Production Logging

What Is Production Logging?

Production logging consists of running logging tools in both production and injection wells. They can be run under dynamic (flowing) or static (shut in) conditions. With proper interpretation, production type, production intervals, and flow rates can be determined. Production logging can be identify:

1. Water entry/exit locations and sources

2. Non-performing perforations

3. Flow behind casing or tubing

4. Crossflow

5. Leaks in tubing or casing

6. Unproductive/receptive intervals for stimulation

7. Packer leaks

8. Lost-circulation zones

You may use PL on your injectors or you may use it on producers that are communicating with or in the vicinity of injectors. For this reason, the discussion is kept generic, at least initially, so that the relevant concepts for either application can be appreciated. Typical components in PL surveys are summarized below. There are variations in the degree of sophistication of these measurements (and tool configurations) from vendor to vendor but the concepts remain the same.

Temperature

The temperature sensor measures the temperature of the borehole. Temperatures logs were one of the first production logs and are still widely relied on today to qualitatively (and sometimes quantitatively) yield a variety of information. One of the primary uses is for fluid entry identification from the change in temperature that normally occurs when fluids from different depths enter a wellbore during production or enter the formation during injection. Temperature can be used for injection evaluations although interpretation can be difficult.

Temperature logs can indicate flow behind casing or tubing, such as channeling (use standard surveys as well as warmback measurements!). Other applications include locating gas entries, defining lowest point of production or injection, identification of casing, tubing, or packer leaks, checking gas-lift valves, defining the geothermal gradient, locating lost-circulation zones, determining hydraulic fracture height (approximately at least), and defining cement placement and top.

Pressure

The pressure sensor measures the pressure in the borehole on a depth-to-depth basis. While logging, change in pressure versus change in depth is used to determine the pressure gradient (and consequently density) in the wellbore. This can be used to identify gas, oil and water interfaces during production. The pressure sensor can also be used to determine wellbore pressures for critical well control applications, to evaluate friction losses and for a early time buildup when well is shut-in prior to making shut-in logging passes. As a fluid density device it can be used for fluid identification, fluid entry or exit point determination and water holdup determination if there is gas production.

Spinner

Flow along the wellbore is measured, commonly with a spinner. The spinner is a fan blade type device that is rotated by the fluid movement in the borehole. Many new-generation spinners have diagnostics that determine the flow rate and flow direction and also detect any problems in the system and will correct the flow rate automatically if there is a tool error.

The spinner response is typically linear with production velocity, but is offset from the zero point. This is due to the friction in the spinner's bearings as well as the viscosity of the production fluid and is called the spinner threshold. To get good results from the spinner survey, the borehole flow rates should exceed some minimum value (e.g. 10 feet per minute in fluid or 28 feet per minute in gas). Charts are available to convert production in barrels per day to flow rates in different sizes of pipe. The tool velocity also adds or subtracts from the spinner rate and is used to calibrate the spinner and determine the spinner threshold. Line speed is a critical component in most production logging. It is important to remember that the spinner is only indicating what is happening in the borehole where the spinner is positioned and that the production dynamics of boreholes may vary greatly, causing the spinner to sometimes give unreliable results especially in multi-phase wells.

Dielectric (Water Holdup)

This is used for inferring components in the production stream and, for PWRI, would be more useful in an offset producer where water cut has increased. This is also referred to as the capacitance sensor and measures the dielectric constant of the fluid in the borehole. Since the dielectric constant of water is high (about 80) and that of oil and gas is low (2 -6), this sensor is used to determine the fluid type, namely hydrocarbon or water. This sensor compliments the pressure gradient. The difference in the pressure gradient between oil and water is very small (0.09 psi), but the dielectric values are greatly different, making the capacitance tool very sensitive to small amounts of water. However, the capacitance sensors response to percent of water mixes is not linear and when water becomes the dominant percent of the mixture it becomes difficult to discriminate any the percent of water and oil in the mix (some sources indicate that the oil cut needs to be greater than 3% to be detected).

Gamma Ray

As is well known, the gamma ray sensor measures natural radioactivity. The gamma ray is mainly used for adjusting the depths of the production logs with other logs to a common basis. The gamma ray can also be used to follow injected radioactive material in the borehole to determine flow profiles and velocities and can be used to trace frac sand that has been tagged with radioactive material.

Casing Collar Locator (CCL)

The casing collar locator (CCL) measures magnetic anomalies induced by changes in metallic mass in the borehole. It is also used as a means of depth correlation and can be used to locate perforations, packers, x nipples, gas lift valves, screens, and other mechanical components in the borehole.

Vendors

PL tools and services are offered by a variety of vendors – with broad geographical coverage and levels of sophistication. Appendix A is an audit of some of these service providers. It is only a partial list of vendors. The products and services of the following vendors are summarized in the Appendix. More information is available from these service companies.

Vendors (refer to Appendix A)

Company	Location	URL
Baker Atlas	Worldwide	http://www.bakerhughes.com/bakeratlas/reservoir_production/polaris_index.htm
Cardinal Surveys Company	Odessa, TX, Hobbs, NM	http://www.cardinalsurveys.com/default.asp
Expro International Group PLC 2001	Aberdeen and other offices worldwide	http://www.exprogroup.com/casedholeservices/epl.htm
Halliburton	Worldwide	http://www.halliburton.com/spe98/flow2000.asp
Kuster Company F.T.I. Inc.	Long Beach, CA and other worldwide offices	http://www.kusterco.com/
Lee Tool Division of Schlumberger Canada Ltd.	Red Deer, Alberta	http://www.leetool.ab.ca
Madden Systems Incorporated[1]	Odessa, TX; Houston, TX; New Orleans, LA	http://www.maddensystems.com/index.htm
Maxim Technology Limited	Wales, UK	www.maximtech.co.uk
Oildata Wireline Services Limited	Port Harcourt, Nigeria	http://www.oildatainc.com/index.html
Read Well Services	Bergen, Norway; Aberdeen, UK; Doha, Qatar	http://www.readgroup.no/group/index.asp
Schlumberger	Worldwide	http://www.connect.slb.com/index.cfm?id=id4638
Spartek Systems	Sylvan Lake, Alberta	http://jaguar.rttinc.com/~spartek/index.htm

PWRI Specific Issues:

Many of the specific difficulties occur when logging in horizontal or high angle wells, especially if there are multiply fractured zones. Warmback measurements can help to discriminate what the true entry point(s) is (are).

Appendix A

PLT Service Providers

Baker Atlas

http://www.bakerhughes.com/bakeratlas/reservoir_production/polaris_index.htm

POLARIS System

The Baker Atlas POLARIS System is a combination of the Reservoir Performance Monitor (RPM) and Multi-Capacitance Flow Meter (MCFM) logging tools – a slimhole diagnostic system for evaluating and understanding horizontal well and reservoir performance.

Reservoir Performance Monitor (RPM)

This is a slimhole (1.7-in. OD) multi-function pulsed neutron tool. The RPM instrument combines multiple nuclear measurements in one system. Carbon/Oxygen (C/O) and pulsed neutron capture (PNC) measurements acquired with the RPM tool provide water saturation and three-phase holdup determination while oxygen activation measurements allow water flow and channel detection. The small diameter instrument addresses a broad scope of reservoir evaluation and management applications, including reservoir saturation and produced fluids monitoring, formation evaluation, production profiling, workover and well abandonment evaluation, borehole diagnostics, locating bypassed oil, and identifying water production.

Multi-Capacitance Flow Meter (MCFM)

A multiphase production logging tool for non-vertical wells. The small diameter, multiple-sensor MCFM instrument incorporates technology for measuring three-phase flow – oil, water, and gas – in horizontal, highly deviated, and undulating wellbores. The combination of an across-the-wellbore capacitance array with temperature, pressure, and acoustic sensors allows the MCFM instrument to pinpoint the location of three-phase fluid entry into the wellbore. The MCFM tool can simultaneously measures all three phases in multiphase flow.

With most production problems, the location of unwanted fluid production is of primary interest. However, to completely solve the production problem, the source as well as the location are needed; e.g., whether it is due to cresting or coning, depletion, fingering, injection breakthrough, fractures or faults, or behind-casing flow. The POLARIS system, combining RPM and MCFM, can go to the region of unwanted fluid production and operate in a high-resolution logging mode to identify both the location and source of the unwanted fluid.

Measurement of multiphase flow behavior and inflow profile determination in horizontal wells is possible with the Multi-Capacitance Flow Meter Service.

Polaris Applications

· Reservoir monitoring and management

• Establish base logs and monitor fluid contacts, production, reservoir depletion, and fluid movement
• Evaluate and manage enhanced oil recovery projects

· Formation evaluation

• Determine reservoir porosity and fluid saturations
• Pinpoint bypassed reserves
• Through-casing or drillpipe evaluation
• Production profile
• Determine borehole fluid holdup and distribution, regardless of well deviation
• Evaluate injection or production profiles in multiple string completions

· Workover access and evaluation

• Identify bypassed hydrocarbons and establish fluid contacts
• Slimhole access without compromising measurement quality
• Evaluate stimulation operations
• Borehole diagnostics
• Identify casing leaks, water channeling, and other behind pipe water flow
• Resolve completion problems

· Pre-abandonment well evaluation

• Identify and assess commercial value of bypassed hydrocarbons prior to well abandonment
• Locate trapped hydrocarbons between tubing and casing strings for thorough environmental evaluation

Features and Benefits

The RPM instrument can be run in combination with the MCFM tool or with conventional production logging sensors such as flow meters, temperature, fluid density, pressure, and hold-up indicators. This combination flexibility provides a complete multimode, multi-sensor solution-based system for a wide range of downhole reservoir conditions and production environments.

The RPM instrument is the industry’s most extensively characterized multimode tool, with our unique dynamic response generator providing superior measurement accuracy and confidence, independent of borehole geometry. Major advances in full 3-D and Monte Carlo modeling provide a more accurate tool response characterization in a wide range of borehole, casing, and formation/ fluid conditions.

Real-time RPM data can be matched with previous generation PDK-100 results for easy comparison in mature fields. For remedial work and time-lapse monitoring, RPM data can be overlaid with existing logs in real time. An advanced feature of the RPM service allows real-time computation of "intrinsic" . Innovative data analysis techniques provide this sigma measurement corrected for borehole and diffusion effects without prior knowledge of borehole size and fluid salinity. RPM corrected values can be directly compared with borehole and diffusion corrected data from PDK-100 or other PNC tools.

A History of Innovative Firsts in Pulsed Neutron Logging

Dresser Atlas, a predecessor of Baker Atlas, introduced the first commercial pulsed neutron logging tool in 1963. The Neutron Lifetime Log^® service proved to be very successful for determining water saturation in saltwater-bearing reservoirs.

In the mid 1970s, Baker Atlas introduced the first commercial Carbon/Oxygen log. The primary application of this logging system was to determine water saturation in fresh, brackish, or mixed salinity reservoirs.

Over the next two decades, Baker Atlas introduced a second-generation pulsed neutron log, the PDK-100 (1985), the Hydrolog^SM (1989) and the Annular Flow Log (1993). Another innovation, the Pulsed Neutron Holdup Imager, was introduced in 1994.

In 1999, Baker Atlas introduced the Reservoir Performance Monitor (RPM) instrument, a multipurpose, pulsed neutron logging tool. The new system combines the measurement capabilities of all previous pulsed neutron devices into one slimhole instrument, providing greater measurement flexibility than ever before and setting the new standard for reservoir evaluation and analysis.

The POLARIS system, which incorporates the Reservoir Performance Monitor (RPM) and Multi-Capacitance Flow Meter (MCFM), was also introduced in 1999.

