By Petroleum Technology Transfer Council

Using capillary strings to unload gas wells and increase production

Field results show capillary strings used in the proper application are successful in combating liquid loading

 Robert Lestz, ChevronTexaco, Houston, Texas

 ChevronTexaco has successfully employed capillary strings in South and East Texas to resolve problems associated with liquid loading. ChevronTexaco now has more than 100 installations. Detailed analysis of the initial 17 installations in South Texas revealed a 74% success rate. Installation costs will pay out in less than three months with representative gas prices and production increases (of about 100 Mcfd). 

  CAPILLARY STRINGS

 Capillary strings are 1/4- or 3/8-in. stainless steel tubing run inside existing tubing or casing. They are run into the well under pressure in a method similar to running coiled tubing into a live wellbore. Strings are typically run through the tubing and into the casing to either the top perforation or into the perforations. The bottomhole assembly consists of a perforated nipple and check valve on bottom. They can be run to depths exceeding 20,000 ft. Chemicals are either siphoned by gravity or pumped through the capillary string. 

 Applications include: foaming water production to assist unloading of gas wells, effective placement of corrosion/scale inhibitors, preventing salt blocks via continuous injection water and inhibiting the formation of paraffins.

 Future applications being investigated include improving gas lift efficiency, reducing electrical consumption on electrical submersible pumps and enhancing the performance of plunger lift.

 Benefits when used for foaming water production include: incrementally higher recoverable reserves, increased or stabilized production, reduced downtime (minimizing the need to soap, flare or intermit), improved gas measurement, improved system dynamics (eliminating competition between wells) and reduced reservoir damage from fines migration, cyclic loading and relative permeability effects. 

 From an operational standpoint, capillary strings require less manpower. Routine tasks can be eliminated, allowing personnel to focus on other operational issues. Stable operations improve compressor run times. These benefits do require some time for maintaining chemical injection and there are daily chemical costs.

 Wells that are experiencing liquid loading problems, primarily due to water, are ideal candidates for a capillary string. Liquid loading problems can be identified by changes in production rates, erratic production, differences between the tubing and casing pressures (with open-ended tubing), positive responses to soap sticks or batch treatments, or wells producing below the critical rate (Turner or Coleman equations).^1,2 Although capillary strings do not achieve the lowest abandonment pressure compared to plunger lift or pumping units, they do provide an effective method of unloading and dewatering the deepest producing intervals. 

 The key parameter for obtaining successful capillary string results is selecting the proper chemical. For any application, the critical factors in identifying the correct chemical include stability at the bottomhole temperature and compatibility with the capillary string’s metallurgy. For water foaming applications, the produced water’s pH, composition and salinity are required.

 Understanding the source of the water (formation or condensation) is helpful, too. As in the case of water condensation, the injection depth or percentage of water added to the chemical will be affected. In addition to the water characteristics, oil condensate production plays a major role in the success or failure of foaming applications. Oil condensate acts as a natural defoamer and will have an adverse effect if it is not taken into account. Prior to installing a capillary system, an excellent indicator of potential success is to conduct a foam test with produced liquids and methane gas, followed by a batch treatment with the recommended foamer. 

 As with any technology, there are limitations and drawbacks. Initial costs are between those for plunger lift and velocity strings. Operating costs for foaming applications usually increase due to the daily chemical cost. There is a lack of access to the wellbore and master valve, since the typical capillary string installation is hung on top of the swab or crown valve. If the downhole foam is too stable or an excessive amount is injected, then foam carryover problems can be experienced at the dehydration unit and/or compressor. And when using the capillary string to prevent scale, paraffin or salt, there is the potential to stick the capillary string if any problems are encountered in continuously placing the chemical.

  FIELD RESULTS

 The operator began using capillary strings in August 1998, and now has about 175 installations. Well depths range from 6,500 to 20,000 ft. Installations have been in numerous wellbore configurations including: 2-3/8-in. tubing, 2-7/8-in. tubingless, 3-1/2-in. tubing and 4-1/2-in. tubingless completions. Wells with capillary strings typically produce less than 10 bwpd, although strings have been used in wells producing up to 200 bwpd. 

 Reviewing results of the first 17 installations in South Texas, the success rate (defined as production stabilized or increased) was 74%. Combined, incremental production was about 2 MMcfd, averaging more than 100 Mcfd per well. The incremental increase in recoverable reserves, compared to previous methods of production (soap sticks and intermitters), totaled 2.8 Bcf. 

 Performance vs. soap sticks in 2-3/8-in. tubing packer completion (Fig. 1). Although soap sticks would unload this well, daily production rates were quite variable, ranging from 50 to more than 600 Mcfd. With a capillary string, production was much more stable, making field operations (including compression) more efficient. Average daily production also increased, from 250 Mcfd with soap sticks to 360 Mcfd with a capillary string.

Fig. 1. Although soap sticks would unload this well’s 2-3/8-in. tubing packer completion, production rates varied widely from 50 to 600 Mcfd. With a capillary string, production was more stable and increased to 360 Mcfd.

 Performance vs. soap sticks in 4-1/2-in. casing without tubing (Fig. 2). In this 4-1/2-in. casing application, the capillary string increased production by 500 Mcfd and recoverable reserves by 0.2 Bcf. Previous production was erratic and required daily attention with daily soap sticks to sustain production. This example demonstrates the ability of foam to reduce the critical velocity to keep the well unloaded. Note the well loading at 2.2 Mcfd without a capillary string and now producing at 1.3 MMcfd without loading.

Fig. 2. In this 4-1/2-in. casing application (without tubing), the capillary string increased production by 500 Mcfd and recoverable reserves by 0.2 Bcf.

 Performance vs. manual intermitting and batch soap treatment (Fig. 3). Manual intermitting was time consuming and less than effective. Batch soap treatments confirmed that the correct foamer was identified, that loading was occurring and there was more production to be gained. When a capillary string was installed, production more than doubled, stabilized and required minimal manpower. 

Fig. 3. Neither manual intermitting or batch soap treatments worked effectively to prevent loading in this well. A capillary string allowed production to more than double and required minimal manpower.

  LESSONS LEARNED

 All wells that produce liquids will reach a point when liquid loading negatively impacts production. Capillary strings and foamers are one of many methods to successfully combat liquid loading. Field experience has shown that capillary strings used in the proper application can be successful approximately 75% of the time. The ease of a batch test can inexpensively and effectively identify a capillary string candidate. The choice of a capillary string is a balance between a mid-range investment cost, an increase in operating costs, incremental production, reserves, cash flow and a simpler, more efficient operation. 

  ACKNOWLEDGMENT

 The author thanks ChevronTexaco management for allowing this work to be shared, and appreciates the technical conversations and sharing of data received from Eddie Bruner, ChevronTexaco; Dave Krueger, Carey Dilbeck, Gordon Gates and David Lewis, BP; and Ken Dunek, Marathon. I also wish to recognize Lance Cole, PTTC, for assistance provided in preparing this article. As part of full disclosure, ChevronTexaco owns interest in Downhole Injection Systems, a capillary string service company. 

  BIBLIOGRAPHY

 1. Turner, R.G., Hubbard, M.G. and Dukler, A.E., “Analysis and Prediction of Minimum Flow Rate for the Continuous Removal of Liquids from Gas Wells,” SPE paper 2198, published in Journal of Petroleum Technology, November 1969.

 2. Coleman, S.B., et al., “A New Look at Predicting Gas-Well Load Up,” SPE paper 20280, published in Journal of Petroleum Technology, March 1991.