Natural gas was first commercially discovered in the San Juan Basin of New Mexico in 1921, making this year the Basin’s centennial. The first San Juan Basin natural gas strike occurred one mile south of Aztec, N.M., when the Aztec Oil Syndicate completed their No. 1 State, in Sec. 16, T 30 N, R 11 W, for an initial rate of three to four million cubic feet of gas per day from the Farmington sandstone. Production was found at a depth of about 1,000 feet. The gas discovered south of Aztec was piped into town and used domestically throughout most of the 1920s. This was the first commercial use of natural gas in New Mexico or the San Juan Basin. Located in northwest New Mexico and southwest Colorado, the San Juan is one of the largest gas basins in the United States, along with the Marcellus in the Appalachian Basin and the greater Hugoton Field of Texas, Oklahoma and Kansas.
Pictured Cliff Wells
In 1973, I was working for Amoco Production Company (then a subsidiary of Standard Oil of Indiana) in Farmington, N.M. At the time, Amoco owned and operated about 6,500 dry gas wells in the prolific San Juan Basin. The main gas intervals were the Dakota, Mesa Verde, and Pictured Cliffs sandstones. (In what is now Mesa Verde National Park in southwest Colorado, the Anasazi Puebloan people constructed dwellings in the cliffs of the Mesa Verde uplifted sandstone outcrops.) The sandstones occur at depth in the San Juan Basin and are oil and gas productive from intervals named after the cliff dwellings, that is, Cliff House, Menefee and Point Lookout. The Dakota was the deepest, then the Mesa Verde Group, and then the shallowest – at about 4,500 feet – was the Pictured Cliffs. This latter sandstone crops out between Farmington and Shiprock, N.M. and has ancient hieroglyphs – hand-carved pictures, on the faces of the sandstone. Above the PC are the Fruitland coal beds. These coal beds were strip-mined farther west on the Navajo Indian Reservation and used to fuel the Four Corners Generating Station.
I was a pumper assigned to maintain and monitor 71 gas wells in an area known as Angel Peak, southeast of Bloomfield, N.M. Some of the wells were in PC sandstone in the shallow Fulcher-Kutz field. These wells were drilled in the early 1940s by companies looking for potash. Natural gas was discovered instead. The wells were drilled to the top of the sandstone, then casing was run and cemented in-place. Wells were then “drilled in” and the sandstone was produced in an open hole. This type of completion was termed a “barefoot” completion. To augment the gas production, nitroglycerin was detonated in the open-hole section to fracture the rock face. Gravel was also placed in the open hole to prevent sand from building up in the formation and blocking the flow. Small tubing, called a syphon string, was run to produce the gas, and for years the wells were in that condition when they were purchased by Amoco.
My job also included doing anything I could to maintain or increase gas production. Over time, water would build up in the well and the gas pressure and volume could not lift it out – a condition termed “logged off.” So, I would drop soap into the well and shut it in for about a week or two and try to unload the well. The shut-in allowed the bottom-hole pressure to build up and the soap foamed and formed bubbles and allowed the “gaseous water” to flow out of the well when I opened it back up for production.
A New Idea
I followed this process for a few years and became frustrated. Something was choking a certain well, so I decided to try a different approach. These wells had well heads with old designs: two lines off the casing and one off the tubing and all had valves to open or close. Gas was produced through the tubing valve and/or a casing valve. The second casing valve was bull-plugged and closed off. I obtained a few fittings and configured an eight-foot elbow connected to the casing valve and extending vertically above my head. The well had been “soaped” and shut in for about a month.
The day came and I set aside a few hours in the afternoon to focus on the well and try my new idea, with everything to gain and nothing to lose. I installed the fittings, put on hearing protection, used a 24-inch wrench, quickly opened the valve to atmosphere and then walked off a safe distance to my pickup truck to have lunch. At first, the well blew gas fairly hard but quickly faded and died. For the next half hour, it would breathe – huff and puff – but nothing else. I thought, “Ok, you killed it.” I finished lunch and started preparing to shut the whole thing down and call it a day.
