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PEH:Well-To-Well Tracer Tests

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Publication Information

Vol5REPCover.png

Petroleum Engineering Handbook

Larry W. Lake, Editor-in-Chief

Volume V – Reservoir Engineering and Petrophysics

Edward D. Holstein, Editor

Chapter 6 – Well-To-Well Tracer Tests

Øyvind Dugstad, Inst. for Energy Technology

Pgs. 651-681

ISBN 978-1-55563-120-8
Get permission for reuse


Well-to-well tracer tests contribute significantly to the reservoir description, which is essential in determining the best choice of production strategy. Direct dynamic information from a reservoir may be obtained, in principle, from three sources: production history, pressure testing, and tracer testing.

The value and importance of tracer tests are broadly recognized. Tracer testing has become a mature technology, and improved knowledge about tracer behavior in the reservoir, improved tracer analysis, and reduction of pitfalls have made tracer tests reliable. Many tracer compounds exist; however, the number of suitable compounds for well-to-well tracers is reduced considerably because of the harsh environment that exists in many reservoirs and the long testing period. Radioactive tracers with a half-life of less than one year are mentioned only briefly in this chapter because of their limited applicability in long-term tests.

Tracers may be roughly classified as passive or active. In principle, a passive tracer blindly follows the fluid phase in which it is injected. Active tracers interact with the other fluids in the system or with the rock surface. Interpretation of tracer-production curves must account for this. The results from the application of active tracers may give information about fluid saturation and rock surface properties. This information is especially important when enhanced-oil-recovery techniques that use expensive fluids such as surfactants, micellar fluids, or polymers are considered.

In the last 50 years, many tracer studies have been reported and even more have been carried out without being published in the open literature. Wagner[1] pointed out six areas in which tracers could be used as a tool to improve the reservoir description.

  • Volumetric sweep. The volume of fluid injected at an injection well until breakthrough of the traced fluid at an offset producer is a measure of the volumetric sweep efficiency between that pair of wells. Very small volumes injected before breakthrough [relative to the interwell pore volume (PV)] would indicate the existence of an interwell open fracture (or a very thin high-permeability stringer) and would give an idea of the volume of that channel. Knowledge of channels is important to the sizing of remedial treatment.
  • Identification of offending injectors. Problem injection wells can be identified by associating the breakthrough of a specific tracer to its point of injection. At this well, a remedial treatment to seal a channel normally would be applied.
  • Directional flow trends. When fluids are injected in a regular pattern (five-spot, nine-spot, line drive, etc.) and the fluids injected at each well tagged with a different tracer, directional flow trends will be obvious from the repeated early tracer breakthrough at producers in a preferential direction from the injectors. Where directional flow trends are prevalent, the interwell sweep efficiency often can be improved by altering the injection pattern and/or the injection and withdrawal rates at selected wells.
  • Delineation of flow barriers. Faults with large displacement along the fault plane and permeability pinchouts can represent barriers to the flow of fluids perpendicular to their axis. Normally, such barriers are detected by bottomhole pressure buildup surveys run in nearby wells. However, the course of these barriers can be delineated further from the production well’s response (or lack of it) to traced water injection at an array of wells surrounding the producer.
  • Relative velocities of injected fluids. When different fluids are injected simultaneously, alternately, or sequentially in the same well with each fluid tagged with a different nonadsorbing tracer, the relative velocities of these fluids can be measured from the individual-tracer arrival time at offset producers. For example, assume that traced solvents and traced water are injected alternately in the same well. The early arrival of one of the traced fluids at the producing well would indicate that the early arriving fluid had contacted less of the reservoir than the slower fluid. This shows a need to alter one of the fluid injection cycles to achieve more uniform sweep of the reservoir. Similarly, in a micellar flood in which water is injected sequentially, the overrunning or fingering of one injected fluid through another points out the need for better fluid-mobility control to achieve more uniform sweep by the various injected fluids.
  • Evaluations of sweep-improvement treatments. Remedial treatments to correct sweep problems can be evaluated by comparing the before-and-after-treatment interwell volumetric sweep as determined by tracing.


Many companies apply tracer on a routine basis. The reservoir engineer’s problem generally is a lack of adequate information about fluid flow in the reservoir. The information obtained from tracer tests is unique, and tracer tests are a relatively cheap method to obtain this information. The information is an addendum to the general field production history and is used to reduce uncertainties in the reservoir model.

Tracer tests provide tracer-response curves that may be evaluated further to obtain relevant additional information. Primarily, the information gained from tracer testing is obtained simply by observing breakthrough and interwell communication. Adequate data presentation and simple hand calculation can give further knowledge about the flow behavior in the reservoir. More quantitative information can be obtained by fitting response curves obtained from numerical simulation to the observed response curves. Additional information also can be obtained by applying analytical procedures on the basis of generic or simplified reservoir models.

Types of Tracers Available


A passive tracer that labels gas or water in a well-to-well tracer test must fulfill the following criteria. It must have a very low detection limit, must be stable under reservoir conditions, must follow the phase that is being tagged and have a minimal partitioning into other phases, must have no adsorption to rock material, and must have minimal environmental consequences. The tracers discussed in the following sections have properties that make them suitable for application in well-to-well test in which dilution volumes are large. For small fields in which the requirement with respect to dilution is less important, other tracers can be applied.

Radioactive Water Tracers

In most field studies, the tracer is expected to behave exactly as the water it is going to trace. Very few compounds will behave as passive tracers in all situations, but near-passive tracers will, in many applications, work satisfactorily. If the objective is to measure fluid communication exclusively, a near-passive tracer may be as good as a true passive tracer. Table 6.1 lists the most frequently applied radioactive tracers.

The compound that best fulfills the passive tracer requirements is tritiated water (HTO). The passive water tracer mimics all movements and interactions that the water molecules do in the traced water volume. For instance, HTO can track the free movement in and out of dead-end pores because it is insensitive to coulombic forces set up by negatively charged rock surfaces. Other interactions can exchange with connate water in the rock pores or exchange with crystal water molecules. Thus, HTO sometimes seems to lag behind the injection water breakthrough as measured, for instance, by a salt balance (ionic logging). This has sometimes been interpreted that HTO is unstable at reservoir conditions and that it may be subject to isotope-exchange reactions of tritium with hydrogen in neighboring hydrogen-containing compounds, some of which are stationary.[2] Isotopic exchange, however, is expected to be negligible.

Other noncharged tracers are methanol, CH2TOH, and the other light alcohols. These tracers will behave qualitatively similar to HTO with respect to transport but have different interactions. Other organic molecules may be applied as radioactive water tracers and can be labeled either with tritium or with[3] C. Larger alcohols, however, may have a partition coefficient that may cause a considerable retention.

Zemel[4] measured partition coefficients of some alcohols. Over a limited range, the effect of temperature on the partition coefficient, K, can be represented by a semiempirical equation:

RTENOTITLE....................(6.1)

where T is the temperature in Kelvin, A is a constant related to the enthalpy, and B is a constant related to the entropy change. Table 6.2 gives B and A values for some alcohols.

Anions are the more applicable electrically charged tracers; however, in laboratory experiments, clear evidence of ion exclusion can be seen (i.e., negatively charged species tend to be repelled from the negatively charged rock surfaces). As a result, the tracers tend to flow in the middle of the fluid-conducting pores and will not easily enter into dead-end pores or through narrow pore throats, which results in a smaller available PV for anions than for noncharged species. The production profile differs in reproducible ways from that of HTO.

Anionic tracers are represented here by thiocyanate or S14CN-. Fig. 6.1 gives a typical production profile from flooding experiments. This profile is compared with the production profile of the simultaneously injected HTO. It is evident from the curve that the breakthrough of HTO occurs before that of S14CN- and that the tail of the HTO profile is more pronounced. This profile difference is qualitatively the same for all near-passive anionic water tracers. The retention volume may be represented by the peak maximum value or the mass middle point (first moment, μ1) for nonsymmetrical profiles. These values are found best by fitting the profile with an analytical function consisting of polynomials.

