Production logging

While most types of logs are used to characterize the wellbore, formation, and fluids prior to well completion, a number of logging tools are available to provide information during production operations and beyond. This article discusses the various types of production logs and how they can often be used together to provide crucial information for understanding and resolving problems..

Production logging

Production Logging is one of a number of cased hole services that includes cement monitoring, corrosion monitoring, monitoring of formation fluid contacts (and saturations), perforating and plug and packer setting. Services performed in dead, overbalanced, conditions can use relatively simple surface pressure control equipment and are often performed using large open hole style logging cables. With a well that has pressure at surface it is normal to use a small logging cable in order to;

1. Minimise the tool weight needed to overcome the well pressure trying to extrude the cable.
2. Minimise the grease injection requirements to seal around a wireline cable.

Wells with surface pressure typically have a completion tubing of relatively small internal diameter, ID, compared to the casing size across the reservoir. This reduced ID means that cased hole toolstrings for live wells are typically sized at 1-11/16" in order to pass through the smallest nipple in a 2-3/8" tubing. It is usual for cased hole equipment manufacturers to produce a platform of sensors with common power supplies, telemetry (or memory) to cover production logging, saturation logging, and multifinger caliper corrosion logging.

Application of production logs

Production logs are used to allocate production on a zone by zone basis and also to diagnose production problems such as leaks or cross flow. These various tasks can be split between those where the target production is into or out of the well and those where the flow never enters the well, typically flow behind pipe. The former is usually easier and more quantitative while the latter is more qualitative.

Fundamentals of production logging

Ideally we would like to measure radial inflow rates using a cheap and accurate sensor. Unfortunately no such sensor exists. Alternatively we could measure the axial flow rate in a well at a depths above and below the zone of interest and compute the difference and hence the inflow rate. Unfortunately there is not any practical measurement of axial flow rate beyond some special applications of oxygen activation logs. However it is possible to measure an axial velocity and combine this with an assumed or measured internal diameter to arrive at an axial flow rate. This last approach is most commonly used. Common velocity sensors include;

1. Turbine/Spinner flowmeters.
2. Markers/Tracers such as oxygen activation logs or radioactive iodine tracer logs.
3. Heated anenometry

Turbines or Spinners are assumed to rotate at a speed proportional to the average fluid velocity passing through the swept area of the blades with an offset for friction/imperfections. This becomes a simple gain and offset transformation from the rotational speed of the spinner. Unfortunately the gain and offset are not constants but are a complicated function of fluid density, fluid viscosity, spinner pitch, pipe diameter, fluid velocity, etc. This means that the spinner is typically calibrated downhole by recording the spinner speed at a series of different logging speeds (usually 30, 60,90 ft/min or 10, 20, 30 m/min) and plotting the resultant average spinner speed versus the corresponding average logging speed to determine the slope (gain) and threshold (offset). The calibrated spinner velocity then needs to be converted to an average pipe velocity.The correction coefficient determined by the velocity profile across the pipe cross section can vary from 0.5 for an infinitely small spinner in laminar flow to 1.0 for a spinner that sweeps the entire pipe area. N.B. The prefix "full bore" when applied to a spinner is a marketing name. Full bore spinners rarely cover more than half the pipe cross section. If the cross sectional area of the spinner at the depth of the spinner blades occupies a significant fraction of the pipe area then the pipe area should be reduced before multiplying it by the spinner velocity and the correction coefficient.

Categories of applications

Production-logging tools find many applications from the time a well is drilled until abandonment and, occasionally, beyond . An appropriate categorization of production logs is by usage. This approach leads to the five distinct categories listed below that also represent a rough chronological order of tool evolution. Effective interpretation of the data from each type of log requires significant education and experience.

1. Diagnose production problems and allocate production
2. Monitor cement placement
3. Monitor corrosion
4. Monitor reservoir fluid contacts
5. Select zones for recompletion

Category one

Includes tools used to track movement of fluid either inside or immediately outside the casing of a well. The logs frequently used for such flow diagnosis and allocation include:

• Temperature surveys
• Mechanical flowmeter surveys
• Borehole fluid-density or fluid-capacitance surveys

Each of these tools responds to fluid velocity or fluid type. The logs are run to determine if a production problem, such as excessive water or gas production, is the result of a completion problem or a reservoir problem. Their value thus resides in the guidance they give for continued expenditure on a well that is performing poorly. This type of application is largely responsible for the growth and evolution of modern production logging. Also belonging in Category One are:

