected for some HPHT jobswere beyond the scope of existing fieldequipment. The HOBDT tool electronics car-tridge was installed in a flask, electrode padswere upgraded to new, higher temperature-rated materials at the field location, and thewells were successfully logged.
Other recent engineering efforts have beenfocused on developing more efficient andcost-effective hostile logging tools, includingthe Xtreme system, a new 25,000 psi, 500°F-rated quad-combo array induction and inte-grated porosity and lithology logging suite (see“Ultra-HPHT Logging,” previous page). Thisnew tool string is being used to log ultra-HPHTwells in the Far East and Gulf of Mexico.
■Temperature effects on logging tool circuits. The damaging effects of high temperatureon electronics can be seen by comparing a scorched circuit board (top) from a tool thatwas exposed to 350°F bottomhole temperatures with a new board (bottom).
Typically, for openhole HPHT logging,power is applied to the logging string at sur-face to confirm tool operation. The tool isthen powered down while running in, andnot powered up again until it is near thecasing shoe to minimize heat generationfrom the internal electronics within theflasks. Any logs required in the casing areperformed while pulling out of the hole afteracquisition of the main openhole log.Calipers and pad-contact tools are notopened until logging upwards from totaldepth (TD) for the main log acquisition.
Immediately after logging is completed and the data are delivered to the operator,the tools are returned to the Schlumbergerfacilities for intensive postjob maintenanceprocedures. Many sensitive components,although in working order, are routinelyreplaced to ensure optimum performance onsubsequent logging jobs, since temperaturecycling often results in failure. High temper-atures are particularly wearing on O-ringsand seals, and all are replaced before thetools are reassembled and tested.
Logging in the North Sea Among the HPHT logging regions in theNorth Sea today, the Elgin and Franklin fieldsare the most active (next page). The largestHPHT development on the UK ContinentalShelf, the Elgin and Franklin fields are settingnew benchmarks for future projects in the oiland gas industry throughout the world.6
Reserves are estimated to be approximately380 million bbl [60 million m3] of conden-sate and 1800 Bscf [50 Bscm] of gas.
56 Oilfield Review
Job preparation—Rigorous job preparationis critical to success in HPHT logging. Toensure tool reliability, every tool is qualifiedfor logging at the expected temperature ofthe well. First, the electronics for each toolare heat checked to their maximum-ratedtemperature of 350°F. Heat cycling a tool isa long process. The electronics cartridges areplaced in instrument ovens and temperaturesare increased in 60°F [33°C] increments.Tools are verified to work continuously at therated temperatures for at least a half hour.
The tools are flasked before they are usedin the logging job, providing a significantincrease in thermal protection from HPHTenvironments. Tool performance at theexpected well temperature is established bycalculating the temperature rise inside thedewar flask.
Any failures encountered during heat qual-ification are repaired and the tool is testedagain until reliable operation at high tem-perature is attained. This may be a lengthyprocess. However, to limit thermal cycling ofcomponents, heat qualification is performedonly when replacement parts have beeninstalled or the time between jobs exceedsthe normal quality-check period. When alltools are qualified to the expected maximumwell temperature, they are given a completetool string system check before they are dis-patched to the wellsite (below).
As the logging operation draws near, asafety meeting is held with all personnelinvolved. Safety is paramount, and all partic-ipants must have a clear understanding oftasks to be performed. Finally, job prepara-tion continues at the wellsite, where all toolsare subjected to a final operational checkbefore entering the borehole.
Efficiency—Time management at the well-site is crucial to successful HPHT operationsand data acquisition. Run-in speed and log-ging speed are optimized prior to the job,allowing for repeat sections, down-loggingand contingency arrangements for problemholes.5 At the wellsite, in the hours followingthe last circulation, the well temperaturerises quickly. To reduce the risk of tool fail-ure, every effort is made to ensure that thelogging operation is performed efficiently—minimizing the time that the tools areexposed to high well temperatures.
Downward logs are recorded faster thannormal and are vital in case a tool problemoccurs close to the bottom of the well wheretemperatures are highest. The main log isrecorded in an expeditious manner, butwithout compromising data quality. Theresults acquired on the uplog are comparedwith those acquired on the downlog toensure the integrity of the information gath-ered. Before subsequent runs are made, awiper trip may be required to reduce theborehole temperature.
■Extensive testing for all HPHT loggingtools before each job. First each tool is temperature-qualified by heating in ovensto the expected maximum downhole temperature in the well. Then the completetool string is given an operational check in the shop before being shipped to the offshore well.
Summer 1998 57
Mungo
Monan
Marnock
Skua
Shearwater
Machar
Ekofisk
Gyda
Ula
CodErskine
Elgin
UK sector
Norwegian sector
Franklin
London
Bacton
Forties
Aberdeen
■Elgin and Franklin fields. ELF Exploration UK PLC is currently developingthe Elgin and Franklin fields in the Central Graben about 150 miles [240 km] east of Aberdeen. These fields lie within 3.4 miles [5.5 km] ofeach other and their proximity allows development in tandem; each field will have its own wellhead platform with production from both fieldsprocessed through one central facility.
5. Down-logging is the process of acquiring data as thelogging tool descends the borehole. In conventionalwells this is not done, because most logging toolswith pad devices are designed to work effectively(with good pad contact) when coming out of theborehole (logging upwards). Cable tension and subse-quent depth control are better when pulling the toolout of the hole. In HPHT wells, the risk of failureincreases with time in the borehole, so down-loggingis performed to acquire as much data as early andquickly as possible.
