In 1994, while chairman and CEO of Barrett Resources, I got a call from my good friend Ray Thomasson, who said, “Bill I have a prospect Larry McPeek has worked up in the Wind River Basin that you might find interesting.” I had known both men for decades, trusted them and respected their abilities. I’d worked with Larry at Amoco, and, like me, he was an explorationist – a mindset I understood completely.
I’d worked every feature of geology in Wyoming’s Wind River Basin and was familiar with about every well drilled there during my career, so I frankly considered myself somewhat of an expert on the basin, “exhibit A” being my development of the prospect that led to the discovery and development of the giant Madden gas field northwest of this concept Ray and Larry had developed. It helped greatly that Peter Dea on my staff was also familiar with this area, so our combined expertise could evaluate this prospect with confidence. I was eager to see what Larry had come up with.
I took Peter and Paul Rady, both geologists, and Joe Barrett, our land vice president, to Ray Thomasson’s office to listen to Larry McPeek’s presentation.
Production History
The Cave Gulch Prospect was located along the Owl Creek Thrust in a geologically complex area. Earlier exploratory wells around the periphery of the area hadn’t seen much success.
Several seismic surveys had been conducted in the area as well, but shooting seismic through the vertical beds on the surface and through the complex sub-surface of the Owl Creek Thrust made it very difficult to interpret the data from these surveys. I took a simpler approach.
The key well on the prospect had been drilled and completed in the Lance sandstones by Chevron, marking the initial discovery well for the Cave Gulch field – Chevron just didn’t realize it at the time. It appeared to me that, based on their seismic, they offset their initial discovery by drilling their next well to the north. Although it came in structurally low, it had some minor shows. The second offset well was drilled to the south and it, too, came in structurally low to the discovery well. Even though it too had some shows, it was plugged and abandoned. No more drilling took place for the next 30 years.
The information available to the industry about the true production figures for the well was incomplete, so no one really knew how this well had actually performed until Larry McPeek did the legwork to get the official production records. He discovered that the well had produced more than 7 billion cubic feet of gas during its 30-year life.
This was no company-maker, but it wasn’t an inconsequential amount either.
The other key to this prospect was that the dipmeter surveys Chevron ran in the initial discovery well in addition to the dry holes indicated that it was possible to get structurally higher northeast of this 7 BCF well.
Why Chevron did not utilize this dipmeter data to select their initial offset locations I do not know, but I’d learned by then that the size and resources of the majors did not automatically make them superior to the smaller independents like us. It appears they followed a pattern familiar to many companies in relying primarily on the seismic to select their offset locations. Further, Chevron had previously discovered the shallow Waltman Field (in the Fort Union) to the south and this, too, may have figured in their offset drill site locations. All this is mere speculation on my part. I held fast to a central tenet to my approach to prospecting throughout my entire career – preferring to rely on solid subsurface data in evaluating geology, in this case, dipmeter data, over seismic data.
After leading a review of Larry’s geology and concept, Peter projected it to be a 50-BCF-sized prospect, and he recommended we take it. I liked the idea of drilling structurally up-dip from a 7 BCF well on the basis of good dipmeter data, so we bought the entire prospect from Ray (i.e. 100-percent working interest).
‘The Well of the Year’
Moving forward, Joe’s landmen encountered a complicated leasing situation, but they acquired all the leases they could. However, Phillips Petroleum controlled the key lease holding our proposed drill site. Our initial overtures to lease from them were turned down, but when we pointed out their federal lease only had six months remaining before it expired, they agreed to give us a lease if we would drill and test a well in time to save the lease. Getting all this done became very urgent. We had to select a location, form a federal unit, get approval to drill the well, drill the well to total depth, and finally test the well to establish commercial oil or gas production prior to the lease’s expiration in order to save it. This was complicated, so it required coordinating specialized expertise across several technical and regulatory disciplines.
We quickly formed a federal unit and, based on the dipmeter data, selected a location up-dip from the initial Chevron discovery well. We contracted a rig, moved in and spudded the well in August 1994. Several days after spudding the well, we started encountering strong gas shows in the shallow Fort Union sandstones with further shows deeper in the Upper Cretaceous Lance formation. With only a few days before the lease was to expire, we reached total depth of 8,500 feet. That was great news, and it was about to get even better. Frank Farnham, our engineer on site, called in from the rig after looking at the logs on the well.
