SECTION 5
UNEXPECTED INCREASES IN WATER PRODUCTION

Sources.  Mechanical problems.  Many water entry problems are caused by poor mechanical integrity of the casing. Holes caused by corrosion or wear and splits caused by flaws, excessive pressure, or formation deformation can allow unwanted reservoir fluids to enter the casing. An unexpected increase in water production could be the result of a casing leak. Many times casing leaks result in a pump failure or stuck pump. Most casing leaks occur in the casing above the top of the cement. Therefore, when the leak breaks into the wellbore, drilling mud that was left in the annulus between the casing and open hole during primary cementing operations enters the wellbore.

After repairing a casing leak, check the plugged back total depth and remove or circulate out any drilling mud or other debris that may have entered the wellbore. Often times after a casing leak, the well will need to be re-stimulated to remove formation damage caused by the invasion of fluids from the leak into the producing formation.

Communication problems  are classified as either near wellbore or reservoir related.¹⁹ Some problems could easily be placed in both categories. Near wellbore problems are channels behind casing, barrier breakdowns, and completions into or near water. Reservoir-related problems are coning, cresting, channeling through higher permeability zones or fractures, and fracturing out of zone.

Channels behind casing  can develop throughout the life of a well, but are most likely to occur immediately after the well is completed or stimulated. Unexpected water production at these times strongly indicates a channel may exist. Channels in the casing-formation annulus result from poor cement/casing bonds.

Barrier breakdowns.  Even if natural barriers, such as dense shale layers, separate the different fluid zones and a good cement job exists, shales can heave and fracture near the wellbore. As a result of production, the pressure differential across these shales allows fluid to migrate through the wellbore. More often, this type of failure is associated with stimulation attempts. Fractures break through the shale layer, or acids dissolve channels through it.

Completions into or near water.  Completion into the unwanted fluid allows the fluid to be produced immediately. Even if perforations are above the original water-oil contact, proximity allows production of the unwanted fluid, through coning or cresting, to occur more easily and quickly.

Coning and cresting.  Fluid coning in vertical wells and fluid cresting in horizontal wells both result from reduced pressure near the well completion. This reduced pressure draws water from an adjacent connected zone toward the completion. Eventually, the water can break through into the perforated or open hole section, replacing all or part of the hydrocarbon production. Once breakthrough occurs, the problem tends to get worse, as higher cuts of the unwanted fluid are produced. Although reduced production rates can curtail the problem, they cannot cure it.

Channeling through higher permeability zones or fractures.  Higher permeability streaks can allow fluid that is driving hydrocarbon production to breakthrough prematurely, bypassing potential production by leaving lower permeability intervals unswept. This is most common in active water-drive reservoirs and waterfloods. As the driving fluid sweeps the higher permeability intervals, permeability to subsequent flow of the fluid becomes even higher, which results in increasing water-oil ratios throughout the life of the well or project.

Fracturing out of zone.  An improperly designed or poorly performed stimulation treatment can allow a hydraulic fracture to enter a water zone. If the stimulation is performed on a producing well, an out-of-zone fracture can allow early breakthrough of water. If the fracturing treatment is performed on an injection well, a fracture that connects the flooded interval to an aquifer or other permeable zone can divert the injected fluid, providing very little benefit in sweeping the oil zone. As mentioned in Section 2, many operators tag the tail end of their proppant with radioactive tracer, so if the well does not respond as anticipated, they can log the well to determine where the fracture went.

Methods to Identify Sources.  Chloride/TDS tests . Production-water sampling and analysis should be conducted on a regular basis on each producing well. Establishing a baseline water analysis provides valuable information if production or well conditions change suddenly. Changes in chloride or total dissolved solids (TDS) provide insight to problems and remedial action that may need to be taken.

Chloride concentration can be used to determine if produced water is connate water (production water) or water introduced to the well during stimulation or from other sources. Changes in chloride concentration can indicate invasion of water into the well due to poor mechanical integrity. Lower than normal chloride concentrations can indicate a shallow casing leak. Iron concentrations can predict the probability of formation damage from iron oxide precipitation. pH can also indicate the probability of metal oxide precipitation. Knowing the specific gravity of your produced water is useful in determining bottomhole hydrostatic pressure.

