In this paper we describe a novel method for water unloading of natural gas wells in mature reservoirs experiencing low reservoir pressures. Current methods for water unloading from gas wells have at least one of the drawbacks of restricting gas production, requiring external energy, using consumable surfactants, or being labor intensive. The proposed design offers a new approach to water unloading that does not restrict or interrupt gas production. It can operate without external energy, and uses no consumables. Virtual and physical simulators have been developed and the full-scale version of the concept has been studied in test wells to demonstrate the feasibility and performance of the new water-unloading concept. An industrial-grade preproduction prototype was tested successfully in a test gas well to validate this study.
Several methods for unloading water from gas wells have been used in the industry. These methods commonly have a combination of the following characteristics: a) they use external energy, b) they use consumables, and c) they restrict gas production. This paper presents a new approach to water unloading that does not restrict or interrupt gas production, can operate without external energy, and uses no consumables. Physical and software simulators have been developed to demonstrate the feasibility of the new approach and to configure the approach for various well characteristics.
Water enters most gas wells. At the early stages of production the gas pressure is sufficiently large to lift the water that enters the wellbore. Gas and water mist flow to the surface where the water content is easily separated from gas using separation equipment. As the production of the well continues, the reservoir pressure drops to the point where water can no longer be lifted to the surface by gas flow. This results in the accumulation of water in the bottom of the wellbore, sometimes reaching a height of several thousand feet. In such situations well production stops and the only remedy is water extraction (unloading) by means of conventional pumping, which is prohibitively expensive.1-4
In the last several decades several other methods to unload water from gas wells have been devised to avoid water pumping. These methods utilize the gas pressure for lifting water out of the wellbore. The most popular methods are:
a) Velocity Strings: Reducing the diameter of well tubing to increase flow velocity and hence lift water mist all the way to the surface. This method naturally reduces production rate due to restricted flow area and increased friction and fails as soon as the gas pressure drops again below some critical point.5
b) Foaming Agents: Use of surfactants such as detergents (e.g., soap) to reduce the Interfacial tension between fluids by creating foam which let the gas to go through more easily. This method uses consumable material and hence can be operationally expensive.6
c) Plunger Lift: Use of plunger lift, which is based on a method of intermittently shutting in the well to let the gas pressure build up to a level which would make water lifting possible, and then sudden opening of the well top to allow the departure of high pressure gas and water mix. In order to be able to push the water column up a solid cylinder, or "plunger??, is used. This cylinder acts as a barrier between the gas and liquid and moves up and down with every opening and closing of the well. Because this method works intermittently it requires frequent shut-down of the well flow, which results in reduced overall production.7,8
d) Several other methods are less commonly used, such as gas lift, etc.
The CWC Method:
The new method benefits from the fact that a great portion of the water which returns to the well bottom is actually the result of the condensation of water vapor and consolidation of water mist in form of larger droplets in the upper segment of the well (upper 3000 foot segment) where the temperature is much reduced. Traditional methods allow for return of this condensed water to the bottom of the well, thereby losing all the valuable potential energy that has already been put into the water by gas-lifting it to those higher elevations.
This paper presents a comprehensive simulation study demonstrating technical merits of automatic intermittent and distributed heating for reducing back pressure and maintaining flow in low pressure gas wells.
Reduction or elimination of the additional wellbore backpressure plays a key role in boosting gas wells productivity and extending the lifetime of the field. The backpressure is mostly due to the development of excess liquid water along the tubing stopping the low pressure gas flow. We present two-phase thermal flow simulations to study the impact of intermittent volumetric heating along the wellbore to reduce or eliminate the excess backpressure caused by either water condensation in the upper part of the wellbore, or the overall increase of density of the two-phase fluid. The proposed method helps in continuous prevention of the excess water development enabling the well to produce without interruption up to its natural limit.
Modeling the thermal exchange in the wellbore, two-phase flow pressure simulation demonstrates that flowing and thermo-dynamic conditions of the water/gas mixture along the wellbore have a substantial impact on the overall backpressure. Our results show that by modifying the thermal profile of the wellbore fluid at specific locations and times, we can maintain significantly lower backpressures and increase well productivity. Our case studies highlight that for very low pressure gas wells, the external power requirements can be more acquiescent to automation and control than the existing methods.
The results yield valuable insight in the development of a novel liquid unloading techniques based on volumetric heating of the wellbore fluid. Our results can also be applied to the elimination of hydrates in gas wells.
This paper presents the results of a dynamic modeling approach for prediction of the critical rate to unload stripper gas wells. Methodologies in the literature such as the ones by Turner et al1and Coleman et al predict critical gas rates by using force balances based on bulk properties of the liquid and gas column. Using a one-dimensional modeling of two phase flow in a vertical column, we are able to incorporate the phase behavioral effects caused by temperature and pressure changes affecting fluid density and localized conditions of liquid droplets demonstrating a more accurate way to predict critical gas rates.
The dynamic prediction model allows incorporation of the formation depth and pressure, temperature gradients and tubing size. Gas composition ranges from dry gas to rich gas with potential for condensate formation. The model allows mapping and tracking the phase behavior conditions after flow stoppage under the condition of low gas rate and predicts the energy requirement to partially lighten the liquid column and resuming gas flow.
The liquid loading arises when gas reservoirs become depleted and the bottom-hole pressure is not sufficient to lift the whole gas-liquid column up to the surface. Over the time, the liquid accumulation inside the wellbore may produce a hydrostatic backpressure on the reservoir resulting in cessation of flow.
Liquid loading is often detected by a sharp drop in the gas production rate, significant changes on gradient surveys, liquid slugs production and an increase of the difference between the casing and tubing pressure with time. There are cases in which that the liquid loaded wells may produce for a long period of time without any advance warnings and suddenly experiencing a major drop in well productivity.
As discussed by Lea and Nickens several remedial methods have been introduced as a solution for water unloading, each having its own limitations. Some are based on continuous removal of water such as velocity strings; application of surface active agents and some other mechanical removal techniques such as plunger lifts are based on intermittent removal of water. The main limitations of theses techniques are the cost, loss of production, dependency on gas flow and the temporary nature of the remedial solutions.