What's new in production

This month, we turn our attention to injection wells, which, of course, have a direct or indirect effect on production maintenance and ultimate hydrocarbon recovery. But injection wells don’t often get the tender loving care afforded to production wells. Even more neglected are water disposal wells. But they, too, can be of crucial importance in maintaining commercial oil and gas production. 

Enhanced oil recovery (EOR) injection operations are very common. Secondary recovery methods, such as waterflooding or gas injection (e.g., CO2), are mature applications. Tertiary oil recovery methods, such as with surfactant or polymer injection, have also been in practice for decades.  

An injection well may, at first, and for some time, have an injection profile indicating effective fluid entry across the full injection interval. However, the profile may degrade over time, such that fluid enters only a very limited portion of the interval, or into a thin, single “thief” zone, bypassing recoverable oil. Also, skin may build up in an injection interval through inadvertent introduction of solid debris, oil carryover, or scale formation, among other possible damage mechanisms. Stimulation is then required, but it can be challenging, because coverage of the desired interval may be difficult to achieve, or because those portions of the zone not accepting injectant appreciably must be isolated and selectively stimulated.   

To conduct profile modification or stimulation operations in a water or gas injector requires shutting the well in. But shutting down injection can have an immediate negative effect on production. Shutting in a water disposal well for a stimulation treatment can require cutting back on production or even shutting in production wells, as water disposal sometimes barely keeps up with water production. There are also uncommon cases in which a certain level of water injection must be maintained in a field to prevent subsidence.  

So, why not modify injection profile or stimulate injection during injection? Such a notion is readily dismissed, but there are viable approaches to profile modification and injection zone stimulation without having to cease injection operations at all.  

Profile modification during injection. Profile modification is typically achieved through selective stimulation within an injection interval, but that only modifies profile near the wellbore, not deep in the reservoir. Plus, it requires special treatment placement tools which may not be practical or economic. Deep profile modification (conformance) for reservoir sweep efficiency improvement is attempted with polymer injection or even cement methods in extreme cases (e.g., to close off fractures or faults that are “short circuits” from injectors to producers). Injection of polymer, which is viscous, diverts flow of injectant to portions of the reservoir that are not being contacted sufficiently. However, such operations are long-term endeavors and often require special equipment and even facility modifications. Polymer injection can be especially challenging offshore, where space for necessary equipment and chemical storage can be very limited.  

A means to profile modification during injection can conceivably be accomplished with relative permeability modifier (RPM) application. RPMs are modified polyacrylamide polymers of moderate chain length (much shorter than EOR polymers). They adsorb onto sandstone formation minerals, creating very highly water-wet surfaces, thereby increasing resistance to water flow while enhancing hydrocarbon flow. A well-designed RPM also will expand in a water environment but not in an oil or gas environment, so that water flow is additionally blocked, at least partially, but not at the expense of hydrocarbon production. There are specific RPMs that are effective in both sandstone and carbonate formations. In carbonates, the mechanism is not through water-wetting the rock surfaces, but through the formation of microgels within water-filling pores or natural fractures that will restrict water flow relative to oil or gas flow.  

However, applications of RPMs for water control in oil or gas producers have long since been the target of skepticism, and rightfully so. While there are many cases of successes, high-water-cut well candidates must have specific properties conducive to RPM treatment effectiveness. Most wells do not qualify, such as those in which water and oil production are fully commingled. Unfortunately, misunderstanding of the proper applications and skepticism has led to limited commercial availability of RPM products these days. But they are out there.   

What about considering RPMs for injection wells? RPM can be added directly to the injection water stream in appropriate concentration, entering and treating the paths of least resistance, and modifying profile as injection proceeds without interruption. With employment of distributed temperature sensing (DTS) fiber downhole, changes in the injection profile during treatment can be monitored in real time, and RPM injection can be terminated at any point, depending on what is observed. RPM injection can be periodically resumed, or “turned on and off” to deliver RPM “rings” extending deeper in the formation, again while monitoring profile in real time via DTS to avoid excessive treatment.   

Stimulation during injection. This notion realistically applies to injection or disposal wells completed in carbonate formations or in formations containing significant carbonate mineral content. This is because the application utilizes hydrochloric (HCl) acid, and only carbonate minerals react appreciably to HCl.  

An application proven in a field in Indonesia over a decade ago serves as an example of successful stimulation during injection. In that field, wells produced oil and gas from a naturally fractured limestone. Many of the wells produced at high water cuts, because the fractures extended downward into a water zone. To maintain commercial production, water disposal was required and total field injection rate had to keep up with field water production rate. If water disposal rate in any particular well declined for any reason, one or more producers were choked back so that water production would not exceed injection capacity. In practice, stimulating a water disposal well required that it be shut in while being treated with HCl. That also required shutting in one or more producers, which was most undesirable and could be detrimental to producers. 

So, to address that situation, an experimental treatment was conducted in which a concentrated solution of 25% HCl containing corrosion inhibitor was metered into the injection line at a rate, such that when diluted in the injection stream, it would yield 5% HCl with the proper concentration of corrosion inhibitor downhole. With continuous injection for several hours, injection rate was increased to a target level that prevented cutting back or shutting in any of the producers. While this was a one-off treatment, it was a relatively simple and inexpensive method that could have been repeated periodically as needed.  

In general, that application represents a stimulation method in which the volume of acid (or other reactive fluid) can be controlled to only that which is needed to reach a target injection rate. For unconventional operations, in which water disposal is becoming an increasingly challenging issue, either because of increased water production or limited disposal well availability, this method for stimulating water injection during injection could surely be considered.      

About the Authors

Leonard Kalfayan

Contributing Editor

Leonard Kalfayan has 42 years of oil, gas and geothermal experience. He has worked for Hess, BJ Services, Unocal, and as a consultant. He is an SPE Distinguished Lecturer and Distinguished Member. He has authored numerous publications, and also holds 13 U.S. patents.