Artificial lift

Foamer Technology Optimizes Artificial Lift in the Alliance Shale-Gas Field

Recently, Quicksilver Resources and Eni E&P, through its subsidiary Eni US Operating, began a common effort to optimize production and lift costs in the Alliance shale-gas field in the prolific Barnett shale play in Texas.

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Recently, Quicksilver Resources and Eni E&P, through its subsidiary Eni US Operating, began a common effort to optimize production and lift costs in the Alliance shale-gas field in the prolific Barnett shale play in Texas. Such efforts included a deeper analysis of artificial-lift performance and exploitation of other deliquefication technologies. Previously, foaming agents had been seldom deployed, but now a comprehensive assessment of their technical and economic performance has been conducted.

Introduction

Hydraulic fracturing is the key technology in unlocking production of shale-gas wells. The production of huge amounts of pumped water affects the life of a shale-gas well; the first phase and dewatering methods have to be considered as crucial aspects of a shale-gas development. In fact, as a consequence of reservoir depletion, the gas rate decreases to a point at which the water cannot be transported out of the wellbore and starts to accumulate.

Methods such as gas lift and plunger lift and the use of smaller tubing diameters, pumps, and foaming agents are commonly adopted to control this situation. Foaming agents do not need downhole modification, can be tested easily on existing wells and facilities, and are chemically compatible with corrosion inhibitors, so the same injection points and devices can be used.

Shale-Gas Production Wells and Liquid Loading: Alliance Field. As of March 2012, gas production for Alliance is approximately 176 MMcfD. The field counts more than 200 wells spread over an area larger than 65 km2 and clustered in more than 60 well pads, each enclosing a variable number of wellheads. Most wells are horizontal and packerless, with a vertical depth of approximately 7,400 ft, and are stimulated by hydraulic fracturing.

To stimulate the entire lateral length, hydraulic-fracturing treatments are performed by isolating smaller portions of the lateral, called stages. The number of stages depends on the length of the horizontal drain and the spacing of each treatment. In the Alliance field, a spacing of approximately 400 ft is usually considered, with up to 20 stages. For each stage, approximately 10,000 bbl of water is injected, so a typical well of 6,000 ft of horizontal length with 15 stages implies a water volume close to 150,000 bbl. Almost all the wells have gas lift valves (typically 9 to 12), with the last one set at the deepest injection point in the tubing.

During the first development phase of the field, lift gas was fed by a multistage gas compressor installed at the well pad. At the beginning, the well produces through the annulus [outer diameter (OD) of 5.5 in.], with a gas-production peak of 4 MMcfD and a water production between 1,000 and 2,000 B/D. As the reservoir pressure decreases and gas production drops to approximately 2 MMcfD, production is switched to the tubing to increase flow velocity.

Finally, as a consequence of gas-rate reduction below the critical lifting rate—usually approximately 1 MMscfD for a 2.375-in. tubing per Alliance experience—the well starts to load and gas lift injection is performed. A production profile for a well with a lateral length of 3,000 ft and 2.375-in. tubing is shown in Fig. 1.

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Fig. 1—Production profile for a well with a lateral length of 3,000 ft and 2.375‑in. tubing.

 

Use of Foamer To Reduce Gas Lift and Increase Gas Production. The multiphase-flow behavior in a vertical conduit is categorized through several basic flow regimes. A gas well with high rate (high velocity) is able to continuously lift liquids to the surface in an annular mist-flow regime. Tubing walls are coated with a liquid film, but the pressure gradient is determined predominantly by the gas flow. With decreasing gas velocity, the flow regime becomes a slug annular transition flow. Further decline of the gas production causes the slug-flow regime, where gas bubbles expand as they rise into larger bubbles and slugs. Liquid transported with these slugs can fall back in the wellbore and increase the pressure gradient.

A gas well in this situation can still produce a high amount of gas as long as there is enough energy provided by the reservoir to lift fluids, but production may become unstable and a small increase in the backpressure can kill the well. If no actions are taken when the well reaches the bubble-flow regime, the fluid column in the wellbore builds up until the liquid hydrostatic head kills the well, completely stopping production.

Foamers reduce the critical velocity by changing the physical properties of the liquid being transported: The surface activity of the foamer reduces the surface tension of the liquid, facilitating the dispersion of gas bubbles in the liquid and thus decreasing the overall liquid density.