Application	Operating Mode
Formation evaluation  (fluid saturations and porosity) Through casing When openhole logs are not available Through drill pipe when openhole logs cannot be run due to hole conditions	PNC, C/O
Time-lapse fluid monitoring	PNC, C/O
Production/injection profiling	PNC, C/O, PNHI, MCFM, AFL
Evaluation of stimulation operation	PNC, C/O, PNHI, MCFM, AFL, PRISM
Hydrocarbon location in fresh, brackish, or unknown water salinities	C/O
Bypassed hydrocarbon exploration in abandoned or workover wells	PNC, C/O
Production and reservoir depletion monitoring	PNC, C/O, PNHI, MCFM
Enhanced oil recovery project monitoring	PNC, C/O
Reservoir gas/oil/water contact monitoring	PNC, C/O, PNHI, MCFM
Future reservoir management base logs	PNC, C/O
Log-inject-log operations	PNC, C/O
Water channeling and/or casing leak identification Hydrolog	AFL
Water, oil, and gas holdups	PNHI, MCFM
Multiple string completion injection and production profiling	AFL
Hydrocarbon typing – differentiation between gas and oil	PNC
Locating trapped hydrocarbons between tubing and casing strings	C/O, PNC

Instrument Specifications
Diameter	1.6875 in.	42.9 mm
Length	80 ft.	24.4 m
Weight	375 lbm	175 kgm
Pressure Rating	15,000 psi	103 MPa
Temperature Rating	350° F	177° C
Min. Hole Size	> 1.8 in.	> 45.72 mm
Operating Range	3.7 - 9.0 in.	94 - 229 mm
Max bend radius	30°/100 ft	30°/30 m

Multi-Capacitance Flow Meter (MCFM)

System Overview

The Multi-Capacitance Flow Meter (MCFM) is a multiple-sensor, production logging instrument used to measure multiphase flow in highly deviated and horizontal wells. The MCFM tool was jointly developed by Baker Atlas and Shell International Exploration and Production (SIEP) using technology developed by SIEP for monitoring multiphase flow in surface flow lines.

The MCFM deploys a wing containing 28 capacitance sensors that span the wellbore to determine both flow composition (percentages of gas, oil, and water) and velocity in order to measure flow rates (Q_g , Q_o , and Q_w ).

The wing section is dynamically oriented by the powered Positive Orientation Section (POS) to ensure optimum vertical positioning, thus allowing the tool to accurately measure three-phase flow, even in extremely high water cut environments.

The wings of the MCFM tool are maintained in the vertical position to measure multiphase flow behavior in horizontal wellbores.

A quartz pressure sensor is included in the MCFM instrument to determine downhole pressures, and allow pressure surveys to be carried out while an evaluation program continues, e.g., performing a shut-in pressure survey.

Digital Sonan sensors also form an integral part of the MFCM diagnostic measurements, aiding in-flow regime identification and verification, channeling assessment, and flow behind pipe.  Key Measurements Water, oil, and gas holdups are measured at eight levels along the wing deployed across-the-wellbore, based on the measured dielectric of the flow. Bi-directional velocity profile is determined from multiple measurements at seven positions across-the-wellbore using cross-correlation of sensor responses within six sensor arrays placed along the wing and the centerline spinner. Water, oil, and gas flow rates are determined continuously while logging the horizontal interval or during stationary measurements. The MCFM tool is a logging instrument capable of measuring all three phases – oil, water, and gas – simultaneously.

An across-the-wellbore velocity profile is constructed from the transit-time measurements of the capacitance sensors in rows one, two, seven, and eight of the MCFM tool.

Reservoir Performance Monitor

System Overview

The RPM instrument employs three high-resolution gamma-ray detectors arrayed above a new, more efficient and reliable neutron generator. State-of-the-art detector electronics measure both the arrival time and energy of detected gamma rays. The generator is pulsed at distinct frequencies and the detectors operate in various acquisition modes to obtain the different logging measurements. The system is combinable with other production logging instruments, and is constructed in short, modular sections for ease in shipping and handling.

Operational Modes

Carbon/Oxygen spectroscopy mode – principal measurement is the C/O ratio. The neutron generator pulses at 10 kHz in the C/O acquisition mode with the full inelastic and capture gamma ray energy spectra recorded by each detector. These data are processed to determine critical elemental ratios, including carbon/oxygen and calcium/silicon from the inelastic spectra and silicon/calcium from the capture spectra. Data from each detector may be used individually or in combination to provide optimal readings. C/O interpretation includes a new dynamic response generator to accurately predict the expected C/O response level-by-level in your well.

Pulsed Neutron Capture mode – principle measurement is sigma, the thermal neutron absorption cross section. In the PNC logging mode, the neutron generator pulses at 1 kHz while the detectors record complete time spectra, and an energy spectrum, used to monitor instrument stability. Time spectra from short-spaced and long-spaced detectors can be processed individually to provide traditional thermal neutron capture cross-sectional information. The two spectra can also be processed simultaneously to automatically correct for borehole and diffusion effects and produce results very near the intrinsic formation values.

RPM instrument principle of operation- inelastic events; shown in yellow, occur during the generator burst. Capture events, shown in blue, occur after the neutrons become thermalized.

Instrument Specifications
Diameter	1.6875 in.	42.9 mm
Length	29.9 ft	9.12 m
Weight	115 lbm	52.3 kgm
Pressure rating	20,000 psi	138 MPa
Temperature rating	350° F	177° C
Minimum hole size	> 1.8 in.	> 45.72 mm
Maximum bend radius	30°/100 ft	30°/30 m

Pulsed Neutron Holdup Imaging mode measures both sigma and the C/O ratio In the PNHI acquisition mode, the neutron source pulse rate is also l kHz with the measurements made to determine gas, oil, and water holdups. When combined with other production logs, the PNHI can provide a comprehensive downhole production profile picture, even in deviated or horizontal wells. Neutron activation mode measures water flow oxygen activation The neutron activation mode provides water flow measurements using one of several data acquisition methods. Stationary measurements are made in either of two operating modes. Measurements at selected logging speeds can be used to segregate different flow rates in either an annulus or in an adjacent tubing string. Precision Radioisotope Spectral Measurements mode provides radioisotope identification and measurement With the neutron generator turned off, the RPM tool can also be used to detect the distribution of materials, tagged with radioactive tracers that are injected into a well during stimulation treatments. In this logging mode, the effectiveness of operations such as hydraulic fracturing or gravel pack placement can be evaluated.

Cardinal Surveys Company

Odessa, TX, Hobbs, NM

http://www.cardinalsurveys.com/default.asp

Positive monitoring of reservoir performance.
Detailed, zone-by-zone, information.
Changes in the downhole conditions detected.
Reevaluate marginal production wells.
Rework watered-out or gassed-out wells.
Recompletion of unproductive offset wells.
Guidance for remedial-workover designs.
Cost-effective well recompletions.
Improved completion for future wells.
Immediate verification of perforation efficiency.
Positive identification of the production intervals.
Confirmation of openhole log analysis and assumptions used in the initial completion.
Pinpoint mechanical problems.
Document baseline production profile for future reference.
Optimize pump placement.
Discover unwanted water sources for remedial procedures.
Correlate production results with injection profiles for sweep efficiency of floods.
Confirm engineering and geological assumptions and analysis.
Verify stimulation job effectiveness and techniques.
Plan accurate placement of mechanical isolation tools (bridge plugs and packers.)
Locate thief zones and undesirable cross-flows.
Real-time snap shot of production well.

Components

• Rope Socket (15" - 5/8" fishing neck)
• Capacitance Tool (40") – Functions as a capacitor. An insulated probe functions as one plate and the tool housing acts as the other plate. Various materials passing between the plates have different dielectric properties that change the total capacitance of the circuit. In most instances, a 3% or more oil cut is necessary before a noticeable change in the capacitance is registered. This 3% threshold varies with the salinity of the water and the gravity of the oil. The primary advantage of the capacitance tool over the older density tool is that its readings are not dependent on a radioactive source and sensor. Thus, fluid identification cannot be affected by radioactive material in the well bore or in the ejector. In addition, there is no long half-life source of radioactive material to be fished should the tools be dropped.

• Caliper (7/8" O. D. [with arms retracted] by 68" in length and can be used in hole up to 14 inches in diameter.
• Collar Locator (7/8” x 28.5") – magnetic coil assembly
• Scintillation Gamma Ray Detector (60"). It is a scintillation type 9sodium iodide crystal).
• Microprocessor Controlled Ejector (75.5"). The ejector is digitally controlled. Its motorized plunger forces small bursts of radioactive material out of a pressure chamber through an o-ring sealed exhaust port on the side of the tool casing. The tool has the ability to consistently eject selected slugs from 0.1 cc to a full 20 cc ejector dump.
• Temperature Tool (7/8" O. D. by 37" in length). Accuracy approaches 0.1 degrees Fahrenheit. This component is critical for channel detection. There is a platinum Resistor Temperature Detector (RTD). A stable crystal oscillator serves as an accurate, drift-free frequency reference in the tool electronics.
• Memory Pressure Gauge (14”)
• Total Tool Length with crossovers = 30’

General Guidelines

Avoid the intentional design of tests that rely completely on nuclear-based data acquisition. Their maximum radius of investigation is approximately 24 inches from the sensor.

‘Avoid the LAST LOG SYNDROME. It is generally acceptable for most production logs to be within 2 to 3 feet of measured depth. However, if you are on the 4th or 5th generation of logs, you may be correlating 10’ to 15’ off depth. Always try to use the original open hole logs or the logs used to perforate the well.”

Tracer Velocity

Pros: High resolution of data points Limited by the spacing from ejector to detector Cons: Minor plant fluctuations effect calculated rates I.D. changes have a drastic effect on the calculated rates

Generic Operations

• The producing (pumping) temperature log is the first information available for determining the status of this well's production and it can greatly influence the strategy for investigating the well.

• A correlation gamma ray survey and collar log is then run from T.D. up through zones of interest. The correlation log is compared to file logs to make adjustments to depth.

• A capacitance log is then run from T.D. to above the pump. The capacitance tool can differentiate between water, oil, and gas in the well bore. Note that when calibrated, pure water is one extreme, pure air or gas the other, and pure oil is about a 75% reading.

• The next step is to run the radioactive tracer survey. The tracer will allow the determination of the direction and rate of fluid movement. There are the three basic components of the tracer: 100% shot, zone breakdown shots, and no-flow shots. The 100% shot is ejected above the top perforation. As the single radioactive slug travels up the wellbore, at least three passes through the slug are recorded. By measuring the distance of movement and the time of travel, it is possible to calculate the velocity and therefore, the volumetric flow rate in the casing. This method of velocity measurement is necessary because of pump surges in the fluid column. Stationary velocity readings are not accurate. Zone-by-zone breakdown is accomplished by the same velocity method as the 100% slug. Readings are taken in areas between sets of perforations. Each set of rates obtained is compared back to the 100% shot and a percentage of entry is calculated for each set of perforations. A no-flow shot is ejected between the bottom perforation and LTD. It is monitored in the same manner as the other velocity measurements. The primary objective is to determine if there is any fluid movement from below LTD in the casing. This is essential information. If the temperature surveys indicate fluid movement from below LTD, the no-flow shot is the only means to prove whether the movement is inside or outside the casing.

• The log may or may not be complete at this point. After determining the type and quantity of fluid being produced from each zone, decay temperatures and cross flow surveys may be needed for further definition. It is almost always a good idea to run at least one decay temperature survey unless all objectives for running the survey have already been conclusively reached through the prior survey methods.

