Chapter 7 Downhole tracers

CHAPTER 7

DOWNHOLE TRACERS

INTRODUCTION Downhole tracers are used to investigate the region in and around the oil well, the link connecting the oil-bearing reservoir with the surface facilities. It is the only path of communication with the reservoir; the conduit for production of oil, gas, and water from the reservoir; and for secondary and tertiary injections into the reservoir. Because of its importance, a large number of tracer procedures have been developed to study the integrity of the wellbore, how fluids enter and leave it, and conditions affecting well operation down hole. This section is concerned with the use of tracers for following wellbore operations and for investigations in the neighborhood of the borehole. T r a c e r d e t e c t i o n in t h e b o r e h o l e

The borehole of an oil well is a difficult environment to work in. Temperatures, pressures, and flow forces can be high, and space is very limited. The small diameter and relatively great depth of the wellbore limit the size of the equipment and the kinds of operations that can be carried out. Virtually all monitoring operations in the wellbore are carried out by special tools that are moved up and down the wellbore on a wireline. Most such operations are contracted by independent logging companies t h a t provide both wireline and tools. These companies usually perform the logging operation and, depending upon the type of operation, often provide an interpretation of the logging results. This is not a requirement, and simple gamma-detection wireline tools are often operated by oil c o m p a n y personnel. While there are m a n y kinds of logging operations, the nuclear logs are the principal ones of interest in tracer studies. These allow the use and detection of g a m m a - e m i t t i n g radioactive tracers for following the movement of fluids and solids in the neighborhood of the borehole. Very few other detection methods have been used for following downhole tracers. Magnetic resonance logs have been used with responding ions as tracers in log-inject-log studies. In principle, electrochemical detectors can also be used to follow water tracers in this environment; but in practice very little has been done with them. These detectors require direct contact with the tracer in aqueous solution and, usually, a relatively "clean" environment. Electrochemical detectors have been used for gas tracers, and for monitoring the hydrogen ion concentration in water down hole. Three kinds of tracer operations involving radioactivity are used to tag gases, liquids, or solids moving in or about the wellbore:

294

Chapter 7

1. In the conventional procedure, radioactively tagged material is injected into the well and a radiation monitor on a wireline used to follow its movement or location down hole for well treatments and production logging. 2. In a second method, a nonradioactive tracer is activated down hole by neutron radiation, forming a new gamma-emitting tracer, monitored by a downhole detector. This may be a n a t u r a l l y occurring material, such as the fast neutron activation of oxygen in water used to trace leaks behind casing, or an added material, activated for this purpose as in the fast neutron activation of barium. 3. In the third method, capture gamma radiation, induced by neutron irradiation of a nonradioactive material, is related to the macroscopic thermal neutron cross section, and hence to a measure of the amount of absorbing material present. This is illustrated by the log-inject-log tracer procedure for residual water. Currently, only radioactive tracers that emit penetrating (gamma) radiation are used for downhole measurement; however it is also possible to use beta emitting tracers for gas tracing down hole. An ion chamber can be used as a beta detector, so long as the gas that enters the chamber is free of condensed liquid phases such as water or oil. Ion chambers can be designed to operate under borehole temperatures and pressures, and most produced gas can be used as the counter gas. The principal detector used for monitoring gamma radiation down hole is the sodium iodide scintillation detector. Described in chapter 2, this detector has high sensitivity for gamma radiation and can operate under borehole conditions (although temperature and pressure protection are usually required); however, it suffers from relatively poor energy resolution. The detector of choice for resolving g a m m a spectra is the intrinsic germanium detector, used for virtually all laboratory spectral analysis. Unfortunately it requires liquid-nitrogen cooling to operate, is much more expensive, and is considerably less sensitive t h a n the NaI detector. As a result, with some exceptions, it is not used for oilfield logging. It should, however, make a significant improvement in spectral deconvolution if the cost of operations could be reduced. The Geiger-Mueller or GM tube has largely been replaced by the scintillation detector but is still in use in wells where high temperatures and other conditions make the use of scintillation detectors chancy. The principal downhole neutron detector is the He-3 filled proportional counter. There is an odd division in the oil industry whereby tracers monitored in the wellbore are categorized as logging procedures, whereas those monitored at the surface are regarded as tracer procedures. We will ignore this distinction here. The use of logging procedures for characterizing fluids and formation properties has been well described in the logging literature and we do not feel it needs further exposition in these pages; however, logging procedures that involve the traditional use of tracers as described above will be discussed.

Downhole Tracers

295

FAST NEUTRON ACTIVATION OF TRACERS For most materials, fast neutrons are the most penetrating kind of radiation generated down hole. They are particularly useful for dealing with problems outside of the wellbore in cased and cemented wells. The most useful source of fast neutrons in the wellbore is the downhole accelerator, in which deuterons are accelerated against a tritium target to undergo the d(T,n)a reaction described in chapter 1. The reaction can take place at relatively low accelerating voltage and yields mostly 14 MeV neutrons. Most fast neutrons lose energy by elastic collisions. A small n u m b e r of them enter into inelastic collisions with target nuclei, characterized by a minimum energy threshold t h a t must be exceeded for the reaction to take place. The cross section for the reaction is usually quite small, in the millibarn region. Exceptions include the 138Ba(n,2n)137Ba reaction, which has a cross section of 1 barn. One of the more widely used fast-neutron reactions downhole is t h a t with oxygen, used for detecting water behind casing.

Leaks behind casing Wells are cased and cemented to the formation in order to contain the movem e n t of fluids between the formation and the surface within the wellbore. Paths of communication outside the casing can cause serious difficulties by allowing flow between formations at different pressures. This can lead to contamination of shallow potable aquifers by oil and brine from deeper layers, and to undesirable flow between oil- and water-bearing formations. Channeling of w a t e r within the cement annulus provides the principal paths for such movement. Such external paths are difficult to detect. Radioactive tracer logs, as well as noise and temp e r a t u r e logs, have been used for this purpose, although some of these methods require access to the channel from the wellbore. Logging by fast neutron activation can detect channels t h a t leak between sands in unperforated parts of the reservoir without accessing the wellbore.

Oxygen activation log The oxygen activation log is based ( W h i c h m a n et al., 1967) upon the activation of oxygen in w a t e r by high-energy (14 MeV) neutrons. The threshold energy for reaction is 10 MeV. When water is irradiated by these neutrons, some of its oxygen is converted to 16N by the 160(n,p)16N reaction. The reaction cross section is 40 millibarns. The nitrogen-16 produced by the r e a c t i o n t h e n undergoes beta decay with a half-life of 7.1 sec, with 69 percent of the beta decay path accompanied by a 6.13-MeV gamma ray.

16N --)~+ 160 + T (6.13 MeV)

296

Chapter 7

The high-energy gamma ray easily penetrates the casing, cement, tubing, and fluids in the well and is measured by the detector in the borehole. This is a relatively inefficient procedure, because of the poor (NaI) detector efficiency for this high g a m m a energy and poor source geometry from the narrow cement channels. As a result, counting statistics will be poor. A logging tool suitable for this kind of operation, together with a generalized schematic of the neutron generator and the g a m m a ray detectors in the borehole is shown in Fig. 7.1. The detectors are located at different distances from the neutron source. A third detector, much farther away, called a GR (Gamma Ray) detector is often used with other logging tools as an add-on to monitoring natural gamma radiation. This is also shown in the diagram, as it is used in some of the oxygen activation procedures discussed later in this chapter.

,/

Channel cross section

Downhole tool

!eutron ge Water channel (moving down)

Detector 1 Detector 2

GR detector

Figure 7.1. Oxygen activation tool showing downflow measurements

Downhole Tracers

297

In this figure the tool is shown in the wellbore with w a t e r moving down a channel in the cement between two sands, The channel is also shown in cross section on the upper right side of the figure. The sands are normally perforated for access, although this is not shown here. In this method, the 16N generated from oxygen in the water serves as a water tracer. The velocity of the water moving in a channel is obtained by timing the change in g a m m a radiation between two detectors a known distance apart. For downward flow in the channel, as shown here, they are positioned below the neutron generator and for upward flow above the generator. CONTINUOUS NEUTRON ACTIVATION A procedure for monitoring water flow behind casing by oxygen activation was first described by Arnold and Paap (1979). They used a pulsed neutron source with two g a m m a detectors mounted above it and timed the resulting change in g a m m a radiation at two detectors a known distance apart. Arnold and Paap derived an equation to account for the count rate, C, observed from the g a m m a radiation emitted by the 16N induced in the water. The equation was solved numerically for the count rate to be expected for various w a t e r velocities, v, flow channel cross-sectional areas, A, radial distances from the flow channel, r, and volumetric flow rates, q. From this, they arrived at a relationship between C/q and velocity, v. If distance r is known, the flow rate can then be calculated from the velocity and the count rate at the detector without knowing the cross-sectional area of the flow channel. The velocity, v, is obtained from the measured activity at each detector as shown below. The induced 16N activity decays exponentially according to its decay constant, ~. As the w a t e r travels past each detector, the activity decreases by ~t, the decay constant times the travel time. The travel time, t, can therefore be expressed as the distance between detectors, d, divided by the w a t e r velocity, v. Hence, the count rate, C i, at each detector can be presented as: C 2 = C 1 e -(~v/d)

(7.1)

The velocity, v, of the water moving in the channel is therefore given directly by: ~d v = ln(C 1/C2)

(7.2)

The distance, r, from the sonde to the flow channel was estimated from an empirical relationship between the ratio, Caleb of the count rate at two different energies and the intervening mass. The count rate at the high energy, Ca, was t a k e n from the region between 4.92 and 7.2 MeV, and Cb, the low-energy, countrate, from the region between 3.25 and 4.0 MeV. A plot of C a]Cb as a function of

298

Chapter 7

the intervening mass (gm/cm 2) for different casing diameters and thicknesses gave a linear fit. Although presented as an empirical relationship, the procedure described above is based upon the way g a m m a radiation interacts with m a t t e r by Compton scattering and by photoelectric absorption. The upper channel used here represents mostly unscattered primary radiation, whereas the lower energy channel is mostly Compton scattered radiation. For known densities, the ratio of unscattered to scattering radiation is a function of the thickness of the intervening material; it can therefore be used to estimate the distance from source to detector.

Background problem The activity due to the flowing w a t e r m u s t be corrected for the s t a t i o n a r y signal g e n e r a t e d by activation of oxygen bearing materials in the well w h e n there is no flow, as well as for the normal instrumental g a m m a background in the borehole. This is done by calibrating the sonde for the stationary signal and, for the i n s t r u m e n t a l background, in a part of the well where there is no flow. Unfortunately, the chemical composition of materials in the neighborhood of the well bore can be variable, and flow can occur in unexpected regions. As a result, background m e a s u r e m e n t s made at different locations and different times m a y not always be directly comparable with the m e a s u r e m e n t s made under flowing conditions, which can lead to large errors in evaluating flow. SHORT PULSE NEUTRON ACTIVATION The short pulse activation was proposed (McKeon et al., 1991) as a means of avoiding the problem of background calibration. Instead of using a continuous (pulsed) n e u t r o n signal with a short b r e a k for g a m m a acquisition, a short neutron activation period of 1 to 15 sec is used, followed by a longer period of 20 to 60 seconds for gamma-ray acquisition. This allows time for a distinct nitrogen16 t r a c e r pulse to be generated in the water. The emitted g a m m a radiation, monitored by the detectors, marks the arrival of the pulse at each detector. The w a t e r velocity is obtained by measuring the time required for the pulse to travel the fixed distance from the source to the detector. Since the 16N pulse has a halflife of 7.1 sec, the time of detection is limited, which places a lower limit on the w a t e r velocity t h a t can be measured. There are usually three g a m m a detectors, as shown in Fig. 7.1, each at a different distance from the source to allow for different response times. Fig. 7.2 (McKeon et al., 1991) shows a simulated 16N pulse tracing flow in a channel. As shown, the signal at the detector is a function of time. It is composed of three parts: a constant instrumental background, an exponentially decreasing signal from the decay of stationary activated material, and the peak from the moving w a t e r signal. The total count is the sum of all three signals. The neutron activation time, tA, is also shown in the figure in black. While no counts are

299

Downhole Tracers

acquired during activation, the water (tracer) pulse is still moving during this time and it must be accounted for. If d is the distance between detectors, and v is the water velocity, the arrival time of the pulse peak, tp, is given by half of the activation time plus the measured travel time, d/v: tA d tp = ~ + v

(7.3)

:i

i ~

6-

r--

m Neutrons on ~ Background ~ Stationary

2-

0

0.0

2.5

5.0

7.5

10.0

12..5 15.0

17.5

20.1

Time (sec)

Figure 7.2. Simulated 16N pulse in flowing water The best locator for the the response curve, rather other distribution is given the count rate, C = fit), is a

travel time of the tracer pulse is the first moment of than the peak position. The mean, t,, of this or any by its first moment, as discussed in chapter 4. Here, function of t, and the moment can be expressed as:

oo

~tC(t)dt =

+

oo

(7.4)

~C(t)dt 0

The magnitude of the gamma signal increases with the time of activation, tA, however, if tA is long compared to the transit time, part of the water signal is lost. Also, if the water velocity, v, is too low, errors in locating the peak occur because the curve shape is altered with time due to the exponential decay of the

300

Chapter 7

signal at the half-life of 7.1 sec, shown in Fig. 7.3. The authors simulated the pulse shapes to be expected from the 16N gamma rays using a Monte Carlo Neutron and Proton (MCNP) transport code (Briesmeister et al., 1986). The (simulated) total count as a function of flow velocity (for a given activation time and radial distance) is shown in Fig. 7.3a. As seen in the figure, the pulses become increasingly asymmetrical as the flow rate decreases due to the exponential decay of the stationary signal. At high-water velocities, the pulse can be detected by the GR detector (#3) with very little shape change, since by the time the pulse reaches this position the activated stationary component is gone, as shown in Fig. 7.3b. The activity also falls off exponentially with the distance from the tool to the water channel as expected, but because of the high energy of the emitted gamma ray, it is not significantly affected by casing thickness.

Neutrons

50

on

16o

,,,!

/,

120-

/

..,'o

0.0 ft/min \

30'

; /

0

40

.0 ft/min

e20'

,

o

~ f t / m i n

lO'

40-

0 0

9 10

~ 20

~ 30

40

i 50

0

Time, ser

5

10

15

20

Time, sec. b

Figure 7.3. Simulated response for different flow rates The activation times used depend upon the water-flow rate and the positions of the detectors. For any given situation in the well, there is a tradeoff between signal strength and the sensitivity with which velocity can be measured. A long activation provides high signal strength at the price of losing part or all of the signal, particularly at high-water velocities. The low oxygen activation cross section together with the relatively lowneutron flux down hole generate a low-activity pulse. Counting statistics can be improved by summing the data acquired in multiple activation cycles. Numerical

Downhole Tracers

301

techniques are used to estimate the flowing profile and to separate the total count into the three components. Field data from several examples (McKeon et al., 1991), not reproduced here, d e m o n s t r a t e the presence of water channels behind casing. Several measurements were also reported from the EPA leak test well in Ada, Oklahoma. This included a set of leak rate m e a s u r e m e n t s set by EPA observers u n d e r blind conditions, in good agreement with actual flow velocities. These log data give only flow velocity. In order to obtain the flow rate, the radial distance to the leak channel must first be estimated. The flow rate, Q, can then be estimated from the total flowing count rate, C3, by: Q = C3

b [v2e (xd/v)] GS

(7.5)

where b is a proportionality constant, v = flow velocity, d = travel distance, G = geometry factor, and S = neutron output. All except the geometry factor are measurable. Since the actual dimensions and position of the channel are not likely to be known, the geometry factor would be very difficult to estimate. Pulse evaluation The major advantage to the pulse method over the continuous proCedure is the formation of a discrete pulse as an entity clearly separable from background. This is i m p o r t a n t since it avoids all questions as to w h e t h e r channel flow is occurring, particularly at low flows. Both methods suffer from very low count rates because of poor counting efficiency, limited neutron flux, and the lowreaction cross section. The statistics of counting are significantly improved by s u m m i n g the results from a number of repetitive pulse cycles at a given duty station. A theoretical study of the oxygen activation technique by Ostermeir (1991) compared the pulse technique with the continuous method. A pulsed neutron generator is used in both techniques. The big difference is the time interval between repetitive pulses. In the continuous technique, the repetition rate of the tool is so much faster t h a n the acquisition rate that it is essentially a continuous pulse. In the pulse technique, the author suggests, the optimal period between pulses is twice the source-detector spacing divided by the flow velocity. For a 60-cm spacing and a 10-cm/sec flow rate, this requires a period of 12 sec between pulses (the pulse rate of the tool is in millihertz.) The author calculates the effect of changing many of the parameters and estimates the uncertainties associated with the measurement. He also examines the continuous method and shows that for nonoptimal flow velocities at larger (radial) distances from the flow channel, the background count rate can entirely obscure the flow response. This effect is shown in Fig. 7.4 for a channel-flow velocity of 10 cm/sec and channels offset a radial distance of 7, 11, and 15 cm from the detector. The three response curves

302

Chapter 7

for channel flow are indicated by arrows as oxygen response, compared with the horizontal lines showing the background associated with each offset.

lOO 9o 80

0 v

Oxygen . ~ , response ~ \

60

&,,/

7cm

\~/

\

....

t_ ~

40

Q)

zo

.....

