Water Shut-Off in Gas Wells: Proper Gel Placement is the Key to Success

Abstract

Summary The objectives of water-shutoff treatments in gas wells suffering from water influx are to reduce water production and, at the same time, increase gas-production rates and producible gas reserves. Several field treatments, conducted under the umbrella of a research project focused on water abatement in gas wells, have demonstrated that a sequential gel/gas-injection technique in fractured gas reservoirs was successful in reducing water production and increasing gas production. Further efforts focused on improving gel placement in both fractured and matrix reservoirs to improve the treatment efficiency. Injectivity of the gelant was improved for injection into matrix reservoirs by either reducing the concentration of the high-molecular-weight polymer in the gelant formulation or by using a low-molecular-weight polymer. Gel placement was improved by displacing the gelant away from the near-wellbore region with semistable foam rather than with gas. Such displacement allows for improved gas production after the gel treatment. Laboratory-scale simulations were used to history match the coreflood results to calibrate the gelation and overdisplacement options in the simulations. Field-scale simulations demonstrated the merits of the proper gel-placement technique using a foam to displace the gelant away from the wellbore in matrix and fractured reservoirs. Optimized gel formulations in combination with the new overdisplacement technique provide a treatment alternative for combatting 3D coning situations. This overdisplacement technique can also minimize the startup problems experienced in fractured gas reservoirs after gel treatments. Introduction Gas production from waterdrive reservoirs often suffers from excessive water production. The influx of water into the gas well requires the gas to lift the water from the bottom of the wellbore to the surface. As the water influx increases, the pressure gradient required to lift the water up the wellbore also increases. This causes a decrease in gas flux from the reservoir into the wellbore; gas production decreases, and eventually the gas well stops flowing. The objective of this water-abatement research project will be to place chemical blocking agents in the gas reservoir to reduce water influx into gas wells, resulting in increased gas-production rates and ultimately increasing the recoverable reserves. One promising technique to block water propagation in situ is the application of polymer gels. An inherent risk with any gel application is that the flow of any fluid - oil, gas, or water - can be severely impaired. This necessitates the selective placement of the gel in the reservoir so that only the flow of water is impaired. Gas wells are usually perforated only at the top 1 or 2 m of the gas-producing formation. The short producing interval in vertical gas wells does generally not allow for mechanical isolation of the water zone. Therefore, the injection of gelant only into an isolated water zone is not possible unless additional perforations can be shot directly into the water-producing layer. In the latter case, the gelant could be injected directly into the water-producing zone and a protection fluid (gas or foam) would be injected into the gas-producing layer. The use of a protection fluid ensures that the gelant does not crossflow and inadvertently block the gas-producing zone. However, in most situations, the isolation of the water-producing layer and the gas zone is not possible or economical. Thus, a different gel-placement technique needs to be employed to selectively block the water from flowing into the wellbore. Dovan and Hutchins1 have advocated a sequential gel/gas-slug injection technique. Here the gelant is bullheaded (without isolation) into the wellbore. Before the gelant is allowed to set, it is overdisplaced from the near-wellbore region with gas. Dovan and Hutchins' laboratory experiments showed that the remaining in-situ gelant, after being overdisplaced with gas, had excellent waterblocking characteristics and did not hinder gas flow. Early field experience of this sequential gel/gas-slug injection technique demonstrated, approximately, a 30% success rate. By improving the selective placement of the gelant in gas wells, the success ratio of the field applications should be increased to the point at which this water-shutoff technique is routinely implemented by gas-producing companies with water-production problems. The overall research project consisted of three focus areas: laboratory investigation, simulations, and field applications. In the laboratory program, gel evaluation studies were conducted first, followed by coreflood experiments in Berea cores, in carbonate packs, and in fractured cores. Using gas to overdisplace gelant from the core during our linear-coreflood experiments was not an efficient technique because the gas fingered through the core very early on. It was not surprising that the remaining gel blocked both water and gas. Our experiments did not demonstrate the same degree of selective water-over-gas blocking as the Dovan and Hutchins 1 experiments showed. New coreflood experiments were conducted in which the gelant was displaced out of the core with a more efficient displacing agent, such as foam. The simulation component focused on two areas. The first task was to simulate the laboratory-scale experiments in which gas and foam were used to overdisplace the gelant. The second task was to simulate a field application of the sequential gel/gas process. In the field-scale simulations, a gas well that suffered from bottom-water influx was modeled. The field-scale simulations, carried out on matrix- and fractured-reservoir-scale simulations in the matrix reservoir, compared the outcome of four cases:no treatment,gel treatment with no overdisplacement,gel treatment with gas overdisplacement, andgel treatment with foam overdisplacement. Successful field applications of the sequential gel/gas-injection process for water control have been conducted in both high-pressure2 and low-pressure fractured gas reservoirs. However, the startup period for these wells, immediately after the gel treatment, can be problematic. It may be necessary to install gas lift, or the well may have to be blowndown to remove excess water before the well starts to produce gas on its own. Several field trials have been conducted on coning situations in sandstone reservoirs. The success of our gel treatments in matrix formations has been very limited because of various factors. p. 217–227

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