GAMMA-TROL (Stimulation Evaluation Logging)

Combined with a radioactive tag, stimulation evaluation logging assists in inferring treatment placement. Included in the service is either a temperature or gamma-ray log or both. Cardinal Surveys Company offers these services either separately or combined under the following names:

• Gamma-Trol (Gamma-ray only)
• Temp-Trol (Temperature only)
• Gamma-Trol II (Combination
• Gamma ray and Temperature).

The Gamma-Trol II service can also be used to locate the top of cemented intervals. The cement can be tagged during cementing, and the temperature and gamma ray log will accurately pinpoint the cement top.

Injection Profile (Radioactive Tracer Profile Logging)

An accurate profile of the exact placement of injected fluids is essential for proper management of water injection. The Injection Profile Log, usually consisting of a temperature log, two radioactive tracer logs (the intensity profile and a series of stationary velocity measurements), channel checks, packer checks, injecting temperature log, shut-in temperature logs and cross-flow checks (where applicable), can be used for getting profiles.

This log is used to determine the placement of injection fluids in the formation. Of general interest is a profile of the zone-by-zone placement of injected fluids versus rate. A comparison of injection and shut-in temperatures can be used to qualitatively determine major storage (injected) zones.

In tertiary or Enhanced Oil Recovery (EOR) projects, the injection profile is applied in a similar manner. Sometimes special logging techniques are required due to the physical properties of the injection fluids. Many tertiary or EOR projects alternate injection of multiple fluids (Water After Gas-WAG, or vertical profile modifications such as polymer treatments). In these instances, it may be desirable to log the well after each change in injection fluid to determine the relative impact of different fluids.

Because a radioactive tracer is used, the Injection Profile also affords other benefits such as location of casing annulus channels. Channels in the casing annulus can be seen when tagged fluid exits the casing through a perforation and continues in a path near the wellbore. The extent of the channel can be determined by following the tagged fluid as long as it remains near the wellbore. In a similar manner, communication between perforated intervals can be discovered. The radioactive tracer identifies other mechanical problems such as holes in the casing, unopened perforations, leaking packers or bridge plugs.

“Due to the versatility of the radioactive tracer, it is the best and most accurate method of running a Mechanical Integrity Test (MIT) on disposal wells.” Using the same logging procedures, the radioactive tracer can yield the zone-by-zone breakdown of fluids exiting the wellbore. Temperatures can also aid in identifying any upward or downward channels.

TRAC-III Production Logging

Cardinal's TRAC-III logging string consists of a Scintillation Gamma Ray Detector, (microprocessor-controlled) Radioactive Ejector, Collar Locator, Capacitance Probe, Caliper, and Temperature Tool. All sensors come in ⁷/8" O.D., 1" O.D., 1¹/4" O.D., and 1³/8" O.D. cases. The tools are used to:

· Document baseline production profile for future references.

· Verify effectiveness of well treatments.

· Discover unwanted water sources for remedial procedures.

· Correlate production results with injection profiles for sweep efficiency of floods.

Well Parameters For Example Procedure

Production	20 BPD Oil	210 BPD Water	100 MCFD Gas
Surface Pressure	<300 PSI	Casing	5.5"
Tubing	2.875"	Packer	5500'
Perforations	5600' - 6000'	PBTD	6100'

The following procedure represents the fundamental steps needed to accomplish most TRAC-III applications. However, due to the investigative nature of production logging, it must be noted that the following procedure may be modified at any point in order to optimize the definition of events or abnormalities. This procedure should be considered as a general plan of action.

1. Conduct safety meeting to identify location hazards, review well information, review test objectives, and make necessary plans to maximize safety and test results.

2. Rig up Cardinal Surveys logging unit and conduct the pre-job wellhead radiation survey.

3. Attach Cardinal Surveys 1 ³/8" O. D. TRAC-III tool string which consists of a Rope Socket (1.375" x 15" with a 5/8" fishing neck), Capacitance Tool (1.375" x 40"), Caliper (1.375" x 69"), Collar Locator (1.375" x 28.5"), Scintillation Gamma ray Detector (1.375" x 60"), Microprocessor Controlled Ejector (1.375" x 75.5") with I-131 as the tracer isotope, and a Temperature Tool (1.375" x 37").

4. Install 5,000 psi lubricator and test for leaks.

5. Pressure up lubricator and secure wellhead.

6. RIH with TRAC-III tool string into the tubing.

7. Run Flowing Temperature and CCL Logs from 5,400 to 6,100.

8. Run Gamma ray and CCL logs from 6,100 to 5,400. Correlate Gamma ray and CCL logs to supplied correlation log. Adjust depth measurement from Wireline Depth to Measured Depth.

9. Return TRAC-III logging string to T.D. at 6,100 and run Capacitance Log from 6,100 to 5,400.

10. Return TRAC-III logging string to T.D. at 6,100 and run Caliper from 6,100 to 5,400.

11. Place TRAC-III logging string above the zone of interest 5600 - 6000 and eject a slug of radioactive material. As the slug travels up hole with the flow, make at least 3 passes through the material with the recorder set to depth drive. Note the delta times from peak to peak. This will allow for a 100% velocity reading.

12. Repeat step 11 two more times.

13. Repeat step 11 in areas between perforated intervals or between areas of interest in the openhole section. Refer to the caliper results from 5600 - 6000 when placing the radioactive slugs. Try to avoid areas of drastic I.D. change to minimize the error in the velocity measurements.

14. Eject a slug of radioactive material below the zone 5600 - 6000 and above T.D. at 6,100. Eject the slug as low as possible if there is no rathole. Make several passes through the material to determine if there is any flow coming from below T.D. in the wellbore.

15. Shut-in production at wing valve.

16. Allow the well to remain static for approximately one hour.

17. Run a Shut-In Temperature Log from 5,400 to 6,100.

18. Perform crossflow checks. Shoot a series of radioactive slugs approximately 50 feet apart across the zone 5600 - 6000 and make timed passes through all of the slugs at the same time to determine if there is any crossflow between zones.

19. Run a Shut-In Temperature Log from 5,400 to 6,100 approximately 2 hours after the well has been shut-in.

20. It may be desirable to pull a Shut-In Capacitance Log at this point from 6,100 to 5,400.

21. POOH with Cardinal Survey's TRAC-III production logging tool string.

22. Rig down equipment, return well to prior status, and conduct the post job wellhead radiation survey.

Stabilization

Stable producing conditions are crucial to running a TRAC-III that will give insight to the wells normal production characteristics. This is important when the test objective is to see the well's production profile. It is also important for determining the effects of a past stimulation that is not performing as expected.

If we run a TRAC-III immediately after the well has been worked over, it will only tell us what the well does at that particular point in time. You want to allow the production to stabilize, unless you have had a sudden, large increase in water production.

It does not matter if this increase of water production was brought on by a stimulation, direct channel from an offset injector, or natural causes. Don't wait for stabilization. There is a strong possibility this new water is from a higher pressure source than anything you've been producing. In these situations there is regularly crossflow into proven oil zones. It is necessary to find the water source so that you can take remedial action.

GAMMA TROL

GAMMA TROL - II is a combination of Temperature and Gamma Ray logging used determine the placement of well stimulations and treatments.

Well Parameters For Example Procedure

Frac	140,000 lbm 20/40	BHT	90^oF
Surface Pressure	<3,000 psi	Casing	5.5"
Tubing	2.875"	PKR	5600'
Perforations	5700' - 6000'	PBTD	6100'

The following procedure represents the fundamental steps needed to accomplish most GAMMA TROL ® applications. However, due to the investigative nature of production logging, it must be noted that the following procedure may be modified at any point in order to optimize the definition of events or abnormalities. This procedure should be considered as a general plan of action.

1. Conduct safety meeting to identify location hazards, review well information, review test objectives, and make necessary plans to maximize safety and test results.

2. Rig up logging unit on and conduct the pre-job wellhead radiation survey.

3. Attach Cardinal Surveys GAMMA TROL ® tool string which consists of a Rope Socket (1.25" x 15" with a 5/8" fishing neck), one or more weight bars, Collar Locator (1.375" x 28.5"), Scintillation Gamma ray Detector (1.375" x 60"), and a Temperature Tool (1.375" x 37").

4. Install wireline blow out preventer and tool trap.

5. Install lubricator and test for leaks.

6. RIH with GAMMA TROL ® tool string into the tubing.

7. Run Base Temperature and CCL Logs from 5,500 to 6,100.

8. Run Gamma Ray and CCL logs from 6,100 to 5,500. Correlate Gamma ray and CCL logs to supplied correlation log. Adjust depth measurement from Wireline Depth to Measured Depth.

9. POOH with Cardinal Survey's GAMMA TROL ® production logging tool string.

10. Rig down equipment, store lubricator in a safe area, and stand by during well stimulation.

11. Record ISIP and 15 minute shut-in pressures.

12. Install wireline blow out preventer and tool trap.

13. Install lubricator and test for leaks.

14. RIH with GAMMA TROL ® tool string into the tubing.

15. Run After Temperature and CCL Logs from 5,500 to 6,100.

16. Run After Gamma ray and CCL Logs from 6,100 to 5,500.

17. Allow well to remain static for approximately one hour.

18. Run a Shut-in Temperature Log from 5,500 to 6,100.

19. POOH with Cardinal Survey's GAMMA TROL ® production logging tool string.

20. Rig down equipment and conduct the post job wellhead radiation survey.

Radioactive Tagging

The Tagmaster ® was developed in the late 1970's.

Downstream, High Pressure Tagging

Tagging a treatment downstream of the pumps has many inherent advantages over injecting radioactive material in the low-pressure pump intakes.

· No surface equipment (pumps, blender, manifold, etc.) has radioactive material passing through it. This prevents a buildup of contamination that will accumulate to a point where field personnel will be exposed, not only to the radiation passing through the system, but also to residual contamination from past tags. These units can become too contaminated to be legally operated!

• The radioactive flush is instantaneous. There is no opportunity for any particles to become trapped in surface equipment that might be released during flush.
• If a frac treatment screens out to the surface, all contamination will be downstream from the "T" assembly.
• If there is a radioactive spill, it will be in an area with no personnel in the immediate vicinity.
• Personnel exposure is kept to a minimum.

Placement of Radioactive Storage

While chronic exposure to low level radiation is hazardous, the immediate danger is from exposure to the radioactive additive in concentration. Many systems store the radioactive additive on, or near, charged fluid lines. If the line should burst you could have a dangerous and expensive problem to contend with. The Tagmaster ® stores radioactive material in concentration 50 - 100 feet away from all treating lines.

Storage

Containment pots for the radioactive additive are mounted in the back-center of the Tagmaster®. The pots are plastic coated, steel containers that have approximately one inch of lead shielding. This gives five half-value layer shields for Iridium 192, the primary isotope used in the Tagmaster ®.

Professional Tagging Technicians

All of Cardinal's technicians have received government approved training programs. They are trained in the proper methods of containment, cleanup, A.L.A.R.A. techniques, Cardinal's regulations, and government regulations concerning the transportation, use, and exposure limits of radioactive materials.

Tagmaster ® Quality Control Log

The Tagmaster ® Quality Control Log is an optional service offered by Cardinal Surveys Company. It entails a PC based data acquisition system that monitors radiation intensity of injected materials during the stimulation.

RSO

Cardinal's Radiation Safety Officer is responsible for safety, training, and regulatory compliance where radioactive materials are involved. The RSO maintains and reviews records of Before and After Location Surveys, Personnel Exposure (whole body and thyroid bioassay), and monitors Cardinal facilities.