35SCN is applicable only to small reservoirs because the half-life of 35S is only 87 days. 36Cl- has shown to be an excellent tracer. There are no possibilities for thermal degradation, and it follows the water closely. The 36Cl- is a long-lived nuclide (3×105 years), and the detection method is atomic mass spectroscopy rather than radiation measurements. The disadvantage is that the analysis demands very sophisticated equipment and is relatively time consuming.

For mono-valent anions, the retention factors (see Eq. 6.2) are in the range of 0 to -0.03, which means that such tracers pass faster through the reservoir rock than the water itself (represented by HTO). A compound such as 35SO42- may be applied in some very specific cases but should be avoided normally because of absorption.

Some anionic tracers may show complex behavior. Radioactive iodine (125I- and 131I-) breaks through before water but has a substantially longer tail than HTO. Both a reversible sorption and ion exclusion seem to play a role here. 125I- and 131I- have half-lives of 60 and 8 days, respectively, which makes the compounds less attractive as tracers in large reservoir segments.

Cationic tracers are, in general, not applicable; however, experiments have qualified 22Na+ as an applicable water tracer in highly saline (total dissolved solids concentration > seawater salinity) waters. In such waters, the nonradioactive sodium will operate as a molecular carrier for the tracer molecule. Retention factor has been measured in the range of 0.07 (see Eq. 6.2) at reservoir conditions in carbonate rock (chalk). [5] Accordingly, the tracer is delayed somewhat by sorption and ion exchange to reservoir rock but in a reversible manner.

Wood[6] reported the use of 134Cs, 137Cs, 57Co, and 60Co cations as tracers. The same cations also were injected as ethylene diamine tetra-acetic acid (EDTA) complex in a carbonate reservoir. The EDTA complexes were recovered completely in a 3-day push-and-pull test. For the cations, only the Cs+ were produced while the Co3+ never appeared in the producer; however, the Cs+ cations generally cannot be used. It will adsorb strongly on clay-containing rock.

56Co(CN)63 is a stable complex that has been tried as tracer. Not all trials have been successful, and the compound is not normally applied. Especially at temperatures greater than 90°C, they should be avoided. [2] The complex can be labeled with several isotopes of cobalt (56Co, 57Co, 58Co, 60Co) in addition to 14C.

Chemical Water Tracers

Application of several nonradioactive chemical tracers has been reported in the literature. Table 6.3 lists the most frequently used chemical water tracers. The most-applied nonradioactive anion is the thiocyanate anion. It has a low natural background in the reservoir, and a detection limit in the range of 1 μg/L (1 ppb) can be obtained by electrochemical detection after separation on a high-pressure liquid chromatograph. In the reservoir, this tracer will behave as the radioactive labeled S14CN- or as the 35SCN-.

Nitrate (NO3-), bromide (Br-), iodide (I-), and hydrogen borate (HBO3-) also have been applied as tracers. [4] These can be analyzed by ion chromatography or by high-pressure liquid chromatograph. A minimum detection limit in the range of 25 to 1 ppb is reported for the different compounds. This detection limit will not be sufficient in many situations. It is also a problem for several of these compounds that the background concentration normally will be too high. Nitrate is the cheapest of the tracers, but its background may be in the range of 500 ppb, which means that an excessive amount of tracer is needed. Examples of organic molecules are fluorecien, rhodamine B, methanol, ethanol, and isopropanol.

The most-applied chemical water tracers are fluorinated benzoic acids. A large suite of mono-, di- and tri-fluorinated benzoic acids have been qualified as tracers. Because their thermal stability is variable, the compounds must be selected with care, especially for high-temperature reservoirs. Trifluoromethylbenzoic acids also may work as tracers; however, these compounds interact with the oil phase to a larger degree and retention of these compounds is observed.

The partitioning of acids to the oil phase is generally low. The partitioning will depend on the pH and at lower pH, when a larger portion of the compounds is in the undissociated form, higher partitioning can be expected. Fig. 6.2 shows laboratory test results in which the 4-FBA is compared with tritiated water in a packed-column flooding test. The two tracers are injected simultaneously and the residence time distribution measured. Both tracers are produced at the same time, and only a marginal retention of the 4-FBA is recorded. This experiment is performed by an oil saturation of approximately 20%. In most practical applications, this retention can be neglected.

There is active research to identify new tracers. Among the new tracers are deuterated compounds. Deuterated fatty acids probably will work well as tracers but, because of production costs, their applicability is limited. A new group of potential tracers are shorter DNA fragments. These compounds have two major advantages. They have an extremely low detection limit and exist in an almost unlimited number of distinguishable variations. It is, however, uncertain if it is possible to produce modifications that can be qualified with respect to flow behavior and stability.

Radioactive Gas Tracers

Several authors report the use of radioactive gas tracers in oilfield applications. The tracers most frequently applied have been tritiated methane, tritiated ethane, and 85Kr. [7][8][9] In addition, the use of tritiated butane, 127Xe, 133Xe, and tritiated hydrogen gas (HT) has been reported. Table 6.4 lists the most widely applied radioactive tracers.

The tritium-labeled compounds may be measured directly in the gas phase by proportional counter techniques. To obtain the low detection limit normally required in well-to-well tracer studies, it is normal to convert the gas to water by combustion. The produced water then is counted by a liquid scintillation technique. The detection limit of the water produced from this process depends on the instrumentation but can be less than 1 Bq/L. Typically, approximately 5 to 10 mL of water must be produced to obtain the low detection limits. The water, mixed with a liquid scintillator, is counted for a few hours. The same technique can be applied for the different tritium-labeled hydrocarbon gases. If several tritium-labeled compounds are present in the same sample, it will be necessary to perform a chemical separation of the compounds before oxidation to produce the water. This separation complicates the analysis considerably; therefore, it is not common to use several of these tritiated compounds in the same reservoir segment.

The chemical properties of tritium-labeled hydrocarbon compounds are equal to their nonlabeled homologues in almost all practical situations, which means that their behavior in the reservoir will be the same as the nonlabeled hydrocarbons. The partition coefficients of these compounds, therefore, can be found by ordinary pressure-volume-temperature (PVT) packages like those applied in phase-equilibria calculations. The partition coefficient will influence the residence time in the reservoir and the concentration of the tracer in the production line. It is important to take into account partitioning both in the evaluation of flow behavior in the reservoir and in the understanding of sampling quality. Because of partitioning to the oil phase, some of the tracers will be in the oil phase at the sampling point. Calculation of total recovery of the tracer then requires partition coefficient and gas/oil ratio (GOR) at sampling conditions. This problem will be more significant for heavier hydrocarbons than for the lighter ones.

All the hydrocarbons that are labeled with tritium can also be labeled with 14C. These molecules are, in general, more expensive and their analyses are more complicated. From a general demand for reducing the application of long-lived radioactive tracers, the 14C-labeled compounds are less attractive than the tritium-labeled compound.

Other alternatives are the noble gases. The noble gases are virtually inert against chemical reaction. 85Kr has a half-life of 10.76 years and is a beta emitter with an energy of 687 keV. The two xenon isotopes, 127Xe and 133Xe, are also inert noble gases that may be applied in special situations in which rapid response is expected. The half-lives are 36.4 and 5.25 days, respectively.

For CO2 as injection gas, 14CO2 will be an ideal tracer. CO2 will interact with the formation water, which must be considered when 14CO2 is used as a tracer. A few papers have reported application of HT.9 Hydrogen gas is reactive, and the tracer is lost in the reservoir.

Chemical Gas Tracers

As early as 1946, Frost[10] reported the use of helium as a tracer under gas injection. The background of the noble gases in the reservoir is, however, generally too high, which makes nonradioactive noble gases unattractive as tracers. These gases can be applied only when the dilution volume is very small. Table 6.5 lists the most frequently applied chemical gas tracers.