Production logging  can be used for: 1) injection profile tests in waterfloods to determine the vertical distribution of fluid flows within the wellbore and near wellbore region, 2) finding tubing-casing leaks, 3) detecting lost circulation zones, 4) determining if packers or bridge plugs are leaking, 5) detecting fluid channels behind casing, 6) developing production profiles, 7) locating gas-oil-water contacts, 8) tracing frac fluids, and is beneficial in many other instances.

Radioactive tracer or fluid travel surveys.  The radioactive tracer log was developed to give positive, accurate information on fluid flow paths and rates within the wellbore. The tool’s capabilities include detecting lost circulation, leaking packers and bridge plugs, fluid channels behind casing, and developing injection and production well profiles. Two types of radioactive tracer surveys are commonly used, the velocity-shot method and the timed-run method. The velocity-shot method is conducted by ejecting radioactive fluid downhole with a tool that has one or two gamma counter(s) and monitoring fluid movement with the gamma counter(s). The two-detector method is preferred over the one-detector method because of difficulty in accurately establishing an injection time. In this method, the tool is stationary and the log is a function of time. This method is not recommended in producing wells because it is not desirable to produce radioactive fluid. Hence, its main application is in injection wells.

In the velocity-shot method, counters are positioned at proper points, a small concentrated quantity of radioactive fluid is ejected, and a recorder records the travel time of fluid movement past the counters. Inside the casing, or in open hole if a caliper log is available, a time profile and resulting velocity profile determine injection distribution within the wellbore area. A typical procedure with the shot method is to record one station above the perforations to check for 100% flow and for any channeling above the perforations. The perforations are then surveyed in one- to two-foot increments until infinite time between counters is recorded. A second check is then made to ensure that no further “down channeling” is occurring.

The timed-run method qualitatively detects the flow of fluids up or down hole, either in casing or in the annulus. In this method, a large amount of radioactive material is ejected at the bottom of the tubing and successive runs are made with a gamma-ray tool; the times of ejection and each run are carefully noted. Movement of the radioactive material is traced. Primary use of this method is to detect unwanted movement of injected water in the casing annulus.

A differential temperature survey  uses a logging tool and is a service available from most wireline logging companies. The differential temperature log measures temperature of the wellbore fluid under static (shut-in) or dynamic (flowing) conditions. Temperature logs run while a well is injecting water at stabilized rates can yield much useful information. The logging tool responds to temperature anomalies produced by fluid flow, either within the casing or in the casing annulus, and is very useful in detecting the latter. Interpretations are also used to determine flow rates and points of fluid entry or exit.

In an injection well, temperature response is a function of depth, temperature of injected fluid, injection rate, time of injection, formation and fluid thermal properties, and the geothermal profile in the well. An injection well that has been taking fluid for some time can be shut in and numerous temperature logs can be run over a period of time to observe the temperature profile as it returns to geothermal values. The zones that have taken the (usually) cooler injection fluid will show a slower rate of return to the geothermal profile than the zones that have taken no fluid. This effect can be detected in uphole zones behind pipe that are taking injection water due to communication problems.

The most common application is in waterflooding projects where a foot-by-foot analysis of formation flooding is desired on injection wells. Advantages in tracing injected fluids with the single element differential temperature log become apparent when proper logging interpretation techniques are used. The temperature gradient log is a continuous recording of downhole absolute temperatures. Repeatability of the temperature measurement is plus or minus 0.01^o F in the range of 50 to 400^o F. Scales vary from fractional increments per inch to any practical limit required. The most commonly recorded scales are: 1, 2, 5, and 10 ^o F per inch.

Logging is usually performed on the downward traverse so that well fluids are encountered in their normal state without being previously disturbed by passage of the line and tool. The casing collar locator is run and recorded simultaneously, as this provides definite depth correlation with other types of logs run in the well.

Besides being used to detect fluid communication downhole in water injection wells, the technique is applicable for finding tubing-casing leaks, gas communication, productive zones, lost circulation zones, gas-oil-water contacts, production profiles, and tracing frac fluids.

Spinner (flowmeter) surveys  are used to meter fluid flow rates within cased or uncased wells. They are useful in determining production rates, detecting thief zones, locating lost circulation zones, finding holes in casing or tubing, and assisting in injection and production profiles.