~ ;

Background ~

.....

@

7cm

crn

lo

o

Channelvelocity(cm/sec)

Figure 7.4. Background effect in continuous oxygen activation

Injectivity profiles by oxygen activation A recent report (Scott et al., 1991) describes the use of oxygen activation to measure injectivity profiles in the Keparuk River field in Alaska. Wells in this field are completed in a manner that makes conventional production logging difficult, as shown in the well configurations of figs. 7.5, 7.6, and 7.7. The tubing section across the perforations through the C sand intervals has a much thicker wall, due to the addition of hardened blast joints and blast rings. The thicker walls absorb more radiation and require higher levels of g a m m a activity for penetration. This and the mixing induced by the injection m a n d r e l s have resulted in poor production logs using 1-131 tagged radioactive tracers. Oxygen activation was used here as an alternate method for measuring an injectivity profile, since the much higher energy g a m m a and the high, well-defined flow rates should give good results here.

Injected water velocity measurements An injectivity profile was measured for well 2W-14 using the method described above and illustrated in Fig. 7.5, showing the well configuration and the resultant velocity measurements. The measurements described here were made with a 11y16-in. diameter tool fitted with a neutron generator and three g a m m a ray detectors, spaced at 1, 2, and 15 ft from the neutron source and identified as

303

Downhole Tracers

the near, far, and GR detectors. The pulse technique was used with an activation period of 2 or 10 sec to generate the tracer pulse, followed by a longer (60-sec) data acquisition period for following its movement. To obtain adequate counting statistics, the procedure was repeated for 3 to 6 cycles (about 4 to 7 minutes of data), depending on the activation time. This method was first tested in well 2W14 at a water injection rate of 2500 bbl/day (75 fdmin.). For this flow rate, most measurements were made with the gamma ray (GR) detector 15 ft from the neutron source. Staggered measurements were made across each interval to improve the resolution.

Gamma log -

-.,~-"--I

D 790

";t '960 7

Well schematic I

I

=

Downhole water velocity ft./min. , ~, , ~, ' ~ ' ~, ' ,| Measurement stations 7900

20

1 B

e--

C~

i~ l

0i 7980

Figure 7.5. Injected water velocity profile on well 2W-14 Measurements were made in the C sands, starting in the B sand below the perforated interval (7960 ft), and from stations chosen at staggered locations moving up the well. Since the steel tubing is also activated by the generated neutrons, this is used to confirm the station position. The left side of the figure shows the background gamma log for the well and the depth in feet. The middle

304

Chapter 7

section shows the well configuration with the perforated section marked in black on the right and the measuring stations m a r k e d as teeth on the left. These station positions were verified by monitoring the neutron-activated sites in the steel tubing. The well configuration shows blast rings, indicated by hatch marks, over most of the perforated section. The section on the right shows the results of velocity m e a s u r e m e n t s for the depth interval as a function of depth. The water velocities are derived from the time required for the induced pulse to travel the distance to a detector. The travel time is taken to be one-half the activation time plus the first moment of the response time, in accordance with Eq. (7.3).

Gamma Well log schematic

Cumulative injection rate BWPD i'

9

9

1

w

Injection loss BWPD/FT i ......

|

1

|

B

l

Figure 7.6. Injected water flow rate profile in well 2W-14

Injected water flow rate Since the geometry of the flow relative to the detector is clearly known here, the velocity profile shown in Fig. 7.5 could be expressed in terms of injected flow rate as barrels of water per day (BWPD), corrected for variations in flow tubing

305

Downhole Tracers

diameter. This is shown in Fig. 7.6, as is the fluid loss into each of the responding sand intervals, in BWPD/ft. Produced water flow rate In principle, measurement of water production profiles does not differ from that of water injection profiles, except that only the water part of the production is monitored by this method. A production profile taken from well 2W-12 was made with the same procedure used for measuring the injection profiles in well 2W-14. The results, illustrated in Fig. 7.7, show that most water production in this interval occurs in the C1 sand from 7622 to 7627 ft.

Gamma ray log

Water production Water production rate (BWPD) per foot (BWPD/ft)

,~ 121

Figure 7.7. Injected water flow-rate profile in well 2W-12 This is a useful indicator for sections where water production is high. For wells where both oil and water are produced, this tracer response log is not sufficient for good water-flow rates, although high water-cut zones can be identified. The authors report that at a combined oil- and water-flow rate of about 4000 bbl/day, and a water-cut of less than 60 percent, laboratory experiments show

306

Chapter 7

t h a t the oxygen activation technique (OAT) gives numbers in agreement with the in situ water velocity. When the oil phase is dominant, the OAT velocity is higher t h a n the average water velocity because it is carried by the faster moving oil phase. This is enhanced in deviated wells because some water travels up on the high side of the well with the oil, while the remaining water travels at a lower speed either upward or downward on the low side of the pipe. Interaction of the flows in the wellbore makes it difficult for any single-phase tracer procedure to monitor two-phase flow without additional knowledge about the flow regime. A separate tracer for each phase might avoid some of these complications.

O t h e r f a s t neutron a c t i v a t i o n s There are several isotopes with a natural abundance of 60 to 70 percent and a high activation cross section that could provide gamma emitting tracers by fast neutron activation down hole. These include: 69Ga(n,2n)68Ga, 121Sb(n,2n)120Sb, and the 138Ba(n,2,)137mBa with an activation cross section of about 1 b a r n (1000mb), and 63Cu(n,2n)62Cu with a cross section of 500 mb (25 percent abundance). The only one of these currently used in the oil field is barium; its applications are discussed below. FAST NEUTRON ACTIVATIONOF BARIUM The fast neutron reaction t h a t produces radioactive barium in place is the 138Ba(n,2n)137mBa reaction. This reaction has a threshold energy of 10 MeV and a cross section of 1.05 barns for 14 MeV neutrons, or about 50 times the 160 cross section. The produced barium-137m decays to stable 137Ba with a half-life of 2.6 minutes, emitting a gamma ray with an energy of 0.66 MeV. The high cross section and the short half-life of the product nucleus make this a relatively effective process. Several situations in which the presence of barium can be of importance in production operations are discussed in the following section.

DRILLING MUD

BEHIND CASING

A recent patent (Jordan et al., 1988) discusses the use of fast neutron activation for locating barite-weighted drilling fluid remaining in the annulus after a cementing operation. The authors use a standard pulsed neutron capture tool ("cyclic activation tool," Dresser Industries) consisting of a 14-MeV neutron generator with two spaced gamma detectors below. The generator was pulsed on for 4 milliseconds and off for 6 milliseconds. Data are collected only during the last part of the off cycle to allow decay of gammas from prompt neutron reactions. The barium data were corrected for changes in activating conditions by comparing them with the results of the competing 56Fe(n,p)56Mn reaction, generated by activation of the casing. This reaction can act as an activation monitor since the iron content of the casing is constant except at the joints. The casing has a

Downhole Tracers

307

cross section of about 100 millibarns. Mn-56 decays by beta decay with a half-life of 2.6 hr, emitting several g a m m a rays. The authors used the net activity of the 0.847 MeV g a m m a photo peak as an activity monitor. Tests were done inside a test casing fitted with concentric canisters of different weights of barite. B a r i u m scales downhole The procedure described above can be applied to other production operations involving barium. The major problem in its use is the possibility of b a r i u m cont a m i n a t i o n because of barite from mud remaining in the neighborhood of the wellbore. Another possible application for this reaction is the identification of b a r i u m scale down hole. B a r i u m sulfate causes severe problems in m a n y oil fields. It is a difficult scale to remove chemically unless identified early. This procedure m a y provide a useful method for locating scale buildup and monitoring the effectiveness of scale treatments down hole. Nonradioactive barium has some potential as a location tracer used with this procedure, particularly where it may be necessary to repeat a m e a s u r e m e n t at intervals. It requires a way of putting sufficient barium solution at the desired position. Barium is easily placed in cement or in a steel pin in the casing. It can be used in solution even in normally precipitating conditions by the formation of complex ions of sufficient strength. Some of the barium crown ether complexes are w a t e r soluble and should be stable enough for this purpose.

LOG-INJECT-LOG TRACER PROCEDURES

M a n y common logging tools can be used to make estimates of the oil saturations in the neighborhood of the wellbore. These estimates are not usually accurate enough to be used for determining residual oil. In order to increase the accuracy of the methods, a procedure known descriptively as log-inject-log (LIL) has come into use. In this procedure, the formation water in the neighborhood of the wellbore is monitored (logged) with a suitable detector for background. Tagged w a t e r is injected to displace the formation water, and the well is logged again using a detector sensitive to the injected water. Assuming t h a t residual oil is immobile, t h a t the formation water is displaced by the injected water, and t h a t the formation porosity is known, this procedure can be used to m e a s u r e the w a t e r s a t u r a t i o n directly. Residual oil s a t u r a t i o n is derived from the w a t e r saturation by the saturation condition: Sor = 1- Sw

(7.6)

A variety of logging procedures and detectors have been used with this technique. The downhole log m e a s u r e m e n t s must be accurately related to the w a t e r s a t u r a t i o n in the formation, and borehole effects must be kept from interfering

308

Chapter 7

with the formation measurement. A tool frequently used for this purpose is the pulsed neutron capture (PNC) tool.

R e s i d u a l oil by n e u t r o n - a c t i v a t e d brine tracer The PNC tool is the s t a n d a r d 14 MeV downhole neutron g e n e r a t o r with g a m m a detectors spaced at various distances from the generator, and associated timing and monitoring circuitry. The neutron generator is t u r n e d on for a fixed period of time to produce a burst of neutrons. The neutrons are thermalized in the formation and captured by formation materials in an (n,y) reaction with prompt emission of g a m m a radiation, monitored by the g a m m a detectors on the PNC. The capture g a m m a radiation is a direct measure of the neutron capture reactions t a k i n g place. Following the neutron burst, the decay of the capture g a m m a radiation is monitored for a fixed period of time using a sequence of timed gates. These neutron emission gamma counting cycles are averaged over a n u m b e r of cycles to reach satisfactory statistics. The decay in g a m m a count rate is directly proportional to the rate of neutron decay. The neutron population as a function of time is given by the following expression: N = Noe "Zvt

(7.7)

where Z is the macroscopic absorption cross section, v is the velocity of the neutrons, t is the time, and No is the neutron population at zero time. The cross section data are obtained from the decay constant, k, of the g a m m a decay curve. The neutron velocity, v, at formation temperature is known, hence the decay cons t a n t for the g a m m a decay curve, ~., is equal to Zv, and the neutron lifetime is inversely proportional to Zv. The exponential neutron decay curve can be sepa r a t e d into two components by a set of timed gates for a given set of conditions" a borehole component t h a t decays with a relatively short half-life and a formation component with a relatively long half-life, shown schematically in Fig. 7.8. This is i m p o r t a n t because it provides a m e a n s of s e p a r a t i n g out the borehole component and allows a m e a s u r e m e n t of the fluid saturations in the formation without interference from fluid in the borehole. The simple correlation between g a m m a decay r a t e and cross section used above assumes t h a t the cloud of neutrons is uniform. In fact, it is not; and some additional corrections m u s t also be made for neutron diffusion. Any water-soluble material t h a t 1) does not react with the formation m a t e r ials, 2) follows the water path, and 3) has a high capture cross section can serve as a water tracer for this log-inject-log procedure. Most formation waters contain chloride ions. Chlorine has a much higher cross section for neutron capture t h a n other formation materials normally present. For this reason, the chloride present in formation brine is frequently used as a water tracer. Displacing the formation

309

Downhole Tracers

w a t e r with a brine of a very different salinity makes it possible to distinguish between the two waters. This technique is widely used for s a t u r a t i o n m e a s u r e m e n t s in the log-inject-log method. The brine s a t u r a t i o n is obtained from the difference in the capture cross sections before and after displacing the formation w a t e r and the known porosity of the formation, ~: Sw =

Zl-Zf

(7.8)

~(Z2-Zd) Here, E 1 and Z2 are the capture cross sections of the formation w a t e r and of the injected brine, respectively, as measured on samples in the laboratory, Zf and Y-d are capture cross sections measured by the PNC tool down hole in the presence of oil and formation water and of oil and displacing water, respectively, and ~ is the porosity of the formation. The residual oil is derived from this by the saturation condition; Sor = 1 - Sw. The difference in salinities m u s t be quite large or the propagation of errors of m e a s u r e m e n t can nullify it.

\ 10G

.>__
,--..Far \ \ Near \ \ \

Neutron Pulse on

'

'

"

5 o o

Gamma decay, lasec.

Figure 7.8. Decay of g a m m a activity following a neutron pulse

310

Chapter 7

W a t e r s a t u r a t i o n by n e u t r o n - a c t i v a t e d boron t r a c e r This is a v a r i a n t of the log-inject-log procedure t h a t can be used for m e a s u r ing w a t e r s a t u r a t i o n as described above and can also be used to follow w a t e r movement behind casing. The latter application is described here using boron as a tracer. In this procedure (Blount, 1990), a boron solution is injected into the wellbore. If channels are present and accessible through the wellbore, the boron solution will move through them and show up in the formation above or below the perforations. A pulsed neutron capture (PNC) tool is used to log the wellbore. Neutrons are thermalized in the formation and react with the boron in solution to emit the capture g a m m a s recorded by the tool. The neutron source activates a boron solution t h a t has been pumped into the channel. It does not differ in function from pumping in a radioactive tracer and monitoring the movement of the radioactivity. It differs in kind because it monitors an induced g a m m a signal r a t h e r t h a n a direct boron signal. The boron log suffers from the same problem associated with the radioactive tracer injection: it can only access channels t h a t communicate with the wellbore through perforations. Channels t h a t are not accessed by perforations are not visible to this procedure. The PNC log is a relatively expensive log to run and, except for special situations, m a y not offer any advantages over downhole production logs using radioactive tracers. The boron tracer technique uses the PNC tool to monitor change in g a m m a radiation due to the presence of boron, and the change in capture cross section is determined from this. The well is first logged with the PNC tool and both the wellbore Z and the formation Z determined. With the PNC tool above the perforations, a boron solution is then pumped into the perforations at pressures below fracture gradient. As soon as the boron solution fills the wellbore, the well is again monitored for the wellbore Z. The boron solution is displaced from the wellbore and the well is logged again. Logs of two wells showing large channels above and below the perforations are shown in Fig. 7.9. The formation Z shows an increase by a factor of two, clearly indicating the presence of boron in channels behind the casing. Interference due to boron in the wellbore is eliminated by delayed counting as shown in Fig 7.8. An important property of the PNC tool is the ability to measure the amount of material in the formation in the presence of a significant amount in the borehole. RADIOACTIVE TRACERS In principle, a solution tagged with a known concentration radioactivity can be injected into the formation and counted to give a direct m e a s u r e m e n t of residual w a t e r and, hence, of residual oil. We could not find such m e a s u r e m e n t s reported in the literature. The major difficulty in this type of measuring m a y be in getting rid of the effect of the radioactivity in the borehole. At this writing, we

Downhole Tracers

311

are u n a w a r e of any procedure currently in use for doing this without affecting the radioactivity in the formation.

0 GR 50 0 b

,

I

Formation sigma

40 .

I

0 GR 50 0

Formation s!gma

4O

Figure 7.9. Channel flow by LIL with boron as a tracer

RADIOACTIVE TRACERS FOR WELL TREATMENT DOWNHOLE Downhole t r e a t m e n t in oil wells refers here to the kinds of t r e a t m e n t s (excluding mechanical treatments) initiated at the surface but applied to a limited section of the borehole, often many thousands of feet below the surface. They can be divided into two classes: 1) well stimulation t r e a t m e n t s and 2) well control treatments.