One group of tracers that has found wide application and has become the most widely applied of the chemical gas tracers today is the perfluorocarbon (PFC) group of molecules. PFCs have excellent tracer properties such as high stability, chemical inertness, and high detectability. The most frequently applied compounds are perfluorodimethylcyclobutane (PDMCB), perfluoromethylcyclopentane (PMCP), perfluoromethylcyclohexane (PMCH), and 1,2- and 1,3-perfluorodimethylcyclohexane (1,2-/1,3-PDMCH). Table 6.6 lists some of their properties. PFCs are liquids with a density of approximately 1.8 g/mL at standard conditions; therefore, they can be injected into the reservoir with high-pressure liquid pumps. [11]

One technique for analyzing PFCs is gas chromatography (GC) in combination with an electron-capture detector. The electron-capture detector is extremely sensitive to perfluorinated hydrocarbons and especially the cyclic compounds.

Senum[12] reported a method to analyze the PFC content in a hydrocarbon gas from a production stream. The gas contained in pressure bombs is flushed through a capillary absorption tube sampler (CATS) filled with activated carbon that absorbs the PFCs. The PFC-containing pellets are desorbed thermally, and the gas is directed through a combustion system composed of a precolumn, catalysts, and traps to remove the hydrocarbons before the PFCs enter the main separation column on the GC/electron-capture detector system to determine the amount of each tracer.

Another applicable technique is GC in combination with mass spectroscopy. [13][3] This technique distinguishes tracers from other compounds not only by chromatographic separation but also by molecular mass. This reduces background noise, which is essential to obtaining a low limit of detection. The technique employing CATS has made the collection and logistics of gas samples much more efficient. Shipment and handling of high-pressure sampling cylinders are expensive and complicated. Sampling on CATS made a large improvement, making gas tracing on remote locations easier to operate. This technique allows analysis of tracer quantities in low 10−13 L/L concentrations. Because of the very sensitive analytical techniques, the amount of tracer needed even in large reservoirs is only a few kilograms. The CATS technology is applicable only to PFC tracers and has not been developed for the other gas tracers.

In addition to the PFC tracers, SF6 is a frequently applied chemical tracer. SF6 can be measured in very low concentration on electron-capture and mass-spectroscopy detectors. The tracer is stable at reservoir conditions, and it is relatively cheap. This compound is a gas at standard conditions and must be injected with gas booster pumps. The PFCs and SF6 have a very high global-warming potential; therefore, finding an alternative tracer is needed.

Another group of compounds that have good tracer properties is freons; however, because of their ozone-depleting character, these compounds are rarely applied. Hydrocarbon gases, in which hydrogen is substituted with the deuterium isotope, will work as a tracer, but because of high production costs, these compounds are not in common use.

Health, Safety, and Environment Constraints

The regulations for the use of radioactive and chemical substances vary from country to country. The application of radioactivity is generally restricted, and it is important to plan the tracer test with the actual regulations in mind.

Radioactive tracers are either gamma emitters, beta emitters, or both. Tritium is a low-energy beta emitter. A sheet of paper stops this beta radiation, and it will not cause any harm to humans as long as it is kept outside the body. If spillage occurs, operators can be exposed to radiation because of direct contact with skin or because of evaporation and inhalation. Procedures must be followed carefully to ensure a safe operation.

Radioactive tracers such as 22Na and 131I emit gamma radiation. This radiation penetrates steel walls, which means that an operator can be exposed to this radiation. The tracers are transported in lead containers and special handling procedures are needed to reduce the radiation exposure to a minimum. The activity, measured in becqeurels, is normally 2 to 3 orders of magnitude less than the activity applied for tritium-labeled compounds.

Gas tracers like the PFCs have a high global-warming potential. Most of the back-produced gas will be burned in the end, and the tracers will decompose; therefore, the amount of PFCs entering the atmosphere is low. The tracers, however, may be banned in the future, and research activities are ongoing to identify new gas tracers that are more environmentally friendly.

Tracer Flow in Porous Reservoir Rock

Retention Caused by Partitioning Between Phases

When tracers are flowing in the reservoirs, it is normally a requirement that the compounds follow the phase they are going to trace. The best example of a passive water tracer is HTO. The HTO will, in all practical aspects, follow the water phase.

For gas tracers, there are no known passive tracers. All gas compounds will, to a certain degree, partition between the phases. The most ideal gas tracer is tritiated methane. This gas tracer follows the methane component in the gas phase closely, and the PVT properties of this gas tracer can be found with ordinary PVT calculations. The properties of the other radioactive hydrocarbon gas tracers may be found with the same PVT calculations by examining their respective nonradioactive homologues.

In Fig. 6.3, the flowing properties of a selection of some gas tracers are compared. These tracers were tested in a 12-m-long slimtube with an inner diameter of 0.5 cm. The filling material was crushed Ottawa sand. Tritiated methane, CH3T, was the reference tracer. The oil saturation in the experiments is 30% and the production curve, when a small slug of tracer is flowing through a porous medium, is measured. All tracers, even the tritiated methane, are delayed with respect to the average flow rate in the reservoir. A nonpartitioning tracer would have been produced after one PV (available gas volume) had been flushed through the system.

Normally, the KC values (see Eq. 6.3) decrease and, thereby, the variations in retention time are reduced when the pressure is increased. The KP value (see Eq. 6.4) converges to 1 for all compounds when miscible conditions are obtained. The separation of the tracer production curves is reduced considerably in Fig. 6.3b when the pressure increases from 150 to 250 bar. It also is observed that the ethane tracer, 14CH3CH3, is produced before that of the PMCP at 150 bar while, at 250 bar, PMCP is in front of ethane. The partitioning properties of the PFC have different characteristics than the partitioning properties of the hydrocarbons.

Water tracers, like gas tracers, may partition to the oil phase. Many water tracers exist that behave almost as ideal tracers. Fig. 6.4 shows laboratory tests in which some benzoic acid tracers are compared with the HTO. These experiments are carried out in a packed column of 2-m length. The packing material was crushed Berea sandstone. Other types of equipment also are used frequently. It is common to use cores of consolidated reservoir or reservoir-like rock (i.e., sandstones and/or carbonate material).

Retention factors, β, may be derived from Eq. 6.2 on the basis of the production profiles found by such experiments.

RTENOTITLE....................(6.2)

where VT is the retention volume for the tracer candidate and VS is the retention volume for the standard reference tracer. The retention volume for the standard reference tracer (nonpartitioning) may further be regarded as the volume of the mobile phase, VM, in this system. If other retention effects can be excluded, the retention factor is an expression for the delay caused by partitioning the tracer between the mobile and the stationary phase.

Partition Coefficients. The partition coefficient depends on the temperature and pressure as well as the composition of the system. Unlike the radioactively labeled hydrocarbons, the partition coefficient of the PFC gas tracers are not easily obtained. The equation of state (EOS) used in PVT calculations is not optimized for these types of compounds, and lack of interaction parameters makes partition coefficient estimation on the basis of the EOS difficult. Normally, laboratory measurements are necessary.

When the composition, temperature, and pressure are given, each component will have a given partitioning coefficient at equilibrium. This component may be defined in different ways. Two different definitions are used frequently for gas/oil systems:

RTENOTITLE....................(6.3)

and RTENOTITLE....................(6.4)

CO = the tracer concentration in the oil phase, and CG = the tracer concentration in the gas phase. The partition coefficient, KP, is calculated by dividing the mole fraction of the tracer in the gas phase, yi, by the mole fraction of the tracer in the oil phase, xi.