• Evaluations of the placement of acids or hydraulic-fracturing material
• Diagnoses of premature flow or lost circulation in a drilling well

Category two

There are two different objectives of cement-placement monitoring:

• To determine where the cement went (cement top)
• To determine whether the cement provides zonal isolation

The logs used to locate the cement top include:

• Temperature log, which responds to hydration heating
• Unfocused gamma ray log, which responds to behind-pipe density
• Regular bond log, which measures the acoustical deadening of pipe

Category three

Zonal isolation should be addressed when pressure imbalance causes crossflow through poorly cemented sections, leading to excessive production of unwanted fluids. The tools most often used for this purpose include:

• Cement-bond logs
• Temperature
• Noise
• Radioactive tracer
• Neutron-activation logs

The temperature log detects alterations caused by flow, the noise log measures turbulent sound caused by flow, and the tracer log tracks tagged fluid behind casing. The neutron-activation log creates tracer in behind-pipe water.

Corrosion-monitoring tools are specialized in nature and include mechanical caliper tools and electromagnetic casing-inspection tools. The mechanical caliper tools are used to assess corrosion internal to the casing and to measure the shape of casing as well as the amount of rod and drillpipe wear inside tubing or casing. The electromagnetic devices respond to changes in metal thickness either inside or outside the pipe containing the tool. These logging tools are either of the eddy-current type or of the flux-leakage type, or a combination of the two. The eddy-current devices measure the load on a coil resulting from eddy currents induced into the wall of the casing. This load increases with increases in wall thickness. The driven frequency of the coil determines the depth of penetration of the field into the casing wall. The flux-leakage devices measure, by means of pad-conveyed coils in contact with the pipe wall, the induced currents that result from magnetic field lines that escape at abrupt changes in metal-wall thickness. Both types of tools make indirect measurements that are then related to metal loss through calibration.

Categories four and five

The last two categories, monitoring of fluid contacts in formations and selection of recompletion zones, use the cased-hole nuclear logs such as:

• Neutron
• Pulsed-neutron
• Various spectral logs

Please refer to the nuclear logging page for information on these logs.

Misconceptions about production logging

There are three pervasive myths about production logging:

1. A production log can be run by anyone
2. Only one logging tool is needed
3. The answer (anomaly) will jump out from a casual scan of the log

A production log can be run by anyone

Quality control is paramount, and careful attention must be focused upon three parts of the logging operation:

• Procedure (this will usually determine the value of the resulting logs)
• Tool calibration
• Depth control

Only one logging tool is needed

Just like openhole-logging tools, production-logging tools should be run in complementing suites so that one log can be compared with another. Seldom does a single log identify a problem sufficiently to prescribe a remedial action.

Table 1 lists the more common tool combinations used to diagnose problems and allocate flow. The Class A tools respond to flow either inside or outside the pipe containing the sonde and are usually employed for initial evaluation of a production problem. Class B tools respond to flow past the sensor and are used for detailed flow allocation from multiple entries into or exits from the pipe containing the sonde. The resolution of some of the Class A tools is actually better than some of the Class B members.

• 

  Table 1

Answer (anomaly) will jump out from a casual scan of the log

This myth is responsible almost entirely for the lack of adequate training in this area.

Production logs should be interpreted in a consistent fashion that first identifies normal or expected features. The abnormal portions can then be examined to determine which parts are pertinent to the problem and which parts are irrelevant. It is these irrelevant features that so often confound novices to the point that they delay or forego appropriate remedial action.

Once these three myths are set aside, the requisite skills, listed next, can be developed for use of production logs. In the authors’ experience, a collaborative effort by service provider and client is needed to yield the most meaningful results. The effective user must be able to:

1. Select the proper combination of tools.
2. Establish operating procedure.
3. Monitor data quality.
4. Interpret results.

Production logging tools

The tools referenced in Table 1 are each described in greater detail in separate articles.

• Temperature logging
• Radioactive tracer logging
• Noise logging
• Focused gamma ray density logging
• Unfocused gamma ray density logging
• Fluid capacitance logging
• Fluid identification logging in high angle wells
• Continuous and fullbore spinner flowmeters
• Diverting spinner flowmeter

Planning considerations for production logging

Sinker bar weight

A dead weight (sinker bar) is necessary to overcome the force of the wellhead pressure acting on the cross-sectional area of the logging cable. Fig. 2 shows the required sinker bar weight in relation to the shut-in wellhead pressure. The weight shown is just enough to balance the force of the well pressure acting on the wireline.