312

Chapter 7

In some cases the t r e a t m e n t s are simple and the results well known from experience in the field; in others they are used as a form of shock therapy, often with little concern about how the procedure is applied. The procedure is important, however, and is expected to produce certain results. The treatments may be complex and must be applied to very specific locations in the wellbore for success. In such cases, tracers can be a powerful tool for verifying t h a t the t r e a t m e n t is successful and is applied to the specific area(s) required. The primary advantage of using (gamma-emitting) radioactive tracers for these applications lies in the ability to monitor them at the downhole location by means of a g a m m a detector on a wireline. A second advantage, one of increasing importance, is the ability to monitor both sequential and simultaneous operations by using tracers of different gamma energies. STIMULATION TREATMENT The production of hydrocarbons from an oil-bearing formation is limited by the permeability of the formation in the neighborhood of the wellbore. Production can often be increased by acidizing or adding solvents, surfactants, or a variety of other treatments that remove obstructing materials from the neighborhood of the wellbore. In low-permeability formations, hydrocarbon production can also be increased by inducing fractures at the wellbore. These kinds of well t r e a t m e n t are defined as well stimulation, and all share the characteristic t h a t they are expected to increase fluid entry into the borehole. The t r e a t m e n t may be different, but a similar situation holds in reverse for injection wells. CONTROL TREATMENT Not all production from the wellbore is desirable. Hydrocarbon production is often accompanied by undesirable amounts of other materials. There are m a n y examples of this. In unconsolidated formations, sand production can cause severe erosion problems and can lead to plugging of the well. Formations t h a t produce much brine and little or no oil place a strain upon disposal facilities and should be plugged. Formations t h a t produce water incompatible with other w a t e r produced in the wellbore can result in scale deposition and should be plugged back if possible. The control of undesirable production down hole is defined here as control treatment. All procedures for controlling this kind of production, including sand control, gel treatments, cement squeezes, flow diversion, etc., fall into this class. Similar control t r e a t m e n t s can be used for wells t h a t act as injectors for secondary recovery processes such as water flooding and various enhanced recovery procedures. TRACERS USED FOR WELL TREATING Gamma-emitting tracers have long been used in wellbore treating and stimulation operations (Flag et al., 1954; Gore et al., 1956). Early t r e a t m e n t s were limited to a single gamma-emitting tracer; energy discrimination down hole was not initially available. Tracer tagged stimulation t r e a t m e n t s were monitored

Downhole Tracers

313

down hole by a gamma counter on a wireline by Geiger counters. Introduction of the energy-sensitive scintillation (NaI) counters enabled the counter to follow, simultaneously, the fate of two or more tagged t r e a t m e n t s downhole using tracers having different energies. Procedures for tagging sand particles with a n u m b e r of radioactive isotopes, e.g., 51Cr, 192Ir, 198Au, 468c, 1248b, and llOAg, were well known. Baking sand coated with a suitable tracer solution at high temperature is a common procedure for tagging sand. A variety of tracer solutions for following liquid injections were also available. A number of radioactive isotopes have been identified (Pemper et al., 1988; Taylor et al., 1989; Gadeken et al., 1987) for use as downhole tracers, but the isotopes listed above plus 131I account for most of the downhole tracer work. These gamma-emitting tracers were used to verify the path of injected acids, and to observe the effect of flow diverters on the acid path. They were used to look at induced fractures and to estimate the position and extent of traced sand injected into the fracture at the wellbore face. The radioactive tracer log and the temperature log are the common ways of monitoring the extent of injected sand. A difficulty with monitoring the extent of traced sand from the wellbore is that if the wellbore and the fracture entry are not parallel, they may intersect at an angle and suggest a foreshortened extent of sand. Some early a t t e m p t s were made to look at two simultaneous downhole operations by using two tracers that differed widely in half-life (Pearce, 1979; Lindley and McGhee, 1983); however this is expensive and of limited effectiveness. Recent improvements in techniques for analyzing g a m m a ray spectra now permit the use of multiple tracers down hole. This allowsthe simultaneous monitoring of related downhole operations and has resulted in an expanded capability for analyzing and following downhole stimulation. The procedures used and the kind of results obtained are discussed below.

Spectral gamma ray analyses The rapid development of computer aided methods for analyzing g a m m a spectra in the past decade has had a significant effect on the logging industry. The effect on the petroleum industry lies principally in the ability to do g a m m a ray spectroscopy down hole. These techniques were developed originally to separate the uranium, thorium, and potassium components of n a t u r a l g a m m a ray logs, and have had a revolutionary effect upon the use of tracers for following downhole stimulations. NaI SCINTILLATION DETECTORS NaI(T1) detectors used for gamma ray detection are energy sensitive and can be used to obtain a spectrum, generated by the g a m m a radiation from the natural components in the borehole (U, Th, K), plus any gamma-emitting tracers added. The photoelectric peaks are used to identify each g a m m a ray energy

314

Chapter 7

associated with a radioisotope and to eliminate radiation from other sources. The gamma ray spectrum is complex, as discussed in chapter 2, because of the relatively poor resolution of the photo peaks and the competing reactions of gamma radiation in matter. This often results in a poorly resolved spectrum with little character, which limits the number of nuclides that can be used simultaneously but is adequate for most downhole processes. Such tracers make it possible to follow the results of sequential processes down hole and to distinguish between the fate of a proppant and that of the fluid transporting it. Photoelectric peaks are used to identify the separate gamma emitters by energy, and a variety of methods are used to deconvolve the gamma spectrum into its isotopic components, as discussed in chapter 2. Some of these procedures are used with modifications by the service companies and are discussed below. At this writing, the higher resolution germanium detector has not been reported for use by service companies, although it has been reported in this kind of downhole operation (Anderson et al., 1986). The high cost of germanium detectors and the requirement of liquid nitrogen temperatures make this too costly for most downhole work. A natural gamma-ray spectrum taken with a germanium detector downhole is shown in Fig 7.11. It is interesting to compare this spectrum with the (solid) curve from a NaI(T1) detector shown in Fig. 7.10. DECONVOLUTION OF GAMMASPECTRA There is a significant difference between spectral deconvolution as normally practiced in the laboratory and that which is required down hole. In the laboratory, the source detector geometry is fixed and chosen to optimize the analytical procedure. The laboratory spectrum can be deconvolved in terms of a collection of Gaussian photo peaks and an associated Compton continuum. Simple spectrum stripping is adequate for many laboratory applications. The purpose of the analysis in the laboratory is to determine quantitatively the amount of each isotope present in the sample. In the spectra collected down hole, the source-to-detector geometry is not fixed and, in general, is not precisely known, although it is usually assumed to be radially distributed about the borehole. The source-todetector distance will also vary depending upon where the tracer is distributed in and around the borehole. As a result, the shape of the spectrum will depend upon how much of the gamma radiation is degraded by Compton interactions. Resolution of the spectrum into the respective photo peaks will also depend on the choice of geometric models. In general, numerical methods of deconvolution give better statistics than spectrum stripping for downhole use.

Natural radioactivity The earliest use of spectral deconvolution down hole was in the resolution of natural radioactivity into its three components. The numerical methods used are discussed here as an illustration of the general procedure applicable to all downhole tracers.

Downhole Tracers

315

K-40 Th+U+K I

,,

I i

dN

.-, "--

I, ~,.

!yf - \

t ~,, x ,.

Energy (MeV) I W1

I

W9

I

W~I

I W4

I

WR

I SCNt.uMeE~oCR

Energy windows

Figure 7.10. N a t u r a l radiation g a m m a spectrum G a m m a r a d i a t i o n downhole arises mostly from the m e m b e r s of the U-238 series, the Th-232 series, and K-40. These were discussed earlier in chapter 2, and the U-238 series illustrated in Fig. 1.17. Each of the series contains a n u m ber of g a m m a emitters. A typical downhole spectrum is shown in the composite curve labeled (Th + U + K) in Fig. 7.10 (Schlumberger, 1986). This curve shows relatively little character, although it is composed of emissions from a large n u m ber of individual g a m m a emitters. Superimposed on the s p e c t r u m is a characteristic photopeak from each of the three sources, which also shows up as a bump on the composite curve. These are a thalium-208 peak from the thorium series, a bismuth-214 peak from the u r a n i u m series, and the potassium-40 component of n a t u r a l l y occurring potassium. The composite curve is, however, a linear combination of the g a m m a radiation from all three sources, regardless of character. Therefore, it can be resolved into its constituent sources by monitoring the count rate in each of three spectral regions or channels, and solving the three equations in three unknowns. The channels are usually chosen to include one p r o m i n e n t p h o t o p e a k for each of the three sources. The count rate for each channel, i, is given by the following expression: C i = Uij + Thij + Kij

(7.9)

where C is the m e a s u r e d count rate, i is the channel n u m b e r or window, and j represents the source of radiation: e.g., j = 1 for K, j = 2 for U, j = 3 for Th. Thus, if i=l is the potassium channel, Kij = C l l K is the contribution due to potassium

316

Chapter 7

in t h a t channel, Uij = C 12U is the uranium series contribution to the count rate in t h a t channel, and Thij = C13Th is the thorium series contribution. The total count in this channel, C1, is given by the sum of these contributions: C 1 = C l l K + C12 U + C 1 3 T h Similar equations are written for the other two counting channels, C2 and C 3. In matrix notation, the three simultaneous equations can be written as:

E]

(7.10)

[C]= C2 = [A][W] = [A] C3

Here [A] is the square matrix of the coefficients Cij, and [C] and [W] are column vectors as sbown. Solution of the three equations in three u n k n o w n s gives the contribution from each of the separate sources. To convert the counts to concentrations, a standard containing a known amount of the three components at radioactive equilibrium is counted in the same counter. As in all counting systems, there is an independent counting error, equal to the square root of the count rate, associated with each of the measurements in all of the channels. This error is propagated throughout the system since the solutions are a function of all the count rates. In general these errors will not be equal; hence simple averaging will not equitably distribute the error. A weighted average is therefore used to distribute the most probable error. In order to minimize the errors, a larger number of channels is chosen than is needed to solve for the three components. In the case illustrated in Fig. 7.10, five window channels are used. The equations can be written in a similar m a n n e r in matrix form. In this case, [C] is composed of the count rate in each of the five channels, [W] is composed of the elemental concentrations of potassium, uranium, and thorium in ppm or weight percent, and [S] is a 3 X 5 sensitivity matrix for channel i and source j, expressed in counts/second/ppm. Coefficients of this matrix are calculated by a weighted least squares method to minimize the error (Beers, 1959; Serra et al., 1980; Smith et al., 1983). The solution for each of the elemental concentrations can be expressed in the following form, where S contains the new coefficients: g

[W] = S [C]

(7.11)

In addition to the independent errors noted above, other sources of error present are a function of the conditions of m e a s u r e m e n t down hole (Smith et al., 1983). In all of these systems, variations in downhole conditions m u s t also be t a k e n into account. Calibrations must account for casing diameter, thickness, and density, the properties of the cement annulus, and any other variations t h a t

Downhole Tracers

317

are known to affect calibration conditions. Spectral analysis of naturally occurring radioactivity is widely used in the oil industry because of the added geochemical information. Germanium detector comparison As a standard for comparison with the scintillation detector, a natural gamma ray spectrum taken with a high resolution germanium detector downhole is shown in Fig 7.11 (Zhao et al., 1993). It is important to recognize the relative ease of deconvolving this spectrum into its component sources, compared with that from the NaI detector. The detector used here was mounted in a vacuuminsulated cryostat using solid propane as a coolant (-170~ The resolution was 5 keV for the 1.33 MeV gamma of Co-60, measured at the end of 3500 meters of cable.

0_

v

>

N

8

~>

rn

Energy, MeV

Figure 7.11. Natural gamma spectrum with Ge detector

The authors point out t ha t the 1.76-MeV gamma ray of Bi-214, used for identification of uranium by the NaI detector (Fig 7.10), is a ninth generation decay product of U-238. If the U-Ra equilibrium is destroyed by solution or reaction, the apparent uranium concentration can be off by a very large factor. The high resolution of the Ge detector will allow even third generation decay products, always in equilibrium with U-235, to be correctly detected.

318

Chapter 7

Radioactive tracers downhole

Analysis of g a m m a emission from downhole tracers is done in the same m a n ner as for naturally occurring radioactivity. The procedures have been described thoroughly in the literature (Gadeken and Smith, 1986; P e m p e r et al., 1988; Gadeken et al., 1988). The resolution of the NaI detectors limits the useful n u m ber of windows (channels) to 256. These channels can be grouped into a smaller n u m b e r of windows, as desired, for data analysis. One service company uses 13 windows to collect the data; another uses 25. In general, when downhole tracers are used, the added activity will be much larger t h a n background, but some of the background can be subtracted by energy discrimination if need be; otherwise the use of downhole tracers involves the same kind of spectral analysis as described for n a t u r a l radioactivity. Typical spectra of tracers frequently used in downhole surveys are shown in Fig. 7.12 (Schlumberger, 1986). The counting errors associated with deconvolving a complex spectrum limit the n u m b e r of tracers t h a t can be used simultaneously to a m a x i m u m of three

~

6

0.88

1,38

041

Agl 1o

0.38

Au198 1131

Sc 46 .......

1.69

2.10

Sb124 ---ir192

0.91 " ~ :

2.62 _ a __Th232

~'-~

I 46

K4O ~.~_~

0

i

0:5

1.12

1:0

1.76

1.'5

2.18

2:0

U238

2:5

3:0

Gamma ray energy, MeV

Figure 7.12. Typical downhole gamma spectra of common tracers

Downhole Tracers

319

isotopes (Gadeken and Smith, 1989). Better results are obtained with a lower number. Most of the downhole work to be discussed here is concerned with tracers used to differentiate between the placements down hole of two or more simultaneous or sequential operations. The g a m m a tool identifies the location of each tagged t r e a t m e n t in the borehole by its deconvolved energy signature. The depth of p e n e t r a t i o n is e s t i m a t e d from the ratio of the Compton to photoelectric response in the detector. The source geometry in the borehole is usually not known. Most service companies a s s u m e a radially distributed source as a first approximation, even though some of the downhole fracture t r e a t m e n t s are not intended to be radially distributed. This is probably adequate for the limited qualitative interpretations required. E a r l y use of these multiple tracer techniques pointed out m a n y problems in the application. A set of tests reported by Williams et al. (1986) showed the utility of the method but also m a n y of the unexpected difficulties. Early problems in s e p a r a t i n g the components of the g a m m a spectrum resulted in large errors in isotope assignment. The authors reported difficulties due to degradation of the radioactivity of the tagged sand under storage, requiring frequent monitoring and calibration. There were also problems with movement of tagged sand in the formation following the fracture t r e a t m e n t , most of which have since been resolved. The use of tracers to follow well stimulation is now conventional oilfield practice. Tracers are injected with the hydraulic fluid used to fracture the formation, with any acid or other intermediate t r e a t m e n t to clean the fracture up, and with the materials used to prop the fracture open. They are particularly important in a staged sequence of treatments. At least ten different g a m m a - e m i t t i n g tracers have been identified for this purpose. By proper choice of tracer energy, it is possible to follow the results of three or four sequential operations, or to follow sepa r a t e parts of the same operations, distinguishing the hydraulic fluid from the proppant carried by the fluid.

