Dennis F. Wyatt, Jr.
Halliburton Energy Services
Houston
Ronald J. Crook
Halliburton Energy Services
Duncan, Okla.
Water source identification is the first and most important step in controlling unwanted water production that can severely limit the productive life of a well and, thereby, decrease hydrocarbon recovery.
Water-control treatments often fail because the source of the water problem is not identified, the wrong treatment is performed, or the correct treatment is performed incorrectly.
Table 1 (87099 bytes) lists typical problems, means of identification and evaluation, and chemical treatments available for correcting the problem.'
WATER PROBLEMS
Most water problems can be classified as either near well bore or reservoir related. Near well bore problems can result from casing leaks, channels behind casing, barrier breakdown, and completion into or near water or gas.
Reservoir-related water problems are caused by coning and cresting, channeling through higher permeability formations, fingering, fracturing out of zone, and fracture communication between injector and producer.
Well logs can help diagnose downhole situations that can lead to unwanted water production, and the effectiveness of water-control treatments can be evaluated with cased and open hole logs.
OPEN HOLES
Open hole logs can point to possible causes and sources of unwanted water or gas production, such as oil/water contacts, original reservoir fluid saturations, and borehole conditions. These logs also can help identify formation lithology to aid in the interpretation of the cased-hole logs and help ensure chemical compatibility with treatment fluids.
Typical logs include caliper, gamma ray and SP logs, and resistivity and porosity logs.
Caliper logs locate areas where severe borehole washout has occurred that can contribute to poor cement bonding. Gamma ray and SP logs can delineate shale beds from possible water or hydrocarbon-producing reservoirs.
Resistivity and porosity logs, such as sonic, density, or neutron logs, can be combined to determine the location of water and pay zones. A comparison of these logs with cased-hole logs can be used to monitor changing water levels or to detect reservoir coning.
Fullwave sonic measurements can be combined with bulk density log data to predict fracture height as a function of the differential pressure between downhole treatment pressure and fracture closure pressure.
CEMENT EVALUATION
Cement behind the casing isolates formation zones but unwanted fluid paths often develop in the cement because of improper cementing procedures, bad borehole conditions, well age, or workover operations.
Cement evaluation logs can help determine the condition of the cement annulus by detecting channels in the cement sheath that could allow hydraulic communication between zones. These logs show if the cement is isolating the water zones and if the poor isolation is caused by insufficient or nonexistent casing- to-formation bonds.
Cement evaluation logs include cement bond logs (CBL), or the pulse echo tool (PET), a form of ultrasonic bond log.
CBLS
Conventional CBLs use a single acoustic transmitter and two receivers to evaluate the cement bond. The transmitter emits an acoustic signal pulse that travels through the borehole fluid, casing, cement, and formation and back to the receivers. The logging system records the waveforms and determines the travel times and amplitudes of the signals reaching the receivers (Fig. 1)(99953 bytes).
The first signal to arrive at the near receiver is the pipe arrival signal. The associated transmitter-to-receiver travel time is recorded on the log as the travel-time curve.
Formation signals will appear in the wave train if there is sufficient bonding between the pipe, cement, and formation. In most formations, the acoustic wave travels slower through the formation than through the casing. The first formation arrival signal reaches the receiver after the pipe arrival signal.
In a fast formation, the acoustic wave travels faster through the formation than through the casing. Low-porosity limestones and dolomites are considered fast formations. The formation arrival signal cart occur before the pipe arrival signal in a fast formation. The variations in travel time that occur when the formation arrival occurs before the pipe arrival may correspond to variations in the formation.
The far receiver determines the amplitude of the pipe signal and records the entire acoustic waveform. The waveform can identify the following conditions:
- Free pipe
- No bond to the formation
- Channel
- Microannulus
- Good bond.
CBLs are omnidirectional. The acoustic signals generated by the transmitters travel away from the tool in all directions, and the receivers receive acoustic waves from all directions. The bond quality is determined as a circumferential average of the bonding around the casing.
It is difficult to distinguish high-strength cement con- taining a channel from evenly distributed low-strength cement without a channel because circumferentially averaged amplitude and attenuation may be the same in both cases.
For annular cement to attenuate the signal, there must be good shear mechanical bonding between the cement and the casing outer wall. If there is a microannulus between the cement and the casing, the log may indicate poor bonding even if the gap is thin enough to prevent fluids from flowing.