• 

  Fig. 2 – Sinker bar weight to balance wellhead pressure (Courtesy Bowen Tool Co.).

Additional weight above that which is indicated on the graph is needed to realize downward movement of the logging string. As the inclination angle of the wellbore increases, it becomes especially important to increase the sinker bar weight over the value specified by the vertical axis of the figure. When an inclination angle requires unreasonably long sinker bars, roller centralizers are required.

Typical slickline diameters are represented by the group of lines at the bottom of Fig. 2. The low sinker-bar weight needed to carry out a slickline survey, even at high wellhead pressures, requires only a short lubricator. As a result, slickline services are enjoying a rebirth. New versions of these tools contain sufficient downhole memory to record what is essentially a continuous log.

Maximum tool length to negotiate bend

Fig. 3a illustrates the maximum length of a tool that can pass a bend. The ends of the tool contact the bottom of the borehole, and its middle touches the top.

With the following equation, the maximum tool length that can pass through a bend can be calculated. While Fig. 3a shows a bend into a horizontal wellbore, the expression is valid for any bend and is independent of whether the final wellbore is horizontal.

....................(1)

The expression for L_t involves the hole and tool diameters, as well as the inside radius of the bend. The inside radius can be expressed in terms of the angle of the bend, and the distance to bend through the specified angle (see Fig. 3b):

....................(2)

An example of the use of the maximum-length equation:

....................(3)

Any 1.5-in. OD tool 7.61 ft in length can pass through the bend. If longer tools are required, then the tool string must be segmented with "knuckle" joints.

• 

  Fig. 3 – (a) Tool limitations through a bend; (b) inside radius, bend angle, and distance to turn.

Depth control

The counter wheels on a production-logging unit measure the length of cable in the well to an accuracy of 5 out of 15,000 ft, provided that a great deal of back and forth travel (yo-yoing) is not required to work the tool string down the well. Better depth control is obtained by placing a casing collar locator (CCL) sub at the top of any production-logging tool string. This sub generates a voltage spike as it moves past a change in metal thickness, particularly as it passes through the connection between joints of pipe. The resulting record of collars is the source of depth control.

Wells are perforated from a perforating depth control (PDC) log, a combination of a collar log and a cased-hole nuclear log such as a gamma ray log. The nuclear log is then depth correlated to a similar log run before the well was cased. This procedure ties the collar record into the depth scale on the openhole logs. Accuracy in this latter depth scale is maintained by means of magnetic flags placed at precise intervals—customarily, 100-ft intervals—along the openhole logging cable. The PDC log is a part of the file on a given well and provides the collar record that serves as the depth reference for subsequent production logging. A short joint of casing called a "pup" joint is often placed in the casing string as a depth marker. Otherwise, normal variations in length are used to correlate collar records.

Sometimes a radioactive collar that emits gamma rays is used as a marker for depth control. For flush-joint casing, collars are available that are strapped around the casing before it is run into the hole. Occasionally, radioactive bullets are fired into the formation before casing the well. Finally, it may become necessary to run a section of a nuclear log and to flag (mark) the logging cable on a particular operation to achieve the necessary depth control.

Production logging applications

Much emphasis is placed on the importance of using suites of production logs, rather than relying on a single log. There is previous indication of the applicability of production logs at various stages of a well’s life, from drilling to abandonment, and even beyond. Four examples show how a suite of production logging tools can provide important diagnostic information at different points in a well's life-cycle:

• Production logs to assess gas kick
• Profiling commingled gas production
• Profiling oil production under WAG recovery
• Gas blowout after abandonment

A set of production logging application tables are available to assist in selection of the appropriate tools for different types of problems.

Pricing for production logging

An understanding of the price structure to perform production logging can help optimize data-acquisition costs. The total cost of a job is the sum of four separate charges:

1. Set-up charge: This is the amount the service company charges to bring their equipment to your well and "rig up" on it.
2. Pressure charge: This charge is based on the surface pressure on the well and represents a rental fee on the equipment necessary to safely log the well.
3. Depth charge: This is a charge based on the maximum depth reached in the well. It reflects the fact that at least three people are needed to rig up, to spool so much wireline off the drum of the logging unit, to reel this same amount of cable back onto the drum, and to rig down. It is the substitute for the familiar hourly charge.
4. Logging charge: This is a per-foot charge for each tool run that reflects the length of interval actually logged by the tool.

From this structure, one can immediately see the potential savings to be had from being present during the logging operation. On-site changes in procedure to ensure the desired diagnostic logs can prevent having to start another day, resulting in incurring the first three charges again.