Depth of treatment penetration from tracer data PRINCIPLES OF MEASUREMENT The depth of penetration of g a m m a radiation into the formation is relatively small. The m a x i m u m distance from the wellbore to the full penetration through casing, cement, and formation, for a 1.5 MeV gamma, is less t h a n 8 in. (20 cm); however this is i m p o r t a n t in differentiating between m a t e r i a l left inside the borehole and the m a t e r i a l injected into the formation. A major difficulty in monitoring radioactive materials down hole has been to distinguish between

320

Chapter 7

source distance and source strength, i.e., between a small source n e a r the detector and a large source far away. A photoelectric peak at the detector down hole records the arrival of unscattered radiation from the neighborhood of the borehole. Most of the radiation arriving at the detector is scattered by the intervening m a t t e r due to Compton interactions, the most likely reaction for g a m m a energies between 100 keV and 3 MeV in formation materials. The linear absorption coefficient for Compton scattering (except for the lightest elements) is proportional to the bulk density in the intervening path. For material of equal density, the ratio of u n s c a t t e r e d (photoelectric) to Compton scattered radiation should be inversely related to the distance from the source. A Monte Carlo simulation was used by Jassti and Fogler (1990) to derive the ratio of scattered (Compton) to the unscattered (photoelectric) radiation arriving at a detector from a point g a m m a source (0.365 MeV) in a sandstone medium. The ratio was found to increase monotonically with distance from source to detector and was a good measure of location in the near region of the wellbore. They made laboratory m e a s u r e m e n t s of the velocity of an injected tracer pulse moving away from the detector in a sandstone core and concluded t h a t the velocity of the pulse could be determined accurately from the a t t e n u a t i o n r a t e of either scattered or unscattered radiation, and t h a t it was independent of pulse spreading. Application of the ratio of scattered to unscattered radiation for monitoring distance of penetration can, in principle, be extended to distributed sources, given the geometry of the source. DOWNHOLE MEASUREMENTS WITH LOGGINGTOOLS Measurements of this ratio in a downhole detector were used by Anderson et al. (1986) as an indicator of source distance. They proposed t h a t the ratio, RC, of counts in the photo peak (unscattered) region, P, to that in a Compton (scattered) region, C, was related to the distance between source and detector. P RC = ~

(7.12)

They tested the concept using a Cs-137 (E = .667 MeV) as a point source and applied it to a field fracture test using sand tagged with Ir-192 as a proppant. A germanium detector was used to collect the data. The region from 220 to 250 keV was chosen for the scattered radiation, and from 295 to 612 keV for the relatively unscattered radiation. The ratio of counts in the two regions was used to distinguish the tracer response due to nearby material in the wellbore from the distant material in the fracture. This procedure was used earlier in the application of 160 activation by Arnold and Papp (1979), who empirically correlated the ratio, P, of count rates at high

Downhole Tracers

321

versus low energies, with the distance from source to counter. The data were calibrated for the density of casing in the well and used to estimate the distance to a cement channel. In a recent patent, Smith and Gadeken (1989) describe a NaI logging counter with one high-energy and two low-energy windows. Two count-rate ratios were derived from these windows. One, Re, the ratio of counts from the high-energy window (photoelectric effect) to those from one of the low-energy windows (Compton scatter) was related to distance from the source. A second ratio, Rp, was t a k e n between the two "low" energy windows, where the low energy window was sensitive to the iron (casing) because of its high photoelectric absorption, whereas the higher energy window responded to Compton scattering as well. Most downhole g a m m a tools are encased in steel and are usually insensitive to low-energy radiation. There are, however, several processes within the wellbore where useful m e a s u r e m e n t s can only be made at these low energies. In succeeding papers (Gadeken et al., 1988; Gadeken et al., 1989; Gadeken and Smith, 1989; and Smith and Gadeken, 1990), the authors expanded the concepts of using energy ratios for estimating relative distance, discussed in the para g r a p h above. They proposed a model in which the tracer is distributed cylindrically about the detector at two locations: one inside the borehole and the other in the formation outside the casing. For a given casing diameter, they treated each t r a c e r as having two spectra, one for each location. The spectra are deconvolved by treating the tracer at each location as a separate component. The authors demonstrated the technique using simulated spectra for 46Sc and 192Ir, showing t h a t the four-component t r e a t m e n t gave superior results to the two-component t r e a t m e n t and t h a t the propagation of errors severely limited the n u m b e r of tracers t h a t can be analyzed simultaneously. In the studies above, the authors also related the counting ratio, Re, of high-energy (unscattered) to low-energy (Compton scattered) counts to D, the distance between source and detector: B

RC = A + D--~

(7.13)

They showed t h a t a plot of RC versus 1/D2fits a fairly straight line where A and B are constants dependent on the tracer type and the casing diameter. For a single tracer, this was proposed as a means of locating the m e a n distance (radial) of cement or gravel packs. They claim good results using this method on data from a published cement study (Kline et al., 1986). In real cases in the field, the tagged materials are distributed over large intervals. The radial distances obtained from logs are only approximate but can provide an indicator of relative position. The authors gave a number of field examples. In a n o t h e r paper on the use of multiple tracers for monitoring downhole t r e a t m e n t s , P e m p e r et al. (1988) pointed out t h a t the choice of low-energy window width should be the best compromise between sensitivity and statistical

322

Chapter 7

fluctuations. An increase of width from 30 to 40 keV gave a 23 percent increase in sensitivity, and from 30 to 80 keV gave a 60 percent increase. They also showed that when multiple tracers are used down hole, or natural background is high, the Compton ratio, RC, for measuring source-detector distance should be corrected for the extra background, B, in the Compton component due to tracers other than the present one for which RC is being calculated: P RC = C-B

(7.14)

A variety of simple functions have been proposed to relate this ratio, RC, with the (radical) distance from the source to the detector. They are all qualitative in nature and are used only as indicators of whether the source is inside or outside the casing.

Downhole tracer procedures There are now numerous papers reporting the use of tracers for following downhole operations. Such operations as acidizing, flow diversion, squeeze cementation, fracturing, and fracture propping are frequently tagged (Gadeken et al., 1988; Pemper et al., 1989; Taylor and Bandy, 1989; Gadeken and Smith, 1989; Kennedy et al., 1990; and Schwanke et al., 1990). The procedures used in designing such operations almost always involve several different service companies. These usually include a tracer company, a pumping company, a logging company and the oil company requesting the test. Radioactive tracers must properly follow the materials being traced. This requires that the tracer have the same transport properties as and be well mixed with the material being traced. In a rare procedural paper, Priest (1988) describes the handling problems and procedures used for injecting radioactively tagged sand. The author discusses the safety aspects of transporting and using radioactively tagged sand in the field. He also describes surface injection and mixing equipment, as well as procedures, and provides several case histories. The author makes the point that radioactive tracers for sand fractures should be injected as close to the well as possible to reduce the chance of radioactive contamination at the well site. DOWNHOLE TRACERTEST DESIGN In a series of papers referenced above, Gadeken discusses the design of such tests down hole. The design of a tracer project for downhole logging is based upon proper placement of the tagged material and the ability to monitor its placement downhole by the emitted radiation. Success in the test requires good coordination among all the companies taking part in the operation (Haliburton, 1990). The tracers must be properly chosen and placed down hole at the assigned depth, and

Downhole Tracers

323

good logging practice m u s t be followed. As much as possible should be known about all aspects of the test to maximize the information extracted from the log. Tracer concentrations should be high enough to allow for good statistics in the m e a s u r e m e n t s and to avoid large background corrections; however, excessive tracer concentrations should be avoided. The scintillation detectors used in these logs are designed to have a linear response for radiation levels up to about 6000 API units. Counting rates much higher t h a n this are counterproductive. They distort the response and obscure the differences in tracer location. The rule of t h u m b for tracer addition is to add a few tenths of a millicurie of tracer (depending on the tracer) per 1000 pounds of solids or gallons of fluid. This usually gives readings from several hundred to a few thousand API units; however many other factors can play a role in the tracer activity logged down hole. Experience in local operations of this type is a great help. A graph of recommended tracer concentrations in millicuries per 1000 for the common tracers used in downhole logging is shown in Fig. 7.13 (Haliburton, 1990). This figure includes correction for decay of the tracer during the time between tagging and logging. If logging speeds are kept low, in the order of 10 ft/min, even low radiation levels can be used successfully. As in all such treatments, the tracer response should be one to two orders of magnitude above background to minimize the counting error. Downhole test problems Tracers are used to track injected fracturing fluid, acidizing or other well treating solutions, flow diverters, cement squeezes, and a variety of other downhole treatments. In all of these, the tracer log must be indicative of the location of the injected t r e a t m e n t in the borehole. Many of these procedures are combined and performed simultaneously, while others may be done in a sequential order. In some of these procedures, e.g., fracturing, it is important to show t h a t the injected materials have moved beyond the wellbore casing. A major source of confusion in interpreting logs for depth of penetration is inadvertent deposition of tracer inside the wellbore. The common radioactive materials used for the downhole studies described here are cationic (except for 131I). The formation surfaces tend to be anionic and will attract and absorb cations. This can be advantageous if carefully thought out, since it might put more tracer near the well surface of the injection treatment region. It can, however, cause problems in log interpretation if it simply deposits on the well surfaces. Corrosion down hole often involves iron oxide surfaces, which can be anionic and thus adsorb cations. In acid solution there is little problem with cation absorption; however at intermediate to high pH, the addition of carrier and the use of a complexing agent is warranted.

Post-test evaluation of the downhole tracer log for t r e a t m e n t penetration can be so complicated by tagged materials left in the borehole that every effort should be made to avoid this problem by using clean operating procedures and paying

324

Chapter 7

careful attention to detail. In some cases it may be necessary to swab or even to produce the well in order to remove u n w a n t e d tracer m a t e r i a l s from the borehole. The deleterious effect of such r e m n a n t s upon the a p p a r e n t radial d i s t a n c e of t r a c e r s from the borehole was d e m o n s t r a t e d in l a b o r a t o r y m e a s u r e m e n t s using Sc-46 as a tracer (Gadeken et al., 1989) placed in an annulus around the wellbore. The data showed that the apparent Compton ratio increases almost linearly as the fraction of total tracer concentration, f, changes from being all in the formation (f = 1) to being all inside the borehole (f = 0). It is accompanied by an a p p a r e n t decrease in the diameter of the tagged a n n u l u s calculated from Eq. (7.12) as the fraction of tracer remaining in the borehole increases. This can be a significant source of error.

,O

Au198

10 ,

~=

O= ~~ t,._

I

/

"Se

/__/

=7 O ~

1

/,-

J

*._.~

~

1 131

r,

/

z ,,'" /

/,,

. .

.

--

. .

. .

. .

..

..

..

..

..

/

Z

... Sb124

~'

__._.,. . ~ "

a"O_ ) - -~

..

" - ~ - ~ _ _ _ ~ . ~ . ,__ w

~

"-'~ -

Ir192 Sc46

go =:'IT:

Ag110 ,1

0

'

'

'

10

20

30

40

50

60

70

80

90

10b

Estimated time between tagging and logging, days

Figure 7.13. Recommended tracer concentrations for downhole operations

In general, better quality results are obtained when the best counting statistics are available. Larger diameter detectors provide better data t h a n small ones because of higher counting efficiency. Averaging results from several passes of the log improves the counting statistics and the log interpretation from a test. As the number of tracers used increases, the counting error (signal-to-noise ratio) also increases and makes interpretation more difficult. The needs of the test m u s t be balanced against the desire for better data. A 31/2-in. diameter detector

Downhole Tracers

325

is more efficient t h a n a smaller one, but it may not pass through tubing. Similar compromises are required for other factors. Given a choice, it is preferable to have simple r a t h e r t h a n complex test conditions. The assumption t h a t all stages of a multistage test remain separate in the borehole is not always valid. Mixing effects in the borehole can cause staged treatments to mix in unexpected ways. In all cases, as much auxiliary log and other data as possible should be gathered to help analyze the results. Despite the problems t h a t can occur in such tests, the successes outweigh the failures. Tracers provide a unique ability to monitor specific downhole operations t h a t is not otherwise available. The downhole environment is not always well understood. Only by the use of such tracer tests can we learn to fit downhole procedures to the specific well environment under test.

Proppant tagging Tracers for fracture proppants come in two general types: sand coated with a tracer fixed on the surface by heat t r e a t m e n t or resin coating, and as porous nonsand particles. The direct coating of tracer on the sand particle is the oldest method in use, usually accomplished by coating the sand with a solution of the desired tracer salt and baking the sand in an oven. Iridium, gold, and silver salts are easily reduced to the metal, and scandium salts to the oxides. The procedure requires careful handling and a clean sand surface for adhesion, and there may be some difficulties with tracer loss by friction or by wash-off. There have been reports of tracer loss from some proppants. One method of improving adhesion to the sand has been to coat the baked-on tracer with an epoxy resin. Curable resincoated proppants have also been used to prevent loss from the fracture during cleanup and production (Norman et al., 1990). The second method, coming into general use, is to absorb the radioactive material onto a porous ion exchange particle that may also serve as the proppant or be mixed with the another proppant as a tracer. In this procedure, the radioactive cation is adsorbed on a carrier such as aluminum oxide (A1203), which has ion exchange capacity and can be loaded with suitable ions. This procedure has the additional advantage t h a t the tracer can be absorbed in the a l u m i n u m oxide as a nonradioactive isotope. It can be permanently fixed on the substrate at high t e m p e r a t u r e and then activated in a research reactor, which simplifies the handling, m e a s u r i n g , and packaging of the tracer. Most of the commonly used tracers, such as 192Ir, 195Au, 468c, and llOAg, can be produced by an (n,~ reaction on the naturally occurring element. Cross sections are high, and there is little interference. The only possible problem with this type of tracer tag is t h a t the t r a c e r dynamics during injection into the formation can be different from those of the proppant. Differences in size and density between tracer and proppant can lead to errors in interpretation if they cause separation of the tracer from the proppant.

326

Chapter 7

Tagging injected liquids Any of the radioactive tracers discussed here can be used to trace injected fluids as long as they are completely soluble and do not react with materials in the wellbore. As indicated earlier, exceptions to ideal behavior can be designed into the fluid to ensure reaction with a desired component down hole. A variety of traced fluids have been used down hole. Virtually any downhole liquid t r e a t m e n t can be tagged, including acids, solvents, detergent solutions, scale and corrosion t r e a t m e n t s , and m a n y m o n o m e r and polymer solutions. M a n y liquids are injected in conjunction with other m a t e r i a l s , such as flow d i v e r t e r s a n d proppants, which may or may not be tagged. An alternative to the use of tagged fluids is the use of radioactively tagged particles of neutral density in the fluid. Tagged ion-exchange beads can be used for this purpose. Their density can be adjusted to fit the density of the brine, and multivalent ions are strongly absorbed by these beads. The beads will not travel far into the fracture but are permeable to water, which lets them act as m a r k e r s for w a t e r entry positions into the formation. They can be used to locate naturally occurring fractures at the borehole since the beads will collect at the perforations and can be logged after the injection.

Field examples HYDRAULIC FRACTURE TRACING Fractures are induced downhole by injecting a fluid into the well at sufficient pressure. A proppant is injected with the fluid to keep the fracture open when the pressure is released. One of the problems in this practice is to establish t h a t the fracturing fluid and the proppant carried by the fluid enter the same interval, and t h a t the proppant is deposited at the proper location in the formation. Fig. 7.14 shows a log of a fracture study in which 46Sc was used to tag the fluid and 192Ir was used to tag the proppant (Gadeken and Smith, 1989). The log shown is an average composed of three logging passes to improve the counting statistics. The n a t u r a l g a m m a - r a y log on a scale of 0 to 150 API units is shown on the left side of the wellbore schematic. Horizontal lines indicate 100-ft intervals. The "fit error" curve is an indicator of statistical error. The wellbore schematic shows the perforated interval. The two channels on the right of the wellbore show the tracer response curves on a scale to 1500 API units and the relative distance from the borehole, from n e a r to far. In the region from X220 to X360 there is a significant increase in the distance of penetration, which indicates good fracture propping. The relative distance plot shows a small increase to about X360, which suggests limited success in this region. The presence of both 46Sc and 192Ir throughout the logged interval suggests sand deposition inside the wellbore. The operating company had indicated t h a t the pumping rates were higher t h a n desirable, which could account for

327

Downhole Tracers

sand deposition. Overall results show that the fracture extended beyond the perforated interval but was not propped as effectively as expected.

Tracer log Relative Gamma log i 0 API 150! o API 1000 distance near far fit error I ..... _

,

_

1

~" rfit error .,,.~lamma

l~

7 ,i ,ix3oo! "

i

0_

1 ~,,j

!

Ir-192 - Sc-,

c-

i,

!

",..L . . . . .

Figure 7.14. Tagged fracture study showing fracture fluid and proppant TAGGED GRAVEL PACK TRACING An alternative use for tagged particles is in sand control for wells drilled t h r o u g h unconsolidated formations. Gravel packs are used to prevent sand incursions in the well, to maintain high permeability, and to prevent sand fines from plugging the perforations. The use of tracers for monitoring sand control is widespread in the oil field (Bruist et al., 1983; Jefferis et al., 1983; Gadeken et al., 1991). In recent years, this has been combined with an acid wash followed by prepacks set behind the perforations as auxiliary sand control. In all cases, placement of the gravel packs and/or prepacks downhole is an important concern.

328

Chapter 7

Tracer tagging for particles used for gravel packing is the same as that described above for fracture proppants. A tagged gravel pack study was used to confirm the completion procedures in an offshore California field (Bruist et al., 1983). Two tracer applications were used here: one for the tagged gravel pack and one for a radioactive m a r k e r for depth control in perforating. In this case, the collar locator did not accurately pick up the collars. In order to place the perforations accurately, a short joint of drill pipe with a p e r m a n e n t radioactive m a r k e r was positioned about 100 ft above the firing head. This was then correlated with the gamma ray log and with radioactive markers in the casing to position the guns for firing. A small amount of 10- to 20-mesh gravel was tagged with llOAg by a hightemperature baking procedure, uniformly mixed with the rest of the gravel in the slurry, and pumped down hole. The gravel was logged after placement by a g a m m a ray tool, and a neutron log run concurrently to compare "near" (borehole saturation) with "far" (formation saturation) to determine whether the annulus contained water. The results are shown in Fig. 7.15. Agreement between the two logs was expected for a good gravel pack. TAGGED DIVERTERS AND MULTISTAGEACID TREATMENT The effect of diverting agents on the injection of acid is a common concern in such treatments. Diverters are injected before injecting acid to divert the acid from entering intervals t h a t are highly water s a t u r a t e d in favor of less permeable formations producing oil. The results of a m u l t i s t a g e tagged acid t r e a t m e n t were reported by Kennedy et al. (1990). The t r e a t m e n t consisted of: 1) injecting a water zone diverter tagged with 2.7-day half-life 198Au and logging the well; 2) acidizing the well with 124Sb as a tracer (in the ammonium chloride post flush) and relogging the well; 3 ) a d d i n g nitrogen foam as a diverter and acidizing with 468c as a tracer in the post flush; and 4)injecting additional nitrogen foam and reacidizing, using 192Ir as an acid tracer. Fig. 7.16. shows results of the test logs. The well schematic shows perforations in two zones, A and B. The n a t u r a l gamma-ray spectrum is shown on the left of the well schematic, an induction log on the right side, and five channels showing the results of each t r e a t m e n t on the far right. The first log (Au) shows the invasion of the diverter into zones A and B, with most going into zone B. The first acid treatment (Sb) and the first foam plus acid t r e a t m e n t (Sc) showed little change in the distribution. Only the second foam plus acid t r e a t m e n t (Ir) showed a significant effect in zone A. This treatment was followed by an increase in oil production from the well. D i r e c t i o n a l o r i e n t a t i o n a t the borehole

Some of the procedures that take place in and around the borehole are associated with a preferred direction. The most prominent of these is fracturing.