When the molar composition and the densities of the two phases are known, the relation between the two values can be expressed as

RTENOTITLE....................(6.5)

For simple systems, partition coefficients can be found when the vapor pressure, pv, of the tracer compound is known. At low pressure, the partitioning between the phases will obey Henry’s law, and the Henry’s law constant, HC, is

RTENOTITLE....................(6.6)

In the case in which Raoult’s law is valid (ideal behavior), the partial pressure, pi, of the component in the gas phase is given as

RTENOTITLE....................(6.7)

and RTENOTITLE....................(6.8)

where p is the total pressure. Combining these two equations gives

RTENOTITLE....................(6.9)

The vapor pressure of the pure component divided by the total pressure gives the KP value. This relation will normally be too simple to be accurate but may have sufficient validity to carry out a rough estimate.

Flow Equations When One Phase Is Mobile. The partition coefficient may be measured directly by measuring the concentration of the component in each of the two phases in an equilibrium system.

In a dynamic situation, the KC value can be found by measuring the retention time of the actual component. KC values can be calculated when the saturation and the retention time are known. In a dynamic column experiment in which the column contains only two phases (one stationary), the fraction of time, tf, the tracer stays in the gas phase may be expressed as the number of tracer molecules in the gas phase in a reference block of the column divided by the total number of tracer molecules in the same reference block.

RTENOTITLE....................(6.10)

Dividing by CMVM above and below the fraction time and inserting Eq. 6.3 leads to

RTENOTITLE....................(6.11)

CM and CS are tracer concentrations in mobile and stationary phases, respectively. The tracer is produced when one retention volume, VT, has been injected. This volume multiplied by the fraction of the time the tracer stays in the mobile phase is equal to the volume of the mobile phase, VM, in the system.

RTENOTITLE....................(6.12)

A combination of Eqs. 6.11 and 6.12 gives

RTENOTITLE....................(6.13)

Assuming steady-state flow, VT/VS may be replaced by the tT/tS, where tT and tS are the retention time of the partitioning tracer and the nonpartitioning reference tracer, respectively. Applying Eqs. 6.14 and 6.15 and rearranging, the oil saturation in the flooded porous medium can be estimated (with retention factor β found in Eq. 6.2) by Eq. 6.16.

RTENOTITLE....................(6.14)

RTENOTITLE....................(6.15)

and RTENOTITLE....................(6.16)

In Eq. 6.14, VS is assumed to be the volume of the oil phase.

Flow Equations When Two Phases Are Mobile. Eqs. 6.10 through 6.16 assume one mobile and one stationary phase. For a generic two-phase case, the tracer flow equation may be expressed in a dimensionless form where S = saturation, C = concentration, K = partition coefficient, and f = fractional flow and when dispersion is neglected.

RTENOTITLE....................(6.17)

x* = x/L and t* = (q t) / (a L ϕ) to obtain the dimensionless form of the system.

Assuming a two-phase gas/oil system in which the tracers are flowing partly in the gas phase and partly in the oil phase, the linear velocity of the gas and oil phases are given as[14]

RTENOTITLE....................(6.18)

and RTENOTITLE....................(6.19)

where fo and fg are the fractional flow of oil and gas, respectively, and q = volumetric flow rate, ϕ = porosity, and a = flow cross section. As previously shown, the fraction of time the tracer stays in the gas may be expressed by Eq. 6.10. The mean velocity of the tracer in a two-phase flow may be expressed by Eq. 6.20 when accepting that VS/VM is equal to So/Sg.

RTENOTITLE....................(6.20)

Rearrangement gives

RTENOTITLE....................(6.21)

This tracer-flow-velocity model may be applied when the KC values are known. Fig. 6.5 gives a graphical outline of ft (based on Eq. 6.21) for five different partitioning coefficients. The fractional flow curve for the gas, fg, is arbitrarily chosen. The ft curves = 1 at the saturation where fo/So = fg/Sg (i.e., when both phases are flowing with the same linear velocity). When the Kc value=1, the tracer flow rate is independent of saturation and shape of the fractional flow curve. The ft curves plotted in Fig. 6.5 show that the relative flow of the tracers depends strongly on the saturation. Below the gas saturation at which the two phases flow with the same linear velocity, the lower-partitioning tracers will be in front while above that saturation decreasing Kc value will give increasing flow rate.

Residual-Oil Measurements. Eqs. 6.10 through 6.21 give the basis for estimating remaining oil in the reservoir. In the most simple system, in which the oil saturation is stationary, So may be calculated from the knowledge of the partition coefficient of two tracers and the peak of the tracer-response curve by

RTENOTITLE....................(6.22)

Under ideal conditions, VT may be replaced by the retention time of the two tracers. There is always a question about which retention time to use in the calculations. Alternatives are breakthrough, production peak, moment (mass middle point), or other specific landmarks. The production curve is a superposition of contribution from individual streamtubes in the reservoir; therefore, the choice of retention time will reflect either saturations in certain streamtubes or an average value. A sensitivity evaluation of Eq. 6.22 shows that it is preferable to apply two tracers with KC values far apart from each other. The most efficient would be to include one tracer that has no partitioning to the liquid phase. Eq. 6.22 then is simplified to Eq. 6.16.

One of the questions that may be raised against the method is the possibility for obtaining equilibrium between the phases. The calculations are based on a real equilibrium between the phases, which depends on saturation, diffusion rates, flow rates, pore structure, and partition coefficient.

To obtain reliable results, it is crucial to understand the flow situation. If the oil phase is stationary, Eq. 6.22 may give a satisfactorily result. If two phases are flowing, it is important to know the fractional flow curves (i.e., relative permeability), and a reservoir simulator will be necessary to obtain a reliable result.

Biodegradation

Microbial stability of water tracers may be a problem. This problem will be less important at higher temperatures at which the microbial activity is lower. The problem, however, must be addressed in sample handling and storage. Some tracers, in special situations, may biodegrade after sampling. To avoid such degradation, a biocide may be added to the sample immediately after collection. Adding 0.1 ppm NaN3 to the stock solution can prevent bacterial growth.

Fluorobenzoic acid tracers have been reported to biodegrade when exposed to seawater. The biodegradation has been measured for monofluorobenzoic acid and di- and tri-fluorobenzoic acid. No degradation was observed for the di- and tri-fluor compounds. Alcohols also may biodegrade under certain conditions. In general, the odd-carbon-number alcohols are more resistant to bacterial attack than the even-number ones.

Ion Exchange

Ions adsorbed on the reservoir surface are free to exchange with ions in the water. This ion exchange is a reversible process and tends to obtain equilibrium between surface concentration and the concentration in the water. Different adsorption isotherms may be used to describe this situation. In most cases, this ion exchange can be described by a Langmuir isotherm (Eq. 6.24).

The flow of the tracer through the reservoir may be influenced by adsorption to the grain surface. To come into contact with the grain surface, the gas tracer may need to diffuse through a film of oil, water, or both. The adsorption depends on the partitioning of the tracer into the two liquid phases in the reservoir. Different models are applied to describe the adsorption on the grains. The simplest form is the linear relation in which the adsorbed amount, ac, is proportional to the concentration in the contacting phase Cc.

RTENOTITLE....................(6.23)

A tracer in a dynamic system will be retained independently of concentration. In many cases, however, the active adsorption sites on the surface will be saturated and the amount adsorbed will not increase linearly with the concentration. In some cases, a more accurate expression is the Langmuir isotherm,

RTENOTITLE....................(6.24)

U and V are two parameters that decide the shape of the curve for the actual system at a specific temperature. c = the concentration in the liquid phase caused by partitioning between the gas and liquid phase, and ac = the amount of tracer adsorbed to the grain. At low concentration, which is the case when tracers are considered, this equation will be a straight line with slope U. Other isotherms also may be considered but are less likely to be needed. Different adsorption isotherms will influence the produced tracer peak.

If the tracer is positively charged, it can be exchanged with cations adsorbed to the reservoir surface. The affinity to the surface may vary, and some cations will be more tightly adsorbed than others. The effect on the tracer flow will be retention of the tracer. According to the most likely adsorption isotherm, the adsorption will be linear with the tracer concentration as long as the concentration is very low.