The footage-logging charge is often cited as the reason for running only one tool. This is false economics because this charge, even for a three-tool suite, is usually no more than 40% of the total.

Record keeping

Forward planning will ensure maximum long term use of log data. The log headings used by most service companies, while recording some specifics about the run itself, have little information on why and how the logs were run. Consequently, most professional loggers have their own forms to bridge this documentation gap. While the organization of these forms is a matter of personal preference, a good rule is to prepare a preliminary summary that specifies at least the following:

• Why the logging is undertaken.
• Previous production-logging summary.
• Current well-completion data with a wellbore sketch.
• Collars used for perforation.
• Depth reference point.
• Most recent well-test data.
• Anticipated total depth, bottomhole pressure, and temperature.
• A second form completed at the time of logging is a chronology that lists
• Logs run and their order.
• Run number.
• String logged and its status for each run.
• Status of other strings or annuli.
• Logging direction and speed.
• Tool calibration checks.
• Intervals relogged.
• A summary of conclusions.

Nomenclature

Dh	=	casing or hole diameter, ft
Dt	=	tool diameter, ft
Lt	=	maximum tool length to pass through bend, ft
Lturn	=	distance to bend, ft
Ri	=	inside bend radius (or turning radius), ft
α	=	angle of bend, degrees

Noteworthy papers in OnePetro

Hill, A.D. and Oolman, T. 1982. Production Logging Tool Behavior in Two-Phase Inclined Flow. J Pet Technol 34 (10): 2432-2440. SPE-10208-PA. http://dx.doi.org/10.2118/10208-PA

Wade, R.T., Cantrell, R.C., Poupon, A. et al. 1965. Production Logging-The Key to Optimum Well Performance. J Pet Technol 17 (2): 137-144. SPE-944-PA. http://dx.doi.org/10.2118/944-PA

Hammack, G.W., Myers, B.D., and Barcenas, G.H. 1976. Production Logging through the Annulus of Rod-Pumped Wells to Obtain Flow Profiles. Presented at the SPE Annual Fall Technical Conference and Exhibition, New Orleans, Louisiana, 3-6 October 1976. SPE-6042-MS. http://dx.doi.org/10.2118/6042-MS

Howell, E.P., Smith, L.J., and Blount, C.G. 1988. Coiled-Tubing Logging System. SPE Form Eval 3 (1): 37-39. SPE-15489-PA. http://dx.doi.org/10.2118/15489-PA

Carnegie, A., Roberts, N., and Clyne, I. 1998. Application of New Generation Technology to Horizontal Well Production Logging - Examples from the North West Shelf of Australia. Presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 12-14 October 1998. SPE-50178-MS. http://dx.doi.org/10.2118/50178-MS

Chauvel, Y. and Clayton, F. 1993. Quantitative Three-Phase Profiling and Flow Regime Characterization in a Horizontal Well. Presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, 3-6 October 1993. SPE-26520-MS. http://dx.doi.org/10.2118/26520-MS

Cmelik, H.R.M. and Sarabian, R.A. 1979. Quantitative Analysis of Production Logs in Two-Phase Liquid-Gas Systems. Presented at the SPE Production Technology Symposium, Lubbock, Texas, 5-6 November 1979. SPE-8761-MS. http://dx.doi.org/10.2118/8761-MS

Lenn, C, Kuchuk, F J., Rounce, J, Hook, P, 1998. Horizontal Well Performance Evaluation and Fluid Entry Mechanisms. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 27-30 September 1998

Al-Momin, A, Zeybek, M, WahabAzrak, A, Burov, A. First Successful Multilateral Well Logging in Saudi Aramco: Innovative Approach toward Logging an Open Hole Multilateral Oil Producer. Presented at the SPE/DGS Saudi Arabia Section Annual Technical Symposium and Exhibition, Al-Khobar, Saudi Arabia, 15-18 May 2011

Vu-Hoang, D, Faur, M, Marcus, R, Cadenhead, J, Besse, F, Haus, J et al. A Novel Approach To Production Logging in Multiphase Horizontal Wells. Presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, 26-29 September 2004

Online multimedia

Friehauf, Kyle. 2013 Hydraulic Fracture Identification and Production Log Analysis in Unconventionals Using DTS. https://webevents.spe.org/products/hydraulic-fracture-identification-and-production-log-analysis-in-unconventionals-using-dts

External links

Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro

See also

Types of logs

Production logging application tables

PEH:Production_Logging