He also holds a prominent position in the Radiation Safety Committee. Records and procedures are periodically reviewed by the committee to make changes where needed to enhance our A.L.A.R.A. program.

Isotope Quality Control

Cardinal has the majority of isotopes we use in the Tagmaster ® targeted by the Nuclear Science Center at Texas A&M University. Our control of materials supplied for targeting and follow-up testing, with a state of the art 4096 channel spectrum analyzer, assures quality and quantity control.

Tagmaster ® Specifications

· 4140 Carbon Steal "T"

· Weco 1502 connections

· 20,000 psi working pressure valve

· 20,000 psi working pressure check valve

· 14,000 psi working pressure hose with 40,000 psi minimum burst pressure

· 20,000 psi working pressure manifold

· 4 - Plastic coated, steal containment pots with 1" of lead shielding

Isotope	Atomic Symbol	Half-Life	Special Concerns	Photo peaks Mev
Iodine	^131I	8.04 days	Thyroid Seeker	9.99 (X-ray), 0.08, 0.2843, 0.3645, 0.638, 0.724
Iridium	^192IR	74.2 days	None	0.067 (X-ray), 0.140 (Compton), 0.210 (Compton), 0.315, 0.470, 0.605, 0.79, 0.90 (shoulder)
Scandium	^46SC	83.8 days	High Beta/Energy	0.887, 1.119, (0.89 plus 1.1 sum peak)
Antimony	^124SB	60.2 days	High Beta	0.603, 0.645 (hidden shoulder), 0.722 (shoulder peak), 1.30 - 1.37, 1.69, 2.09, (1.69 plus 0.603 sum peak)
Gold	^198AU	2.696 days	High Beta	0.412
Bromine	^82BR	35.34 hours	High Energy	0.55, 0.61, 0.7, 0.77, 1.04, 1.33, 1.48, 1.90, 2.14

Expro RAM Production Logging Tool

Expro International Group PLC 2001

Expro North Sea Ltd
Kirkhill Place
Kirkhill Industrial Estate
Dyce
Aberdeen
AB21 0GU
Tel: +44 1224 214600
Fax: +44 1224 770295

http://www.exprogroup.com/casedholeservices/epl.htm

Introduction

In 1986, Expro performed the first memory PLT operations in the UK North Sea. Additional development led to the release of the Expro RAM production logging tools in 1998.

The five main sensors - Gamma Ray, Collar Locator, Quartz Pressure, High Resolution Temperature and Fluid Capacitance - are contained in one assembly measuring only 55 inches (1.4 meters) long. This construction removes 8 electronic pressure sealed connectors from the string therefore lessening the chance of connector failure and improving overall reliability. The RAM tool is combinable with up to 9 additional sensors such as calipers, fluid densities and extra spinners. However, in its normal deployment mode, with one spinner, the total PLT length is 112 inches (2.85 meters) for surface readout and 138 inches (3.5 meters) for memory applications.

Offshore, this compactness allows deployment of PLT operations in the most restricted of areas and on land eliminates the requirement of having large deployment cranes on site. It also means that the tool does not need to be fully disassembled between jobs thereby reducing rig up and rig down time.

Applications

The RAM tool is a short, all-in-one production logging tool, providing flow, quartz pressure, temperature, fluid dielectric, gamma ray and CCL. Use of a single combination tool increases reliability by minimizing electrical and mechanical connections, reduces rig up time, improves data quality through the close proximity of all sensors and brings the benefits of a smaller toolstring - allowing well access from even the most restricted of areas.

In addition, the tool has the ability to deploy 100% downhole backup while remaining shorter than most other single toolstrings. A separate telemetry cartridge connects to the upper head and is available in a number of telemetry formats. A High Speed Telemetry Cartridge (HSTI) or High Speed Memory Interface (HSMI) Cartridge can be attached to the upper head. The RAM is both memory and SRO compatible, requiring no separate interfaces or modules.

A range of industry-standard sensors can be connected to the tool’s lower head - such as fluid density, accelerometer, x-y-calipers, fluid profile, inline flowmeter or continuous flowmeter. The high temperature and pressure rating make the RAM tool suitable for a wide range of production logging operations and its use results in a typical full-length string of only 112”/2.9m.

All tools are manufactured in NACE specification (MR0175) materials for use in wells containing H₂S/CO₂

Flowmeter

Range (Interface)........................................................ 30 - 60,000 bbls/day

Directional.............................................................................................. Yes

Resolution............................................................................. 12 pulses/rev.

Pressure

Type................................................................................................. Quartz

Range...................................................................... 15,000 psi - 16,000 psi

Accuracy...................................................................................... 0.02% FS

Resolution.................................................................................. <0.008 psi

Repeatability................................................................................ 0.01% FS

Temperature

Range............................................................................... 0 - 177°C/350°F

Accuracy..................................................................................... 0.5°C/1°F

Resolution.......................................................................... 0.025°C/0.05°F

Time Constant............................................................................... <1.5 sec

Gamma Ray

Range..................................................................................... 0 - 1,000 API

Sensitivity................................................................................. 1 Count/API

Fluid Dielectric

Range............................................................................................ 0 - 40%

Accuracy..................................................................................... 2% Range

Resolution........................................................................................... 0.1%

RAM Specification

Diameter	13/8” (35mm)	111/16” (43mm)
Length	55” (1.4m)	55” (1.4m)
Pressure (max)	15,000 psi	20,000 psi
Temperature (max)	177°C (350°F)	177°C (350°F)
Weight in air	35 lbs (16 kg)	52 lbs (23.6 kg)
Fishing Strength	10,000 lbs (4,550 kg)	10,000 lbs (4,550 kg)
Sensor Supply Voltage	12v	12v
Line Voltage (SRO)	60 - 250v	60 - 250v
Current	80mA	80mA

Multi Sensor Memory Production Logging Tool

The tool is able to operate in deviated or horizontal wells and has the capability to log all types of multiphase flow and can be deployed via slickline, coiled tubing or e-line. All of the MS-MPLT sensors are compatible with the Expro RAM PL tools.

Applications

• Vertical, deviated or horizontal wells
• Determination of downhole flow rates
• Layering
• Zonal distribution
• Crossflow and leaks
• Multi-phase flow

Technical Specification

Memory
Type	Non-volatile EEPROM
Size	Expandable up to 16Mb
Sample rate	Multiples of 0.1 sec
Data set	Minimum of 30,000 on all channels
Length / OD	2ft / 111/16" (0.61m / 43cm)
Full-bore Flowmeter
Size	Various for use in up to 95/8" casing
Measurement range	100 to over 30,000 bbl/day in 7" casing
Length / OD	2.95ft / 111/16" (0.89m / 43cm)
In-line Flowmeter
Size	21/8" and 111/16"
Measurement range	600 to over 60,000 bbl/day
Length / OD	1.44ft / 111/16" (0.43m / 43cm)
CCL
Type	Passive
Length / OD	1.53ft / 111/16" (0.46m / 43cm)
Gamma Ray
Type	Scintillation
Sensitivity	1 cps / API unit
Length / OD	2.2ft / 111/16 (0.67m / 43cm)
Water Hold-up
Type	Capacitance
Measurement range	0.01 to 1 (accuracy decrease at high values)
Length / OD	2.18ft / 111/16" (0.66m / 43cm)
Pressure
Type	Shear quartz
Accuracy	± 3.2 psi (± 0.22 bar)
Repeatability	± 0.005% of full scale
Length / OD	1.02ft / 111/16" (0.29m / 43cm)
High Resolution Temperature
Type	Platinum resistance
Accuracy	± 0.5ºC
Resolution	0.09ºC
Length / OD	1.02ft / 111/16" (0.29m / 43cm)
All sensors are rated to 150ºC
Radio Active Fluid Density
Type	Radio active source
Length / OD	2.18ft / 111/16" (0.66 / 43cm)
X-Y Caliper
Type	4 arm
Length / OD	3.25ft / 111/16" (1m / 43cm)

Halliburton

http://www.halliburton.com/spe98/flow2000.asp

Flow 2000 Production Logging Services

In addition to the high-speed telemetry/gamma ray/casing collar locator cartridge, the Flow 2000 production logging stack includes the following sensors:

· HMR Gauge Carrier provides fast, high-resolution transient well testing with pressure derivative in real time. · Capacitance Holdup Tool identifies three-phase flow with low water cuts. · Gas Holdup Tool provides fullbore gas holdup from low energy gamma ray scattering in fluid and steel pipe. · Differential Pressure Tool determines liquid holdup and identifies fluid in wellbore deviations up to 70°. · Six-Arm Fullbore Spinner measures mono- and multi-phase flow with a threshold above 100 BFPD (in 7-in. casing). · Enhanced Flow Diverter for multiphase production or injection flow rate measurements and enhanced multi-layer transient testing. · Enhanced Wheeled Centralizer provides strong centralization in vertical, deviated, and horizontal wells.

http://www.kusterco.com/kplt.htm

Kuster Production Logging Tool (KPLT)

	Input Power: 4 "C" 3.6v Lithium Thionyl Chloride Cells 1 "AA" 3.6v Lithium Thionyl Chloride Cell	Data Sampling: Max Sampling Rate: 50 samples/sec. Min Sampling Rate: 1 sample per year
	Analog Sensor Interface: Converter Type: Delta-Sigma Modulation Dynamic Range: 96dB max. Digital Output: 16 bits max.	Digital Sensor Interface: Programmable Between Autoscaling Frequency Measurements Totalizing Counters, 16 bits
	Memory Capacity: Memory: 2 Megabytes 4 Megabytes available Max. Number Of Stored Points: With All Sensors: 130,000 With Limited Sensors: 1,000,000	Sensor Specifications: Temperature: Measurement Range: 32F to 300F Length: 14.50" Measurement Accuracy: .063F Measurement Resolution: .018F Measurement Time Constant: 0.3 sec.
	Pressure: Measurement Range: 0-10,000 psi Length: 21.50" Measurement Accuracy: 0.02% F.S. Measurement Resolution: 0.01 psi Repeatability: 0.1% F.S.	Flowmeter Sensor:(Full Bore and Continuous) Measurement Range -200 to+200 RPS Measurement Accuracy: 0.083 rev/sec. Measurement Resolution: 0.083 rev/sec. Length, Full Bore: 29.00" Length, Continuous: 18.50" Min. Detectable Flow rate Full Bore 100bpd: (5" casing) Continuous 200bpd: (5' casing)
	Dielectric Sensor: Measurement Range: 1 to 100 Measurement Accuracy: 2% Measurement Resolution: 0.1 % F.S. Length: 30.00" Maximum Water Cut Measurable: 30%	Gamma Ray: Measurement Range: 0-500 API Units Length: 37.00"
	Casing Collar Locator: Measures locations of tubing and casing collars for depth control. Length: 18.00"	Sensor Descriptions: Battery Pack - Supplies the necessary power to the various sensors, the central processing system and memory section.

Memory Section - Serves as the programmable central processing unit, which has been programmed to interrogate and record to memory measured sensor data at a prescribed sampling rate.

Temperature - Measure the temperature of the wellbore fluids to delineate fluid entry or exit and production/injection history.

Dielectric - Measures the capacitance of the wellbore fluids to delineate the mixture of water and hydrocarbons.

Gamma Ray - Measures gamma ray emissions from the downhole environment and is used as a "depth-control" tie-in to openhole logs.

Casing Collar Locator - Measures locations of tubing and casing collars for depth control.

Pressure - Measures pressure of wellbore fluids for use in PVT calculations and calculation of gradients for fluid identification.