Then the well started a steady blow with a fine water mist, followed by a small stream of water and surges of gas. It blew a solid two-inch stream of soapy brackish water, drilling mud, sand and some rocks, with the sound of a jet engine. Within 10 minutes, the well blew clean dry gas. I shut the well in, removed the fittings and opened it to production through the tubing. The gas flow was severely restricted, and I concluded the tubing was plugged downhole. So, I opened the casing side fitted into the flow line to the meter-run. I could hear the gas in the pipeline and went to the meter house to see that the readings were now off the chart. I went back and pinched the well using the casing valve to get the readings back on the chart – anything off the chart was free unmeasured gas to the purchaser.
For the next month, the well produced at a steady rate. The meter run tube, orifice size and static spring were set to measure a maximum of about 30 thousand cubic feet per day. The well was now capable of producing a lot more than that. I called Southern Union Gas Company and a gas measurement specialist came to the well and we took tubing and casing pressure readings. He calculated that the Barton meter run could accommodate a larger orifice plate and static spring. An eighth-inch orifice plate had been in use for more than 20 years because of the small volume. He enlarged the plate and spring. I opened the casing valve a little more to set it to stay on the chart. A circular paper chart was changed every seven days and sent to be integrated for gas sales volume. At the end of each month, Amoco would get paid, and the volumes were continuously graphed by the production engineering department over the life of a well.
Southern Union eventually installed an inch-and-a-half wide orifice as the gas sales increased. As a pumper in the field, I had radio communications with the office in Farmington. One day the production engineer contacted me and wanted to know why the well had increased in production. Did Southern Union reduce the pipeline gathering pressure? He indicated how odd it was, because no other PC wells had increased in gas sales and my well was producing more gas than when it was originally drilled. I invited him to the well location for discussion, as I did not want to broadcast over the company radio system what I had done to achieve the new production levels.
He came out a few days later and I explained in detail what I had done and the results leading up to the increased gas sales measurements by incrementally increasing orifice plates and static spring sizes. The well continued to perform and out-produce every well in the Fulcher-Kutz PC field.
The Amoco engineer had obtained all the field data he needed and went back to the office. He reviewed all the existing well files and the methods of individual well completion and found that all the Fulcher-Kutz Pictured Cliff wells had been completed “barefoot.” He proposed and received approval from management to re-work all the wells and modernize the completions.
The first step in the work-over program called for the wells to be shut-in, and fluid was pumped onto the wells to kill the pressure and prep for recompletion. An industry standard work-over rig was used, contracted from Drake Well Service. The wells were entered, and the existing old one-inch production tubing was removed. In the case of the well whose production I had initially increased, we found that the tubing had parted, was rusted and corroded and had no material strength. The tubing was actually milled out to total depth. The wells were cleaned out, removing sand, drilling mud and gravel, and then deepened to open the full sandstone pay intervals. Four-inch tubing was run and cemented back to surface, then the wells were perforated and sand-gelled water fracture-stimulated. Inch-and-a-half tubing was run and landed, and the new well head fittings were installed. A 24-hour shut-in period allowed the reservoir to stabilize and then the tubing was swabbed. When enough fluid had been recovered, the wells started flowing on their own. A five-day flow back was initiated in which the well was shut-in for twenty-one hours and flowed for three hours. Total fluid recovered and gas volumes were recorded. All the wells cleaned up, recovering most of the frac water, but not all, and were put on production down the pipeline.
At the end of the project, Amoco owned approximately 15 percent of all the Fulcher-Kutz PC wells, but produced 87 percent of the total gas from the field. All the PC well recompletions were successful, but then there was one peculiar well. A few other wells acted in a similar fashion, but one well performed in a very anomalous way.
A Peculiar Well
The peculiar well had been swabbed and flowed, and the total barrels of water used in the reservoir stimulation was 100-percent recovered. This is rare, especially when the PC wells seldom produced any formation water. The well continued to flow gas at low rates along with the new water. Gas was produced from the casing side, and the tubing produced water to the pit slowly and steadily. Over the next few months, the gas production gradually increased and the water volume slightly decreased. The gas production steadily increased day after day after day.
The big question became, “Where was the water coming from?”, along with, “How does a well continually increase in gas production?”
It was observed that the water production pit had a conspicuous black covering of some sort. A sample was taken and sent to the lab and found to be coal dust. The only source for coal dust would be from the overlying Fruitland formation.