CBL interpretation assumes that changes in bonding cause changes in the pipe signal amplitude. Other factors also can cause variations in pipe signal amplitude:
- Pipe diameter
- Pipe weight or thickness
- Borehole fluid density
- Cement thickness
- Cement compressive strength
- Tool sensitivity.
PET
The pulse echo tool (PET) produces an ultrasonic bond log that overcomes some of the limitations of the omnidirectional CBL. PET logs contain eight ultrasonic transducers equally spaced in a helical pattern. Each transducer generates an acoustic wave that travels toward the casing perpendicular to the casing wall.
Most of the energy that arrives at the inner wall reflects back and forth within the casing. Some energy is transferred outside the casing at each reflection, reducing the amplitude of the reflected wave at each reflection.
The output frequency of the PET ranges from 300 to 600 khz. At this frequency, the thickness of most microannuli will be small compared to the acoustic wave length. The PET is relatively insensitive to liquid-filled microannuli; however, the ultrasonic bond log may indicate free pipe in gas-filled microannuli and in cement containing gas bubbles.
The acoustic impedance of a material is the product of its density and compressional velocity. The train of reflected waves returning to the transducer provides information about the annular material.
Acoustic impedance can distinguish between cement, liquid, and gas in the annular space and can estimate cement compressive strength. These waves also can indicate reflections from additional interfaces, such as a second string of casing or the formation.
The preferred cement evaluation program combines both the CBL and PET logs.
CASING EVALUATION
Many water-entry problems are caused by poor mechanical integrity of the casing. Holes from corrosion or wear and splits caused by flaws, excessive pressure, or formation deformation can contribute to unwanted entry of reservoir fluids.
Casing condition can be evaluated and monitored by mechanical, electromagnetic, and ultrasonic tools. Casing evaluation logs find holes, splits, or deformities in casing that could allow unwanted water/gas entry and determine corrosion conditions that could lead to leaks.
MECHANICAL EVALUATION
Mechanical devices use independent, spring-loaded feeler arms to measure the internal radius of the casing. Mechanical calipers provide information about the internal condition of the casing. However, the calipers inspect only a small circumferential fraction of the casing.
Locating small holes or splits with a mechanical caliper tool usually requires multiple passes with the tool.
The logs produced by most mechanical calipers determine minimum diameter, maximum diameter, and remaining wall thickness curves. The remaining wall thickness is determined by subtracting the measured internal radius of the casing from the nominal outside radius of the casing.
ELECTROMAGNETIC TOOLS
Electromagnetic phase-shift devices measure the attenuation and phase shift of a transmitted electromagnetic signal to determine circumferential averages of casing thickness and diameter.
The phase shift between the transmitter and near receiver on a one-transmitter, two-receiver coil array determines the casing thickness. The coarse resolution restricts the capability of the omnidirectional measurement to detect small anomalies clearly.
A second phase shift is measured between the near and far receivers and detects casing anomalies over a short length of the casing. The associated curve on the log is designated as the differential index. On this curve, a large deflection to the right followed by a large deflection to the left indicates an increase in metal. A large deflection to the left followed by a large deflection to the right indicates a decrease in metal.
The phase-shift tool cannot clearly distinguish between perforations or other small defects because of the vertical resolution of the omnidirectional differential measurement and the dependence of the measurement on casing thickness and metal volume.
Perforation diameters are significantly smaller than the vertical resolution of the measurement. If perforation diameters are small and shot densities are low, then the volume of metal over a perforated section of casing will not be much different from the volume of metal over an unperforated section. The differential readings will be small, and the perforations will be difficult to identify. However, intervals that have been perforated at high-shot densities can be distinguished with the phase-shift log.
FL/EC MEASUREMENTS
Electromagnetic flux leakage/eddy current (FL/EC) measurements can help evaluate metal loss. These logging tools provide 360 wall coverage with high vertical resolution by using an array of pad-mounted coils. FL/EC measurements identify flaws on the external or internal surface of the pipe.
Flux is contained within the walls of the casing. When holes, pitting, or other defects are present in the wall of the pipe, perturbations in the flux lines cause some flux to spill out of the confines of the wall. A flux leakage coil responds to holes and inner and outer wall defects.
An eddy current coil allows current to penetrate into the pipe wall. When the current passes a defect on the inner wall, the receiver coils are unbalanced. The coil produces a characteristic signature for the defect on the inner wall, but there is no response for flaws on the outer wall or internal flaws beyond the depth of penetration of the current.
