Installing capillary tubing and injecting deliquification chemicals can restore production to a liquid loaded well in just a few hours. (All figures courtesy of BJ Services)

Liquid loading is the final stage in the productive life of a gas well. Liquid, as produced water and condensate, builds up in the well bore. Production becomes intermittent and eventually stops because the gas cannot overcome the hydrostatic pressure of the liquid in the well bore. Artificial lift methods extend the productive life of the well by helping to remove the liquid from the well bore.

Understanding the well, the reservoir, and the mechanics of liquid-loading are keys to selecting the most efficient and economical solution to a liquid loaded gas well production problem.

Drowning a well

The phenomenon of liquid loading is governed by the critical velocity of gas flow. If the gas flow rate is high enough, the gas stream can carry water droplets out of the well. Over a well’s producing lifetime, the formation pressure is depleted, reducing the gas rate below the critical velocity. At the same time, water production may increase.

These factors lead to a build-up of water in the well bore, which causes three problems:
• The hydrostatic pressure of the liquid in the wellbore restricts gas flow to surface. This stage typically manifests as slug production: Formation gas builds up to some critical pressure, allowing a slug of gas to escape through the water before the pressure drops below the liquid hydrostatic head and starts the cycle again. This surging pattern delays the operator’s return on investment. It may also loosen formation fines that can plug pore throats and further reduce or block gas production.
• Eventually, the back-pressure on the formation will prevent the gas from reaching the well bore, and production will cease.
• If the liquid seeps into the formation, it can cause water blocks that may remain in the formation, preventing gas flow, even if the well bore is cleared.

For these reasons, it is critical to analyze and treat a liquid loading problem as early as possible. Early awareness of an impending liquid loading situation allows the operator to implement a remedy with minimum loss of production. Typical mechanical solutions for liquid loading include plungers and downhole pumps. These involve both capital expenses for installation and operating expenses to maintain them. In offshore aging wells, gas lift is often used to assist in lifting. Gas is injected downhole through special pre-installed gas mandrels. The injected gas serves to maintain the critical velocity above that required to lift the liquid. Typical chemical solutions include batch or continuous injection of deliquification surfactants designed to reduce the surface tension of the liquid. This, in turn, allows gas entrainment and an effective reduction in liquid density. The critical velocity required to lift the liquids is reduced, allowing the well to return to continuous flow.

Some of these solutions are expensive in terms of initial capital expense and ongoing operating and logistics costs. The ideal solution is to minimize the total remediation cost while maintaining or increasing gas production. For these reasons, more than 10,000 wells around the world use capillary strings to deliver chemicals directly to the perforations to treat problems such as liquid loading and solids deposition. For liquid loading applications, this technology has a lower capital expense than pumps and requires less maintenance. It is more efficient than plungers in that the production is steady and not intermittent. It is more cost-effective than gas injection because it uses the energy of the well rather than external energy sources to lift the liquids. Finally, by injecting deliquification chemicals with other critical inhibitors via capillary tubing, other problems such as scale and corrosion can be treated simultaneously.

Choosing a solution requires a thorough understanding of the well condition. Gas production can drop for many reasons. Some investigation is required in order to ascertain the cause of the liquid loading and to select an appropriate artificial lift solution. Incorrect diagnosis of a well’s condition can lead to unnecessary and expensive interventions.
In the worst case it can lead to premature plugging and abandonment (P&A).

For example, a steady decrease in gas production with increased water production may signal the development of scale deposits in the perforations or tubulars rather than liquid loading. Sudden water breakthrough can also reduce production by causing formation fines to migrate into pore throats and perforation tunnels. Similarly, the slug production that typifies the beginning of liquid loading may also be a sign of a plugging problem such as a salt block in the tubing. Understanding field and well conditions is critical to choosing an economical artificial lift solution.