Preliminary spinner surveys are generally made with the tool being withdrawn from the hole at a steady rate to permit selection of various station levels for observation of absolute flow rate as related to spinner revolutions per minute. The flowmeter can be run into or out of the well at a constant speed to obtain a continuous flow profile versus depth. It can be stopped at various depths within the wellbore to record the total volume of flow at a preselected interval.

The flowmeter unit contains a low inertia impeller to measure the movement of borehole fluids as they pass through the impeller blades. Movement of the impeller rotates a small magnet that actuates a magnetic switch. Fluid flow rotates the impellers, generating a square wave pulse, with frequency proportional to number of impeller revolutions per second. A flowmeter module that supplies power to the spinner unit also couples the signal into the rate meter that processes the signal for the recorder.

Types of fluid flowing through a spinner have a pronounced influence on its operation. Dirty fluids foul the impeller movement and gaseous fluids overspin the impeller. Surveys performed in fluid having viscosity higher than water result in optimistic apparent flow volume values. Surveys made in lower viscosity fluids result in pessimistic flow volume values.

Some spinners are limited to certain ranges of flow rates. Therefore, before doing a survey, check with the appropriate service company to verify that the spinner will work within the flowrate ranges of the well in question.

Cased Hole Formation Resistivity (CHFR) Tool. ²⁰ The ability to measure formation resistivity directly through casing in monitoring wells allows the measurement of water saturation further away from the wellbore. Advances in digital electronics have made it possible to produce the sufficiently accurate and stable downhole sensors required to measure formation resistivity through steel casing.

• Evaluation of reservoir fluid saturation changes with time, including the identification of swept zones, potential flow barriers, and bypassed oil.
• Monitoring of movement in oil/water contacts.
•  Identification of take-off rate-induced water coning, by repeat logging at different take-off rates, allowing time to re-establish stable conditions.
• Estimating residual oil saturation to a waterflood or a combined water-alternating-gas (WAG) flood. Measuring formation resistivity through casing allows the evaluation of residual oil saturation further away from the wellbore than open hole logs or sponge cores.

The CHFR tool can also be used for primary evaluation of reservoirs where no logs could be acquired in open hole, due to operational problems where open-hole logging is too risky. Wells with old or faulty logs can also be re-examined.

Measurements are taken while the tool is stationary. The CHFR injects current into the casing through a centralizer at the top of the tool that returns to the surface. Slight variations in current loss through the casing are related to current leaking into the formation and can be calibrated to formation resistivity. Voltages investigated by the tool are in the nanovolt range, requiring exceptionally stable and low-noise electronics downhole. Frequency is limited to about 1 Hz to avoid polarization associated with a DC-measurement and skin effects caused by a higher frequency. Casing current loss is measured through 4 rings of 3 electrodes attached to caliper-like arms that open up and establish contact with the steel casing at each station. Good electrical contact is essential; wells with scale or corrosion inside the casing create problems. In double-cased intervals the CHFR will read only the resistivity of the cement between casings.

Downhole tool calibration is achieved by comparing cased-hole measurements to open-hole logs.

Mechanical integrity tests (MIT).  A well is considered to have mechanical integrity if there are no significant leaks in the tubing, casing, or packer and no fluid movement into fresh or useable water. Any fluid coming into the wellbore, from production or injection, remains in the wellbore until it is produced or leaves the wellbore in the interval(s) approved for injection or disposal. Mechanical integrity can be determined by pressure testing or by casing inspection logs. In some instances an acoustic fluid level shot can assist in locating a leak in the casing.

Pressure testing  is commonly used to perform mechanical integrity tests. An MIT is required periodically on injection and disposal wells by State regulatory agencies. This is conducted by pressuring up the tubing-casing annulus and observing whether the pressure holds or not.

Pressure testing to isolate casing leaks is typically conducted using a retrievable bridge plug (RBP) and packer. The goal is to isolate the leaking interval as quickly as possible. The majority of casing leaks occur where there is no cement behind the casing. One common technique is to run the packer and RBP into the well and set the RBP just into the top of the cement interval behind casing. Pressure test the RBP and move the packer up and down the hole, pressure testing both through the tubing and on the annulus at different packer settings until the leak is isolated. Once a long section of casing passes the pressure test, the RBP can be moved and reset if desired. Be sure to use fluid to pressure test that is compatible with the producing formation, as each time the RBP is released the fluid will be dumped downhole. Different circumstances dictate how narrowly the leaking interval needs to be isolated. If the casing is in poor condition over a long interval, it is possible to further damage the casing by setting the packer and RBP in these bad intervals.