Comparing the response of the flux leakage measurement and the eddy current signals can determine whether the defect is on the outer wall, inner wall, or through a hole. Holes as small as 0.1 in. in diameter can be seen on flux leakage curves. The eddy current can detect defects as small as 0.25 in. diameter.
ULTRASONIC EVALUATION
Two types of ultrasonic tools are used for casing inspection: acoustic imaging and pulse echo.
The acoustic imaging tool uses a rotating ultrasonic transducer to measure the casing inside diameter, casing ovality, and tool centralization. The transducer produces a narrow acoustic beam that propagates through the borehole fluids toward the borehole wall and reflects back to the transducer. The transducer records the travel time and amplitude of the reflected signal.
Acoustic imaging tools determine well bore fluid and casing wall conditions. Solids in the well bore, such as scale and paraffin, can scatter and disperse the transmitted and reflected signals. The data also can be difficult to interpret if the transducer head is too close to the wall. If the head is too far from the wall, the acoustic amplitude of the received signal is reduced.
The pulse echo tool (PET) is used primarily as a cement evaluation tool; however, the PET also can determine casing ID and thickness.
RESERVOIR MONITORING
Pulsed neutron logs provide cased-hole formation evaluation and reservoir monitoring. There are two types of pulsed neutron logs: pulsed neutron capture (PNC) and pulsed neutron spectrometry (PNS).
PNC logs are run in areas with high-salinity formation waters and PNS logs are for areas with low or unknown salinity. Pulsed neutron logs determine current reservoir fluid saturations and evaluate changes in water level or coning.
Pulsed neutron logs detect and quantify the water flowing past the tool during logging. When water moves past the generator, oxygen is activated by high-energy neutrons and forms a radioactive isotope of nitrogen. The isotope is unstable and decays with a 7.35 sec half-life. The tool detects the gamma rays given off during the decay as water flows past the tool. This technique can identify the following problems:
- Channels outside the casing
- Leaking tubulars
- Water production
- Water entry into the casing.
The technique also can identify water-producing reservoirs and detect changing fluid holdups in the casing with borehole measurements.
PNC
PNC tools detect water flow inside or outside the casing. Fig. 2 (128504 bytes) shows a well that was involved in a log-inject-log project to determine residual oil saturation in a reservoir before a water-flood.
The log was run during the early injections of brine. A background increase with an absence of high natural gamma activity indicated that a leak in the packer assembly was allowing water to flow upward in the casing-tubing annulus. The increased background response from X640 ft to X625 ft also shows a channel out-side the casing. The right one half of the log illustrates the magnitude of the casing leak as established by interpretation.
PNS
PNS tools detect the presence of water flow by measuring the activated oxygen in a spectral window that is placed around the main oxygen peak in the capture gamma ray spectra. The tool determines if water is flowing past the tool by detecting an increase in the count rate of the oxygen-activation curve.
Fig. 3 (48405 bytes) is a log from an Indonesian well that had the original perforations squeezed off before being recompleted. The log detected crossflow and an oil/water contact in the casing.
The sudden high value of the C/O ratio above X148 ft indicates that oil filled the casing from this depth upward. The oxygen-activation curve indicates a water flow upward from X294 ft to X148 ft where the water entered open perforations. The water was entering from perforations that previously had been squeezed with cement to isolate watered-out reservoirs.
PRODUCTION EVALUATION
Production logs measure the various fluid properties needed to perform pressure-volume-temperature (PVT) analysis and detect fluids flowing in and around the casing. A production log suite usually consists of a flowmeter and pressure, temperature, and one or more fluid-type identification sensors.
Production logs can analyze reservoir performance and perform completion diagnosis. When evaluating reservoir performance, sensors identify fluid types, flow rates, and entry or exit depths. After completion, the sensors can identify prob- lems such as leaking tubulars, plugged perforations, and channels in the cement sheath.
FLOWMETER
Flowmeter logs or spinners accurately measure the velocity and direction of fluid flow in the well bore. Three types of tools are available:
- Continuous flowmeter
- Fullbore flowmeter
- Basket flowmeter.
The continuous flowmeter contains a jewel-mounted impeller protected by a metal cage. The impeller turns at a rate proportional to the average velocity of the fluid flowing in the center of the well bore.
The fullbore flowmeter consists of a multibladed propeller that opens to fill the casing after dropping out of the tubing. Fullbore tools measure the fluid flow across the entire casing diameter for both high-angle and low fluid velocity wells.
Basket flowmeters perform stationary measurements in high- angle wells where fluid segregation is expected. A funnel opens to fill the casing, forcing all the fluids into the tool and past an impeller.