Liquid loading in Indonesia

When production dropped in a mature Indonesian gas field, the operator asked BJ Services to recommend economical ways to reverse that trend. BJ Services used the proprietary FoamXpert software to analyze the wellbore geometry and production data for 50 of the wells in the field. The software is designed to determine if a well is suffering from liquid loading and, if so, to determine if the well is a candidate for continuous injection of deliquification chemicals through a capillary string. As a rule of thumb, wells with high water production (more than 15 bbl/100 Mcf produced) are not good candidates for surfactant injection. These wells require alternative, e.g., mechanical, artificial lift solutions.

The software determined that 29 wells were liquid loading and 27 were good candidates for capillary chemical injection. To test the software choices, the operator chose to install capillary strings in nine of the “good candidate” wells and seven “control” wells that the software did not select. In order to complement the capillary installation with the proper chemical program, the service company performed blender tests to determine which surfactant provided the best foaming in the produced liquids.

Over the first year, production in the nine good candidate wells increased by an average of 122 Mcf/d per well. Production in the seven “control” increased an average of 12 Mcf/d per well.

Subsequently, the operator installed capillary tubing and chemical injection systems on 35 additional wells using the guidance of FoamXpert software. This increased the field-wide production by 10 MMcf/d without installing any downhole pumps or plungers. At US $7/Mcf for gas, the operator saw a revenue increase of $70,000/day. The return on investment (ROI) for the capillary and chemical was measured in hours of production.

Tight rock in Texas

Under similar circumstances in northeastern Texas, the service company worked with a number of major and independent operators to improve production in a mature tight gas field. Working in Panola and Rusk counties, the service company identified 400 wells that would most likely respond to continuous chemical injection to solve liquid loading problems.

For each well, the service company installed a capillary tubing string down to the perforations. A chemical tank and pump were set on the surface. Installations were done under live well conditions and did not interrupt production. Each installation took approximately three to four hours with a two-person crew and one truck. No workover was required.

For the initial 400 wells, production increased an average of 320 Mcf/d. The payout for the capillary system was achieved in an average of 37.6 days. As a result, the operators requested more than 1,000 additional systems in the area.

Offshore loading

In the final example, a valuable Gulf of Mexico gas well was experiencing problems with liquid loading. It produced in cycles of two to four days of production followed by a two-week shut-in to allow a gas head to build for another cycle. To improve production efficiency, the operator decided to deploy a capillary string to deliver foam to the perforations. The operator considered using gas lift, but there was insufficient gas available on the platform.

There is a significant challenge in running capillary offshore compared to an onshore installation. A surface-controlled subsurface safety valve (SCSSV) is required offshore, whereas this is not the case for most onshore wells (although land wells near urban areas that have high H2S content often require an SCSSV). Traditionally if capillary was installed offshore it was run in the casing/tubing annulus. This would either require an initial installation or an expensive workover. With a depleted well an operator typically will not invest capital for a workover to install a capillary string. In this case the operator chose to run the patented InjectSafe wireline-retrievable SCSSV, which provides an integral capillary tubing flow path by seating in an existing tubing-retrievable SCSSV or hydraulic nipple. Chemical is applied internal to the tubing through a capillary system that does not violate the integrity of the flapper valve in the SCSSV. This is done at a fraction of the cost of a workover to install capillary in the annular space.

The operator also needed a safe

and economical means of hanging the capillary tubing without affecting the lower master gate valve. That valve provides a critical second barrier (mandated in all offshore and in some land wells) when rebuilding upper tree components. Instead of running the capillary through the lower master, as is typically done on land wells, the new patented InjectSafe Wellhead Adapter allows the capillary tubing to be hung off below the tree with full function of all of the tree valves.

In a four-day (daylight only) operation in early December, BJ installed an InjectSafe system and 12,475 ft (3,805 m) of capillary tubing in the operator’s well. Foam injection began immediately, and the well has been producing gas steadily with no shut-ins, improving time to market and reservoir depletion efficiency. A well that had been an intermittent and low producer, less than 100 Mcf/d, now produced steadily at 1.3 MMcf/d.