22Na has shown to move through porous media with only minor delay caused by sorption and ion exchange to reservoir rock but in a reversible manner. Most other cations (Cs+, Co3+) have shown strong adsorption and cannot be used as tracers.

Planning and Design of Tracer Tests

Timing of Tracer Programs

The timing for tracer injection depends on the information that is requested. Normally, it is desirable to inject the tracer early in the injection process to obtain information as soon as possible and be able to take the necessary actions to optimize the production strategy. However, it has been seen that water tracer is lost in the reservoir because of imbibition of water. Therefore, if there is large imbibition potential in the reservoir and water is trapped in volumes that do not contribute to the normal flow path, tracers can be trapped and only minor tracer concentrations leak out in the flowing part of the reservoir. This information can be valuable on its own, but if the problem is not considered, it may contribute to wrong interpretation of the results. In this situation, water may break through from an injector that is traced without observing any positive detection of tracer. In general, injecting the tracer in the very front of an injection program is not recommended.

Tracers should not be injected until the pattern area has been pressured up with the injected fluid. If the traced injected fluid is spent in collapsing a gas phase or otherwise pressuring the reservoir, the volume injected to tracer breakthrough, which indicates the volumetric sweep to breakthrough, may be significantly larger than that determined after the pattern area has been pressured.

Well-to-well tracer tests may be performed, in principle, either as a pulse injection or as a continuous injection. The most often applied method is pulse injection. The continuous injection may be useful especially where unsaturated water-wet rock may absorb short tracer pulses by water imbibition from the injected waterfront edge. To obtain a constant concentration in the injected water, a constant recording of the water-injection rate is necessary. In general, continuous injection is more complicated and a tracer engineer must follow the injection for a long period. For pulse injection, however, the whole program can be carried out within a few hours.

Field-Test Design

The design of a field tracer test has two components: a tracer part and an analytical part. The tracer component includes choosing the tracer for each well, estimating the required amount of each tracer, dealing with the regulations, and planning for acquisition and injection of the tracer into the ground. The analytical part includes selecting an analytical strategy, setting up a sampling program, and determining the background realistic detection limits in the samples collected from the particular field.

Traditionally, two methods have been applied to determine how much tracer must be added to obtain a tracer-production response significantly above background. In general, it is desirable to inject as small an amount as possible to reduce environmental problems, contamination, and costs. Both radioactive- and chemical-tracer compounds are potentially harmful to the environment; therefore, the amount applied must be kept to a minimum. In some cases, the maximum permissible concentration of the tracer that may be released to the environment is limited by requirement from the authorities.

In many situations, produced gas containing tracer is reinjected into the reservoir. This has, in some cases, contaminated the whole reservoir and destroyed the possibility of applying the same tracers in another segment of the reservoir. If not considered, flow conditions can be misinterpreted because of positive identification of tracer originated from reinjection of tracer in uncontrolled conditions.

The third reason for the use of low concentrations is to reduce costs. In small reservoirs, the tracer cost is a minor part of the total cost connected to the test but, in larger reservoirs, the tracer costs may be significant, especially if exotic tracers are required.

One method to estimate the tracer concentration is to assume that the injected tracer is diluted uniformly by the entire swept volume when it is produced. Sufficient tracer is added to ensure detection at this dilution volume. The peak tracer concentration is presumed to be well above the average.

The first part of the calculation is to estimate a dilution volume, which is obtained by calculating the water- or gas-filled PV between the injector and the production wells. The first approximation is to assume radial flow from injector, but it usually is modified by any known reservoir conditions, such as known flow channels or barriers, large permeability variations, or other constraints causing nonradial pressure gradients. It is important to know porosity, net pay zone, and distances between wells for the calculation. Optimal design can be obtained by performing full-field simulations. The problem with this method is that many of the parameters are unknown, which again is the main reason for performing the tracer test.

The smallest injection pulse required is usually the amount of tracer needed to obtain an average concentration of 10 times the minimum limit of detection in the dilution volume. This is expected to give a peak production on the order of 100 times the detection limit. To be able to follow production curves reflecting the contribution from different layers and zones, it is important to have at least this amount of tracer injected.

In the ideal situation, the dilution volume, Vd, can be calculated with a radial approximation.

RTENOTITLE....................(6.25)

where r = distance between the injector and the producer, h = height of the reservoir zone, ϕ = porosity, and Sw = water saturation. For a gas tracer, Sg should substitute for Sw. In addition, the expansion of the gas has to be taken into account. F is a correction factor that accounts for nonsymmetry caused by barriers, well location, and other restrictions causing changes in the drainage area.

An analytical method to determine tracer production curves in a layered system exists. [15] The method assumes that the tracer pulse moves radially from the injector to the producers through homogeneous, noncommunicating layers with longitudinal dispersion in the direction of flow. The number of layers, their thickness, and their permeability are used to represent the reservoir heterogeneity. The tracer pulse moving through each layer is diluted at the producers by untagged water from other streamlines in the same layer. This dilution effect is a consequence of pattern geometry. Production of the combined tracer responses from all these layers makes up the response curve of tracer concentration as a function of the cumulative volume of water injected.

The model predicts peak height, breakthrough time, and shape of the produced tracer-response curve from the amount of tracer injected and the pattern geometry. The fundamental equation (Eq. 6.26) used to calculate tracer-pulse flow in a streamtube is further applied to give analytical expressions for pattern-breakthrough curves. [16]

RTENOTITLE....................(6.26)

The concentration of a tracer at any location within the streamtube, ψ, is the difference between two terms, given by Eq. 6.26. L = the distance along a streamline, and s1 and s2 = the front and end location of the tracer pulse in the streamline, respectively. σ = the standard deviation that, in a radial system, can be found from

RTENOTITLE....................(6.27)

where α = dispersivity and r = the radius at the front defined at a location corresponding to the 50%-concentration point. On the basis of these predictions, tracer amounts can be injected to ensure a peak concentration in the production well that is well above detection limits. In practice, however, such calculations are often based on so many unknown or estimated parameters that it is advisable to inject more tracer than these calculations predict.

A reservoir simulator probably can provide the best estimate for tracer amounts; however, these simulations are based on detailed reservoir description. At the stage of tracer injection, the reservoir model is generally uncertain and, again, it is advisable to inject more than these calculations predict. Sufficient tracer must be injected to enable measurement of unexpected flow behavior.

Collection of Samples for Tracer Analysis

Sampling frequencies will depend strongly on the field considered. Tracer tests are, in general, a method to verify proposed flow scenarios. To cover unexpected behavior, sampling should be started long before expected breakthrough. Sampling frequency should be highest at the start of the flood to avoid missing early breakthrough.

Water samples may be stored in bottles that normally are collected from the separator. Water sampling is cheap, and frequent sampling is advised. Initially, only some of the collected samples need be analyzed; intermediate samples can be discarded if no tracer is found. Once tracer is found, samples are analyzed backward until the tracer breakthrough is found. In certain situations, some tracers may biodegrade after sampling. To avoid this, a biocide may be added to the sample immediately after collection. Adding 0.1 ppm NaN3 to the stock solution can prevent bacterial growth.

Samples can be collected at the wells or from a test separator shared by a number of wells, provided the stream is sampled only near the end of the test when the water is representative of the currently sampled well. Well sampling usually involves a water-separation problem, which can be avoided by sampling at the separator. The optimal situation is to have a dedicated separator for the particular well. New technology involving multibranched wells, horizontal wells with perforation in several reservoir compartments, subsea manifolds, or even subsea separators cause additional problems in providing relevant samples.