Full Bore Flowmeter - Measures the change in fluid velocities and incorporates into bulk flow to provide injection or production profile (for casing diameters).

Continuous Flowmeter - Measures the change in fluid velocities for single phase and small diameter pipe.

High Temperature Production Logging Tool

Lee Tool Division of Schlumberger Canada Ltd.

7449 - 49Avenue Crescent

Red Deer, Alberta

T4P 1X6

Phone: 403.347.2524

Fax: 403.342.5065

http://www.leetool.ab.ca

Memory Production Logging System

The Lee Tool Memory Production Logging System is a cost-effective, rugged, and easy to use PC-based system and tool string.

Memory Logging is the measurement of a wellbore environment where tool power and data storage are incorporated within the logging tool, thus eliminating the need for electrical, radio frequency, or fluid continuity to surface. The Memory Production Logging (MPL) system consists of two groups of components: the surface system and the downhole tools. These two portions of the system operate independently of each other. They are only linked together when the tool is being programmed or when the data from the tool is being downloaded.

Surface System Downhole Tools

Tool Sensors may include a combination of the following:

• PC Computer (PC-Logger) Battery Section
• Remote Speed/Depth Display Memory Production Logging Adapter
• Tool Interface Box Tool Sensors (see below)
• Thermal Continuous Feed Plotter
• Depth Encoder
• CCL Nuclear Fluid Density Thermal/Epithermal Neutron
• Gamma Ray Flowmeter XY Caliper
• Dielectric Pressure Multi-finger Caliper
• Gradiomanometer Temperature

Deployment Methods

• Drillpipe/tubing conveyed logging, both vertical and horizontal
• Coiled tubing conveyed logging, both vertical and horizontal
• Slickline conveyed logging
• Long-term logging set in a landing nipple
• Used in conjunction with electric line - cased or open hole tools

Applications

• Flow Profile/Injection Profile Logging
• Depth Correlation
• Extended Flow, Pressure and Temperature Tests
• Transient Rate and Pressure Tests
• Mechanical/Hydraulic Isolation Logging
• Lost Circulation Zone Detection
• Neutron Logging
• X-Y Open Hole/Casing Caliper Log
• Multi-Finger Tubing Caliper
• Cement Top and Cement Plug Logging
• Casing/Tubing Leak Detection

• Collar Locator
• Gamma Ray
• Gradiomanometer
• Centralizer
• Dielectric
• Pressure/Temperature
• Fullbore Flowmeter
• Memory Adapter
• Spinner

The surface depth files are merged with the downhole data with time as the common link. The data are then presented in standard log format for all sensors and passes. Line speed, depth and spinner RPS are used to create a calibration file or spinner crossplot. This spinner crossplot is then included with overlays to provide a wellsite interpretation/presentation.

Time Synchronized

Before beginning the job, the MPL adapter is connected to the PC-Logger computer. Both have internal real time clocks that are now synchronized. When the job commences, the MPL adapter records data vs. time, while the PC-Logger computer records depth vs. time

After the job is completed, the MPL adapter is connected to the PC-Logger computer. The depth vs. time files from the PC-Logger computer are merged with the data vs. time memory from the MPL adapter. Time is used as the reference and the resulting files contain data vs. depth. These files are now standard log output, the same files that would be generated by real time logging.

Tool Sensors

The PC-Logger is a stand-alone PC system, built to withstand field use, yet portable and easily transported by boat or helicopter to remote locations. The surface PC-Logger acquisition system is common to both real time and memory. To go ROM memory to real time, simply replace the downhole MPL adapter with a telemetry section and add a power supply at surface. This will provide full real time capabilities for all standard Production Logging Services on mono conductor cable.

MPL adapter electronics contain 32 megabytes of Flash EPROM memory with an open architecture design that supports future memory expansion. The MPL Adapter is the memory-logging equivalent to Surface Readout (SRO) telemetry. The MPL Adapter counts the pulses from each sensor, sorts records and compresses the data within its own memory for retrieval at surface.

A variety of tool sensors are available, in 1-3/8" (34.99mm) or 1-11/16" (42.9mm) strings, capable of working up to 10,000 psi (70 MPa) and 302 degrees Fahrenheit (150 degrees Celsius).

Madden Systems Incorporated

Madden Systems Incorporated
1801 E. Pearl Street
Odessa, Texas 79761

http://www.maddensystems.com/index.htm

Production Logging

Introduction

Production logs are used to determine dynamic and static downhole conditions in production, injection, and disposal wells.

Standard Production Logging Tool (280^oF Rating)

This Slicklogger® System's physical characteristics of a short, rigid, single housing and small O. D. make it a durable solution for coiled tubing applications in highly deviated well bores. The system also excels in getting by tight radius crooks in vertical well bores This tool can be run in a memory or electric line configuration.

Tool Specifications

Tool Length Memory Configuration 15' 9" E-Line Configuration 10' 9" Tool O.D. 1.375" Pressure Sensor Type: Quartz Crystal Accuracy: ± 0.03% F.S. Resolution: 0.01 psi Ranges: 10k, 16k, 20k Make: Quartzdine Temperature (Borehole) Rating: 280 degrees F Type: Platinum RTD Accuracy: ± 1 Deg. C. Resolution: 0.001 Deg. C. Response: 0 - 100 Deg. C (4 seconds) Temperature (Compensation) Accuracy: ± 1 Deg. C. Resolution: 0.01 Deg. C. Gamma Ray Detector Type: Scintillation Collar Locator Type: Coil / Rare Earth Magnet Capacitance (Fluid I.D.) Determine water presence in well bore fluids. Flow Meter (Spinner) Type: Continuous Sensors: Reed Switch / Magnetic Resolution: 0.25 rps or 0.08 rps Data Status: Velocity / Direction / Diagnostics Output Logging Curves Gamma Ray Collar Locator Pressure Temperature Capacitance Flow Velocity Pressure Gradient Temperature Gradient Compensation Temperature Line Speed Time and Depth

Hazardous Conditions Production Logging Tool (450^oF Rating)

The tool has a small O. D. of 1 5/8". This tool has metal seals in addition to o-rings and is capable of operating in very hot and corrosive environments. It has successfully run on 25,000 feet of 7/32” electric line to depths in excess of 18,000 feet and temperatures over 500^oF.

This tool can be run in a memory or electric line configuration.

Tool Length Memory Configuration 18' 3" E-Line Configuration 10' 5" Tool O.D. 1.625" Pressure Sensor Type: Quartz Crystal Accuracy: ± 0.03% F.S. Resolution: 0.01 psi Ranges: 10k, 16k, 20k Make: Quartzdine Temperature (Borehole) Rating: 450 degrees F Type: Platinum RTD Accuracy: ± 1 Deg. C. Resolution: 0.001 Deg. C. Response: 0 - 100 Deg. C (4 seconds) Temperature (Compensation) Accuracy: ± 1 Deg. C. Resolution: 0.01 Deg. C. Gamma Ray Detector Type: Scintillation Collar Locator Type: Coil / Rare Earth Magnet Capacitance (Fluid I.D.) Determine water presence in well bore fluids. Flow Meter (Spinner) Type: Continuous Sensors: Reed Switch / Magnetic Resolution: 0.25 rps or 0.08 rps Data Status: Velocity / Direction / Diagnostics Output Logging Curves Gamma Ray Collar Locator Pressure Temperature Capacitance Flow Velocity Pressure Gradient Temperature Gradient Compensation Temperature Line Speed Time and Depth

Onboard diagnostics record systems failures to allow compensation of data while logging at these extremely high temperatures. This gives a quality control base to cross reference-acquired data to downhole events, rather than possible tool problems.

Geothermal Production Logging Tool

This tool was developed for the Geothermal Industry and Scientific Community to allow surveillance of steam wells used in the generation of electricity. We have successfully logged wells with a bottomhole temperature of over 650^oF.

The Geothermal Tool contains all the sensors our other Slicklogger® systems do with the exception of a capacitance (dielectric) probe. However, it is rarely needed in applications at its designed temperature range. The Delta Pressure calculations suffice for fluid identification in that realm.

While the tool has the capability to be run as a memory tool, it is most often used with e-line in a surface readout configuration.

Tool Length Memory Configuration 16' 4" E-Line Configuration 10' 5" Tool O.D. 1.77" Pressure Sensor Type: Quartz Crystal Accuracy: ± 0.03% F.S. Resolution: 0.01 psi Ranges: 10k, 16k, 20k Make: Quartzdine Temperature (Borehole) Rating: 650 degrees F Type: Platinum RTD Accuracy: ± 1 Deg. C. Resolution: 0.001 Deg. C. Response: 0 - 100 Deg. C (4 seconds) Temperature (Compensation) Accuracy: ± 1 Deg. C. Resolution: 0.01 Deg. C. Optional Gamma Ray Detector Type: Scintillation Collar Locator Type: Coil / Rare Earth Magnet Flow Meter (Spinner) Type: Continuous Sensors: Reed Switch / Magnetic Resolution: 0.25 rps or 0.08 rps Data Status: Velocity / Direction / Diagnostics Output Logging Curves Gamma Ray Collar Locator Pressure Temperature Flow Velocity Pressure Gradient Temperature Gradient Compensation Temperature Line Speed Time and Depth Onboard diagnostics record systems failures to allow compensation of data while logging at these extremely high temperatures. This gives us a quality control base to cross reference-acquired data to downhole events, rather than possible tool problems.

The Purpose of Production Logging

A typical assumption that may be made is that production is coming only from the perforated zone. It is not uncommon to find production communicating behind the pipe from a supposedly "isolated zone" and entering the wellbore at the perforated interval. Many times, the perforated interval will be depleted and accepting crossflow from the "isolated zone". This production may, or may not be lost due to economic restraints and it will certainly cause a conflict in the reserve calculations for the two zones. Future completions could also be jeopardized by this unintentional and uncontrolled depletion.

Case in point:

A customer called wanting to know his options for determining where a foamed cement or polymer squeeze would go to if he pumped one in his well. The field had a history of a bottom water drive encroaching up to the productive pay and he was concerned how much damage the partially depleted zone would incur during a squeeze job. His concern was justified in that this well was the best producer in the field and several of his past treatments were failures. The wells made more water and less hydrocarbons after the treatments.

It was suggested that he use a production log to identify the problem and then design a conformance treatment for that particular problem. The production log indicated that the water source was not from below as anticipated, but from 400' above the primary pay. The water source was also crossflowing into the primary pay. The solution was as simple as a few perforations and an old fashioned "Bullhead Squeeze". Relatively low tech and low cost, but an adequate solution.

What if:

Where do you think the polymer or foamed cement treatment would have gone had the job been run on the assumption? It would have gone to the lowest pressured interval in the well, which is the primary pay.

Principles Of Operation - Sensor Measurement

Frequency Measurement

The instrument - using a standard time-period-averaging technique, measures time period, rather than frequency. The sensor signal is used to gate a high frequency (8 MHz) reference clock, which effectively times a known number of sensor signal cycles.

At calibration time, the minimum possible frequency over the working temperature and sensor range is determined, and used to calculate how many sensor signal cycles can be counted in a given measurement time. We presently calculate this figure for 1, 2, and 3 seconds, and the instrument dynamically decides which figure to use depending on the sampling rate selected by the operator. Thus, a sampling rate of 3 seconds will have better resolution than a 1 second rate. Again this is dynamic and during the job the resolution will change depending on the sample rate at a given time.

Example Pressure Resolution Calculation

Given a one second sampling interval, with some overhead time for data transmission and other measurements approximately 650 ms is available for pressure frequency measurement. At a minimum pressure crystal frequency of 23 kHz, the number of cycles occurring in 650 ms is 23000 x 0.650 = 14950.