6. Gibson MT, Bergerot JL, Broucke A, Humphreys Aand Cotterill M: “The Development Philosophy ofElgin/Franklin HPHT Wells,” paper presented at the1995 Offshore Drilling Technology Conference,Aberdeen, Scotland, November 22-23, 1995.Lasocki J, Guemene J-M, Hedayati A, Legorjus C andPage WM: “The Elgin and Franklin Fields: UK Blocks22/30c, 22/30b and 29/5b,” Abstracts, PetroleumGeology of NW Europe (1997): 179.Also see “Elgin/Franklin Project,” produced by ThePublic Relations & Communications Department, ElfExploration UK PLC, Aberdeen, Scotland.
58 Oilfield Review
The Elgin and Franklin fields lie in a struc-turally complex area in the southern part of the North Sea Central Graben basin, more than 3 miles [5 km] below the seabed(below). The formations in the Central Grabenbasin resemble a fractured bowl. Normalfaulting during Cretaceous sedimentationdivided the Jurassic reservoir into numerousisolated fault blocks. The deeper fault blockshave higher pressures and temperatures.
Good reservoir quality is due to significantsecondary porosity preserved by extreme over-pressure. These deep Elgin and Franklin fieldscontain high-pressure gas condensate. The
combination of extreme reservoir conditionswith an initial pressure of approximately16,000 psi [110 MPa] and temperatures of 375°F [190°C] poses a considerabledevelopment challenge.
Schlumberger logged the discovery andappraisal wells in these fields, and is nowinvolved in a four-year program of loggingthe ten HPHT development wells for bothfields. The program consists of openholelogging in the potential reservoirs of eachwell—the Franklin sand and underlyingPentland sand. Cased-hole cement loggingwill be performed in the 133⁄8-in. and 97⁄8-in.casings and the 7-in. liner. Caliper logs willbe run in the 97⁄8-in. casing.
Elgin field results—The HPHT loggingresults obtained in one of the Elgin devel-opment wells at 380°F [193°C] show thequality of logging repeatability in spite of the 15 to 30% increased internal tooltemperatures occurring between passes (next page, top).7 During two hours of log-ging, all electronic components and circuitsin the flasked cartridges remained well belowthe 350°F maximum manufacturing ratings.Down-logging was acquired wherever possi-ble to reduce thermal exposure time.However, some tools, such as pad-type tools,may exhibit poor data quality—normallyclosed on downhole logging—because of inconsistent pad-to-borehole contact. Forthese tools, a separate uphole log run isnecessary, with the downhole log used as aqualitative repeat log.
The MDT tool has been successfully usedin the Elgin field to acquire formation pres-sures in several wells with hydrostatic pres-sures greater than 17,500 psi [121 MPa] andbottomhole temperatures greater than 380°F.The WTSR Sapphire gauge was used inmemory mode with good results. The20,000-psi strain gauge provides a real-timeevaluation and compares well with the moreaccurate WTSR memory data. In a formationwith unknown permeability, pressure draw-down measurements are usually limited toprevent excessive differential pressuresacross the MDT sealing packer. Also theAberdeen field location-modified HOBDTtool, rated to work at 410°F [210°C], wasused successfully in some of the Elgin wells.
Ultradeep, High-Pressure LoggingThe Gulf of Mexico is another extremelyactive area for HPHT logging. Surface seis-mic data acquired and processed by Geco-Prakla enabled EEX Corporation to identifyprospective geologic structures that aremuch deeper and higher pressure than thosepreviously drilled (next page, bottom). In adeepwater well drilled by Sedco Forex, EEXused the new Xtreme tool string to evaluateits Llano prospect in the Garden Banks,Block 386. This well, in 2663 ft [812 m] ofwater, reached the Lower Pliocene andMiocene reservoirs at well depths neverbefore achieved in the Gulf of Mexico:27,864 ft [8493 m] measured depth and26,969 ft [8220 m] true vertical depth. A vertical seismic profile (VSP) run at 25,000 ft[7600 m] in the cased section of the wellidentified prospective pay zones deeper than30,000 ft [9100 m]. Pore pressures at thesedepths exceed 20,000 psi, above the pressurelimit of conventional HPHT logging tools.
NESW
Seabed
Depth,m
Tertiary
Cretaceous
Upper Jurassic
Franklin sand
Middle Jurassic
Triassic
Hydrocarbons(gas and condensate)
Main reservoir(Franklin sand, Upper Jurassic)
Fault 0 km 2
0
2000
4000
6000
8000
Lithology
Sandstone
Sandstone
Sandstone
Claystone
Claystone
Limestone
Sandstone(Franklin sand)
Coal
To BPForties
Pipelineto Bacton
Franklin field
Elgin field
■A section through theElgin and Franklin fields.The Elgin field is a complexfaulted anticline structureand the Franklin field is atilted fault block. The prin-cipal reservoir is composedof a highly bioturbated,fine-grained, shallowmarine sandstone of theUpper Jurassic Fulmarformation, locally namedthe Franklin sand. Hydro-carbons have also beenfound lower in the Pentlandformation of the MiddleJurassic age.
Summer 1998 59
Planning for the logging operation beganmonths in advance with the primary objec-tives being reduced operational risks andmaximum logging efficiency. Personnel fromEEX worked closely with Schlumberger log-ging engineers to consider all possible con-tingencies. Operational challenges includedissues related to logging tool conveyance,pressure limitations of downhole equip-ment, cable type and length, and datadelivery requirements.