329

Downhole Tracers

Much theoretical work has been done on predictions of fracture properties. The position of entry of fracture proppants and of fracturing fluids at the borehole is not generally known. The height of the fracture proppant is the only property conventionally measured at the borehole; very little work has been done on orientation of the proppant at the wellbore. The only additional equipment needed to measure the orientation at the borehole is a directional gamma detector.

Gamma ray logs CNL log 12/29 12/30 12/31

Tracers AuAu SbSc Ir ~GR

r

top gravel

A

c J. u w

top gravel J

j.

j,

_ _

B

|

~xxl

L~

_

top gravel

>

L Before After Acid treatment

Figure 7.15. Silver-110 tagged gravel pack logs

Figure 7.16. Tagged diverter and multistage acid treatments

A detector can be made directional by surrounding it with a shield of dense, high-atomic-number material with an opening in one direction. A sodium iodide scintillation detector within such a shield is a simple, relatively efficient arrangement. The shield material, thickness, and the shape of the slit will limit the directional resolution of the detector. More complicated arrangements, such as

330

Chapter 7

coincident crystal pairs, are also possible. The shield must be capable of rotation and also be coupled to a direction-sensing device such as a gyroscopic compass. A recent paper described the testing and use of a prototype directional g a m m a tool (Gadeken et al., 1991). In this tool (Fig. 7.17a), tungsten was used to shield a 1/2-in. diameter by 8-in. long NaI crystal. The included angle of the slit was about 40 degrees. The rotating shield was coupled to a 3-axis accelerometer to determine the gravity vector relative to the tool axis, for directional orientation. The tool was tested in a t a n k using 192Ir in four simulated fracture planes. Fig. 7.17b shows the response of the tool to each of these fracture planes. F r a c t u r e planes p e n e t r a t i n g the wellbore show the expected dual response lobes in direction of the plane; however, those that are offset or tangential to the borehole show single lobes t h a t point in the direction of the offset fracture plane. Two tests were also reported on field fracture logs. In the fracture orientation measurements described above, the fracture is presumed to be conventionally tagged with a radioactive isotope. Orientation is determined by monitoring the residual tag with the directional tool. An alternative way to do this would be to inject a tracer from a downhole tool and monitor where it goes, using the directional monitor during the process. To m a k e this effective, the two tools need to be combined.

r~,~,.~..,.~r

SI Tungsten Shield Rotoscan tool

Simulated fracture planes

Figure 7.17. Directional tool showing response to simulated fractures

331

Downhole Tracers

An interesting application of a directional monitor would be to observe the direction and velocity of flow at an observation well, presuming that flow at the wellbore is indicative of flow direction from the well. In this procedure, a tracer pulse would be placed in the borehole and its rate of disappearance and direction of flow monitored at each depth. Procedures such as this are used for monitoring groundwater flow in hydrology; they could also be useful in oilfield work. Jassti and Fogler (1990) proposed a method for monitoring the velocity of a tracer pulse in the near-wellbore region, as referred to earlier in the chapter. This could be combined with a directional monitor to provide both direction and velocity of flow in the neighborhood of the wellbore.

Diameter of exposed crystal

'

.E_

Lv//

Total no.

//

/

/

/

/

of holes, N

~ _

focal

~

plane

R

\

\

\\

Depth of focus, X \

Figure 7.18. Focusing collimator

FOCUSING COLLIMATOR An alternative directional method used in medicine is to combine relatively low-energy radiation with a focusing collimator. For low-energy radiation, the high atomic number shield becomes essentially opaque because of the predominance of the photoelectric effect. As a result, a cone-shaped array of holes in a

332

Chapter 7

lead or tungsten shield acts as a lens, focusing the radiation from a small area on the detector. An extensive literature can be found on the design and application of such collimators. A schematic of such a detector is shown in Fig. 7.18 (Hine and Sorenson, 1970). Collimators are used at g a m m a energies up to about 500 keV, with some loss of resolution; the resolution at lower energies is much higher. The choice of focal plane and depth of field depends upon the n u m b e r of holes, their shape and size, the dimensions of the collimator, and other factors. As in optical lenses, the depth of field decreases as the focal length increases; however the shape of the focus at the surface does not have to be circular but can be a vertical or horizontal slit if desired. Relatively low-energy g a m m a radiation limits this i n s t r u m e n t to studies inside the wellbore; however it would be able to monitor flow direction and tracers at the perforations. It could also be useful for examining the wellbore down hole and for following the effects of radioactively tagged wellbore treatments, such as corrosion and scale inhibitors on the casing. Technetium-99 would be a useful tag for such work, since it is readily available, easily inserted into corrosion and scale inhibitors, and has a suitable energy and half-life. Nondirectional tools capable of monitoring such low-energy radiation downhole are commercially available (Gadeken et al., 1989), and it should not be difficult to fit a collimator to such tools.

Anomalous background interference: Radioactive scale Background count rates in the borehole are normally due to the presence of n a t u r a l radioactivity on the ground. Another source of natural radioactivity t h a t has become increasingly important with the use of sea water for w a t e r flooding, is scale deposition in the borehole. The scaling is caused by the reaction of sulfate and carbonate ions with alkaline earth cations (Ca++, Sr ++, Ba ++, and Ra ++) to form insoluble scales. These cations are denoted as the group II cations in the periodic table. Radioactive scale can form wherever the concentration of these ions is high enough to meet precipitation conditions and wherever r a d i u m ions are mobile with oilfield brines. The secular equilibrium between the members of the natural radioactive series was discussed in chapter 1. Radium is a component of both the 238U and the 232Th series. Chemically, it is a member of the alkaline e a r t h group. When a solution carrying radium ions is present and scaling conditions exist for the other members of the alkaline earths, it will co-precipitate with them. The r a d i u m in the scale will s t a r t a new radioactive series. Depending upon the local concentration of radium in solution, and time for the new radioactive equilibrium, the scale can easily reach radioactivity levels of hundreds of API units (Smith, 1987). Scaling conditions usually occur at the wellbore when two incompatible waters meet, or when a change in pressure or t e m p e r a t u r e lowers the solubility

Downhole Tracers

333

of the precipitating species. Not all scales of this type are radioactive, nor is all anomalous radioactivity in the borehole due to scale. When radioactive scale is diagnosed, it can be removed by acidization, if it is predominantly a carbonate scale. Some of the sulfate scales are, however, difficult to remove by chemical t r e a t m e n t and m u s t be removed mechanically. Legal problems are associated with removal of the scale if it is brought to the surface. N a t u r a l l y occurring radioactive materials (NORM) in the North Sea, Western Europe, the United States and Canada, and m a n y other parts of the world are controlled by essentially similar regulations, which are discussed further in chapter 8. The presence of scale is not necessarily bad, since scale formation can also serve to seal off a water producing formation to increase the productivity of the well by decreasing the water cut. The presence of barium scales down hole can also be detected by the fast neutron reaction 138Ba(n,2n)137mBa, described earlier in the discussion of a proposal (Jordan et al., 1988) for locating mud behind casing.

O T H E R GAMMA-RAY T R A C E R M E T H O D S Several downhole processes are important to the operation of a well, including the placement of cement, mud, and completion fluids, and the displacement of some of these by other materials. The displacement process is assumed to be piston-like, although leaks behind casing show that this is not always true. Very few tests have been reported on how these materials are displaced downhole. An exception to this is the cement study reported below.

Cement behind casing Cementing is one of the important downhole procedures. Tracer methods for monitoring cement, usually restricted to marking a cement position, are rarely applied to the entire process down hole. An example of a continuous method for following cement placement down hole was given in a recent paper by Kline (1986). This paper also describes the method used for tagging the cement with tracer and the procedures used to monitor it down hole. This tracer method was used to measure cement coverage behind casing. Assuming a piston-like displacement of mud by cement, it is also a monitor of mud displacement. Short-lived tracers were used to tag the cement as it was pumped down hole. To ensure uniform tracer injection under variable cement flow rates, the cement flow rate was monitored by an accurate magnetic flow meter. The meter output was fed to a proportioning controller t h a t drove a laboratory chrom a t o g r a p h y pump to inject the required amount of tracer solution into the cement stream. To avoid contamination with radioactivity, the pump handled only oil. A floating piston was used to separate the pumped oil from the aqueous

334

Chapter 7

tracer solution. The tracer solution was forced out of the shielded container by the oil and mixed with the cement at the T-section. A schematic of the procedure is shown in Fig. 7.19. The cement was tagged with one of three gamma-emitting tracers: the 8.1-day half-life 1-131, the 2.7-day Au-198, or the 1.5-day Br-82, and was monitored with an energy sensitive gamma-ray tool immediately after cementing. Injected tracer levels of about 0.1 mCi/bbl gave enough signal down hole to be easily monitored by the tool by means of energy discrimination.

Magnetic flowmeter From pump truck

Cementing line injection joint

~ ~

To cementing head

s I I , I

, I ,

Pump control

Wa~rC~Shielded 'dL~ tracervessel

circuit Injection pump

Oil reservoir

Figure 7.19. Schematic of constant tracer injection system for tagging cement The physical model used for these tests assumes a radial, horizontal cross section of the dimensions shown in Fig. 7.20b. The bypassed mud is assumed to be in the outer layer in this model. The gamma signal, I, from the tagged cement is given by: r(1)

I=

K/

Jr(2)

e'~rdr r

(7.15)

where r(1) is the outer radius of the cement and r(2) is the outer radius of the casing. The gamma-ray absorption as a function of radial distance was measured experimentally using tagged cement poured around sections of casing into molds of different diameters. The absorption due to the casing and the fluid inside the casing are constant and are lumped into the constant, K, in the equation. The

335

Downhole Tracers

results of these measurements are shown in Fig. 7.20a. The method was applied in an experimental program of ten wells. Fig. 7.21 is a schematic of the cemented annulus in one of these wells. In this figure, the superficial cement radius calculated from the tracer log is plotted along the profile obtained from the 4-arm caliper prior to r u n n i n g casing. The same profiles are run on both sides of the center line. Arrows are used to indicate where the cement radius is smaller than the caliper radius and the cement does not completely fill the annulus, leaving a void. For most of the wellbore, the cement annulus is greater t h a n the caliper radius, indicating t h a t the borehole was washed out from post-drilling operations. From SP logs, the greatest enl a r g e m e n t occurs, as expected, in shales or shaley sands and the least in permeable sands; hence it is probably not an artifact due to radioactive filtrate. Various procedural variations were tested during the program, but no superior methods were found, given good cementing conditions. The author concludes t h a t poor cement zones are not directly related to mud displacement at normal levels. A paper by Smith and Gadeken (1990) used the change in the photoelectric to Compton ratio with distance to analyze the data reported above and verified the results reported by Kline. Both of these methods assume t h a t the tracers are radially uniform, since the detectors are nondirectional. Recent development of a directional detector, reported earlier in this chapter, would provide a useful way of determining how radially the cement is distributed.

1.0

>..

.0=

0.5

0.0 2.75

' 3.50

5.00

. . . .

6.50

by-passed mud

Radius, inches a. G a m m a response

b. Model

Figure 7.20. Cylindrical model showing gamma absorption curve

Chapter 7

336

Cement radius sCaliper

radius

TOP-s~f4cement

SP log

Float collar 4628

Figure 7.21. Calculated cement radius in typical well Well tracer method

Channels behind the casing that are accessible to the wellbore are often detected by the response of the tracer-loss log (Schlumberger, 1973) used in injectivity logging. This is described in greater detail in the section below on production logging. Channels behind casing can always be monitored by injection of water containing a tracer whenever channeling from some zone is suspected.

PRODUCTION LOGGING Production logging uses gamma-emitting tracers and a wireline g a m m a tool to monitor the depths at which fluids are injected or produced in the borehole. Most of the work reported is concerned with fluids injected downhole for secondary or tertiary recovery methods. The purpose of logging is to provide a flow profile t h a t characterizes the flow distribution of these fluids at the borehole face and, presumably, indicates how they move through the formation. These are single-phase injections except for steam, which for tracing purposes can often be treated as two independent single phases.

Downhole Tracers

337

Production logging should cover fluid production downhole as well as injection. Downhole production logging is often more complicated for two reasons: 1) it usually involves at least two and often three phases, which can be difficult to decipher; and 2) disposal of the radioactive tracer produced at the surface can be a safety and regulation problem. As a result, relatively few produced fluids are monitored. Most production logging monitors only the injection of fluids into the formation. At this writing, very little logging of produced fluid has been reported; however there are some interesting exceptions. In at least three cases, production wells were monitored through the annulus of rod-pumped wells (Simon and Keely, 1969; Petovello, 1975; Hammack et al., 1976) using radioactive tracers. All reported simultaneous use of multiple logging m e a s u r e m e n t s , including fluid density and temperature, as well as other logs. The two-phase flow regime was decoded by combining the tracer survey with the densitometer evaluation. The data were used to determine fluid production as a function of phase and position. The densitometers described were based on g a m m a absorption using a single g a m m a source. In principle, separate tracers can be used to monitor each produced phase, providing the phases flow separately and can be accessed by the tracer. No work of this nature has been reported.

Water injection logging The use of tracers for following the injection and production of fluids in and out of the formation has been critically reviewed in a recent SPE monograph on production logging (Hill, 1990). The author describes the tools; discusses the operational details, procedures, and log interpretations; and compares the use of tracer techniques with other competitive and supportive logging techniques. The following will briefly summarize sections in the monograph that refer to the use of tracers for this purpose. Twenty-five references are given. One of the principal uses of tracers in the wellbore is in the area of production logging. The widest application has been for monitoring the downhole injection profile of water injection wells. In this application, a pulse of radioactive tracers is added to the injected water stream from a tool on a wireline down hole. As the w a t e r moves down hole, the movement of the tracer pulse in the borehole is monitored by r a d i a t i o n detectors on the tool. Two kinds of tracer-logging procedures are commonly used to monitor the injectivity profile: the tracer-loss log and the velocity shot log. In both of these procedures, 1-131 tagged iodide solution is the commonly used tracer material. It emits easily measured g a m m a radiation; because of its widespread use in medicine, it is cheap and readily available; and the short (8-day) half-life reduces the possibility of contamination problems. A schematic of a generic wireline tool used for production logging is shown in Fig. 7.22. It contains a tracer injector that can be controlled from the surface and

Chapter 7

338

either one or two gamma detectors that are normally NaI(T1) scintillation detectors. There may also be a collar locator. Other logging tools such as temperature monitors are frequently added. The length of the tool and the arrangement of parts are variable.