The tool will therefore count 14,950 pressure signal cycles and use the 8 MHz reference clock to measure elapsed time, to the nearest eight-millionth of a second. At minimum pressure, therefore, the number of reference clock cycles is 8000000 x (14950 / 23000) = 5,200,000.

Typically, the maximum frequency for a 10,000 psi transducer is 50055 kHz.

At the maximum pressure (and the same temperature) the number of reference clock cycles becomes 8000000 x (14950 / 50055) = 2,389,371.691. A digital counter cannot count 0.691 clock cycles, so it will count either 2,389,371 or 2,389,372 cycles, depending just where in the 8 MHz pulse train the gate opened. The pressure variation represented by this one cycle uncertainty is usually quoted as the sensor resolution, thus:

Resolution	= Sensor Range x (1 / cycle count range)
Or	= 10000 x (1 / (5,200,000 - 2,389,372)
Or	= 10000 x (1/ 2,810,628)
Resolution	= .0036 psi

It is clear that resolution depends on:

(a) Time available for measurement

(b) Reference clock frequency

(c) Dynamic range of the sensor

The measurement time can be adjusted to make the best use of the sensor sampling rate. Using the 8 MHz clock and by sampling at least three second intervals, the resolution on the above sensor will be better than .001 psi. According to some schools of thought, resolution should be represented by the RMS deviation from the "correct" calculated pressure, which leads to figures some 2 to 3 times more optimistic than the ones shown.

Characterization

We use a hybrid polynomial/look-up table characterization scheme. The program looks up the nearest four known calibration points at each of the next two calibration temperatures above and below the well temperature, and performs a local two-dimensional polynomial approximation. This method has the advantages that the characterization error is by definition zero at the calibration points, and it is an order of magnitude less than that of a global polynomial at intermediate points. It also allows calibration down to atmospheric pressure without the risk of higher readings being skewed by non-linearity at the bottom of the range; and it allows reasonable extrapolation at temperatures below the lowest calibration temperature.

It is recognized that reference crystals are affected by temperature. We characterize each sensor over temperature with its associated sensor-processor module, ensuring that the overall characterization takes into account variations in reference oscillator frequency.

The raw sensor frequencies as measured at calibration time are stored in EEPROM in the sensor-processor module itself, along with the calibration date. If the surface computer does not contain the current calibration file for the tool at the data upload, the calibration information is automatically uploaded. The storage of raw information rather than polynomial coefficients permits after-the-fact choice of characterization scheme. It also allows for reprocessing data after re-calibrating the tool.

How do memory logs work?

Tubing Checks - Leak Detection - Gas Lift Analysis

An excellent use for the Slicklogger® PLT Systems is to perform tubing checks. It is a quick, economic, and accurate means of identifying tubing leaks, gas lift leaks, and inoperative gas lift valves. Tubing leaks can be found by mechanical means but this usually takes days to complete. The initial costs associated with the mechanical methods are lower and can appear to be the most cost effective; however, they rarely are, due to the amount of time needed to define a depth range of +/- 20 feet. PL can tell you within a foot.

Other practices of data acquisition for gas lift analysis are being replaced by the dynamically acquired pressure data from a dedicated logging system. Stationary pressure gradient stops have been used since the conception of pressure gauges (bombs). It is normal procedure to make gradient stops in and around gas lift mandrel at 500' increments. If you really want to narrow in, you might have the stops 100' apart in critical areas. Thus, your resolution of data points is 100 - 500'! The Slicklogger® Systems will supply you a data point on a per foot basis. In addition, the other sensors in the tool can identify the conditions within the tubing at the time the data is acquired. You don't have to settle for stationary readings 500' apart where your only control factor is to take long-term reading so that you can average the data and guess at the conditions during acquisition.

Locating Water Source With Temperature Logs

Production Logging actually began in the late 1930's with the introduction of temperature measurements in oil and gas wells. Production logging strings have become more sophisticated at qualifying and quantifying flow profiles in the wellbore. Basically, the production logging string obtains a density and a flow velocity measurement that are then introduced to programs that will calculate where the fluid is entering, the type of fluid, and the quantity of the entry. Flow characteristics such as turbulence, circulating fluids, and slugging can influence spinner and density type sensors rendering the data useless for analysis.

Although very accurate and reliable, temperature is often neglected as the proper tool for identifying water source. Temperature can be measured accurately no matter what the flow conditions of the well. Temperature logs also tend to reflect long-term behavior in a well, not just current conditions.

If some of the produced fluid is water, it is not enough to just know where the water is entering. It is critical to know its origination. Is it fingering in with the production, channeling from above or below by the cement, coning from above or below via the formation, or is the reservoir depleted and "water drive" the source. Finding the source of water will typically require the investigation to be carried out behind the pipe. The most reliable way to find fluid movement behind the pipe is to measure the temperature changes created by that movement.

To interpret the temperature log, one must understand the various factors that influence temperature behavior in the well. These include the natural temperature of the formations penetrated by the well, heat conductivity between the well and surrounding formation, diffusivity of mechanicals such as packers, heat convection attending fluid flow, and thermal changes of fluids under dynamic conditions.

The generation and dissipation of the earth’s heat is ad infinitum. The heat flux from the core travels to the surface through the various lithologies. This geothermal profile will vary from area to area and the slope of the geothermal temperature versus the depth (referred to as geothermal gradient) will vary from formation to formation. The geothermal gradient depends on the thermal conductivity of the lithology. The higher the thermal conductivity, the more easily the heat is transported through the rock. Though varying at different locations, the gradient will typically be 1^o F/100 ft. to 2.5 ^o F/100 ft. This gradient is key and becomes the reference when interpreting temperature logs. While the fluids trapped within the earth remain static, the geothermal gradient will be normal for that area. Once the fluid moves, it will transport some of the temperature from its depth of origin. When the fluid moves it will change the temperature around the borehole where it travels. The new amount of temperature change per depth then becomes a dynamic temperature gradient. The rate or slope of this temperature change will be steeper near its origin and gradually move parallel to the normal geothermal slope. Actual temperature at a given depth will then be different from the normal geothermal temperature.

If the fluid movement ceases, the temperature in the well will start to move back to the original geothermal temperature for that area and depth. This "decay" in temperature back to normal will be determined by the time of the fluid movement, the volume of fluid and the conductivity between the well and the formation. The "temperature decay" is extremely useful in qualifying fluid movement and in some cases the movement can be quantified.

A log from a water injection well (Figure 1 and Figure 2) demonstrates the use of temperature decay to interpret logs. These examples are the same well and same log but different views and scales.

The well had been injecting 500 BWPD with an injection pressure of 800 psi and then the pressure dropped to 500 psi although the injection volume remained the same. The spinner indicates that the water is exiting the borehole at the top of the upper set of perforations. This temperature survey indicates that the water is exiting the wellbore at the upper perforations and then channeling up behind the pipe to the area at 1525 feet. The temperature is also indicating the long-term behavior mentioned earlier. Although no water is exiting the bottom set of perforations, the cool anomaly at the bottom perforations is a result of the prior injection and full recovery to normal geothermal temperature is not yet complete. Prior to injection the temperature in the wellbore is near the normal geothermal gradient. Once injection begins, the temperature of the injected fluid will start to change the original temperatures at any place in the well through which it moves.

This example well (Figure 2) demonstrates temperature characteristics in the shallow depths where the injected water is warmer than the geo-temperature. At 1200 ft, in this example, the average injected water temperature and the well geothermal temperatures are the same. Above that depth the injected water is warmer, below that depth the injected water is cooler.

When the geothermal temperature becomes warmer than the injected water temperature, the curve and the decay curves "cross". Typically, the fluid will be cooler than the earth at the depth of entry to the formation but this must be known for correct interpretations. As more and more fluid invades and is "stored" in the formation, the temperature there will approach the temperature of the fluid at the point of injection. Below the point of injection or below the area of storage, the temperature remains near the normal geothermal temperature.

When injection is stopped, the well will recover toward the original temperatures prior to injecting. Determining the amount of time for recovery takes gives a great deal of information. In the wellbore above the injection zone, the temperature in the well will recover faster. Over the area of storage, the well will recover much slower depending on the volume of water injected. Below any injected water storage, the temperature will have remained near the norm. Thus, the injecting temperature curve versus depth of a water injection well will have a steeper slope and cooler temperature above the injection or storage area and would recover rapidly to the normal geothermal temperatures below the area of injection.

In this example there is no fluid movement at this time below 1730 ft. The shut in temperature curves will become warmer faster in the area above the injected water but will indicate warming much slower over the injected interval. Below the injected interval the flowing and shut in temperatures will be the same.

The log (Figure 2) indicates that the injected water is exiting the wellbore and channeling up behind the pipe to1525 ft. At depths above the channel, the temperature decay is normal. In the channel and storage area, the temperature first moves toward the average temperature of the injected fluid and then will decay back to the normal gradient much slower than where there is no channel or storage. Producing wells can be more complex because flow in the formation is taking place and heat transfer from forced convection and conduction, and Joule-Thomson heating or cooling of the fluid can be significant. However, the temperature log can be used as a means to evaluate well characteristics by measuring and analyzing anomalous temperature behavior.

A producing well with water channeling from below the perforated interval is shown (Figure 3). The well had been shut in several days prior to logging. A base temperature run was made with the well shut in. Then the well was opened to flow and logging surveys were made at one hour, two hour, and three hour intervals after flowing the well. The results show the water moving up behind the pipe from 6075 feet and entering the wellbore at the perforations. The fluid warms the area it moves through quickly and each successive pass defines the source more precisely. Note the small difference between the shut-in and flowing temperature below any area of flow. This is due to the release of pressure causing the fluids to cool. The temperature cools immediately when the pressure drops and then begins to decay back to normal. The amount of change in the area below any fluid movement is dependent on the amount of pressure change between shut-in and flowing and the rate of that change. It is important to note that although the absolute temperature changes the slopes of the curves remain constant.

The fact that the temperature at 6075 ft. increases to above the normal geothermal temperature indicates that pressure is driving this fluid and Joule-Thomson heating is occurring. This heating is again seen at 5970 ft. when the fluid enters the wellbore. There are also examples of Joule-Thomson cooling effects at 5932 and 5952 ft. where gas is entering the wellbore. Simplified, if a non-compressible fluid (water) is moved through an orifice heating will occur. If a compressed fluid (gas) moves through an orifice then cooling will occur.

Maxim Technology Limited

Maxim Engineering Centre,

Vale Business Park,

Cowbridge, Vale of Glamorgan,

Wales, UK.

www.maximtech.co.uk

MAXIM Technology’s range of products can be deployed on either electric wireline for surface read-out (SRO) or memory for downhole recording.

MAXIM's High Speed Telemetry interface (HSTi) system is used to transmit data from downhole tools to a surface acquisition system and is one of the fastest available for use on monocable. Inter-tool communication is available via the Downhole Tool Bus (DTB), which enables very high-speed communication between tools and downhole data processing.

The High Capacity Memory Cartridge (HCMC) facilitates Downhole data recording, which is available with memory in increments of 16 MB for almost unlimited recording capability.

All tools are built using approved NACE specification materials (MRO175) for use in wells containing H₂S and/or CO₂.

Amongst other products, Maxim manufactures the world’s shortest 9-sensor production logging tool (PPL).

Maxim Product Codes and Description

101 Accelerometer Velocity Tool

Measures changes in tool string velocity (acceleration) along the wellbore axis, and also measures wellbore deviation. Enables correction of data corruption caused by tool yo-yo and stick-slip motion.