The high hydrostatic pressure in thewellbore could be met with the new Xtremelogging tool, which is rated to 25,000 psi.However, other tools used to log this wellwere sent to the Sugar Land, Texas, USAproduct center for pressure testing and qual-
Density porosity
p.u. –15 4545
Neutron porosity
p.u. –15
another pull
pull
0
Gamma ray
API 15040
∆tc ∆ts
140 40µs/ft µs/ft
240
0.2
Resistivity 10 in.
20
0.2
Resistivity 20 in.
20
0.2
Resistivity 30 in.
20
0.2
Resistivity 60 in.
20
0.2Resistivity 90 in.
20ohm-m
■Repeat logging section of the Elgin G4 well. Results of multiple logging passes in a well at 380°F show good qual-ity repeats in spite of the increasing internal temperature of logging electronics cartridges. Some zones in the neu-tron and density porosity logs (tracks 2 and 3) experienced high overpull on the second pass, causing a depth shiftin the data. The gamma ray (track 1), induction (track 4) and sonic measurements (tracks 5 and 6) obtained log-ging down agree well with the logging up measurements.
7. Fields T: “Experiences and Developments in HPHTWireline Logging,” paper presented at the 2ndInternational Conference on Progress in HPHT Fields,Aberdeen, Scotland, May 20-21, 1998.
Houston
Cameron New Orleans
Fourchon
Mississippi Canyon
Green CanyonGarden Banks
0 20miles
40Industry deepwater projects
Venice
'Llano'discovery
(block 386)
■EEX well location in deepwater central Gulf of Mexico.
60 Oilfield Review
ification. These included the MDT tool, theCSI Combinable Seismic Imager tool, CSTChronological Sample Taker tool, FPIT FreePoint Indicator Tool and the downhole TLCequipment (above). To prequalify for this job,every tool was successfully pressure tested to22,000 psi [152 MPa].
The extraordinary depth created a specialchallenge for tool conveyance since standardlogging cables could not be used. In extra-deep wells, the weight and drag encounteredwith long cables are problems. In this partic-ular well, an extra-long, high-strength cablewas required to overcome the combinedweight of the cable, tool string and the asso-ciated frictional cable drag encountered. Anew 36,000-ft [1100-m] extra high-strengthcable (7V46NTXXS) was designed and builtby the Vector Product Center, Sugar Land,Texas, to meet these demands, and the off-shore logging unit and logging drum weremodified to hold the new cable.
Safety concerns associated with expectedhigh cable tensions were addressed with acustom-designed wireline dual-drum cap-stan developed at the Schlumberger BelleChasse, Louisiana, USA, Center (right). Thecapstan was installed between the offshorelogging unit and the rig floor to reduce the cable tension necessary to spool thecable onto the logging unit. This equipmentsignificantly reduced the risk associated withwireline-conveyed logging operations indeeper wells.
The first logging descent used the Xtremetool string on wireline to log all but the bot-tom 300 ft [90 m]. The bottom section wassuccessfully logged using the TLC system tomaneuver the Xtreme tool string past obstruc-tions to TD. Following the Xtreme logging,EEX utilized the TLC system to complete theopenhole logging program. Pressure measure-ments were obtained with the MDT tool, andwith low-shock sampling techniques twelveformation fluid samples were successfullyobtained in the unconsolidated sand forma-tions. To maximize efficiency and reduce riskto the openhole section, the DSI Dipole ShearSonic Imager tool and additional VSP wereused after the well was cased and cementedby Dowell. Prior to DSI logging and VSP, cas-ing and cement were evaluated using the USIUltraSonic Imager and CBT logs.
The logging results indicate the presence ofseveral hydrocarbon-bearing sands in boththe Lower Pliocene and Miocene sections.Pressure and fluid samples are being usedwith logging measurements to evaluate thepotential of early production capabilitythrough tie-back options to other EEX facili-ties nearby, or the need and economics for astand-alone production facility.
Well InterventionElsewhere in the Gulf of Mexico, a majoroperator is developing the first extensiveeastern Gulf Coast postsalt deposit in theNorphlet formation. This large eoliandeposit lies in a major regional unconfor-mity and is the major deep—over 20,000 ft[6100 m]—gas play in the waters aroundthe mouth of Mobile Bay. The Smackoverformation is thought to be the hydrocarbonsource. The gas is trapped in the Norphleton salt-cored anticlines that occur on thedown-thrown side of east-west trendinglistric faults.8 The wells are close to land andare very productive, with high flow rates of 50 to 100 MMscf/D [1.4 to 2.9 MMscm/d]and life expectancies of 20 to 25 years. Inthese formations, wells are 400°F to 450°F[204°C to 232°C] with bottomhole pres-sures up to 19,000 psi [131 MPa]. Thesewells, serviced, drilled and completed froma platform, have H2S concentrations from 1 to 3.5% as well as significant amounts ofcarbon dioxide [CO2].
One well was producing water at a highrate for more than five years. With an influxof water production, there was a significantsalt buildup in the tubing and at the surface.The surface facilities could not handle thelarge volume of water. Salt precipitates andcorrosion around valves and chokes pre-sented a safety risk, and the well subse-quently had to be shut in.
8. Goldthwaite D: An Introduction to Central Gulf CoastGeology. New Orleans, Louisiana, USA: NewOrleans Geological Society, 1991.