Laboratory analysis indicated that the water was not the same as PC reservoir water. They differed in salinity, dissolved solids and mineral content. The gas was almost 100-percent methane – again, not the same as the PC gas, which was mostly methane but also had lesser percentages of the minor components such as ethane, butane, propane and pentane. Clearly, the gas was not PC reservoir gas. It was determined that the gelled-water and sand fracture treatment had gone vertically “out of zone” and upward into the Fruitland coal, or the perforations were off-depth, and the Fruitland coal was inadvertently completed. If on depth, the path for the coal gas was somewhat tortuous, having to transit to the well bore back through the PC sandstone fracture pattern. As the coal de-watered, the gas volumes increased, creating a production curve eventually shaped like a bell curve.
This anomalous Pictured Cliff well was the first indicator of commercial volumes of coal bed methane production in the San Juan Basin, and Amoco was the initiator of what became the largest coal gas production area in the world. The highly successful recompletions of the Fulcher-Kutz PC wells and the observation of methane gas from the overlying Fruitland Coal marked the beginning of a new phase of San Juan Basin development. The Denver office for Amoco began a focused effort to evaluate the potential. A complete staff of geologists, engineers of all types, landmen, finance specialists and management formed a team to develop the coal gas.
CBM to the Fore
Based on this teamwork, Amoco chose a location not in the Fulcher-Kutz area, but north, close to the Colorado state line on Cedar Hill just off Highway 550 to Durango, Colo. The first well drilled and completed specifically for CBM was in 1975 by Amoco, in the Cedar Hill field northeast of Aztec. The well was the Cahn No. 1 – as an open-hole test, a “barefoot completion.”
Amoco completed the initial Fruitland coal-bed gas well in Cedar Hill CBM field in May 1977, producing from the thick (up to about 25 feet) basal coal of this formation. Public records show that by Oct. 31, 1993, the field had produced nearly 54 billion cubic feet of gas from only 23 producing Fruitland Coal wells. During that month, average daily production per well was approximately 714 thousand cubic feet. (The most productive wells in this field are characterized by high fracture permeability.) Amoco was the first company in the western United States sufficiently daring to produce large amounts of water from coal beds to stimulate CBM production, as a direct result of the Fulcher-Kutz PC well recompletions.
The Amoco Cahn No. 1 well was reported to begin initial production of a few thousand cubic feet of gas per day and many barrels of water. Over time, as the well de-watered, the gas increased to more than 55 million cubic feet per day.
One of the most prolific CBM wells in the region was the Amoco (now IKAV) Gardner A-l well, which had already produced over 20 billion cubic feet of gas by 2000. Production through coal seam gas processing plants averaged 1.835 billion cubic feet of gas per day at the turn of the century. The basin still produces about 1.7 trillion cubic feet of gas per year as of 2020.
In 1988, the first year that production records for the Basin Fruitland pool were kept, coal-bed methane production from the San Juan Basin of New Mexico was 14 billion cubic feet from a year-end total of 77 wells. Annual production in 1989 increased to 55 billion cubic feet from 323 wells and in 1990 was 131 billion cubic feet from 734 wells. By December 1990, Fruitland coal-bed methane production made up about 31 percent of the total monthly gas production from the San Juan Basin, and 17 percent of the monthly gas production from all of the state of New Mexico.
In the years that followed, the success of the Amoco Cahn No. 1 well resulted in thousands of coal-bed methane wells being drilled.
How Did They Know?
On one particular day, I was standing next to that well, talking with the project’s petroleum engineer, and I asked him, “How did Amoco know that 7,285 feet below this location, they would find oil and gas in the Dakota? They can’t see down there.”
He said, “Well, geologists are the ones that figure that out.”
I then asked him, “How could they know? They can’t see down there either.”
He answered, “Well, in a way they can.”
“How can they do that,” I asked.
“I suggest that you go to the local community college and take a course in geology,” he answered.
Before that day, I was not sure I had even heard about geologists, other than rock collectors, or their relationship to oil and gas. I will never forget what I said to him. I was sort of a country guy, and as I was standing there in my steel-toed boots, Levi’s and hardhat with my thumbs hooked in my belt loops, I looked over at him and said, “They teach that stuff?”
I took his advice and enrolled in a Physical Geology 101 class at the San Juan campus of New Mexico State University. The professor was Bruce Black of Colorado Plateau Geological Service and a consultant to Shell Oil Company. Everything he taught just made sense, and I developed a desire to go to a university and become a petroleum geologist. I received my degree from the University of Northern Colorado in 1980. The Amoco engineer was duly promoted and transferred on to bigger and better things. My career and the San Juan Basin had changed forever, too.