Gas tracers normally have been collected on pressure cylinders. The gas may be collected directly on the flowline or from a separator. The tracer content in the gas will depend on where the sample is collected. The partition coefficient of the tracer depends strongly on the pressure. A sample collected on the flowline at 100 bars and one collected at a separator at 30 bars will give different results. Further estimation of the total amount of tracer produced also will depend on the GOR at the sampling point. To calculate the produced-tracer amount in one particular well, it is necessary to know the pressure, temperature, and GOR at the sampling point. In addition, it is necessary to establish the partition properties of the tracer at these particular conditions. This can be done by measurement or by applying PVT models; however, existing PVT models will not treat all tracer types with the same accuracy.

Collection of gas tracers is more expensive than the collection of water tracers. When gas is collected on pressure cylinders, the cost of the cylinders will add considerably to the analysis cost. A new technology[3] has been developed in which the tracers are absorbed by an activated carbon trap. These CATS are used for collection of PFC gas tracers. The tracer then is collected in these tubes in the field, and only small tubes, without any surplus pressure, are shipped to the laboratory. Special sampling equipment is available that ensures a reliable and reproducible sampling. The CATS method is applicable only for a limited number of tracers, and in many situations, it is still necessary to collect samples with pressure cylinders. The cylinder size and the amount of gas collected will depend on the tracers and the concentration expected in the produced gas. Normally, a 200-mL cylinder will be sufficient.

The laboratory applies a large variety of techniques to measure the concentrations of the tracers. The different techniques will have degrees of uncertainty and the differences between detection limit and quantification limit should be distinguished. At concentrations close to the detection limit, it may be very difficult to obtain accurate quantification of the tracer; therefore, some laboratories report only "detected" without quantification when the concentration is low.

The detection limit obtained by an analytical procedure will be influenced by the quality of the sample. In formation water, the detection limit may be different from the detection limit in production water that also contains emulsion breakers, scale inhibitors, corrosion inhibitors, and other additives. It is, therefore, important to have a good cooperation between the field operators and the laboratory to obtain the best quality on the field samples.

Because of the very sensitive analytical techniques needed, it is essential to avoid cross contamination. It is important to plan tracer operations carefully to avoid any possibilities of close contact between injection equipment and sampling equipment. For example, it might be a source of contamination if injection pumps or tracer containers are transported after injection in the same van or stored in the same building as sample bottles or sample equipment.

Interpretation of Field Data

Different Levels of Interpretation

To obtain high-quality tracer-response curves that are the basis for the further interpretation, a well-designed sampling program is needed. In general, more samples will give the potential for extraction of more information from field tests. Too often, interpretation is difficult because of limited tracer data.

The final objective of a well-to-well study is the interpretation of the response curves. A good analysis of the information given by the tracers, in combination with other available data, gives a better understanding of the flow in the reservoir, not just verification of communication between injector and producer.

The response curve can be analyzed from three different points of view or complexity levels. The simplest interpretation is the qualitative one. By observing the curves, the following pattern characteristics can be derived: injection-water arriving time (breakthrough); existence of high-permeability channels, barriers, and fractures between wells; communication between different layers; stratification in the same layer; and preferential flow directions in the reservoir. Furthermore, the cumulative response can be obtained by integrating the concentration vs. time curve if the production flow rate is known. From this new curve, the fraction of injection water reaching each producer is easily calculated. A common spreadsheet is the best way to make these calculations. This type of interpretation can be carried out without any advanced simulation. It is important to integrate the data obtained from the geological model, primary production data, 4D seismic data (if available), and tracer data in a systematic way.

The second level of analysis uses basic mathematical models to fit simple response curves by means of theoretical expressions and to decompose complex responses in several simpler functions. In this way, partial residence times, as well as other parameters, can be determined for each function. Mathematical models also allow for the evaluation of important parameters, such as permeability, and make it possible to predict the behavior of unknown patterns.

Finally, complex mathematical models like numerical finite-element simulators or streamtube modeling can be used to achieve a deeper analysis. Most of the commercially available simulators have tracer options with varying degrees of complexity. Not all simulators include important physical effects like partitioning, dispersion, and adsorption. A tracer simulator that can be coupled to full-field reservoir simulators has been developed recently. Simulation is a tool to improve the existing reservoir model; therefore, it is crucial to have access to the best available model to enable an efficient optimization based on the tracer-production data.

Evaluation Based on Hand Calculation and Adequate Data Presentation

Qualitative interpretation of field data is illustrated by examples from the Snorre field in the North Sea. Fig. 6.6 shows the segment of the field that was tested and the location of injectors (triangles) and producers (circles). [17] A water-alternating-gas (WAG) injection program is being used in the field.

Fig. 6.7 shows a way to present field data for a gas-tracer program. The data are plotted as a time response. Alternatively, the data can be plotted as a volumetric response. To obtain a better understanding, it is important to plot gas-tracer-production data with GOR. The tracer data are plotted relative to the amount of tracer injected, which means that the concentrations presented for each individual tracer can be compared directly.

From Fig. 6.7, it is possible not only to find communication but also to extract information about the prevailing flow regime. The gas tracer injected into Well P25 breaks through without any significant increase in GOR, which means that the gas has not followed a free gas layer but has been dissolved in the oil. Three different gas tracers were injected in Well P28 at three different times. These tracers were produced only after a significant GOR was recorded. All the tracers were produced at almost the same time. This shows that gas has been trapped and that the gas in the individual gas slugs has subsequently filled this trap. At a certain time, the gas trap has been filled and the gas moves on to the producers. When reaching the producer, the gas contains all three different tracers injected over a 3-year period.

From the data in Fig. 6.7, it is possible to carry out a spreadsheet calculation to estimate the recovery of the injected tracer in each individual production well. This shows that a large percentage of the injected gas has moved in different directions. Breakthrough time also may be estimated, either as the first sample that contains tracer above the detection limit or as an extrapolation backward of the initial phase of the production curve. However, the accuracy of this calculation is limited by the sampling frequency.

To fully understand the flow behavior, it is important to add all information available. The picture may be modified by the knowledge of injection rates and production rates in the neighboring wells.

Because of maintenance and operational problems, production wells may be shut in for some periods. Because of fluid drift in the reservoir during shut-in, samples collected immediately after such periods may give unexpected results. This additional information can be exploited to better understand the pressure distribution in the field. Somaruga et al.[18] used well shut-in in a systematic way to obtain additional information. If the changes that may occur during shut-in are not considered, it may cause misinterpretation of the tracer-response curves.

The water-tracer-response curves should be presented together with the water cut. Fig. 6.8 shows water-tracer-response curves in the same well as discussed previously. Initially, a small water-cut increase is recorded. The tracer injected in Well P34 follows this increase. When the water cut starts to increase more rapidly, one of the other tracers starts production while the concentration of the first tracer vanishes. This method of presentation increases the understanding of the flow behavior and the water contribution from the different injectors.

Response Curves. The time response is the graphic representation of the concentration of activity (after background subtraction and decay correction) as a function of time. Preprocessing the experimental data can smooth the response. From this curve, the cumulative response (recovered activity vs. time) is derived by a simple numeric integration.

Concerning the cumulative response, the Eq. 6.28 gives the cumulative tracer recovered up to an instant, ti.

RTENOTITLE....................(6.28)

where RTENOTITLE = the total tracer recuperation up to ti, RTENOTITLE = the production water flow rate as a function of time, Ct = tracer concentration as a function of time, and ti = the elapsed time (days after the injection). RTENOTITLE often will be available as a discrete value representing each day. Ct will be available only as an individual measurement according to the sampling program. The accuracy of the total recovery will depend on the sampling frequency.

Sweep Volume. Instead of the time-response curves, the data are often presented as volumetric-response curves. The presentation is especially convenient for estimating the swept volume between the particular injector and producer pair. Swept volume, VS, can be estimated from the product of the mean produced volume, RTENOTITLE, and the ratio of the mean volumetric water rate between the injector and the producer, Qm, to the mean volumetric water production rate, Qp.[4]

RTENOTITLE....................(6.29)

RTENOTITLE is calculated from the first moment of the produced-tracer concentration, C.