■EEX team using the InterACT remotecommunications software system. Membersof the EEX Llano Prospect team—RandyHaworth, Geologist and Todd Hubble,Reservoir Engineer—were able to view thelogging operation remotely and in real timeon a PC in their Houston office. After severalsticky attempts to get past an obstructionnear the bottom of the well, the on-siteteam decided to log out of the well. Thequick decision helped prevent the tool frombecoming stuck and may have saved acostly fishing job. The lower section waslater re-logged with the TLC system.
Sheave wheel
Offshorelogging unit
Wireline dual-drum capstan
■Dual-drum capstan. The new wirelineconveyance capstan is installed betweenthe logging unit and the rig floor to reducethe amount of cable tension necessary tospool the extra-long cable onto the loggingunit in ultradeep wells.
Summer 1998 61
To get the well back on-line, the watersource had to be identified and cut off. Inmost wells, the diagnostics would include aneutron log, and WFL Water Flow Log or PLTProduction Logging Tool measurements.Water could be stopped with a PosiSet plugand cement or one of the Dowell suite ofspecialty fluids applied through coiled tub-ing. However, in a 410°F, 20,000-ft deepwell with significant H2S and CO2 concen-trations, normal operating practices do notapply. The New Orleans, Louisiana, USAProduction Enhancement Group (PEG)assisted by analyzing alternative solutions.With wireline logs and production gas/waterratios (GWR) and the GWR rate of increase,the water source could be characterized—channeling, coning or a rise in the watertable—and isolated.
After the water source was found lower inthe reservoir, a gamma ray and casing col-lar locator were used to determine current total depth and establish a platform todump a special cement blended by Dowell,sealing up to half of the perforated interval (see “High-Pressure, High-TemperatureWell Construction,” page 54). A 2% potas-sium chloride [KCl] solution was pumpedto push the cement slurry into the open per-forations. The Dowell cement laboratory inNew Orleans prepared the special cementslurry. Special care was taken to preventparticles from falling out of the cement mix-ture and plugging the bailer. The well wascemented with ten runs of 40-ft [12-m]bailer, followed by pumping of KCl brine.Water production decreased proportionallyafter the well intervention, and all indica-tions are that the cement plugs were suc-cessful. HPHT logging and interventioncontinue to provide solutions to enhanceproduction of the remaining reserves.
New High-Temperature ExplosiveIn every well, perforating is a critical com-ponent of the completion process. But it can be a particular challenge in HPHTwells. The deep, high-pressure wells containhigh-strength formation rock that reducesperforating charge penetration, making themdifficult to complete.
The productivity of a given reservoirdepends primarily on the near-wellborepressure drop. This pressure drop is governedby wellbore drilling damage. Perforatingparameters such as perforation length, diam-eter, phasing, shot density and perforationdamage are factors that determine how wellthe wellbore drilling damaged zone isbypassed. Shaped charges have proved themost effective means for producing the net-work of pathways needed to economicallydrain hydrocarbons from a reservoir.
Millions of shaped charges are shot eachyear in wells with perforating guns in down-hole conditions that range from benign tohostile—with temperatures approaching500°F or more. Downhole temperatureslimit the choice of explosives that can beused to manufacture shaped charges.
The most commonly used oilwell perforat-ing explosive is RDX, which is limited totemperatures of 340°F [171°C] for a 1-hrexposure in a carrier gun (left). HMX is usedfor temperatures up to 400°F. For more hos-tile wells, shaped charges made with eitherHNS or PYX explosives have been used.HNS has a 500°F, 1-hr temperature rating,and PYX has a slightly higher temperaturerating. However, both HNS and PYX high-temperature explosives lack the performanceof lower temperature explosives (RDX orHMX), although HNS typically demonstratesslightly more penetration than does PYX. Thereduction in performance is a consequenceof both the molecular chemistry of theexplosive and practical manufacturing diffi-culties in pressing and handling powderedHNS and PYX.
A new high-temperature explosive, calledHTX—for High-Temperature eXplosive—hasbeen developed for the perforating industry.This formulation overcomes performance dis-advantages that exist with HNS or PYX. Today,HTX is replacing HNS and HMX as the mostcommonly used high-temperature explosive.There are four commercial HTX charges avail-able and more are on the way. HTX chargesare rated at 500°F for 1 hr and have recentlybeen tested to 440°F for 200-hr continuousoperation—long enough for most tubing-conveyed perforating (TCP) operations.
1-hr rating 100-hrrating
*
200
0.8
0.9
Relative performance
1.0
1.1
300
Tem
pera
ture
, ˚F 400
500
Tem
pera
ture
, ˚C
260
240
220
200
180
160
140
120
100
80PETN RDX HMX PYX HTXHNS
* A system test is recommended above 435˚F.
■Comparison of oilwell perforating explosive ratings. The ability of oilwell perforatingexplosives to withstand high-temperature exposure without sacrificing performance isimproving. For example, HTX offers about a 5 to 10% increase in relative penetrationover HNS and even more of an increase over PYX explosive. Test systems demonstrateconsistently high HTX performance even after exposure to high temperatures (440°F)for long periods of time (200 hr).