Casing inspection logs.  Casing inspection methods include multi-fingered caliper logs, electrical potential logs, electromagnetic inspection devices, and borehole televiewers. Of these, the majority measures the extent to which corrosion has taken place. Only the electrical potential log indicates where corrosion is currently occurring. With the exception of caliper logs, all the devices require that tubing be pulled before running the survey, since most are designed to inspect casing rather than tubing and all are large diameter tools.

Remedial Actions.  Cement squeeze techniques.  Too often, the injection of cement slurries into the casing/wellbore annular space, through casing perforations or splits in damaged sections, is performed without sufficient basic understanding of the placement process.²¹ Regardless of the technique used, cement squeezing is basically a filtration process. Cement slurries subject to differential pressure against a filter of permeable rock lose part of their mix water, leaving a cake of partially dehydrated cement particles. The rate of cake buildup is a function of formation permeability, differential pressure applied, time, and capacity of the slurry to lose fluid.

Low fluid loss slurries, when squeezed against low permeability formations, dehydrate slowly, making the operation excessively long. High fluid loss slurries lose water to high permeability rocks too fast, bridging off channels that otherwise would have accepted cement. The ideal slurry should be able to control the rate of cake growth so that a uniform filter cake will build up over all permeable surfaces. The only procedure that makes the dehydration of small quantities of cement into perforations or formation cavities possible is intermittent application of pressure, separated by a period of pressure leakoff caused by the loss of filtrate into the formation. This procedure is referred to as a hesitation squeeze. Squeeze cementing is classified depending on the way the cement is placed behind casing.

Low pressure squeezing  is when the cement slurry is forced through the opening in the casing below the formation fracturing pressure. The aim of this operation is to fill cavities and interconnected voids near the wellbore with dehydrated cement. The volume of cement is relatively small, since no slurry is actually pumped into the formation. When squeezing in depleted formations, spotting the total volume of cement in front of the perforations may be the only way to prevent the formation from fracturing as a result of hydrostatic pressure.

High pressure squeezing.  There are some cases where low pressure squeezing will not accomplish the job. Channels behind the casing might not be directly connected to the perforations; small cracks or microannuli may permit the flow of water but not a cement slurry. High pressure squeezing places the cement slurry behind the casing by breaking down formations at or close to the perforations. Fluids ahead of the slurry are displaced into fractures, allowing cement to fill the desired spaces. Further application of the hesitation technique dehydrates the slurry against the formation walls leaving all the channels, from fractures to perforations, filled with cement cake.

Two things to consider when performing high pressure squeezing: 1) The location and orientation of the generated fracture cannot be controlled; and 2) A properly performed job should leave the cement as close to the wellbore as possible.

Placement techniques.  There are two general ways of performing a squeeze job, with a packer or a bradenhead squeeze. The main objective of the packer squeeze is isolation of the casing and wellhead while high pressure is applied downhole. Retrievable packers with different design features are available. The ones used in squeeze cementing, compression or tension set packers, have a bypass valve to allow the circulation of fluids during the running in and once the packer is set. This feature permits cleaning of tools after the job and reversing out of excess cement without excessive pressures, and prevents a piston or swabbing effect during running in and out of the hole.

Cement retainers (mechanical or wireline set) are used instead of packers to prevent backflow when no cement dehydration is expected or when high negative differential pressures may disturb the cement cake. Retainers are also used when potential communication with upper perforations makes use of the packer a risky operation and squeezing can be carried out without waiting for the cement to set. Cement retainers are drillable packers provided with a two-way valve that prevents flow in either or both directions. The valve is operated by a stinger at the end of the tubing string.

Drillable bridge plugs or cast iron bridge plugs are normally used to isolate the casing below the zone to be treated. Of similar design to the cement retainers, they can be wireline or mechanically run. Bridge plugs do not allow flow through the tool. Retrievable bridge plugs (RBP) are easily run and operated tools with the same function as drillable bridge plugs. They can be run in one trip with the packer and retrieved after the cement has been reversed or drilled out. Most operators dump one or two sacks of frac sand on top of the RBP before the job to prevent settling of cement over the releasing system.

