By Petroleum Technology Transfer Council

Automated casing swab pump increases marginal gas well production

In stripper gas wells, a new de-watering pump technology has realized increased gas revenue – in one case, more than $50,000 over eight years from just one well.

John Holko, Lenape Resources, Alexander, New York; P.M. Yaniga , Brandywine Energy and Development Co., Frazer, Pennsylvania

A new pump developed by Brandywine Energy and Development Co. (BEDCO) has performed satisfactorily and increased gas production from the 3,000-ft-deep Medina formation tight-gas sandstone in New York. The tool lifts 0.5 to several barrels of brine per day and has, in six wells, increased gas production 1.5 – 3.0 times that produced with previous, standard, mechanically operated casing swabs and periodic swabbing with a workover rig. One well, Lenape's Well-52, has used the tool since late 1996, and has realized more than $50,000 of increased gas revenue since installation.

THE PROBLEM

Among stripper gas wells, data reveal that brine accumulation is the primary reason for declining natural gas production and oftentimes subsequent well abandonment. Just a few tenths to a few barrels per day can and does kill gas production. Conventional fluid removal techniques using beam pumps, periodic swabbing of fluids with workover rigs, siphon strings and tubing plungers or rabbits have both physical limitations and significant capital, operating and maintenance cost considerations. Regular, rhythmic removal of fluids as they accumulate in the well increases gas production. Averting a brine column and a brine-wet zone in the production horizon fosters the ease of movement of gas into the well.

AUTOMATED CASING SWAB

The new pump, named Gas-Operated Automatic Lift (GOAL) PetroPump, has a unique “on-tool” actuator-valve assembly. The tool is designed to freely operate within the well casing, descending downhole when wellhead pressure and production drop. Upon descending into the fluid, afforded by a through-tool passageway, a fixed column or weight of fluid accumulates atop the tool that offsets the preset actuator pressure, and the valve automatically closes.

Flex wall cups surround the tool and actuator body and make a circular seal with the well. Additional pressure and gas accumulating in the well below the tool build and lift the tool and fluid load to the surface. On reaching the surface, the fluids are pushed ahead of the tool and processed off the topside of a wellhead lubricator. Follow-on gas production is produced from below the tool on a bottom side port in the lubricator.

The tool is “smart” in both directions, in that the tool, upon ascending the wellbore to the wellhead lubricator, does not have to latch into a wellhead catcher to await physical release by man, clock or other mechanical device. The on-tool actuator valve assembly senses tool pressure, and at such time as wellhead pressure declines to within a preset limit of sales-line pressure, the actuator opens. The tool then again descends for another load of fluid.

TOOL EVOLUTION AND GENERAL FIELD EXPERIENCE

The tool (Fig. 1) has evolved significantly through a multi-year development and field-testing process. The original tool was more than 6-ft long, weighed over 100 lbs and had more than 60 components. The current fourth-generation convertible-tool design, which can accommodate 4-in. or 3-in. ID casing and/or tubing, has just 14 components, is only 38-in. long and weighs less than 45 lbs. Metallurgical upgrades from carbon steel to stainless steel and Hastelloy (a proprietary alloy) largely eliminated corrosion problems, and elastomer modifications have proven effective in reducing wear. The convertible tool now being tested will broaden the tool's application environment, since tubing wells with new 4-in. and 3-in. materials will not present the irregularities of older cased wells. BEDCO is researching the use of non-metallic, continuously spooled casing and tubing to further reduce lift lost.

Fig. 1. GOAL PetroPump tool evolution. Most recent model is on the right.

Required wellhead modifications include a full-port ball valve to allow passage of the tool and, atop the full-port valve, a lubricator to allow top end (above tool) takeoff of fluids, and bottom end (below tool) production of post-run gas. A top-of-lubricator catcher for periodic tool retrieval for cup replacement and/or actuator adjustment has also been developed. Actuator operation can be changed or reset by the removal of only one tool component: a top-end catcher rod. Cups can be removed and changed by the removal of just two components: a lock nut and washer. Periodic tool service and adjustment can be achieved using two 18-in. adjustable wrenches. Field testing and pumper input have led to a physical configuration comprised of standard field threads, wide flats and easily accessible key components.

The gas/fluid ratio for the current tool is about 3 Mcf/bbl per tool cycle. Pressure differential to move the tool within the well is about 12 psi in conventional steel casing. Data demonstrate the tool is capable of lifting 0.1 barrels to as much as 40 bbl of fluid per cycle, but normal operating range is 0.25 – 6.0 bbl per tool cycle. Cup life on the tool has proven to be greatly extended over conventional tools and cups due to the regular pressure-lift cycling and exertion of uniform forces on the cups. Cup life on some wells now exceeds six months.

FIELD RESULTS

Lenape Resources used the initial and successor tools in Well 52, a 3,200-ft Medina formation completion in New York drilled in 1986. Well 52 has 4.5-in. J-55 casing. It produces through a horizontal wellhead separator into a gas gathering system, with pressure ranging 50 – 100 psi. Recent wellhead shut-in pressure is about 120 psi. By late 1996, the producing method had evolved from unassisted flowing, to a 1-1/2-in. tubed well that was periodically soaped, shut-in and vented to a standard 4.0-in. casing swab that was mechanically/ physically dropped and operated.

The tool was installed in September 1996. Annual production before tool deployment was about 1,100 Mcf/year. Production since tool installation has averaged 3,416 Mcf/year, Fig. 2. It is significant that gas production may be under-reported, since after tool installation, the analog production charts after a tool run spend 15 – 45 min. off chart representing 0.5 Mcf/day to 1 Mcf/day of unmeasured gas. With current costs of the tool excluding installation and additional equipment set at $11,500, payout was achieved in eight months and return on tool investment over the five-year period has been more than 60% IRR. Total additional value above the base production is about $52,000. The tools have been reliable, lifting about 1 – 1.5 bwpd in 0.25 – 0.5 bbl/cycle. This is about a three-fold improvement over standard casing swabs that were previously used. Table 1 shows results for other tight Medina wells. Production multiples in these other wells are also economically attractive. Although results are for gas wells, it should be noted that the tool could also be used in oil wells that have associated gas production.

Fig. 2. Annual gas production from Lenape Well 52, before and after tool installation.

A LESSON LEARNED

Casing integrity and uniformity are paramount for successful use of the tool. Well preparation requires scraping the well casing and/or tubing to assure absence of blockage (salt/ paraffin or other), or any significant deviations within the casing that would not allow free travel of the tool. This casing challenge has fostered development of the convertible tool for use in tubed wells.