62 Oilfield Review
What is HTX?—The HTX explosivecombines two common high-temperatureexplosives, HNS and TATB, into an improvedformulation that has better performance thaneach component has individually (above).TATB is an impact-insensitive, high-tempera-ture explosive with a high-energy output at itsoptimum pressed density. The military useTATB in missiles because it is extremely safe tohandle and very difficult to detonate. HNS isan impact-sensitive, high-temperature explo-sive that has a lower energy output mainly
because it has a lower pressed density. HNS iseasier to detonate than TATB. Both TATB andHNS have similar temperature ratings. Manytests with guns loaded with HTX- and HNS-shaped charges have shown no degradation inperformance at 500°F for one hour, and up to460°F for 100 hours. This meets all high-tem-perature explosive requirements of good time-temperature ratings and good performance.
Improvements in performance have beenseen not only in terms of statistics, but also inthe quality and consistency of manufacturedcharges (below). X-ray photographs show
straighter jets indicating greater shapedcharge symmetry—a result of pressing a uni-form explosive pellet. The latest Enerjetcharge, the 21⁄8-in. Power Enerjet, HTX, shoots24.7 in. into an API target compared to 21.6 in. with the HNS at a lower shot density.
More than 40 wells have been perforatedwith HTX charges in many countries includ-ing the Gulf of Mexico, North Sea,Indonesia, Malaysia, Thailand, Argentinaand Australia.
HTX HNS TATB■Scanning electron microscope (SEM) photographs of HPHT explosive powders. HTX (left) is a processed explosive that combines twohigh-temperature explosives—HNS and TATB—into a fine-grained plastic-bonded formulation that is suitable for manufacturing shapedcharges. The production grades of HNS (center) and TATB (right) are first processed to reduce their particle size by mechanical grinding.
Water
Test briquette
Steel culvert
Casing
Gun
28-day concrete
■HTX versus HNS penetration performance. Test shots in casing and concrete targets (left) at ambient pressure and temperature of therecently released commercial HTX gun systems show that the overall performance of HTX explosives is consistently better (top right)than the HNS explosive systems it replaces. The material properties of HTX explosives lead to improved manufacturing and better qual-ity shaped charges. As a result, the explosives are less susceptible to residual mechanical stresses from manufacturing. This leads tohigher quality—straighter—and more consistent perforating jets (bottom right).
Diameter,in.
Gun system
2.1252.8753.3754.720
Type
EnerjetHSDHSDHSD
* Shot at 6 shots per foot (spf). HNS charge was shot only at 4spf.
Explosiveweight, g
15192221
HTX
API-43(section 1)
penetration, in.
24.7*21.325.322.2
HNS
21.6*20.021.321.9
Jet from 22-g HNS shaped charge
Jet from 22-g HTX shaped charge
Summer 1998 63
HPHT guns—The HPHT perforating chal-lenge is not restricted to explosives, but also to guns and other hardware. Guns mustbe built to survive powerful detonations butthey must also be able to withstand high pres-sures, and do this at elevated temperatures.
Components used in guns must also becompatible with explosives. For example,plastic components give off gases that reactwith explosives. Under normal conditionsthis is not a problem, but as temperaturesincrease and the exposure time to these tem-peratures increases, sufficient gas can begiven off to cause charges to misfire.
Schlumberger routinely changes plasticcomponents to a more expensive plastic thatdoes not give off gases for HPHT perforat-ing—essentially whenever HTX charges areused. Similarly, greases and lubricants reactadversely with explosives. This creates a big-ger problem as every component in the gunshas to be degreased. Special lubricants haveto be used for O-ring seals and hardware hasto be protected from corrosion. Job prepara-tion is therefore critical.
The Program to Evaluate Gun Systems wasintroduced by major oil companies—Agip,Arco, BP, Chevron, Conoco, Elf Aquitaine,Exxon, Mobil, Pogo, Texaco and Unocal. Theprogram establishes procedures for verifyingexplosives, hardware and accessories such as casing collar locators and adapters.Schlumberger has special guns verified to thisstandard. The verification process tests equip-ment to 1.05 times the working pressurerating and 18°F [10°C] above its temperaturerating. Systems verified are all for wirelineperforating. However, similar testing is carriedout on equipment for TCP operations. ForHPHT and other critical wells, componentsare carefully matched to minimize machinedtolerances. Thorough testing is undertaken toensure maximum reliability.
Beating the ClockIn designing HPHT perforating, job timing iscrucial. Shaped charges must be built andarrive on location on time for optimum per-formance, and the guns need to be loaded ina timely fashion. Shaped charges are alsosensitive to humid conditions as the linersabsorb moisture, and will lose performancewith exposure.
If the guns are conveyed with wireline,then the length of time that equipment is inthe hole before the guns are fired must betaken into account. What if the equipmentgets stuck in the hole? What happens if thereare problems with pressure control equip-ment that forces a delay in the job? The timeelement for these contingencies must be fac-tored into the job design.
If TCP is considered, then the time frame ismany hours longer. A whole series of opera-tions must be done before shooting the guns.Frequently, the driller needs the time to setup monobore completion equipment down-hole, insert packers, change fluids in thewell, rig down the blowout preventer (BOP)stand, rig up the Christmas tree, set up sur-face lines and hook up separators. Then theguns are shot. The time needed to get down-hole and set up downhole test equipmentmeans that the guns can be downhole forseveral days, and sometimes weeks. ForHPHT operations, the whole completionprogram must be built around the exposuretime of the explosives.
At the LimitShaped charges have a shelf-life of five years,including a high safety margin. However, thechemical breakdown in a confined explosiveproduces not only gas, but also heat—thereactions are exothermic. At room tempera-ture, the reaction is so slow that the extraheat dissipates. There is no detonation orexplosion, and the charges will perform tospecifications when fired.