The bradenhead squeeze technique is used mainly when low pressure squeezing is practiced and there are no doubts about the casing’s capacity to withstand squeeze pressures. There are no special tools involved besides the bridge plug to isolate downhole formations. Open-ended tubing is run to the bottom of the zone to be cemented. The wellhead is packed off or the blow out preventer rams are closed over the tubing and the injection test carried out as usual. The cement slurry is subsequently spotted in front of the perforations or opening. Once the cement is in place, the tubing is withdrawn to a point above the cement top, the preventers are closed and the hesitation technique applied through the tubing. Reversing or washing down is carried out as normal.

Polymer squeezes.  In some circumstances, polymer gels can be used successfully as an alternative to cement, or in combination with cement, to squeeze casing leaks. The type of polymer and process used depends on the location and severity of the leak, and whether or not the squeeze will be required to hold a solid pressure or simply block encroachment of foreign water in a producing well. The advantage of using polymer is two-fold. Polymer can be washed out of the wellbore after a leak is squeezed, preventing costly rig time involved in drilling out cement. Second, since polymer solutions exert a much lower hydrostatic pressure than a cement slurry, there is less possibility of breaking down the formation and losing the squeeze. On difficult leaks, such as in salt sections where multiple cement jobs are often attempted before the leak is successfully squeezed off, a small slug of polymer can be run ahead of the cement as a buffer to prevent the cement from "running away" or washing out the section you are trying to squeeze. Since the polymer continues to adsorb or bond to the formation and the bulk gel fills the larger voids, it is often enough to slow down the coasting of the cement and give it something to squeeze against.

Four basic polymer gel systems are in use today in casing leak squeeze operations. Different service vendors have different names for these systems, but the basic systems are: 1) acrylic monomer grout, 2) high concentration low molecular-weight polymer (HCLM), 3) high molecular-weight polymer, and 4) cement/polymer combination.

Acrylic monomer grout  is a non-toxic system that is most effective on tight casing leaks and pressure leakoff situations such as leaks that bleed off pressure but cannot be pumped into. This system pumps as a water-thin fluid, then sets up into a tough, ringing gel. Gel times can be controlled from 10 minutes to 2 hours, depending on temperature. Treatment sizes typically range from 10-25 bbl. This is an excellent application for disposal and injection wells that fail MITs because of slight pressure leakoff.

High concentration low molecular-weight polymers  are useful for leaks ranging from tight pressure leakoff situations to moderate leaks that can be pumped into under pressure. This system can be crosslinked using standard metallic crosslinkers, or a low-toxicity organic crosslinking system can be used in environmentally sensitive areas or leak intervals.

High molecular-weight polymers  are most effective in larger leaks, to correct channeling behind pipe, and for some lost circulation applications. The primary benefit of using this system is the ability to economically block the flow of foreign water into the wellbore or block the outflow of produced fluids to thief zones.

Cement/polymer combination  squeezes are used in severe casing leaks that require mechanical integrity and are unlikely to be successfully sealed using either cement or polymer alone. In most cases, a small (25-50 bbl) slug of high molecular-weight crosslinked polymer is injected ahead of the cement. The polymer acts as a filler/buffer, filling larger voids and coating formation surfaces, preventing water loss and cement contamination by formation fluids. The polymer also acts as a pad, holding cement in the near wellbore area where it is most effective. This process blocks foreign water from the wellbore and can allow pressure integrity to be obtained more cost-effectively than would be possible with cement or polymer alone.

Liner/casing patches.  Various types of liners and/or casing patches on the market may assist in solving certain types of casing leak problems. They typically come in different lengths and can be permanently installed in the casing or incorporated as part of the tubing string.

Be aware that many liners or patches that are permanently installed will restrict the internal diameter of the casing across the interval where they are located. This can eliminate running certain types of tools through this interval in the future. If problems occur below this interval, it may be inaccessible for repair with standard tools.

Some patches that are run on tubing string incorporate sealing elements attached to the string at depths that will isolate the leaking interval. Some of these patches have vent tubes between the sealing elements to allow annular access for gas or treating fluids to pass through the patched interval; others do not.

When considering special equipment designed to assist with casing leak problems, consider the potential risk associated with running these tools in the hole. Also consider future uses or operations of the well and how these tools could have an effect.