RTENOTITLE....................(6.30)

Qm, the flow rate between injector and producer, is estimated from the fraction of injected tracer produced at the well at the mean injection rate, Qi.

RTENOTITLE....................(6.31)

where m = the amount of tracer produced at a given well and M = the amount of tracer originally injected. The swept volume can be expressed in terms of the injected and produced flow rates and the fraction, m/M, of water going from the injector to the producer.

RTENOTITLE....................(6.32)

Because of limited data, the tracer-production curve is composed of a discontinuous set of points and, in practice, the integral in Eq. 6.30 is approximated by

RTENOTITLE....................(6.33)

The calculation of swept volume often is complicated by a lack of data. The mean produced volume may need to be estimated on the basis of extrapolated tracer-production curves. In many cases, the sampling program is either not finished or it has been stopped without following the tail of the production curve. To fit the missing data in the tail of the production curve, an exponential decline approximation can be applied.

RTENOTITLE....................(6.34)

where Ce = the measured tracer concentration at the value of Ve from which the exponential fit starts. The slope of the line is represented by 1/a. If Eq. 6.34 is substituted for C in Eq. 6.30 and the integral replaced by a finite sum, the following expression is valid:

RTENOTITLE....................(6.35)

To find the swept volume in an incomplete data set, this equation is used for RTENOTITLE in Eq. 6.32.

Evaluation Based on Analytical Solutions

Eq. 6.26 gives the fundamental equation for tracer breakthrough in a streamtube. A correlation into a single breakthrough curve for various repeated homogeneous-flooding patterns has been found. [15] In a layered system, the overall tracer-response curve is a combination of responses from individual layers. The individual-layer responses are predictable from the correlated pattern-breakthrough curve; however, the tracer arrival time at the production well and the concentration contribution from each layer are functions of the porosity, permeability, and thickness of that layer. Conversely, the decomposition of an actual tracer-production curve from a multilayered system into the individual-layer responses can yield individual-layer parameters. Computer algorithms exist that deconvolve the overall tracer profile into the individual-layer responses and compute ϕ h and khkh of the individual layers.

Evaluation of Tracer-Response Curves With Numerical Simulation

The most thorough analyses of tracer data are carried out in combination with a reservoir simulator applied for that particular field. Many of the applied reservoir simulators, based on numerical solution of flow equations applying finite-difference methods, have options for handling tracers. [19] In addition, streamline models[20][21] exist that handle tracer flow. However, normal simulators have limitations. One problem is the limited possibilities for including physical properties such as partitioning between phases and adsorption to grain surfaces. This problem is of special importance for gas tracers. There is also a problem connected to handling of dispersion because the tracer pulse is, in its initial phase, much smaller than a typical gridblock size.

To overcome some of these problems, Sagen et al.[22] developed a simulation module to improve the accuracy of the calculations. To resolve the influence of reservoir heterogeneities on the measured tracer response, an accurate numerical treatment of the tracer equation is needed. This is especially important when narrow tracer slugs are injected in a reservoir. This tracer module calculates tracer flow with an explicit method for integration of the convection part of the tracer equation. To reduce numerical smearing of the tracer pulses, the timestep for the tracer calculation is selected as large as possible but may still be much smaller than the timesteps of the host reservoir simulator, which most often uses an implicit formulation. In the tracer module, the main tool for reducing numerical dispersion is the use of a second-order numerical scheme for integrating the tracer equation. A separate grid-refinement option for tracer calculation is available. In combination, these methods lead to a good resolution of narrow slugs propagating through the reservoir. The method of separate grid refinement is far less time consuming than performing the whole reservoir simulation on a refined grid. This tracer simulation module has been coupled to some of the standard reservoir simulation tools.

Field Experience


Interwell tracer tests are widely used. This chapter reviews some of the studies reported in open literature. The selection introduces different problems to be addressed, but the original papers should be studied to obtain a more detailed description of the programs.

Tracers in WAG Programs

The Snorre field is a giant oil reservoir (sandstone) in the Norwegian sector of the North Sea. Injection water and gas were monitored with tracers,[17] and the resulting tracer measurements are discussed in Sec. 6.5.2.

The same tracers used in the Snorre field have been injected in the Gullfaks field[23] in the North Sea. The tracers identified unexpected communication paths between layers. The results contributed to methods for improving the WAG recovery performance.

Water and Gas Tracer Injection in Fractured Reservoir

A tracer test was carried out in the Spraberry trend in west Texas. [24] In this field, the oil was produced primarily from fractures and not from the matrix porous sandstone. To carry out the most efficient waterflooding strategy, the knowledge of fracture direction was imperative. Instead of a costly water-injection pilot project, natural gas with tracer was injected into a central well for 16 weeks to define the fracture pattern. The 85Kr tracer applied was injected continuously with a concentration 28 times minimum detectability, which was 13,000 Bq/m3 (10-8 Ci/ft3) gas. The detector system applied was a thin-wall, beta-sensitive Geiger-Muller tube that records the tracer amount in the effluent gas continuously.

At the beginning of the thirteenth week, a 2-Ci slug was injected, and at the beginning of 14th week, a 1-Ci slug was injected. Radioactive gas was recorded only in two wells. No radioactivity increases were detected at any of the other 10 wells monitored, either continuously or intermittently, during the tracer survey. The cyclic nature of tracer appearance was attributed to the necessity for overcoming the varying hydrostatic head of oil in the well and to the appreciable difference in effective permeability of the principal and cross-fracture systems. Apparently, neither of the two wells in which tracer was recorded intersected the same fracture plane as the injection well. The tracer survey confirmed predictions about the general line of fracture orientation in the lower formation of the Sprabarry trend.

Gas and Water Tracers in the El Furrial Field

Viela et al.[25] reported the application of both gas and water tracers in the El Furrial field. The radioactive water tracers applied were isopropyl alcohol, HTO, 22Na, and thiocyanate. Breakthrough time recorded was between 1 and 3 years. In the same field, gas tracers also were added. The tracers applied were PMCP, PDMCB, and SF6. The conclusion was that the tracer survey was important to verify expected flow behavior and to identify unexpected communication paths.

Tracers for Gas Injection

Welge[26] described one of the pioneering works of tracer application to follow injected gas. The communication between the wells in a small part of the Cromwell pool in central Oklahoma was investigated. The well spacing in the area was approximately 65 m. Three radioactive tracers were used: HT (only tritiated hydrogen is mentioned which may be either HT or T2), CH3T, and 85Kr. One Ci of the tritiated compounds and 280 mCi of 85Kr were injected into the same well. In the nearest well, the tracers were produced after 7 days, which indicates an average flow rate of 10 m/day or more than 1 ft/hr. The tracers were not injected simultaneously; therefore, a comparison of the response curves should be done with care. The curves show small variation with the methane peak produced a day or two later than tritium and 85Kr. It also seems that the 85Kr data are a bit more spread out than the other data. The test results were used to improve the knowledge about the sweep area and the volumetric flow in the different directions.

Calhoun[27] reported the use of several gas tracers in the Fairway field. The program consisted of three phases of injection. In the first phase, 10 Ci of tritiated hydrogen and 85Kr were injected. Four months later, 10 Ci of tritiated methane, tritiated hydrogen, and 85Kr were injected in a new set of injectors. In the third phase, 10 Ci of tritiated methane and 85Kr were injected again in several wells. The extensive tracer program showed the source of gas breakthrough of 25 production wells. Continuous sampling of these wells after gas breakthrough has indicated a change in front configurations and fluid-migration pattern. Tracer responses proved the need for controlled injection and withdrawal to even out sweep configurations. Furthermore, tracers have indicated those areas in which injection rates and gas/water cycles should be changed to reduce fingering of the injected gas. This knowledge has been useful in alternating injection cycles and rates to control GORs at a reasonable level. Radioactive-tracer results also indicate that high-pressure gas injection at the Fairway is yielding additional oil recovery, either through swelling of the residual oil or by partial miscibility.