102 Casing Collar Locator

Detects joints between lengths of casing. A special CCL is designed to detect flush-joint casing.

103 Scintillation Gamma Ray

Measures natural background radiation - used as a depth control device and to tie-in cased hole logs with openhole logs.

104 Quartz Pressure Tool

Measures downhole pressure using a quartz pressure gauge.

105 Temperature Tool

Performs a precision, high-resolution measurement of downhole temperature.

106 Caliper Fullbore Flowmeter

Combines a two axis caliper to measure wellbore diameter with a flowmeter to measure fluid flow, and provides lower centralization when deployed with PPL.

107 In-line Flowmeter

Measures flow of fluid in the well. Small diameter so can measure flow in tubing as well as casing.

108 Radioactive Fluid Density Tool

Measures fluid density using a low energy radioactive source, in order to derive fluid identity (oil/water/gas).

109 Differential Pressure Fluid Density

Measures fluid density using a precision differential pressure gauge.

110 Water Hold-up Tool (sometimes referred to as CWH, capacitance water hold-up)

Measures hydrocarbon / water ratio in the well.

111 Centralizer

Centralizes the tool string in the wellbore.

112 Caliper

Measures diameter of casing or tubing.

113 Knuckle Joint

Allows decoupling of section of a logging tool string in order to run some elements centralized and others eccentred.

114 Swivel Joint

Allows rotational movement between the cable head and the toolstring below to allow cable to ‘untorque’ as it is run in the well.

115 Head Tension Voltage Tool

Measures tension and compression at the tool head as well as tool head voltage.

116 Addressable Release Tool

Enables engineer-controlled release of part of a cased hole toolstring in the event that the toolstring becomes stuck.

117 Pocket Production Logging Tool

Ultra-short, all-in-one production logging tool. The basic unit measures pressure, temperature, gamma ray, fluid capacitance, and CCL.

118 Horizontal Fluid Profile Tool

Used to derive fluid identity and flow rates in highly deviated or horizontal wells.

119 Orientation Velocity Tool

Measures tension and compression at the tool head, tool head-voltage, deviation and tool orientation.

125 High Speed Telemetry Interface

Fully digital mono/co-axial cable telemetry system comprising downhole electronic cartridge (HSTC) and surface panel (HSTP) or DELTA surface system

126 Digital Evaluation Logging Tool Acquisition System

Highly compact computer based surface system used to acquire log data in real time. Employs a Windows-based system for ease of use and flexibility.

127 Memory Crossover Tool

Enables a third party memory tool to be run with Maxim downhole tools.

128 Vibration Monitoring Tool

Measures vibration occurring in a stuck drill pipe downhole.

129 Fluid Identification Tool

Identifies the proportion of each fluid type (oil/water/gas) in order to derive the volumetric flow rate of each component in the well.

130 Fluid Diverter Tool

Forces all flow from a low flow rate well through a small orifice in order to make accurate measurements of flow rate and fluid identity.

131 High Capacity Memory Cartridge

Records log data downhole for later retrieval and viewing on a PC.

132 Fixed Cage Flowmeter

A bottom flowmeter with a fixed diameter impeller used where a CFF is not appropriate.

133 Multifinger Caliper

A caliper with a high radial density of measuring fingers used to monitor casing/tubing corrosion, erosion and wear.

134 Electromagnetic Thickness Tool

Measures the metal loss in corroded/eroded downhole tubulars. Combinable with the MFC.

Oildata Wireline Services

Oildata Wireline Services Limited

Plot 282, Trans Amadi Industrial Layout

PMB 074

Port Harcourt, Rivers State

Nigeria

http://www.oildatainc.com/index.html

Introduction

Oildata's Production Logging Tool has been used to successfully record single and multi-phase PLT surveys on numerous horizontal and vertical wells in Nigeria. The tool simultaneously records measurements from up to twelve (12) independent, high-resolution sensors.

Description

The Memory/Real-Time Production logging tool simultaneously records data from up to twelve different production log sensors (e.g. Spinner, Gradiomanometer, Capacitance, Gamma Ray, Temperature, Caliper etc.) in addition to the Casing Collar Locator and Quartz Pressure. In memory mode, log data are stored in a downloadable memory tool. The tool string can be deployed on slickline, coiled tubing or e-line depending on the logistics. In memory mode, depth correlation is achieved by simultaneous recording of the depth and time via an electronic encoder and depth-time interface and correlating the resulting output logs (e.g. Gamma Ray and Casing Collars) to the existing open hole logs.

High-resolution measurements are taken over a sample interval as small as 10 samples a second and stored in non-volatile memory which has capacities as large as 50Mb. Data files and logs can be transmitted using a modem link to any location from the well site. Interpretation is performed at the well site with aid of a computer-based Cased Hole interpretation package. Final interpretation is done at our Computer Centre. It is virtually impossible to distinguish data acquired in Memory or Real time modes.

Applications

· Determination of the contribution of individual zones to total production. Determination of quantitative flow rates

· Accurate measurement of after flow in high permeability reservoirs.

· Well performance evaluation.

· Water Injection/Dump Flood profiles

· Identifying fluid entries and exits.

· Identifying anomalous flow behind casing or tubing.

· Determination of scale buildup in casing or tubing.

Tool Specifications

	Tool	Function	Outside Diameter (Inches)	Length (Inches)	Max. Temp. (^Of)	Maximum Pressure (Psi)	Accuracy/ Resolution	Measurement
	Coil Tubing X/O or Telemetry Tool	Connects to Standard Coiled Tubing/Transmits real time data	1.6875	18.5	300.0	5,000
	Memory Tool	Stores tool program and data	1.6875	24.4	300.0	5,000	0.10 to 1 sec sampling	512Kb -50Mb
	Casing Collar Locator	For Depth Correlation	1.6875	18.5	320 - 350	5,000
	Knuckle Joint	Allows sections of the tool string to be centered whilst centralizing other sections	1.6875	6.5	400	5,000
	Gamma Ray	A high resolution scintillation detector for correlation to open hole logs	1.6875	26.5	320 - 350	5,000	1 cps/API unit
	Dual X-Y Caliper	A Tool similar to the single Caliper, but measures with high repeatability in X and Y axes.	1.6875	41	320 - 350	5,000	0.1"/0.015"	2-3/8" TBG to 9-5/8" casing
	Single Caliper	Measures the casing I.D. in one axis.	1.6875	35.25	320 - 350	5,000	0.1"/0.015"	2-3/8" TBG to 9-5/8" casing
	Thermometer	High precision temperature probe.	1.6875	15	320 - 350	5,000	0.9^oF/Infinite	350^oF Max
	Quartz Pressure	A quartz precision pressure sensor.	1.6875	12.13	320 - 350	5,000	0.005%	0 - 15,000
	In-Line Flowmeter	A rugged spinner flowmeter for continuous measurement of fluid velocity, with a protected impeller.	1.6875	17.31	320 - 350	5,000	-3.0%	600 - 6000,000 bpd
	Fluid Density (Radioactive)	Records continuous fluid density measurements	1.6875	26.53	320 - 350	5,000	0.03g/cc	0 - 1.3g/cc
	Fluid Capacitance	A flow-through device to measure water hold-up to 50% in any flow rate	1.6875	26.2	320 - 350	5,000	1.0%	0 to 50% Hold -Up

Diagnostic Technology

This category involves the application of diagnostic surveys designed to identify specific sources or causes of downhole well problems. Services run in this phase include production logs, noise logs, multi-finger imaging logs, and Compensated Neutron logs.

Production Logs involve the simultaneous real-time or memory record of downhole production using up to 10 independent sensors including Gamma ray, Collar locator, flow meter, fluid density, X-Y caliper, temperature, in-line flow meter, and quartz pressure.

Noise Logs detect downhole audio frequency and amplitude variations due to fluid movements.

The dual or compensated Neutron Log is used to identify gas-oil contacts, monitor gas-cap movements and as an alternative correlation tool. (The memory version of this tool is deployed on slickline).

The Multi-Finger Imager Log provides high-resolution images of the internal corrosion condition of tubing and casing by recording simultaneous independent measurements from up to 40 mechanical feelers or calipers. (This tool can be deployed on slickline or electric line).

Data recorded with memory tools is stored in a downloadable memory tool and subsequent "depth-to-time-to-data" merges result in a depth-matched log, which is of comparable quality to real-time generated logs.

The Memory Dual Neutron Tool (MDNT)

This is designed to investigate formation gas contacts in cased wells. The tool is deployed through tubing on Slickline. The MDNT employs an AmBe neutron source and two thermal neutron detectors in an arrangement commonly known as a Compensated Neutron Tool. Depth correlation is achieved with the Gamma Ray tool run in combination. Uses can include:

· To detect gas contacts through-tubing.

· To detect qualitatively, depletion in producing well.

· Cased hole porosity estimation.

· Depth correlation when there is minimal Gamma Ray character

Outer Diameter	1.6975"
Length	5 Feet
Detectors	Helium 3 Detectors
Acquisition Electronics	Digital Transmission/Memory
Memory Capacity	512Kb to 32 Mb
Battery Duration	1 day to 1 week
Standard Logging Speed	1800ft/hr (30ft/min)
High Resolution Logging Speed	9000ft/hr (15ft/min)
Shop Calibration	Shop Tank Counts Ratio
Tool Positioning	Eccentralized by Knuckle Joints
Typical Combination	MDNT-PRT-PGR-CCL-QPS-MPL-POWER SUPPLY
Maximum Temperature	350^oF
Casing Range	4 1/2" to 9 5/8"
Bore Hole Fluid	Liquid
Repeatability	+/- 10% (Logging speed dependent)

http://www.readgroup.no/group/index.asp

Facility.......................................................... Ravnsborgveien 56, Hvalstad, Oslo

Postal Address.......................................... P.O. Box 193, N-1360 Nesbru, Norway

Read Well Services offers flow measurement and fluid identification devices for reservoir and production monitoring. The production logging (PL) system is compact and portable. It is ideally suited to concurrent well deck operations offshore or mast operations onshore. Downhole tools are operated by a single engineer on any type of electric wire line or alternatively in memory slick line mode. “They offer cost effective and reliable solutions for reservoir monitoring. With a complete production well tool string 6 meters in length and an injector string of less than 4 meters this is one of the most flexible systems available.”

The standard sensors, which include quartz pressure, temperature, gamma ray, collar locator and caliper, are complemented by specialized devices: · High resolution temperature sensors for pinhole leak detection · Diverter flow meters for precise zonal flow allocation in deviated or low rate wells · Nuclear fluid density device unaffected by LSA scale.

Schlumberger

http://www.connect.slb.com/index.cfm?id=id4638

FloView

Applications and Benefits Accurate water holdup First oil-entry detection From bubble count measurements Works at high water cut First water-entry detection for water shutoff (at low water cut) Caliper measurement Fresh and injected water differentiation Features Four resistive probes for direct measurement of holdup and bubble count Single-axis caliper measurement Relative-bearing measurement to locate sensor position in the pipe Oriented images of water holdup and bubble count Water holdup cross-section images for highly deviated and horizontal wells from FloView Plus service and MapFlo multiphase flow mapping in deviated wells Estimated hydrocarbon flow velocity Water salinity change detection No calibration required Not sensitive to friction effects and salinity changes Self-centralized

FloView service provides indication of fluid entries in the borehole. In this example, both the FloView tool and the gradiomanometer detect the gas entry at about X800. However, only the FloView tool shows the water entries in the lower set of perforations.

The FloView Plus service provides cross-sectional views of flow in horizontal sections. In the cross section above, phase segregation is shown in an oil-water flow at 90° deviation. Probe positions are shown by the dots.