1 3/8" O.[

J, rracer ~jector

41/2'

Motor Detector No. 1

{I

E N,

, - Casing Collar Locator

,---Detector No 2

Figure 7.22. Wireline tool for production logging TRACER-LOSS LOG In this procedure, the tool is lowered down hole, a single pulse of tracer is injected into the water stream, and the fate of the pulse is monitored as it moves down hole. The tool used is similar to the one shown in Fig. 7.22 except that only one detector is required for the tracer-loss log. The tracer pulse is injected 20 to 30 ft below the tubing tail but well above the perforations. The pulse is mixed into the injection water by passing the tool through it several times. The tool is then dropped below the pulse and the gamma intensity measured as it is logged up through the tracer pulse. At the

Downhole Tracers

339

start, the tracer pulse is logged several times while the pulse is still above the perforations to establish a base for 100 percent flow. This procedure is repeated as the pulse moves down hole. A gamma-intensity peak is recorded for each downhole location. A maximum of about 15 passes can be made before the tracer slug dissipates or becomes stationary. Injection of tracer is preceded by a g a m m a log of the well for background subtraction and for identifying flow behind casing. A typical tracer-loss log is shown in Fig. 7.23 (Hill, 1990). In this figure, the well schematic is in the center, the logs of the tracer pulse at different depths are on the left of the well, and the time each log was taken is shown on the right. A total of thirteen logs were taken over a depth of 100 feet. The log is analyzed by assuming that the total flow rate into the well is constant, and t h a t the tracer loss is directly proportional to the water loss. The amount of radioactivity, A, in the measured pulse is given by: A = ~Cdv

(7.16)

where C is the tracer concentration in activity per unit volume, and v is the volume. The log, however, monitors the radiation, R, emitted by the pulse as a function of depth, 1, rather t h a n its concentration, C, as a function of volume, v. Since counting conditions and dimensions are the same throughout the borehole, the radiation emitted should be proportional to the concentration: A = ~Cdv = k~Rdl

(7.17)

where k is a proportionality constant. The area under the log curve is simply the integral ~Rdl. The area, A100, under the tracer peaks logged above the perforations, therefore, represents the amount of tracer injected at zero tracer loss. It is equivalent to 100 percent flow, Q100. When the tracer pulse moves past a permeable zone, it loses tracer to that zone in proportion to the loss of water. The area, A1, under the curve in the downstream log is a m e a s u r e of the activity remaining in the pulse at that depth. Each log area, AI, reflects the remaining water distribution as it moves down the wellbore past succeeding zones, so t h a t in principle, AlOO = ~ i - 1 - Ai. The ratio of Ai to AlOO, the area at 100 percent, is taken to be the fraction, F, of flow remaining at that position:

F

-

Qi Ai QlOO - A 10o

(7.18)

The distance between tracer-peak locations in the tracer-loss method tends to be large, so that the depth resolution of the log is relatively poor. Resolution also suffers when the tracer slugs measured are opposite fluid entry zones, since this skews the assignment of depth to a flow rate. This method also depends upon complete mixing of the tracer pulse with the fluid in the wellbore, which may be r a t h e r poor at the beginning. Other problems arise because of 1) distortion of the tracer pulse by tool passage and 2) incomplete mixing of the slug with injection

340

Chapter 7

water. As a result, it is considered to be primarily a qualitative method. Resolution can be improved somewhat by timing each tracer pass and using the velocity calculated to improve the resolution. Further details are given in the monograph.

.:,,,

~~__

|

time

run #

0:00

1

5200 0:29

_.....--

1

,..

2

1:06

3

1:38

4

i

5 II

2:54

6

7 5300~

4:28 i

19n_ 11:32

!

I

13

I

I

Figure 7.23. Tracer-loss log A possible variant of the tracer-loss procedure would be to use a tagged, water-permeable particle of neutral buoyancy as a tracer. The tracer pulse would be composed of a mixture of tagged particles instead of a tagged solute. The log areas discussed above would still measure the remaining water flow; however the flow entering each porous zone should be marked by the deposition of the tagged particles, assuming that the particles are larger than the pores. Since they are permeable to water, they should not cause a significant resistance to flow. A gamma log of the wellbore after the test, under these flow conditions, should be a direct monitor of the distribution of particles and, hence, of the flow entering

341

Downhole Tracers

each zone. In principle, ion-exchange beads of suitable density would be ideal for this purpose; however, there is always the danger that such particles might stick on other wellbore surfaces and give false information. A major application of the tracer-loss method is identification of flow behind casing. This is evidenced by a secondary peak that moves independently up or down the well as shown in Fig. 7.24 (Schlumberger Ltd., 1973). Here, a channel between sands 3 and 4 results in an upward flow of a pulse monitored by the six sequential logs, t l through t6, shown on the figure. A channel is also evident between sands 2 and 1, resulting in a downward movement of the pulse.

Timed gamma ray surveys Well sketch

tl

12

t3

t4

~

ffi

I

Sand -3

Sand "2 Channel Sand

Figure 7.24. Channel flow identification by tracer-loss log

342

Chapter 7

=.! 2 seconds

t

tc'

.-

Figure 7.25. Velocity shot log detection interval VELOCITY SHOT LOGS In the velocity shot procedure, a tracer pulse is injected into the flowing stream from the logging tool positioned down hole, illustrated in Fig. 7.22. The tool requires both detectors shown here. The velocity of the moving w a t e r is obtained from the transit time of the tracer pulse between the two detectors mounted a fixed distance apart. A typical response at the two detectors is shown in Fig. 7.25 (Hill, 1990). Here, Atpp is the transit time for the pulse m e a s u r e d from the two response peaks, and Atle is time between leading edges. This log assumes a constant wellbore diameter, true for cased holes, and a constant flow rate between detectors, generally true if there is no fluid loss between the detectors. If a fluid exit occurs between the detectors during the tracer passage, the depth resolution of the log is limited to twice the detector distance. Corrections for variations in wellbore diameter and for fluid exit between detectors are discussed in the monograph. Analysis of the data is based upon the inverse relationship between flow rate, Qi, and transit time, ati. If the total flow rate (above the perforations) is QlOO and the equivalent transit time is At 100, then: Qi QlOO

-

Atloo Ati

(7.19)

The time interval between peaks can be obtained using several different landmarks, as shown in Fig. 7.25. The choice of landmarks depends more upon ease of characterization t h a n differences in operation. The usual choice is the peak m a x i m u m . Most choices are equivalent with known corrections. Depth resolution can be improved by decreasing the distance between detectors. One way to do this is to use overlapping intervals where the tool is moved a distance

343

Downhole Tracers

less t h a n the detector spacing. This improves the resolution to twice the interval for which t r a n s i t times are determined. A comparison of the results obtained using the interval method vs. the standard method is shown in Fig. 7.26 (Hill, 1990). Solid lines in the figure show the result obtained using the standard method. Dotted lines show those from the interval method. In the case illustrated here, the resolution improved from 12 ft for the standard method to 4 ft for the interval method.

% Flow Entering Interval 100 f

50

Depth (ft.)

% Total Flow 50

0 5020 Q

26

5030

I

r'"

IO0

OOO~~ .........................

15

5040

Figure 7.26. Comparison of interval with velocity logs A major problem in log interpretation arises when the flow changes from turbulent to laminar. In turbulent flow the pulses are sharply defined and the peaks easily characterized. When the flow becomes laminar, the pulses become very dispersed, and landmarks suitable for timing pulse arrivals are difficult to define. An example is shown in Fig. 7.27 (Hill, 1990), where the second detector shows no peak. In such cases, tangency to the baseline can serve as a timing landmark. Other procedures are discussed in the monograph. The m a n n e r in which the tracer was injected can also have a significant effect on tracer dispersion in laminar flow. The velocity shot log is the preferred procedure for injectivity profiles because of its superior depth resolution. In laminar flow, this is probably the only current way to measure low flow rates in a well. It is sensitive only to flow in the borehole and cannot detect flow through channels outside the casing. The tracer-loss log,

344

Chapter 7

on the other hand, has poor depth resolution but is sensitive to flow in channels outside the borehole. Other logs, such as temperature and flow meter, are capable of making similar measurements and can be run simultaneously, mounted on the same tool. Running a combined log in such m e a s u r e m e n t s serves to increase not only the confidence level in the measurements but also the breadth of the well response.

Lower detector response

Upper detector response T

i?j

T

/

.._l,

Figure 7.27. Velocity-shot in laminar flow

Tracer dilution logging The tracer dilution method for measuring flow is described in chapter 2, and its application to monitoring flow in pipelines, rivers, and other bodies of water is discussed in chapter 8. The tracer-dilution method depends upon the conservation of tracer and requires adequate mixing of injected tracer with the flowing fluid. In pipelines and bodies of water, good mixing depends to a large extent upon the vagaries of flow. To ensure that the injected tracer is sufficiently mixed with ambient fluid, the tracer injection and the detector are usually spaced a relatively large distance apart. This is not required if good methods are available for mixing the tracer into the moving fluid. The tracer dilution method for monitoring fluid flow in the borehole differs from its other applications in that a wireline tool contains both the injection and the measuring device, unlike monitors for pipeline flow where the detector and the injector are both outside the pipe. Proper mixing can be ensured by using a turbine or fan on the tool to mix the injected tracer with the ambient fluid in the

Downhole Tracers

345

wellbore. Both chemical and radioactive tracers can be used with this method, given a suitable detector for the chemical tracer used. For radioactive tracers, the large a n n u l a r volume scanned by the detector for the mixed tracer reduces the requirements for total mixing of the injected tracer. In effect, the detector m e a s u r e s the radiation from the flow-weighted average tracer concentration. Incomplete mixing can be used to determine flow by isotope dilution, providing a proper concentration m e a n can be found. This has been d e m o n s t r a t e d analytically (Barry, 1978) and experimentally (Hull, 1957) under certain circumstances. Incomplete mixing allows the close spacing between detector and injector, required for m e a s u r i n g flow in the borehole with high depth resolution. T r a c e r dilution logging can be done using either a pulse injection or a continuous (constant rate) injection of tracer. The two methods are discussed below. PULSE METHOD Although the tracer loss log discussed earlier is a pulse method, it is not a tracer dilution log, which is based upon the conservation of tracer, since tracer is not conserved in the tracer loss log, where loss of tracer is proportional to the loss of injected water. In the pulse dilution method, a pulse containing a known a m o u n t of tracer, A, is injected into the borehole from a downhole tool, where it is mixed with the injection (or production) fluid. The concentration, Co, of the diluted tracer pulse transported in the borehole by the injected or produced fluid, is monitored as it passes a detector mounted on the tool. The area, ~C(t)dt, under the concentration vs. time curve, and the total amount of tracer injected are used to calculate the flow rate, Q, in the borehole at t h a t depth. As shown in chapter 2, this is given by: A Q = j C ( t ) dt

(7.20)

The simplest configuration for such a wireline tool is shown in Fig. 7.28. It contains a pump capable of injecting a fixed volume, Vo, of tracer on demand, a t r a c e r solution of known concentration, Co, and a detector d o w n s t r e a m t h a t monitors the diluted t r a c e r concentration as a function of time. Auxiliary mechanical and electronic control and monitoring equipment are also needed. The tracer solution is dispensed through the counting chamber as a pulse of fixed size by an intermittent, single-stroke pump, e.g., a syringe pump, which empties the counting chamber at a stroke. The mixing device needs only to provide lateral mixing of tracer with the injection fluid in the annulus between the tool and the casing. For this purpose, a wide variety of pumps for mixing and circulating fluids can be used. The tool operates on a wireline and should be able to m e a s u r e flow rate directly at any point in the borehole, regardless of its inclination, flow regime, or flow rate, except, as for any t r a c e r method (Hill, 1989), at exit or entrance flow locations. A second detector can be added to the

346

Chapter 7

tool to serve as an indicator of equilibrium or to allow the velocity shot method to be used. This is a discrete method t h a t m u s t be pulsed at intervals, as the tool is moved up or down the wellbore, to log the flow profile in the well. It would be particularly useful for monitoring very low flow rates as well as for monitoring the effectiveness of such wellbore t r e a t m e n t s as temporary or p e r m a n e n t flow diversion. The resolution of the log with respect to depth is limited by the distance between source and detector required for radial mixing. In common with all the methods for monitoring flow down hole, it may not give accurate readings when fluid exit or entrance points lie between the detector and the injector.

Wire

line-~~ I

,/

| II

N

Tracer detector

Tracer I1------- solution

Tracer ~ , l l ) I injectioni "1 I~1 pump

Tracer circulating pump

Figure 7.28. Wireline tool for tracer dilution pulse logging Addition of a second detector at a fixed distance from the first lets the tool function both in the pulse dilution and in the pulse velocity mode. This has several advantages: it permits a cross check of flow rates for a known flow diameter; a measure of diameter when it is unknown; and, for the pulse dilution method, a check on mixing equilibrium by comparing results at two positions.

Downhole Tracers

347

Chemical tracers

M a n y i n s t r u m e n t a l methods are suitable for monitoring the concentration of the diluted chemical tracer as it passes by, including a wide range of optical and electroanalytical methods. The mass of injected tracer, A = C o x V, is known and fixed in the tool. The flow rate, Q, is obtained from Eq. (7.20). Most chemical detectors measure tracer concentration, so t h a t the area under the concentration versus time curve at the detector, ~C(t)dt), is readily obtained by a s t a n d a r d integrator to yield the flow rate at that depth: CoVo Q = ~C(t)dt

(7.21)

This is a good method for monitoring single phase injection of production profile with chemical tracers and detectors if the fluids are reasonably clean, the usual case for injected fluids. Additional mixing may be required for m a n y chemical detectors t h a t sample only small w a t e r volumes. The larger the volume sampled by the detector, the less critical additional mixing becomes. Radioactive tracers

The procedure above differs for radioactive tracers, only because the radiation detector does not measure concentration directly but monitors the radiation, R(t), emitted by the tracer in the neighborhood of the detector. All s t a n d a r d counting systems contain a "scaler" t h a t integrates the radiation versus time curve to give a total n u m b e r of counts for the time interval. R(t)dt = N is the net n u m b e r of counts collected from the pulse after it has passed the detector and the background has been subtracted. The integral, ~R(t)dt, of the radiation pulse can be converted to t h a t of the concentration integral, ~C(t)dt, if both the counting geometry and efficiency are known for the a n n u l a r distribution of tracer about the detector. For a centralized tool in a cased hole, these are essentially independent of position. Hence, the detector can be calibrated by measuring the count rate when the tool is placed in a section of borehole containing a known concentration (activity per unit volume) of the tracer. This can also be done in the laboratory, calculated numerically, or some combination of these methods m a y be used. Eq. (7.20) can now be rewritten as: AK Q = ~R(t)dt-

AK N

(7.22)

where A is the amount of injected activity, K is the calibration factor in counts per unit time per microcurie (or other activity unit) per unit volume, and R(t)dt = N is the area under the flow curve. Once a tool has been calibrated, it will give the local flow rate directly from the net counts m e a s u r e d down hole. Conversion of the calibration constant to tracer pulses of different energy and a n n u l a r spacing should be a straightforward calculation.

348

Chapter 7

The total (net) count, N, from the passage of the diluted pulse is monitored by a scintillation detector mounted on the tool at a distance from the injector and s u m m e d by the counter. Since it monitors the entire volume of the annulus, small heterogeneities in mixing will have little effect. Normally the concentration of the tracer solution and the volume of the tracer slug injected are fixed and the size (mass) of the injected pulse is known in advance, so these need not be measured down hole. For chemical tracers, the pulse size is difficult to measure directly down hole; however, for radioactive tracers the total activity, A, is easily monitored downhole by a 4n counter. This activity will usually be in the millicurie region and can be monitored by an ion chamber, a very stable counter t h a t maintains its calibration over long periods of time (years). While such measurements are not necessary for the method, they can provide a simple check on the tool operation. CONTINUOUS METHOD The second method for measuring flow rate by isotope dilution is the continuous (constant rate) injection method. Here, a tracer solution of known concentration, Co, is injected downhole at a constant rate, Qo, into a m a i n s t r e a m of unknown flow rate, Q. The tracer will mix with the mainstream and at equilibrium will have a concentration, C, as monitored downstream at a point where the tracer is well mixed with the fluid. A single m e a s u r e m e n t of the final (equilibrated) concentration combined with the known initial tracer concentration and injection rate enables us to calculate the flow rate, Q, of the m a i n s t r e a m , as shown in chapter 2 by: Q = Qo

Co-C C

(7.23)

In conventional pipelines and in monitoring flow in bodies of water, the analyses are done on collected samples. For the downhole tool, the flowstream is monitored continuously without the need for samples. For most cases, the injected concentration, Co, will be so much greater than the diluted concentration, C, that Eq. (7.20) reduces to: Q=

Q~176 c

(7.24)

The tool shown in Fig. 7.28 can be used for the continuous method by changing the tracer injection from intermittent pumping at a known volume of stroke to pumping at a constant rate. A variety of flow controllers, capillary leaks, and rate controlled pumps are available commercially for constant rate injection of tracer solutions. C h e m i c a l tracers

Chemical tracers are well suited to this method since the detectors monitor the diluted tracer concentration directly. The product of the constant tracer

Downhole Tracers

349

injection rate, Qo, and the initial tracer concentration, Co, is the constant mass flow rate, so t h a t the flow rate, Q, of the stream is inversely proportional to the diluted tracer concentration, C, from Eq. (7.24) above. Hence, a log of reciprocal concentration versus depth is a relative flowrate profile of the well. In m a n y cases, this is all t h a t is required. This can also be used to check the system by comparing the sum of all individual flows to the total flow. The tracer capacity of a downhole tool is limited by the maximum tracer concentration and by the tool's limited volume, hence detectors of a wide dynamic range are needed. Radioactive tracers

For radioactive tracers, the same situation holds, except t h a t the detector monitors the radiation emitted by the tracer solution in its neighborhood r a t h e r t h a n the tracer concentration. As in all isotope dilution methods, the injected tracer m u s t be equilibrated by mixing with the flowing fluid before it is monitored by a detector, usually a scintillation device, mounted on the tool at a fixed distance from the injector. At equilibrium, this entire volume is filled with diluted tracer at a fixed concentration, C, while the detector measures only a fixed count rate, R. The calibration constant can be obtained experimentally by measuring the radiation level for a known concentration of tracer in the borehole or the laboratory, or by calculating it numerically from known nuclear and material data, so that Eq. (7.24) can be replaced by: Q-

QoCo L kR - R -

(7.25)

where k is a calibration constant expressed in activity per unit volume per count rate, ~Ci/IJcpm. Once derived, such constants are easily extended to other energies and well diameters. Since activity flow rate QoCo is constant, the log of reciprocal count rate versus depth is the injection (production) flow-rate profile of the well, as shown in Eq. (7.25) where L = QoC o/k is a constant. This may be all that is needed, since the flow profile can be calibrated for individual depths by matching the sum of all the individual flowrates to the known total injection or producion rate of the well. PRODUCTION LOGGING FOR GAS: FIELD STUDY The only application of tracer dilution logging as a means of monitoring a production profile was recently reported for gas production using a nonradioactive tracer (Bennett et al., 1991). The major difficulty with monitoring production profiles in producing oil wells is in analyzing multiphase flow. In the case of wells producing a single phase such as gas or oil, this problem disappears. In this procedure, the authors describe a tracer flow meter in which the gas production profile is determined by measuring the dilution of an injected tracer by wellbore gas. This is the only reported instance of the use of a nonradioactive tracer for production logging.

