A Brammer Case Study: Revitalizing a Mature Gas Well in Northwest Louisiana

Background: Brammer Engineering, Inc. began managing the subject well in late 2020. The well was drilled and completed in Northwest Louisiana during the mid-1950’s and had been producing in the same zone since. When Brammer first got involved, the well had averaged 271 MCF/mo and 0 BO/mo over the past 12-months. It was “flowing” into a low pressure gathering system (Line Pressure = 45#). Our client was ready to shut in the well and put it on their P&A list since the leasehold was held by other producing wells in a fieldwide unit. Brammer’s operational team over the asset was not ready to shut in the well until they had thoroughly evaluated every opportunity for improvement. There were very poor records kept on the well by the previous operator(s). However, when reviewing the production history on the state website, our operational group was encouraged that this well may have some meat left on the bone. The Brammer team quickly got to calling vendors in the area to gather all information they could related to the subject well.

The Approach: The Brammer team had to come up with information to convince our client that this well had some life left in it. For this task, our team’s approach was to start with the most economic, non-invasive analysis and continue process of elimination. Our process of evaluation included:

Echometer Analysis:
- Determine the fluid level, confirm whether liquid loading issue, or concerns with tubing/casing.
  - The Echometer evaluation confirmed that the well appeared to have a liquid loading issue. When the well was shut-in, our Echometer evaluation also indicated that there was a restriction in the tubing. We were able to confirm that there did not appear to be any mechanical integrity concerns with the wellbore. We were also able to use our Echometer system to estimate producing and static bottom hole pressure.
Slickline Operations:
- Determine whether or not the restriction was buildup in the tubing or anything left in the hole previously.
  - Slickline operations confirmed the fluid level in the well and the restriction in the tubing was in alignment with our Echometer evaluation. We confirmed that there were no buildup issues in the well. We successfully latched and retrieved a plunger that was stuck in the well. We were unsuccessful in latching/retrieving the tubing stop due to a broken fishing neck.
Swab Operations:
- Determine feed-in, well performance when getting fluid off it, record pressures/rates, and collect fluid samples to be analyzed to help with our recommendations moving forward.
  - Swab operations confirmed that the well appeared to be an issue related to liquid loading. By using the data recorded and fluid analysis on samples collected during swab operations, we were able to accurately estimate the critical velocity and flowrate to keep the well unloaded.
Artificial Lift Options:
- Now that our team had performed the above operations, it was time to evaluate the best option moving forward to attempt to make our client’s well economic.
  - Utilizing the data and analyses performed on the subject well, we were able to run our evaluations to confirm which artificial lift method we should propose to our client to resolve the liquid loading issue and hopefully return it to production rates seen previously. The main candidates being considered in this evaluation included: wellhead compression, soap treatment, plunger lift, and different combinations of each.

Result: After running the evaluations, our team determined that the most economic and best candidate was to test the well with a wellhead compressor. We ran all the economics and prepared the proposal for our client, but they were originally concerned we were throwing good money after bad and did not see how such a small reduction in flowing tubing pressure and increased operating expense could possibly make this well economic. After continued encouragement, our client gave us approval to proceed with testing the subject well with a wellhead compressor. After setting a wellhead compressor on this well, it averaged over 300 MCFD and 7 BOPD for the first several months. This brought the production curve back up to rates the well had not done in almost two decades. Now over one year later, the well is still averaging over 200 MCFD and 4 BOPD. As with most things related to 65+ year old wells, there has been some adjustments we have needed to make and other minor issues we have had to address related to the subject well, but we have managed to overcome all the obstacles. As of June 2022, the well has netted our client over $570,000 over the past 12-months or a monthly average of $47,500 (inclusive of both OPEX and CAPEX).

Please reach out to David Hankins if your company has any wells you would like evaluated, Brammer would love an opportunity to help.