As the temperature rises, more heat is gen-erated by breakdown than can be dissipated.This is the situation for explosives in a gunsystem sitting in a hot well waiting to perfo-rate the well after a long series of downhole
production tests. If held at high temperaturefor an extended period, the shaped chargedevelops hot spots. This leads to more violentevents—ranging from outgassing, to low-order detonation or even autodetonation.
Low-temperature explosives, such asPETN, RDX and HMX are less stable and aremore likely to autodetonate or break downviolently when taken beyond safe operatinglimits. High-temperature explosives likeHNS, TATB, PYX and HTX are relativelyinsensitive to extreme temperature and lesslikely to autodetonate. But they are morelikely to burn.
Shaped charges have a safe operatingrange controlled by temperature and time(above). Many tests on explosives atelevated temperatures verify the tempera-ture-time curves used by the perforatingindustry. Operate below the safe operatinglimits, and explosives will perform normally.Go above the limit, and the performancedegrades rapidly.
Extensive thermal tests have been con-ducted to establish a temperature and timerating for both HTX and HNS charges. Thesetests were made using procedures outlinedin API gun test procedures.9 To determine anexplosive’s thermal rating, test shots aremade in steel targets at both ambient and
600
500
400
300
200
1001 10 100 1000
Time, hr
Time–Temperature Curves for Explosives
Tem
pera
ture
, ˚F
316
260
204
149
93
37
Tem
pera
ture
, ˚C
RDX
HMX
HNS/HTX
■Temperature-time ratings of shaped-charge explosives. To establish a baseline perfor-mance, shaped charges are shot at ambient temperature. The performance is based ondepth of penetration in a steel target. Then they are shot at elevated temperatures, andthe ratings specify that there is no degradation in performance at the elevated tempera-ture. Exceeding the ratings by only a few degrees is sufficient to show signs of outgassingand decomposition resulting in loss of performance. At the next level of degradation theexplosive will start to burn. Taking HMX and RDX above 300°F and going well beyond thetime limits may result in autodetonation. Other explosives are not known to autodetonate.
9. American Petroleum Institute Test Procedures, APT-43.Washington, DC, USA: American Petroleum Institute,1991.
64 Oilfield Review
specified elevated temperatures. The testresults show that charges made with HTX andHNS explosive can withstand constant expo-sure to a temperature of 440°F for up to 200hr and still give 100% performance (left).After that time, thermal decomposition of theexplosive begins to affect the performance ofthe charge by reducing its penetration, and ifheld long enough at these temperatures,these explosives burn benignly.
HPHT Slickline PerforatingA new perforating technique called theGunStack system has been developed forHPHT wells in the North Sea, where slicklineand wireline were the only systems availablefor deploying guns (next page, left). Whenlong reservoir intervals—up to a few hundredfeet—are perforated, the weight of the gunsrequired to perforate such intervals exceedsthe limit of a single wireline or slickline trip inthe hole. This requires multiple gun runs.Normally, only the first set of perforations canbe done with underbalanced pressures.10
However, by stacking the guns with succes-sive trips in the borehole, operators are ableto perforate long intervals underbalanced.
The GunStack system was used on five ofthe Texaco Erskine HPHT developmentwells. In these wells, a Mechanical ReleaseAnchor (MRA) or a Monobore AutomaticeXplosive Release anchor (MAXR) was run in the borehole on wireline with a gammaray and casing collar locator for depthcorrelation. The anchor was positioned at the bottom of the formation to beperforated. This provides the platform forstacking the individual gun assemblies, andcan also be used to locate memory gaugesfor recording pressure and temperatures asthe well is flowed.
The individual gun assembly sections,charged with HTX explosives, were run in onwireline or slickline to complete the entireperforated interval. The final gun assemblycontained a receptor for the firing head. Afterthe entire gun assembly was completed, a Trigger Charge-Hydraulic Delay Firing (TCF-HDF) head was run in and latchedinside the top of the gun assembly. Then theslickline was pulled to the surface, and thewell was pressurized to initiate the firinghead system.
The firing head delay allowed time—30 to45 minutes—to adjust well pressures to givethe desired underbalance conditions. Thefiring head then detonated the entire gunassembly—perforating the entire interval inunderbalanced conditions. After the well-head pressures stabilized, the slickline wasused to retrieve the firing head and gunassemblies from the well.
6in.
Pressureconnections Electrical
connections
Ground level
Triggercharge firinghead receptorbooster
Thermalbands
Sodiumbromidesolution
Steel bartargets
7-in. ODpressure vessel
20-in. OD
9ft
■The effect of temperature on perforating perfor-mance. Concreteexplosive test pitslined with 20-in.casing (top) areused for extendedHPHT testing atsimulated welltemperatures andpressures. Electrical,water and air pres-sure systems areused to serviceheaters and pres-sure pumps. Perfor-mance can bemeasured by thedepth of penetrationinto a control target—steel bar targets—the deeper the bet-ter. Temperatureratings are deter-mined by standardAPI procedures thatcompare the perfor-mance of test shotsmade in steel targetsat both room temper-ature and specifiedelevated tempera-tures (bottom).