350

Chapter 7

This is a tracer dilution method rather than the usual tracer velocity method used for production logging in the wellbore. As a result, it measures flow rate r a t h e r t h a n linear velocity. This is a much more desirable m e a s u r e m e n t for managing a well and also has the advantage of reducing some of the variables in production logging. It is independent of changes in well diameter. The tool, shown in Fig. 7.29, has a 3-in. diameter and a length of 91/2 ft. It is made up of three components: a continuous tracer injector (using a controlled gas leak), a mixing section for mixing the tracer with the gas from the borehole, and a concentration-sensitive tracer detector containing its own mixer, downstream of the injection mixer. Mixing was induced by two pumps in the logging tool, one of which mixes the injected tracer thoroughly with the produced gas in the wellbore, while the second passes the mixed sample through the measuring chamber. It is interesting to note t h a t such a method could also be used to count betaemitting tracer gases in a gas counter downhole. The resolution of the tool is limited by the spacing between injector and detector: in this case, 45 in. The tool is operated by lowering (or raising) it at a constant logging rate. As the tool moves down the well, the flow remains constant due to the steady upward flow of gas, and so does the concentration, C. Depending upon the logging rate, and the rate at which tracer mixes within the new gas stream, there can be a sharp peak when it reaches a flowing zone, since additional gas suddenly flows

14I-"

14

114" q 29"

45"

.~..,,,.

iDetector unit I Fan V

Flow controller

!-~-[~

(

ton,o / Detector / Detection chamber

controller

.j .- =

T Tracer tank

[~l:tIill

IFan

Sinker Bar I

T Precision regulator

converter

Figure 7.29. Gas tracer flowrate meter

Solenoid

Computer

I

Injection chamber

convertel

Downhole Tracers

....

351

oon

AJ

9149

/1

9

9

.,,o

,o.

J~ ~ ~

,

9

Co.,

,

J

Da~

thermoresistance flowmeter 0 ft/min

40. _

30-

Tracer flowmeter v F~, @ 6 ft/min ~ V ,I, 9 perforations Additional flow ~ - ~

"~'~'"'-~-.._~

0

~,'!

~

O~

.

.

.

.

i

. v

4000

9

'i

v

''

:

Depth, ft.

"

%--.. i ....

4300

Figure 7.30. Gas production rate profile from tracer log between tracer source and detector. By differentiating both sides of Eq. (5.16), it can be seen t h a t the change in flow rate dQ,/dt, produces a proportional change in the concentration, dC/dt: de C dQ dt - (Q-QO) dt m

(7.26)

This is of limited quantitative use because of the incomplete equilibration of tracer with new gas in this short time interval. The tool was tested in a Devonian shale gas well in Kentucky and r u n in 41a-in. casing with 17 perforations shot in the test interval. The tool was lowered down hole on a wireline and the flow rate of the gas, Q, at a given depth was det e r m i n e d from the change in injected tracer concentration in accordance with Eq. (7.20). The logging rate was 6 ft/min. The flow rate in this well is low with individual flow zones varying from 1.0 to 9.2 MCFD. Passage of a 3-in. diameter tool through the 4 l~-in, casing required correction of the relative velocity of the gas both because of the tool's displacement and its logging speed. The results of the log are shown in Fig. 7.30. This figure shows both the tracer log and a t e m p e r a t u r e log t h a t was r u n concurrently. Spinner logs and sonic gas-detector logs were also reported. Only the tracer log detected all the flowing perforations and gave quantitative m e a s u r e m e n t s of mass flow from the responding zones. The sum of the flows from the tracer survey showed reasonable agreement with total flow from the well. The

352

Chapter 7

small circles above the graphs show the nominal perforation positions. The flow rates in this well are so low that the laminar flow would have made a conventional pulse velocity log difficult to interpret. The particular tracer used in this work was not named, but any gas tracers for which a suitable detector exists should be adequate. The detector used was described as electrolytic without giving details but apparently is sensitive to a sulfur-containing gas. An electron capture detector would be suitable for such gases as SF6.

Production logging with isotope generators The use of radioactive tracers for monitoring flow originating down hole carries with it the chance of contamination at the surface. In recent years, environmental awareness has limited such usage more than reason would normally dictate. The contamination problem can, however, be entirely avoided by using short-lived tracers that largely decay before reaching the surface. The only practical way that short-lived radioactive tracers can be available for measurements down hole is by an isotope generator. Most measurements of fluid movement down hole are done over short intervals of depth and do not require long-lived isotopes. These measurements can be done with relatively low-energy radiation, since the radius of measurement is only a few inches of formation fluid in the borehole. Any of the production logging procedures discussed earlier in this chapter, including the velocity shot and isotope dilution by either the pulse or continuous method, can be done using an isotope generator. Higher tracer concentrations can be generated down hole than can conveniently be placed there by conventional tracers, important for measuring very high flow rates. The highest resolution log, using isotope dilution, is obtained by the continuous tracerdilution method. An isotope generator can be stripped in a continuous mode producing tracer at a constant rate. This could be hazardous if conventional radioactive tracers were used for monitoring produced fluids, but the short halflife of the produced tracer eliminates the contamination problem. AVAILABLE ISOTOPE GENERATORS Isotope generators are available with daughter half-lives ranging from fractions of a minute through many hours or more. Currently, all commercially available generators are medical products not designed for downhole use. Table 2.1 gives a partial list of commercially available generators. A half-life of a few minutes would be sufficient for most fluid velocities measured down hole. The 137Cs/137mBa (Cs-Ba) generator, which yields the 2.6-min 137mBa daughter, would be ideal for most production logs. Cesium-137 is widely used as a gamma source for density logging down hole. The emitted gamma ray is, however, entirely due to the daughter activity in equilibrium with it. Cesium-137 decays to

Downhole Tracers

353

Ba-137m by beta decay with a 93 percent probability and a half-life of about 27 yr; no g a m m a s are emitted. Barium-137m decays to stable Ba-137 by the emission of a 0.66 MeV g a m m a with a half-life of 2.6 min. The decay schemes have been shown in Fig. 1.5 and are written below in the two stages: 1) 137Cs --> 137mBa § ~, T1/2 = 27 yr 2) 137mBa --~ 137Ba + 7 (0.66 MeV), T 1/2 = 2.6 min This generator and a number of other generators for short-lived isotopes have been described in the literature (Spytsin and Mikheev, 1968) and have been used (Turtiainen, 1986; Newacheck et al., 1957; Gwyn, 1961; Kugener et al., 1972; Arino et al., 1973) for monitoring flow in pipes. The technology for preparing isotope generators is well known. As discussed in chapter 2, most isotope generators are simply composed of a tubular column containing a parent isotope firmly fixed upon a substrate material. The daughter is eluted from the generator, as needed, by passing a small volume of solution through the column. It should be simple to adapt such a generator for use at reservoir pressure and temperature. A shortlived isotope such as Ba-137m in secular equilibrium with its p a r e n t can be eluted at a constant rate. The equations relating the buildup time and decay of any tracer pair were discussed in chapter 1. The large number of pulses available from such an isotope generator allow higher depth resolution from tracer pulses using either the velocity shot or the isotope dilution method. In the case of the isotope dilution log, resolution is limited only by the distance needed for radially mixing the tracer with local fluids at a given logging rate. Tracer can be eluted in either a water- or an oil-soluble form, depending upon the isotope, as complex ions of suitable solubility, allowing tracing of either produced oil or water down hole. In addition, cesium-137 is a relatively cheap and readily available isotope, so t h a t the cost of tracer used down hole is negligible. An isotope generator (ll3Sn/ll3mIn) for injectivity logging has been reported (Sun, 1991) but not as a downhole tool. The generator produces the 100-min halflife i n d i u m - l l 3 m daughter from l l 5 - d a y half-life Sn-113. This was milked at the surface to fill the tool with tracer as a substitute for 1-131. The 50 mCi (1,71 GBq) generator lasted about six months. A downhole generator could use a much shorter half-life daughter activity generated down hole. ISOTOPE GENERATORS FOR DOWNHOLE LOGGING The use of isotope generators for production logging has significant advantages in two areas: 1) safety in handling radioactive tracers in the field and in monitoring produced fluid without surface contamination; and 2) high-resolution injectivity and productivity profile logs over a wide range of downhole flow rates. A tool for doing production logging is shown schematically in Fig. 7.31. Such a

354

Chapter 7

tool can be operated in the tracer dilution mode, or as a velocity shot or tracer loss log, with few of the problems associated with handling radioactivity in the field.

i~---- Wireline 0

NaI(TI) detector

,.q

Eluent

_

Tracer pump r~-Isotope generator OJ=l

Mixing

pump,~j~ I

O_

Ion chamber ~_> (optional) 0

/, ll

Tracer receiver

f

~ Tracer out

Dilution tool Figure 7.31. Wireline tool for tracer dilution log using isotope generator The tool shown in Fig. 7.31 can perform the same function as those shown in figs. 7.22 and 7.28 for production logging by various procedures, although its internal construction is different. It is composed of four parts: 1) an isotope generator; 2) an elution pump operated either as an intermittent, pulsed, constantvolume injector or as a continuous, constant mass (activity) rate injector; 3) a mixing pump or fan to mix the tracer with the borehole fluid; and 4) a downstream detector. Addition of an optional second scintillation detector would also allow the velocity shot log to be run. The isotope generator is a shielded unit that can be mechanically set in place with conventional tools. Tracer is milked from the unit by passing a small volume of eluent through it by means of an elution pump. This pump has a dual function: 1) it transfers tracer from the generator, and 2) it injects the transferred tracer into the circulating pump for mixing with

Downhole Tracers

355

wellbore fluid. It can therefore serve as a fixed volume injector for the pulse dilution or velocity shot method, or as a constant-rate tracer injector for the continuous dilution method. The a m o u n t of tracer eluted for either a pulse or the constant-rate injection can be calculated from the radioactive decay laws discussed in chapter 1. An ion chamber is shown in the figure as an optional device for m e a s u r i n g the amount of tracer injected by the tool. It is not required but is relatively easy to do and provides a check on the operation of the tool. It also allows controlled variations in the size of tracer pulses to monitor unexpected flow situations. Tracer production logging is normally done with iodine-131 (half-life = 8 days) as a tracer. This isotope is widely and cheaply available because of its m a n y medical applications. It has, however, a very low maximum permissible concentration (MPC) for u n r e s t r i c t e d areas because it is preferentially accumulated in the thyroid. These production logs are usually handled by small, independent logging companies who provide a relatively cheap service. In normal field practice, the radioactive iodide solution is brought to the field in a vial and transferred into the injectivity tool at the site by hand, usually by means of a syringe. The isotope generator is a better way to handle the tracers because it avoids the problem of dealing with open radioactive solutions in the field. The generator can be installed in the tool as a safely shielded device t h a t has been preloaded in the laboratory. Until activated down hole, the tracers are immobile. Production logs can also be used to verify the success of downhole treatments, even those t h a t use tagged materials to monitor their placement. The tracer response from the production log can be separated from t h a t of the tagged treatment by energy discrimination, half-life, and radiation level. The short half-life of the tracers used in the production log prevent it from interfering with placement logs. The flow into or out of the treated zone is the only criterion for success of m a n y of these treatments. CONTINUOUS TRACER PRODUCTION FROM AN ISOTOPE GENERATOR For those generators operating in secular equilibrium, it is possible to strip tracer continuously from a generator at a constant rate. The m a x i m u m amount of activity obtainable by continuous elution can be calculated from Eq. (1.16) for secular equilibrium, which can be rewritten as: A2 = AI(1 - e x~-t )

(7.27)

Here, A2 = N2~2, is the radioactivity of the d a u g h t e r isotope, A1 t h a t of the parent, and ~2 the decay constant of the daughter expressed in consistent units. The m a x i m u m formation rate, R, for continuous stripping of tracer is obtained by setting the derivative of this equation with respect to time equal to zero. The result at t = 0 is given by the following expression, where ~.2 = In 2frl/2, as shown in Eq. (1.5):

356

Chapter 7

dA2 Alln2 R = dt = A1 ~2 = ~ TI/2

(7.28)

This is the m a x i m u m stripping rate of activity per unit time. The stripping rate depends on other factors as well, so that the true production rate is usually lower, but it is a reasonable guide. According to Eq. (7.28), the shorter the halflife, the higher the stripping rate; hence, for Ba-137m (tl/2 = 2.6 min), a 10 mCi source of 137 Cs would have a maximum stripping rate of 2.7 mCi per minute. For an activity having a half-life of one hour, the maximum stripping rate for a 10mCi source would be 120 ~Ci per minute. These are very high downhole activities. A barium-137m generator should be able to handle a very high range of flow rates. The continuous isotope dilution procedure described earlier becomes simple for isotope generators meeting these criteria, since the stripping rate fixes QoC o, the activity injected per unit time, once the system has been calibrated for activity injected per unit time as a function of the flow rate, Qo. This can be done in the laboratory and removes the need to monitor the injected tracer concentration down hole. The scintillation detector for monitoring the diluted tracer is already calibrated for the tracer used and the borehole size. Hence, the well can be logged continuously, since the tracer stripping rate, the net counting rate at the scintillation detector, and the calibration factors are all known. Eq. (7.21) for flow rate, Q, would now be expressed as: Q =

kl(Qo) L2 k2R = R

(7.29)

where k l is the calibration constant relating the tracer injection rate, Qo, to the activity injected per unit time, QoCo, and k2 is the calibration constant relating the measured count rate, R, from the diluted tracer to the tracer concentration per unit volume per count rate. Since Qo is preset and constant, the reciprocal of the count rate R is directly proportional to the flow rate by the constant L2, the log of 1/R vs. depth is a flow-rate profile of the well, and can be calibrated by matching L2 to make the sum of the partial flows equal the known total flow rate in the well, without knowing the other constants in the system. As discussed earlier, a second scintillation counter at a greater distance from the injector can be used to ensure that equilibrium mixing has occurred.

Gas production logging with an isotope generator The isotope generators heretofore discussed have been concerned with monitoring such liquids as water cr oil. Before leaving this subject, we shall also consider the use of gaseous isotopic tracers generated down hole. The only shortlived gas tracer available for logging gas wells is krypton-81m, which is produced by the decay of rubidium-81 by positron emission and electron capture. The p a r e n t isotope decays with a half-life of about 4.6 hr. This is a relatively short

Downhole Tracers

357

half-life for an isotope generator; however rubidium-81 is widely used in biomedical studies and as a result is available daily by air express at most locations (corrected for decay at time of delivery). It is also relatively cheap and very competitive in cost with such radioactive gas tracers as 85Kr and 133Xe. Krypton-81m decays with a half-life of 13 seconds, emitting a 190 keV g a m m a ray with an efficiency of 67 percent. It forms krypton-81, which has a half-life of 2.1 x 105 years. The generator is available at an activity of 10 mCi with the rubidium absorbed on a solid support. The Kr-81m is stripped by passing an inert gas t h r o u g h the generator. There are no other volatile products. Gas velocities are usually at least an order of magnitude higher t h a n water velocities, so the short half-life should be quite usable for logging gas injection profiles and for many gas producing formations. Operated as a continuous tracer dilution log, the m a x i m u m stripping rate of 0.5 mCi/sec should be more t h a n sufficient for most gas-logging needs. Generators currently available a r e designed for medical use r a t h e r t h a n downhole operation. A typical commercial generator is illustrated in Fig. 7.32; it consists of a tube containing the generator and a bypass. Humidified oxygen or air is passed through the generator to elute the generated 81mKr with an elution efficiency greater than 80 percent.