Field Trial: Surfactant Application by Continuous Injection. The first candidates for the foamer application have been selected from wells with a water production of less than 50 B/D. If the wells were already treated with lift gas, the goal of the application was to reduce the artificial-lift costs, perhaps while increasing the net gas production; for candidates where gas lift was not available, foamer injection was tested to obtain a better water recovery and to optimize well performance. For wells without a production packer, the foamer has been pumped continuously into the tubing/casing annulus through a chemical-injection line already installed for antiscale and anticorrosion treatments. This method is very flexible and inexpensive, requiring at the surface only a chemical-injection package consisting of a surface pump and tank. In wells with a production packer, a capillary string has been introduced into the tubing. Capillary strings are very small stainless-steel tubings, with an OD of 0.25 in. for Alliance field application, installed with a slickline truck down to the desired depth. This solution is more expensive, but it has the advantage of applying the optimum dosage of foamer at the optimum downhole injection point.

Field Trial: Preliminary Laboratory Tests. To select the best product and dosage for foamer candidates, multiphase software and laboratory tests with different foams and field-produced fluids were used.

The two standard test methods performed for measurement of foam and evaluation of surfactant included the foam-in-aqueous-media test (blender test) and the column/cylinder test (dynamic test). Liquid samples have been dosed with different concentrations of surfactants and put into a 1-L measuring cylinder. In the blender test, the solution is placed in the unit and foamed by the high-shear blender, while in the column test, a gas source is used to reproduce field conditions. The goal of these tests is to provide information about the maximum height of foam and the time it takes for that maximum height to collapse.

Field tests are also performed. In this case, 100 mL of produced water is added with different foamer concentrations with the aim of optimizing the dosage: The starting point is usually 1 ppm, increased to 2,000–10,000 ppm according to gas characteristics. The fluid is then put in a 1000-mL graduated cylinder, and a rotometer is used to add a flow of gas. Displaced foam and liquid are collected through a discharge tube into a 500-mL graduated cylinder, and the time required for the foam to reach the maximum height is recorded. Foam and liquid are collected in the 500-mL graduated cylinder until the liquids no longer flow from the 1000-mL cylinder. Foamer products are evaluated by the time taken to complete the test, the volume of fluids removed, foam density and bubble-size characterization, emulsion tendency, and water/condensate dispersion.

Well 1: Annulus Foamer Injection and Gas Lift. The well has a lateral length of approximately 2,100 ft. The completion is packerless, with 2.375-in. production tubing and 10 gas lift valves. Before the foamer test, it produced close to 300 Mcf/D of net gas, with a water production of 15–20 B/D and a lift-gas rate of approximately 500 Mcf/D. Foamer was injected into the annulus at an initial rate of 6 gal/D and optimized to 4 gal/D. During the treatment, the gas lift rate was reduced progressively to 25 Mcf/D, with no changes in water recovered and a benefit in gas net production since the beginning of the treatment of approximately 50 Mcf/D. Operating-expense (OPEX) results were also positive: the average reduction of OPEX in the period was approximately 15%.

Well 2: Annulus Foamer Injection, No Gas Lift. This well has a lateral length of approximately 2,300 ft. It has been completed with a 2.875-in. tubing with no packer; gas lift valves have been installed. Before the foamer treatment, gas production was approximately 500 Mcf/D with a water production of 10 B/D. Foamer injection started at a rate of 6 gal/D, then was optimized to 4 gal/D to sustain production, helping the well deliquefication. The injection of chemical in this case caused an increase in the OPEX, because before foamer treatment, the well was treated only with a less expensive injection of anticorrosive and antiscale products.

The results in terms of production, however, were positive, with an average gas-production increase of 130 Mcf/D.

Well 3: Capillary-String Injection. This well has a lateral length of 2,600 ft with no packer. It has been completed with a 2.375-in. production string and 12 gas-lift valves. In this case, foamer was pumped through a 0.25-in. capillary string installed to the tubing bottom, at the lowest possible injection point. Before the treatment, well performance was rapidly declining because of the inability of the well to produce water despite a gas-­injection rate of approximately 400 Mcf/D. As soon as the foamer injection started, gas and water production were re-established, and gas injection could be reduced to less than 100 Mcf/D. The average gas net increase from the beginning of the treatment was approximately 80 Mscf/D, with an average gas lift reduction of 360 Mcf/D that caused a 57% OPEX reduction.

Conclusions

Foamer technology was implemented in the Alliance field in several ways, achieving generally positive outcomes. For this reason, foamer deployment has been progressively extended to approximately 30% of the wells. Since the beginning of the application, an average net gas-rate increase of 5.7 MMcfD has been observed, with a lift-gas-rate reduction of approximately 10 MMcf/D. Foamer injection offered an OPEX savings of approximately 13% owing to gas lift reduction and good deliquefication performances, often resulting in a production increase.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 160282, “Artificial-Lift Optimization With Foamer Technology in the Alliance Shale-Gas Field” by Lisa Farina, Claudio Passucci, Alberto Di Lullo, and Emanuele Negri, Eni; Osvaldo Pascolini, Eni US Operating; and Shawn Anderson and Stan Page, Quicksilver, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8–10 October. The paper has not been peer reviewed.