Tinker[28] reported the use of tritiated hydrogen and 85Kr as tracers under methane injection in the Trembler zone II reservoir of the East Coalinga field, California. The tracers revealed that desaturated intervals were often continuous over wide areas of the field. Those intervals could greatly influence an injection project by acting as a thief zone for injection water. The tracer study suggested generally better reservoir-sand continuity than could be inferred from a related outcrop study.

Tracers in the Enriched-Gas Injection

In the Prudhoe Bay field, [29] 85Kr, tritiated methane, ethane, and propane have been used as tracers for an enriched-gas flooding. In the South Swan Hills unit, Alberta, Canada, [30] tracers were applied to follow enriched gas in a water/solvent cyclic-injection program. This is a limestone reservoir, and the tracers applied were tritiated hydrogen gas, tritiated ethane, and 85Kr.

To gain information about the interwell reservoir characteristics, relative fluid velocities, and volumetric sweep efficiency in the early life of this project, it was desirable to trace the interwell movement of both the injected solvent and water. Tracers were added in as many as 14 solvent and 14 water injectors. The tracer responses in the wells were applied to redesign the injection program to achieve better sweep efficiency. The results proved to be of value as a qualitative indication of sweep, showing water and solvent flowing together to the majority of the offset wells. In some cases, unexpected flow paths were identified. No quantitative interpretation and information on project performance, however, have been derived from these data.

High-Pressure N2 Miscible Injection

In the Jay/Little Escambia Creek field, five radioactive tracers and one chemical tracer were used to tag injected N2.[31] The radioactive tracers used were 85Kr, tritiated hydrogen, methane, ethane, and propane. Sulfur hexafluoride was the lone chemical tracer. The N2 was injected at a pressure of up to 7,600 psig for a period of 1 to 2 weeks before the well was switched over to water injection. The tracers produced are 85Kr and tritiated propane. The main purpose of tracer injection was to determine the source of N2 breakthrough. This knowledge enabled adjustment of injection rates and volumes to improve area convergence on the production wells.

Also in the Fordyce field, [32] 85Kr, HT, CH3T, and C2H5T were applied in a high-pressure ( > 7,000 psig) miscible injection program. The gas injected was dry natural gas with an N2 content of approximately 5%. The tracer-production data were used in a gas-sweep model to predict gas movement and to localize unswept areas.

Labeling of CO2 Injection

Craig[33] reported the use of halogen compounds to trace injected CO2. The compounds applied were freon-11, freon-12, freon-113, and sulfur hexafluoride. The halocarbons were reported to be detectable in concentrations down to 0.5 ppb in laboratory tests on produced fluids. The detection was carried out by separation through a GC column and registration by an electron-capture detector. These four tracers were injected in nine injection wells, and registration of the tracer content in the production was done from 23 production wells.

=== Residual-Oil Saturation in a Leduc Miscible Pilot ===[34]

Because of the large remaining oil in place, Leduc Woodbend D-2A had the potential to be an ideal miscible-flood candidate. Before the miscible injection, it was important to quantify the remaining oil. An injector/producer pair on 64-m spacing was chosen as a pilot for the tracer test. The partitioning tracer applied was tritiated butanol. Fig. 6.9 shows the production curves of the tracers. On the basis of the retention of the butanol and methanol and the partition coefficient of these two tracers at the actual conditions, the residual oil between the two wells was measured. The tritiated methanol was regarded as a nonpartitioning tracer. The residual oil, Sor, was calculated on the basis of different arrival times of the two tracers, as shown in the production curve. The "peak," "half-peak height," and "breakthrough" gave the Sor at 34, 35, and 38%, respectively. The results were compared with the oil saturation obtained from sponge coring and single-well push-and-pull tracer tests. The sponge core gave an S or at 33%, while the single-well tracer test gave a result from 35 to 40%, depending on the porosity model applied.

In summary, all field tracers, whether chemical or radioactive, are currently the only feasible, direct means of tracking the movement of injected fluids in a reservoir. In many fields, this information has been crucial for improving injection and production programs. Investments in new wells and equipment for injection programs are large and decisions should be based on the best possible data. A tracer test is a cost-efficient method to obtain important data that allow the analysis of injection and production options.

Nomenclature


a = cross section, L2
ac = adsorbed amount
A = constant related to the enthalpy
B = constant related to the entropy change
c = concentration in the liquid phase caused by partitioning between the gas and liquid phase
C = concentration
Cc = concentration in the contacting phase
Ce = measured tracer concentration
CG = concentration of tracer in gas phase
CM = concentration of tracer in mobile phase
CO = concentration of tracer in oil phase
CS = concentration of tracer in stationary phase
Ct = tracer concentration as a function of time
f = fractional flow
fg = fractional flow for gas
fo = fractional flow for oil
ft = flow of tracer (see Eq. 6.21)
F = correction factor
h = height of reservoir zone, L
HC = Henry’s law constant
k = permeability, L2
K = partition coefficient
KC = partition coefficient based on concentration
Kci = partition coefficient of component i
Kcj = partition coefficient of component j
KP = partition coefficient based on mol fraction
L = distance, L
m = amount of tracer produced in a given well
RTENOTITLE = total tracer recuperation up to ti
M = amount of tracer originally injected
MW = molecular weight, m
p = pressure, m/Lt2
pi = partial pressure, m/Lt2
pv = vapor pressure, m/Lt2
q = volume flux, L3/t
qT = total volume flux, L3/t
Qi = mean volumetric injection rate, L3/t
Qm = mean volumetric water rate between injector and producer, L3/t
Qp = mean volumetric water production rate, L3/t
Qpt = production-water flow rate as a function of time, L3/t
r = radius of tracer front in radial system, L
s = frontal location in streamtube, L
s1 = front location of tracer pulse in the streamline, L
s2 = end location of tracer pulse in the streamline, L
S = saturation
Sg = gas saturation
So = oil saturation
Sor = residual oil
Sw = water saturation
t = time, t
t* = dimensionless time
tf = fraction of time, t
ti = elapsed time for tracer i, t
tS = retention time of nonpartitioning reference tracer, t
tT = retention time of partitioning tracer, t
T = temperature, T
U = parameter that decides the shape of the curve for the actual system at a specific temperature
RTENOTITLE = average linear flow rate of gas phase, L/t
RTENOTITLE = average linear flow rate of liquid phase, L/t
RTENOTITLE = average velocity of tracer, L/t
V = parameter that decides the shape of the curve for the actual system at a specific temperature
RTENOTITLE = mean produced volume, L3
Vd = dilution volume, L3
Ve = produced volume from which the exponential fit starts, L3
VM = volume of mobile phase, L3
Vp = pore volume, L3
VS = retention volume of standard reference tracer, L3
VT = retention volume of tracer candidate, L3
VTi = retention volume of tracer candidate i, L3
VTj = retention volume of tracer candidate j, L3
x* = dimensionless distance
xi = mole fraction of tracer i in liquid phase
yi = mole fraction of tracer i in gas phase
α = dispersivity
β = retention factor
δG = density of gas, m/L3
δO = density of oil, m/L3
μ = viscosity, m/Lt
μ1 = first momentum
σ = standard deviation
ϕ = porosity
ψ = streamtube


References


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SI Metric Conversion Factors


bar × 1.0* E + 05 = Pa
Ci × 3.7* E + 10 = Bq
ft × 3.048* E − 01 = m
°F (°F − 32)/1.8 = °C
°F (°F + 459.67)/1.8 = K
eV × 1.602 19 E − 19 = J
mL × 1.0* E + 00 = cm3
psi × 6.894 757 E + 00 = kPa


*

Conversion factor is exact.