The FloView tool has four probes that make independent measurements of the multiphase fluids in each quadrant of the pipe. These point sensors measure the local resistivity of the fluid: high for hydrocarbons and low for water. When a probe pierces impinging droplets of oil or gas in a water continuous phase (or water droplets in an oil continuous phase), it generates a binary output signal. These signals allow determining the local water holdup and the number of hydrocarbon bubbles arriving at each probe (bubble count). The probes cannot discriminate between oil and gas.

Relative bearing is used to locate the position of the probes within the pipe cross-section (with respect to the high side of the pipe). The FloView tool uses this positioning data to generate oriented images of water holdup and hydrocarbon flow distribution versus depth. The sonde also has an accurate single-axis caliper and is self-centralized to reduce the tool length.

The FloView tool is combinable with the conventional production logging sensor suite. FloView Plus service combines two FloView tools to double the coverage in the pipe cross-section. The resulting images of the flow regimes and holdup distribution allow complex diagnosis in highly deviated and horizontal wells.

FloView Specifications
Length	6.8 ft [2.07 m]
Diameter	1 11/16 in. [4.29 cm]
Weight	28 lbm [12.5 kg]
Maximum temperature	300°F [150°C]
Maximum pressure	15,000 psi [1000 bar]
Water holdup accuracy	5%
Fluid Entry
Depth resolution	<1 ft
Threshold	50 B/D
Caliper Measurements
Caliper range	2 to 9 in.
Accuracy	0.25 in.
Resolution	0.1 in.
Tool operation requires fluids not in emulsion and bubbles sufficiently large compared with the size of the probe tip.

FloView Local Measurement Principle

The four probes of the FloView tool make independent measurements of the local resistivity of the fluid: high for hydrocarbons and low for water. When a probe pierces impinging droplets of oil or gas in a water continuous phase (or water droplets in an oil continuous phase), it generates a binary output signal used to determine the local water holdup and number of hydrocarbon bubbles arriving at each probe (bubble count). The probes cannot discriminate between oil and gas.

FloView Tools

Two FloView tools in combination form the FloView Plus service, run as part of the PL Flagship production logging tool string. Measurements of holdup and phase velocities allow diagnoses of the flow regimes in both highly deviated and horizontal wells.

FloView Probe Positions of the FloView probes along the arms are set at the surface.

PS Platform

Features

Comments

Applications · Identification of water, oil and gas entry points · Two- and three-phase flow profile determination · Production logging in horizontal, deviated and vertical wells · Logging in wells with limited surface area or rig-up height Features · Integrated directional fullbore spinner with independent X-Y caliper and local holdup probes 16 in. [40 cm] from tool bottom · Physical combinability with various perforating and logging services · Common sensors for memory and real-time applications · Resistance to corrosion (exceeding NACE specifications) · Logging-while-drilling environmental specification · Condensed packaging · High-quality pressure data (CQG Crystal Quartz Gauge)

The PS Platform* tool string is used for determining the downhole flow regime. To reduce overall operation logistics, the PS Platform tool string acquires the same measurements in either memory or real-time mode. The tool design [per Schlumberger] provides the most sensors per linear foot available in the industry - making it the shortest tool. There is conveyance on any type of wireline or multiline (conductive slickline). Memory services have been completed on slickline, on coiled tubing and below tubing-conveyed perforating guns. “Sensors are so stable that wellsite calibration is not required.” By integrating a spinner, X-Y caliper and local probes, the average velocity, hole size and geometry, and water holdup are independently measured as the required inputs for calculating individual flow rates. All these sensors are located 16 in. from the tool bottom, which allows logging in wells with reduced sumps. The Flow-Caliper Imaging tool includes a directional fullbore spinner, an independent, self-centralizing X-Y caliper with a significant range, and local electrical probes. The FloView* probe technology directly determines water holdup, and a bubble count measurement yields a simple, robust estimate of hydrocarbon flow rate and accurate identification of fluid entry points. In wells with high producing rates, jetting influence is minimized and friction effect is compensated for by the design of the Gradiomanometer* tool. A choice of high-resolution CQG* Crystal Quartz Gauge, Sapphire* strain pressure gauge or an additional quartz gauge offers flexibility for high-profile surveys or advanced well testing. When in recorder mode, the data are memorized downhole and retrieved at surface with a portable acquisition system. Each sensor can be programmed up to 10 data points per second, and more than 100 hr of continuous data can be recorded.

Combined Services

Wellbore and reservoir characteristics are defined through simultaneous real-time logging combinations. The GHOST* Gas Holdup Sensor Tool quantifies gas holdup and differentiates gas and liquid entries. The RST* Reservoir Saturation Tool offers sigma, carbon-oxygen, water flow, three-phase holdup and spectrometry logging. The SCMT* Slim Cement Mapping Tool evaluates the cement-to-casing bond and locates channels. The FloView device adds additional electrical probe sensors to increase wellbore coverage in deviated or horizontal wells. The PS Platform string combines the Basic Measurement sonde and the Flow-Caliper Imaging tool in 13.5 ft [4.11 m]. This minimum configuration, along with the optional Gradiomanometer and UNIGAGE* carrier tools, logs in both memory and real-time modes. The additional GHOST, FloView, RST and SCMT tools provide answers in real time.

PS Platform Specifications

Maximum pressure				15,000 psi [1035 bar]
Maximum temperature				300°F [150°C]
Maximum tool OD (no rollers)				1 ^11/16 in. [43 mm]
Maximum tool OD (rollers)				2 ^1/8 in. [54 mm]
Shocks				Class 6 specifications
H2MS Exceeds				NACE specifications
Sensor	Length		Measurement			Accuracy		Resolution
Basic measurement sonde	8.3 ft [2.52 m]		Pressure (strain gauge) Pressure (quartz design) Temperature			± 6 psi [0.4 bar] ± 1 psi [0.07 bar] ± 0.01% full scale 1.8°F [± 1°C]		0.1 psi [0.007 bar] 0.01 psi [0.007 bar] 0.01°F [0.006°C]
Gradiomanometer Tool	4.8 ft [1.45 m]		Fluid density			± 0.04 g/cm^3		0.002 g/cm^3
Flow-Caliper Imaging tool	5.2 ft [1.59 m]		Flowmeter Water holdup Bubble count Relative bearing X-Y caliper (2-11 in.)			5% (2% Hw > 90%) 10% in oil continuous phase 10% (bubble size > 0.04 in. [1 mm]) ±6 ° 0.2 in. [5 mm]		2 ft/min [0.6 m/mm]
UNIGAGE carrier	4.2 ft [1.27 m]		Pressure (quartz gauge)			± 1 psi [0.07 bar] ± 0.01% full scale		0.01 psi [0.0007 bar]
FlowView Tool	6.8 ft [2.07 m]		Water holdup Bubble count Relative bearing 1-axis caliper (2-9 in.)			Same as Flow-Caliper Imaging tool 0.25 in. [5 mm]		0.1 in.
Ghost Tool	7.1 ft [2.18 m]		Gas holdup Bubble count Relative bearing 1-axis caliper (2-9 in.)			5% without probe protector 7% with probe protector Better than 0.1% for 2%> HG> 98% 1% (bubble size > 0.002 in. [0.1 mm] ± 6° 0.25 in. [5 mm]		0.1 in.

RST Specifications

Maximum pressure		15,000 psi [1035 bar]
Maximum temperature		300°F [150°C]
Maximum tool OD (RST-A)		1.68 in [43 mm]
Maximum tool OD (RST-B)		2.5 in. [63 mm]
Sensor	Length		Measurement
RST-A tool	23 ft [7.01 m]		Sigma Porosity C/O ratio Spectrometry Water flow log Three-phase holdup log
RST-B tool	22 ft [6.7 m]		Sigma C/O ratio Spectrometry

CMT Specifications

Maximum pressure			10,000 psi [670 bar]
Maximum temperature			300°F [150°C]
Maximum tool OD			1 ^11/16 in. [43 mm]
Sensor	Length	Measurement		Resolution
SCMT	10.9 ft [33.3 m]	Amplitude Cement map		2 in. (at 1800 ft/hr)

An Example:

The following example was for a producing well. Nevertheless, similar considerations can be applied for an injector. There may be less concern over the oil and water percentages, unless this is run in a producer, which has seen breakthrough from an injector.

The PS Platform service was run in a well having 5-in. casing, a deviation of 31° and unwanted water and gas production. The objective was to obtain a flow profile and determine water and gas entry points.

The well was logged using a string composed of one weight bar, the PS Platform Basic Measurement sonde equipped with a telemetry module and a Sapphire strain gauge, the Flow-Caliper Imaging tool and, because three-phase flow was expected, a Gradiomanometer sensor. The total operating time was 3 hr.

The thermometer reacted strongly to the top two fluid entries, and the bubble count measurements gave even sharper indications of hydrocarbon entry points than did the spinner. The X-Y caliper data indicated scaling and casing corrosion, as well as probable damage from perforations at X640 ft and X320 ft.

The three-phase flow profile indicated that:

• The first production comes from an entry a few feet above total depth (X645 ft) that is producing 800 BWPD and 150 BOPD.
• The second entry (X440 ft) also produces water and oil: 2200 BWPD and 500 BOPD.
• The third entry (X320 ft) produces no water but produces a large amount of gas and 2000 BOPD.

Based on this interpretation, other wells in the area were reevaluated to determine if this lower (X645) interval was present and could be completed to add to production. After removing fill in the wellbore of one well, this interval was perforated and initial production increased by 500 STB of oil per day.

Spartek Systems

#4 - 4 Erickson Crescent

Sylvan Lake, Alberta,

Canada T4S-1P5

http://jaguar.rttinc.com/~spartek/index.htm

SS8000 Production Logging Tool String

The SS8000 is a1" O.D. production logging tool string. The fullbore spinner module will collapse to 1.25 inches. The system includes a Sapphire based pressure sensor, RTD platinum wire fast response temperature sensor, fluid capacitance meter, x-y caliper, gamma ray, CCL, and integrated z-axis accelerometer measurement. The telemetry/power module provides for real time bi-directional communication with the host surface logging system.

The system can be used for monitoring CO₂ and waterflood projects.

	Operation Specifications:
	Temperature range		150^oC
	Pressure Rating		10,000 psi (maximum)
	Module		Length	Diameter
	Fullbore Spinner		2.20 ft	1.25 in
	Pressure/Temp/Capacitance		2.70 ft	1.00 in
	Power/Telemetry Module		2.50 ft	1.00 in
	X-Y Caliper		3.20 ft	1.00 in
	Gamma Ray  / CCL		3.29 ft	1.00 in
	Housing Types	Stainless 17-4 Inconel 718 (Optional)
	Performance Specifications:
	Pressure Accuracy	0.022 % Full Scale
	Pressure resolution	0.0004% Full Scale
	Pressure Drift	<3 psi/year
Primary Features · 1" OD · Compact Length · Modular  · Built in Diagnostics	Applications · Monitoring Well Performance · Problem Diagnostics · Time Lapse Logging · Tracer Injection

Subsurface Technology AS

Subsurface Technology AS ("SubTech") [now part of Weatherford] have, developed and provided custom-built TFL ("Through Flow Line", or "Pump Down") tools. Saga Petroleum ASA had used TFL for well maintenance on Snorre. SubTech developed hydraulic/mechanical operated TFL tools for Saga. The tools provided, could locate and position a memory-based production logging tool (PLT) string.

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[1] While this organization apparently serves U.S. based operations, their web site information on PLT is quite comprehensive and useful for those who are not experienced with PLT.