FLUID HOLDUP
Fluid holdup logs indicate the type and relative percentages of the fluid phases present in the casing at a certain depth. Fluid density, dielectric, and pressure tools are available.
The fluid density tool continuously measures well bore fluid densities. A change in density indicates either that two fluids are in contact or that fluid has entered the well. The fluid density log can locate perforations or leaks in the casing or tubing.
Dielectric tools measure the dielectric constant of the fluid passing by the sensors. The response is sensitive to the presence of water in the flow stream because of the large difference in the dielectric properties of water and hydrocarbons. The hydrolog can detect water and hydrocarbons in the well bore, determine water holdups, and detect fluid entry into the well bore.
Pressure logs, manometers, and gradiomanometers determine changing fluid densities caused by changes in the hydrostatic pressure between a pair of high-resolution pressure sensors.
TEMPERATURE, PRESSURE
Temperature and pressure measurements convert the measured downhole fluid properties into uphole conditions. Any PVT analysis of the production also requires temperature and pressure measurements.
The strain gauge tool and the quartz pressure tool con- tinuously measure pressure in the borehole. The strain gauge tool measures down-hole pressures. The quartz pressure tool measures pressures while compensating for high downhole temperatures.
Temperature logs can continuously measure temperatures in the well bore and can detect liquid movement behind the pipe. The tool also locates cement tops and gas entry points.
Depending on the temperature of the fluid downhole, the tool can determine whether the fluid originates from the formation or has channeled into the well bore from above or below. A tem- perature that is cooler than the well bore indicates that the fluid has channeled in from a shallower formation. A temperature warmer than the well bore indicates that the fluid has channeled up from below the formation.
TREATMENT EVALUATION
Radioactive tracer logging is a method commonly used to measure injection profiles in water-injection wells. A spectral gamma ray log can be used in combination with radioactive tracers to determine information in the following areas:
- Directional flow trends
- Identification of rapid interwell communication
- Volumetric sweep efficiency
- Delineation of flow barriers.
With the information determined from radioactive tracer surveys, better knowledge of reservoir and fluid flow paths are obtained, which helps determine the proper conformance treatment.
Other logging services, such as production, cement bond, casing inspection, or pulsed neutron logs, also can verify treatment effectiveness. All treatments should be checked to detect any unwanted fluid production.
WELL TESTS
Multiple-well transient tests can help determine if communication exists between two or more wells. Multiple-well tests require at least one producing or injecting well and one pressure observation well.
The flow rate of the active well is varied while the bottom hole pressure response is measured at the observation well. No pressure change in the observation well means that there is little or no communication between the wells, and the wells can be completed. A bottom hole pressure response can help determine parameters such as permeability and the porosity-compressibility product.
APPLICATIONS
In one example a water flow analysis log (pulsed spectral gamma log) was run to determine water flow velocity and direction behind two strings of casing for an injection well. The well was located near two producing wells, a water-source well, and another production company's well in West Texas.
The injection well was drilled, completed, and remedially cemented twice to stop gas flow. After squeezing, a water spot appeared on the ground near the water-source well. The water was analyzed, and it was determined that the water-source well was not the source of the water spot.
A water flow analysis log was run on each individual well after shut-in to isolate the source of the flow. The log determined that the other operator's well was the source of the unwanted water flow. The water from the other well was traveling to the surface through the annulus of the injection well and a naturally occurring fracture network. As a result, the water injection from the other operator's well was shut off with a foam cement job.
In another example a fluid density log, temperature, pressure, and spinner tools provided information on a gas- producing well that was experiencing high water production.
The fluid density log indicated that the well bore fluid was all water. A decrease in fluid density near the perforations indicated additional gas production.
The temperature log showed a warming anomaly that indicated liquids were entering the well bore. A decrease in temperature showed gas entering the well bore just above the warming anomaly. The gas entry was caused by gas expansion.
The differential pressure log showed the difference between two pressure measurements at a set interval. The log indicated both fluid movement and gas entry at different intervals in the well bore.
The logging data indicated that the well bore was completely filled with water below the perforations. Above the perforations, the pipe contained 60% water and 40% gas. The analysis indicated that treating the water-producing zone should eliminate the water without minimizing gas production levels.
REFERENCE
1. Crook, R., Haidar, S., and Hard),, M., "Conformance Control Extends Well Life," Paper No. ADSPE 105, Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, Oct. 1619, 1994.