Steel penetration ratio (hot/cold)
425
430
435
440
445
450
218
221
224
227
230
233
Tem
pera
ture
, ˚F
(fo
r 20
0 hr
)
Tem
pera
ture
, ˚C
(fo
r 20
0 hr
)
0 20 40 60 80 100 120
10. Underbalanced pressures are desired when perforat-ing, because they allow for cleaner holes and betterfluid production. See Cosad C: “Choosing aPerforation Strategy,” Oilfield Review 4, no. 4(October 1992): 54-69.
Summer 1998 65
The MAXR has an explosive release thatretracts the holding slips and allows theMAXR and entire gun assembly to drop intothe rathole. This leaves the perforated intervalclear and reduces the safety risks of extraslickline runs needed in the borehole. Arathole was not available on any of theErskine wells because Texaco did not want torisk crossing formation or pressure bound-aries with deeper drilling.
HPHT Well TestingTraditional HPHT well testing uses heavy(kill-weight) mud or clear metal-basedbrine for the annular fluid. These fluidsfrequently cause severe operational difficul-ties, involving high well costs incurred withrequired tie-back strings, corrosion, andother safety and environmental concerns.11
Experience shows that the use of heavymud may cause lost rig time—averagingseveral days per test—due to excessive gelstrengths or barite sag.
High gel strength muds—required to holdheavy barite particles in suspension—can reduce or prevent annular pressuretransmission required to operate DST tools,and barite sag (drop-out of particles due toinsufficient gel strength) can block off DSTtools and TCP gun operating ports.12 Thepreparation of the mud systems is thereforeespecially critical to the success of DST.
One alternative, favored by some opera-tors, is to change kill-weight mud to heavybrines. Clear, metal-based brines avoid the
problems of barite settlement, plugging test-ing valves and pressure transmissibility. On theother hand, these heavy brines are extremelycorrosive (zinc bromide), and expensive(cesium formate), and pose personnel safetyissues (burns) and environmental hazards(spillage offshore).
Testing with seawater—In the last fewyears, the use of seawater for underbalancedwell testing has improved the operating reli-ability of DST tools and TCP guns, which inturn provides improved safety and financialreturns. A number of operators have movedto this system for both 10,000 psi and15,000 psi [103 MPa] environments.
Seawater has important advantages overkill-weight fluid. First, it is cheap, readilyavailable and disposable in the offshoreenvironment. Because it’s a clear fluid, itallows downhole tools to operate in afriendly environment, avoiding transmissibil-ity and mud-settlement problems (below).Finally, it reduces the need to run a tie-backstring to surface to protect the casing stringwhich is required when testing with a kill-weight fluid. This is a major cost saving andan important factor in being able to reuse thewell as a field development producer.
Seawater also has certain disadvantages.The well must be circulated to seawater, anda substantial inflow test must be conductedprior to running the DST string. Also, there isfaster gas migration and the subsequent riskof a gas kick in the well.
MRA
■The GunStack system. This system allowsguns to be placed in the well one sectionat a time to build up a long string. A rig isnot required. First, a mechanical releaseanchor (MRA) is set below the interval to be perforated. Then individual gun sec-tions are stacked on top of the MRA. Afterperforating, the gun sections and MRA areretrieved one section at a time.
Benefits
● Low-cost annular fluid● Reduced annular hydrostatics● No tie-back liner required● Increased heat dissipation, therefore higher flow rates possible● Enhanced data quality● Less environmental impact● Good pressure response for reliable tool operation
Disadvantages
● Faster gas migration● Unconventional well kill● Multizone testing● More time-consuming (change- out fluids and inflow testing)
■Cost and benefitsof seawater testing.An importantreason for chang-ing to seawater isincreased operat-ing reliability ofDST tools and TCPguns, which in turnprovides improvedsafety and operat-ing efficiency.Safety reviewstudies show thatwell testing withseawater offerslower risk thanwith heavy mud.
11. Any potential tubing leak with kill-weight fluidwould result in a high downhole pressure thatwould rupture the casing string.
12. DST tools are generally operated by annular appliedpressure; pressure applied at surface has to reach thedownhole tools to move operating pistons to eitheropen test valves or circulating valves. The pressureloss through the heavy mud systems can result ininsufficient pressure reaching the tools to allowproper operation. The settlement of solids from themud system during the test can result in partial orcomplete failure of the downhole tools, resulting inpoor data or no data being obtained.
66 Oilfield Review
Nevertheless, results of a documentedhazard-review for seawater testing provedthat if recommended precautions are adheredto, the actual well test using seawater is, infact, safer than using heavy mud.13
Pushing the limits—HPHT well tests in thepast encountered pressures up to 15,000 psiand temperatures up to 400°F. Current DSTtools and TCP guns and accessories havefunctioned well within these workingparameters. However, the pressures andtemperatures encountered testing HPHTwells are increasing.
The move to higher pressures and temper-atures has resulted in special designs andmore rigorous testing to qualify equipmentfor a particular task. The duration of the DSThas also increased: in the past the typicalduration was approximately five days; nowtests of up to 10 to 14 days are being per-formed. The choice of elastomer seals usedin DST and TCP equipment for extendedwell testing at elevated pressures and tem-peratures is critical. Recent qualification testsof the DST equipment have taken place withtemperatures of 410°F to 425°F [210°C to219°C] at pressures of 16,500 psi [114 MPa]for a duration of 13 days.
As with all HPHT tests, the preparation oftesting and perforating equipment is a key ele-ment in the success of the project. Equipmentqualification tests following the plannedsequence of events, full quality inspection ofthe systems and assembly by competent per-sonnel lead to a successful operation resultingin good data quality.