Injection logging of steam wells Steam injection is a very productive recovery method, and for extremely viscous oils it, may be the only recovery method. One of the purposes of injecting steam is to heat the formation and lower the viscosity of the oil in order to produce it by conventional means. The vapor phase (steam) contains most of the thermal energy. For this reason, it is important to know the quality of the steam actually injected into the formation and how this is distributed as a function of depth. Steam is composed of liquid water and steam vapor, which differ widely in density. It has long been known (Arnold, 1990) t h a t as steam flows t h r o u g h pipes, T's, and bends, its components segregate and the quality changes. We can measure steam quality at the surface, but we need to know its quality when it enters the formation down hole. Many years ago, when steam tracing was relatively new, service companies commonly used 1-131 tagged methyl and ethyl iodide, and even elemental iodine, for steam (vapor) tracing, and NaI solutions for water (condensate) tracing down hole. This practice continues to some extent, even though the unsuitability of the tracers used for steam (vapor) has long been known. This was discussed in chapter 6. It is only recently that the use of alkyl iodides as steam tracers has been questioned publicly (Nguyen et al., 1988; Griston, 1990). The best tracers currently available for following the injection of steam (vapor) down hole are the

358

Chapter 7

radioactive gases Kr-85 and Xe-131. The major problem with their use is the poor efficiency with which they are measured by downhole radiation detectors. Kr-85 decays by ~ decay with a half-life of about 10.6 yr, but only a small fraction of the decays (0.4 percent) are accompanied by gamma radiation (0.52 MeV). Xenon-131 decays by electron capture with a 5.3-day half-life, but it emits soft x-rays (81 keV) that are detected with poor efficiency because of absorption by the media, and shielding of the downhole detectors.

Air or _,, oxygenout ~

~.....~.,~

-" )~ Kr-81 gas generator

Air or oxygenin ,< "~, 3-way stopcock

Figure 7.32. Medical 81Rb-81mKr applicator

FIELD INJECTIVITYPROFILE MEASUREMENTS Injectivity profiles in steam injection wells require two-phase flow measurements. The procedures used are otherwise similar to those used for conventional injectivity profiles. The density difference between the steam vapor and the condensed water allow them to be treated independently. Some of the procedures currently in use in several thermal wells in California are described in a recent paper (Nguyen et al., 1988). Krypton-85 or 131Xe was used as a steam tracer and 1-131 tagged iodide ion ,:r used as a water tracer. The authors also showed that 1-131 tagged methyl iodide is not a suitable tracer for steam. The logging tool used in these procedures contains two gamma detectors a known distance apart, but no tracer injector. In a departure from conventional downhole production logging, the dual counter is first lowered to a desired depth in the well and the tracer pulse injected at the surface under nitrogen pressure. The transit time of the pulse between the two detectors a fixed distance apart is used to calculate the pulse velocity. This is repeated until the desired interval is covered. The fraction of total flow past the tool is given by the ratio of total transit time (for entire flowing zone) to transit time at that depth. The authors demonstrate the procedures required for three different locations of the tubing tail with respect to the perforations. Including a pressure gauge with the gamma

Downhole Tracers

359

tool m a k e s it possible to estimate downhole steam quality from the gas and liquid velocities, the steam flow rate and the downhole pressure. These d a t a together with downhole flow profiles were used to calculate a downhole h e a t profile. STEAM TRACER SURVEY EVALUATION A survey of procedures and results obtained from t r a c e r surveys of steam injectors (Griston, 1991) revealed t h a t the low radiation levels found in m a n y surveys led to inconsistent results. The two tracers used, 85Kr and 131Xe, produce g a m m a r a d i a t i o n with relatively little p e n e t r a t i n g radiation. The wellbore environment in a steam injector is severe, and logging tools are limited to a one- to two-hour exposure time to reduce the risk of failure. The NaI scintillation detectors are the most sensitive of the available detectors but are very limited in high-temperature operation. Geiger counters, depending upon the g a m m a - r a y energy, have only about 10 percent of the efficiency of scintillation detectors but are a p p a r e n t l y more stable under these conditions. The higher energy of the 85Kr g a m m a and the b e t t e r t e m p e r a t u r e stability of the GM counters have m a d e this combination the s t a n d a r d for most s t e a m t r a c e r surveys. The combination of low detected activity and high steam velocity results in low signals for tracer arrival at the dual detectors. In an example given by the author, a 50 mCi slug of 85Kr gave a barely detectable signal at the top detector, but was not detectable at the bottom detector, for a 0.1 sec sampling interval. Because of the low signal-to-noise ratio of these data, the conventional peak-topeak methods for determining transit time gave poor results. The a u t h o r proposes instead a procedure in which statistical errors for the background and tracer response are each minimized and the ratio of tracer to background radiation (signal-to-noise) is maximized. Using simulated data, an a u t o m a t e d tracer analysis method (ATAM) was set up for identification of t r a c e r arrival and t r a n s i t times. True tracer arrival time of the simulated pulse at each detector was found to be the time required to reach 50 percent of the m a x i m u m (average) radiation. The automatic feature was chosen to avoid subjective t r a c e r evaluation. D a t a were simulated using single phase conditions. Two-phase flow as experienced in the injection wells would add additional uncertainties to the calculated profile. The author discusses results of a tracer survey performed in several different steam injection wells. The results of a survey of a steam drive project near Coalinga, California, are shown in Fig. 7.33. The principal conclusion from these tests is t h a t the reliability of the tracer survey depends strongly on improving the poor signal-to-noise ratio. Repetition of the data t a k e n at each location is important to improve the statistics. The author proposes, as a standard procedure, that the transit time for three tracer pulses be logged at each location. A second source of unreliable tracer data is fluctuations in steam-injection conditions during the survey. He proposes t h a t a separator be

360

Chapter 7

placed downstream of the wellhead choke for monitoring injection steam rate, pressure, and quality. One of the reasons suggested for low tracer concentration is dilution by steam during the injection interval. If it required a second to inject the tracer pulse into steam traveling at a linear velocity of 100 ft/sec, the tracer pulse would be 100 ft long and of far lower concentration. A reduction in the required pulse injection time to 0.5 sec or less would increase its detectability.

10

00 ,

" '-

~1~0 lIB

II

84 0---

10

Top detector

Bottom detector

~1 i,~/i ~

"~ 1so-I

I

A

'AAi 11

1?

13

14

16

~

10

Top I detector I~ I~i

11

12

13

Bottom detector

l:t

15

Elapsed time, seconds

Elapsed time, seconds 10

Minimize ~m..===m

D

At k

.1

.01

Arrival time

.001 8

9

10 11 12 13 Elapsed time, seconds

14

15

Figure 7.33. Steam injection survey

Krypton-81 steam injectivity profiles These are difficult field experiments, made more difficult by the poor signalto-noise ratio of the data. In reviewing the steam injectivity tests described

Downhole Tracers

361

above, it seems strange t h a t the downhole injection procedures of the velocityshot tests are not used for equivalent tests in steam injection. It is not clear why tracers for monitoring injectivity profiles for steam should be injected at the surface instead of at the tool down hole. There may be problems with injecting gas in a high-quality steam environment, although the physical problems, from this perspective, do not seem insurmountable. Presumably there is not enough dem a n d for this kind of work for the service companies to invest the time needed for development. A short tracer pulse from the injection tool should have a far better signal-to-noise level t h a n the stretched-out pulse originating at the wellhead. A tool designed around the 81Rb/SlmKr generator would be almost ideal for a tracer-dilution log for measuring steam injectivity profiles. The major problems are: 1) w h e t h e r a Kr-81 generator could operate at these temperatures, and 2) how to ensure adequate transverse mixing of the tracer across the annulus at these high linear flow rates. The NaI scintillation detector is a good detector for this 190 keV g a m m a radiation if protected from thermal damage, but the response could be improved by using walls both thinner and fabricated of material of lower atomic number. Steam wells are not very high-pressure wells, and the wall thickness of the tool could be reduced considerably without losing strength. The pulse-velocity method would only require fast pulse injection; transverse mixing would not be very important. INJECTED STEAM QUALITY High-quality steam for steam injection is produced in a generator and distributed to the field wells for injection. Depending on the properties of the distribution network, the quality and mass flow of steam delivered to the various wells vary widely, and the system can be sensitive to minor fluctuations in delivery. For this reason, as well as the needs indicated in the preceding paragraph on downhole steam surveys, it is desirable to monitor the steam quality delivered at the wellhead for each well. Methods have also been proposed for m e a s u r i n g steam quality at the formation face down hole (Zemel and Clossman, 1985) using radiation absorption. Injected steam quality can be measured at the wellhead by a number of methods. The low liquid (high void) fraction of high-quality steam makes it a difficult measurement. The high-attenuation cross section of water for thermal neutrons has attracted attention (Woiceshyn et al., 1986; Strom 1987) to the use of neutron t r a n s m i s s i o n as a sensitive quality monitor. There is also the added advantage t h a t steel pipe is relatively transparent to neutrons, so t h a t the measurement can be made at the wellhead from outside the pipe. A n e u t r o n densitometer was reported (Wan, 1991) for continuously monitoring steam quality through pipe. This is a portable meter t h a t has been certified for field use by the Atomic Energy Board of Canada and the Radiological H e a l t h section of the state of California. The densitometer consists of 1) a neutron source in a shielded moderator that produces a thermal neutron stream

362

Chapter 7

and 2) a thermal neutron detector that measures neutron transmission. The neutron source is located on one side of the pipe and the detector on the other side. The developers normalized the transmitted neutron fraction, N*, by relating it to the intensities when pure water and pure steam were present and t h e n correlating with steam quality for various conditions of pressure, mass flow rate, and pipe diameter. In order to use these correlations, the two-phase mass flow rate m u s t be known. By using a flow nozzle as a flow m e a s u r i n g device, the authors were able to determine both steam quality and mass flow rate.

BOREHOLE PROCESSES Procedures in which a tracer is injected at the surface and monitored as it returns to the surface to follow a procedure down hole are included in this group. This includes mostly drilling mud and completion fluids but is expanded here to include drill-bit monitoring. Mud water invasion

One of the few downhole processes monitored at the surface is the behavior of mud as it circulates through the borehole during drilling. The purpose of tracing the circulating mud here is to determine the mixing of mud water with formation water. This is important in two areas. In drilling cores, it is important to know how much of the cut core is flushed by mud water during the drilling operation in order to correct the fluid saturations measured from the core. During logging operations it may be difficult to know the salinity of the formation water because of mixing with mud water. This can be i m p o r t a n t for log interpretation. To monitor its presence, the drilling mud can be tagged with a suitable tracer t h a t identifies the drilling mud water. The majority of work in this area has been concerned with mud/water invasion in cores. The oldest of the tracers used for this purpose is tritiated water (Armstrong et al., 1961; Miller et al., 1975). It has been in use for more t h a n 30 years for this purpose. Tritiated water is advantageous for mud-water monitoring because the Dean S t a r k distillation used to separate the core fluids separates the tritiated water along with the core water. This can be analyzed by counting tritium in the water. A v a r i e t y of other tracers have also been used for tracing mud. These include deuterated water (D20), and the nitrate, iodide, thiocyanate, acetate and dichromate anions. Many cations and some anionic dyes have also been used. The problem with using tracers that are not distilled with the core water is t h a t a separate extraction step is required to separate the tracer from the core for analysis. Any tracer used for mud water should also be tested to ensure t h a t it is

Downhole Tracers

363

following the water. All the tracers discussed here require t h a t the water be separated from the mud before they can be analyzed. The mud system is small enough in volume t h a t a great m a n y materials are potentially useful as tracers. The best way to test a material for use in such a system is to inject a pulse containing a known amount of the material into the mud while it is being circulated down hole, assuming t h a t there is no lost circulation. The mud return is sampled at the surface, and the tracer concentration, c, as a function of time, t, is measured. If there is no loss of tracer, the response function, ]~cAt, should be equal to the amount of tracer originally added, divided by the flow rate. One of the easiest ways to do this for an ionic species is by m e a n s of an ion electrode. Ion meters have become almost as common as pH meters. A small hand or powered filter press combined with a microelectrode is sufficient for these measurements. It may be possible to find an electrode system t h a t can operate directly in the mud without the need for a separation step. Another possible procedure is to use a short-lived gamma-emitting tracer such as Tc-99m. This tracer (half-life = 6 hr) is available from an isotope generator. It emits a soft g a m m a ray (0.14 MeV), which is largely absorbed in the mud system and presents no radiation hazard; however a NaI or plastic scintillator probe in the mud r e t u r n should be able to monitor its presence without any trouble. The system can be calibrated with a known concentration of technetium to give true concentrations. In the usual procedure for mud-water invasion, a small volume of tritiated w a t e r (or other tracer) is thoroughly mixed with the mud. This may require at least one round trip in the hole and is done before the coring operation. The tracer concentration is calculated to allow a water dilution factor of at least 10 without loss of measuring range. The maximum concentration of tracer is limited by environmental concerns. In the case of tritiated water, the concentration and amount needed is usually well below the MPC for unrestricted areas, so t h a t no special disposal or cleanup procedure is normally required for the tagged mud. A sample of the mixed mud is taken for analysis at the s t a r t of the coring operation. Mud samples are also t a k e n t h r o u g h o u t the coring operation at intervals equivalent to set depths of coring or drilling. These samples are collected at the surface but corrected to the drilling depth by the trip time of the mud to the surface. Water is separated from all the mud samples and analyzed for tracer. Tritiated water may be filtered but the water is usually flash distilled in simple side-arm distilling flasks before counting. For other ions, centrifugation or high-pressure filtration is required. The measured tracer concentrations in the mud are plotted against depth to provide a corrected mud tracer concentration for the core being cut at each depth. The collected core sections are extracted by a Dean S t a r k distillation, and a sample of the water from each section is counted for tritium. The ratio of tritium

364

Chapter 7

in the core w a t e r to t r i t i u m in the m u d at t h a t depth is a m e a s u r e of the invasion of the core by m u d water. HYDRAULIC BEHAVIOR OF MUD An interesting application of tracers in m u d is to study the hydraulic behavior of m u d in the wellbore. A p a t e n t (Hall, 1989) proposed the use of an injected t r a c e r pulse for following the hydrodynamics of drilling mud, in the s a m e m a n n e r as is done in for chemical reactors (Levenspiel, 1962), and as discussed in chapter 4 of this work. The first and second m o m e n t s of the t r a c e r response curve are used to d e t e r m i n e the m e a n residence time and the variance of the distribution. The a u t h o r used lithium bromide as a tracer and ion c h r o m a t o g r a p h y as an a n a lytical m e t h o d for both ions. The Li + ion a p p a r e n t l y does not absorb on the walls. S a m p l e s were collected at the surface for analysis. There were no c o m m e n t s on how or if the samples were s e p a r a t e d from the m u d before analysis by ion chromatography. ZnBr2 was also suggested as a tracer, but the hydrolytic behavior of this m a t e r i a l m i g h t m a k e interpretation difficult. Drill-bit

wear

Drill bits w e a r out or become inoperative for a n u m b e r of reasons. Pulling a bit either too early or too late can be costly. There have been several p a t e n t s over the years on methods for identifying drill-bit problems before they become severe. To date, none of these methods has been widely received in the oil field. One of the earliest (Warren, 1949) proposed an u n n a m e d tracer placed behind a welded "spacer" at critical places on the drill bit. W h e n the spacer m a t e r i a l w e a r s through, the tracer is released as a wear indicator (compressed gas is included to disperse the tracer). A m e t h o d for identifying m i s a l i g n m e n t of a drill cone as soon as it h a p p e n s was proposed in a p a t e n t (Graham, 1961). In this method, a vial of radioactive t r a c e r is cut w h e n the axis of the cone moves off center, r e l e a s i n g t h e t r a c e r into t h e m u d column. Kr-85 was proposed as a w e a r indicator in several patents. In some, tracer was released into the m u d s y s t e m with the aid of various propellants and detected by m e a n s of a radiation probe. In one (Fries, 1974), the k r y p t o n is mixed with the bearing grease and released to the m u d w h e n the grease seal fails. In the l a t t e r case, a special s e p a r a t o r at the m u d - r e t u r n draws the gas into a counter. Most of these m e t h o d s depend on the use of a significant a m o u n t of radioactive m a t e r i a l and on difficult m a n u f a c t u r i n g or detection problems. There are now some very sensitive detectors for certain gas tracers, e.g., SF6, by electron capture. A large enough a m o u n t of SF6 can be dissolved and/or dispersed in the grease to be easily detected in the event of a grease seal rupture. A primitive gas s e p a r a t o r should be sufficient to allow SF6 to be m o n i t o r e d by m e a n s of an electron capture detector. The presence of SF6 would actuate an a l a r m indicating bit problems down hole.

Downhole Tracers

365

REFERENCES

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