Many HPHT wells have been tested withspecial tools like the Schlumberger PCT-FPressure Control Tester string developedspecifically for HPHT applications (right). Thismud-immune tool string provided the DSTdone for Texaco on the North Sea Erskinefield. It can handle up to 29,000 psi [200 MPa] tubing pressure, and 25,000 psiannulus pressure with a 15,000-psi [103-MPa]differential pressure (between the tubing and casing annulus) at 425°F, and is rated forH2S service. Special versions of these toolscan handle differential pressures of up to17,500 psi at 425°F.
Ultra-HPHT—Wells with temperaturesexceeding 425°F, are considered ultra-HPHT,especially those with bottomhole pressuresgreater than 15,000 psi.
The equipment required for this environmenthas been simplified to include single-shottools to allow tubing-pressure testing with sin-gle downhole shut-in and circulating well-killing options. The use of multifunction toolsis limited because of the reliability of the sliding seals at higher temperatures.Perforating systems are also being modified tomeet demands of ultra-HPHT environments.
Petroleum companies and service contrac-tors are routinely entering joint studies tomore thoroughly assess the operational limitsof tools and equipment designed for HPHTservice. These studies have led to better defi-nition of equipment specifications as well asretrofitting or re-engineering of tools and toolcomponents to ensure performance inincreasingly hostile environments. Devel-oping new downhole testing equipmentengineered to ultra-HPHT well conditionsrequires special test facilities. Facilities atSchlumberger Perforating and Testing (SPT)center in Rosharon, Texas include pressure-testing vessels that can take DST tools up to36.5 ft [11 m] long at 30,000 psi [207 MPa]and 450°F [232°C] (left).
Tubing
Single-shotreversing valve
Multicyclereversing valve
Pressure-controlled testervalve with holdopen
Pressure-controlledreference tool
Four gauge carriers
Pipe tester valve
Production packerwith seal assembly
Guns
Tubing
Single-shotreversing valve
Firing head
■PCT-F string for HPHT DST. The standardHPHT downhole testing tool, rated to15,000-psi differential pressure at 425°F,was used to test many deep, high-profilewells in the North Sea. These tools aremanufactured using H2S-rated materials.An innovative mud immune system iso-lates the internal parts of the tools frommud solids, keeping them protected andlubricated in an oil bath. Typically, thesetools have been used in wells at HPHT con-ditions for up to 12 days without failure.
■New ultra-HPHT J-tools being pulled outof the test vessel after qualification testing.
13. Flikkema H, Wiggelman J and Winter K: “WellTesting with Seawater as the Test Fluid,” paperpresented at the SPE High Pressure/High Temper-ature Update Seminar, Aberdeen, Scotland, March14, 1995.
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As an example of special development to meet operator needs, a new tool string was designed to work in ultra-HPHT wells in the Far East and the North Sea. The mainchallenge has been to develop reliable sealsfor temperatures up to 500°F (above). SPT hasjust finished extensive qualification tests of thelatest Ultra-HPHT DST tool strings, called theJ-string. Based on previous designs, but withcompletely new seal packages, the J-stringconsists of simple single-shot tools: a flow-control safety valve, the Pump ThroughFlapper Safety Valve (PFSV); a test valve fortubing, the Tubing Test Valve (TTV); and areversing valve, the Single-Shot ReversingValve (SHRV) (right).
The valves are activated by pressuring upon the annulus to rupture disks set to specificpressures. A typical job sequence wouldconsist of opening the TTV after pressuretesting the tubing, then shutting in the wellwith the PFSV at the end of the flow period,and finally, opening the SHRV to reverse outand kill the well.
The Lessons LearnedOil and gas companies are drilling wells tohigher pressures and temperatures, and ser-vice companies are being asked to providelogging and completion operations to meettheir needs. Each well provides lessons thatcan improve performance on subsequentwells—essential to long-term financial andtechnical success. Careful planning from theoutset is essential. During logging, and atevery phase of the completion operation,considerations must be given to schedule,time management, and contingency strate-gies, as well as safety issues. Understandingthe unique characteristics of each well, theequipment used and the objectives of theoperation helps reduce risks and ensuresuccess. One operator compared HPHT oper-ations with conventional wells: “Loggingand completing HPHT wells is like a spaceshuttle mission compared to taking a com-mercial airline flight. Technology and peoplemake the difference.” —RCH
Tubing
Tubing-test valve (flapper)
Single-shot reversing valve
Single-shot reversing valve
Pump-through safety valve (flapper)
Gauge carrier
Production packerwith seal assembly
Nipple
Tubing withpressure gauges
■J-string for ultra-HPHT wells. This newtool string was developed for ultra-HPHTapplications. The main challenge hasbeen to develop reliable seals for temper-atures up to 500°F. The tools are based on single-shot designs for reliability anduse advanced seal technology. They are not affected by mud solids and arecompatible with both kill-weight andunderbalanced fluids.
■Seal test machine.This machine hasbeen built to test dif-ferent configurationsof seals under worst-case fluids situations(oil and completionfluid on oppositesides) and pressuredifferences. Sinceelastomers may becompromised by dif-ferent fluids, theymust be tested underdifferent conditions. A well test sequenceof operating cyclescan be simulated anddriven by a computer.Seals are mounted on a mandrel andmoved to simulate thetool valve openingand closing with dif-ferent pressures oneither side. Changingpressure and toolmotion cycles simu-lates operation indownhole conditions.