“Bill,” he said, “we have hit the motherlode.”
We had more 400 feet of net pay from multiple benches throughout a 2,000-foot gross interval of Fort Union and Lance sandstones. When I first got a look at the well log on August 10, I was struck by the log’s strong resemblance to the Madden discovery well. Frank was right – we had tied into a big one. We immediately set pipe and selected one zone to test to prove we had commercial quantities of natural gas. Doing so would save the lease, so this became our sole focus. We called the Casper Bureau of Land Management office and asked them to send someone out to officially witness the test. The BLM official confirmed that the well tested commercial quantities of gas, and this from only one of multiple zones yet to be tested. A day later and we would have lost the lease. We would have lost a lot more than that, it turns out.
Our discovery well, the Cave Gulch Federal Unit No. 1, IP’d for 10.7 million cubic feet of gas along with 109 barrels of condensate a day as well, leading this horse of a well to be named “The Well of the Year” by Hart’s Oil and Gas Investor in 1994. It sure was. That well kicked off development of a 500-BCF-plus natural gas field, about ten times larger than Peter’s original projection.
So, thanks all around: to Ray Thomasson and Larry McPeek for the prospect, to Chevron for drilling the key well while ignoring the dipmeters they had run, and for forgoing any follow-up drilling. Thanks to Joe Barrett and his land department for forming the federal unit and tying up the key Phillips lease, to our drilling engineers for getting the well spudded, drilled and tested in time to save the key lease, to our regulatory folks working federal land permits and processes, and to all our exploration people who worked the amazingly complex geology on this prospect. This was truly a team effort to literally beat the clock. Naturally, a huge and deserved celebration ensued.
Hell’s Acres
Here I breathe a heavy sigh as the story continues. Three years after the discovery well was drilled and development of the field expanded, Peter and Fred Barrett (also a geologist), along with geophysicist Steve Natali worked up a deep conventional 3-D seismic prospect to test the deeper Frontier, Muddy and Dakota formations in the Cave Gulch Field. Surrounding our Cave Gulch shallow discovery were six 19,000-foot dry holes drilled in the 1980s, yet the deep horizons were all structurally flat to each other. This implied there was no trap, and the seismic data was pretty fuzzy, so of little help. In effect, this was a new wildcat unto itself. But based on our experience showing that deep gas structures (Madden, for example), could often underlie shallow gas-charged horizons, the team mapped in a possible deep structure.
The first deep well was successfully completed as a commercial gas well in the Frontier sandstone for several million cubic feet per day, but the real excitement came when we drilled the offset well, the 1-29 Cave Gulch, to a depth of 19,000 feet to test the deeper Muddy and Dakota formations.
We were about to get more excitement than we bargained for. When we drilled into the top of the Muddy at approximately 19,000 feet, the well unexpectedly encountered very high pressure from a highly porous and permeable Muddy sandstone reservoir. The unexpected pressure blew the drilling mud out of the hole, so the gas flowed uncontrolled.
This is where our engineers and field people stepped up. The well was flowing natural gas through the rig’s blow-out preventer that we could not get shut in. In an amazing display of skill and fast thinking, they got the pipeline company to let us hook the well up to their gas pipeline at a stabilized rate of 45 million cubic feet of gas per day. This one well was producing more than the total company production of hundreds of wells at the time.
Our goal was to try to relieve the extremely high reservoir pressure that caused the blow-out by producing it at these high rates. Again, our Wyoming team was able to harness the 1-29 while maintaining that staggering flow rate, producing 7 BCF of gas reserves in a little less than six-and-a-half months with virtually no decline. Because of the precarious condition of the well, we were monitoring the well around the clock. It was a little like having Frankenstein strapped to the table, and we all know how well those straps ended up working out.
At about two in the morning on Aug. 13, 1998, our pumper on location felt and heard the ground rumbling and shaking, so he wisely ran like hell away from the well.
The ground erupted, natural gas spewing out of the ground with so much pressure it was blowing several moon-like craters out of the ground around the well.
Ironically, the 1-29 was located near a town named Hell’s Half Acre. It was aptly named and probably should have been renamed Hell’s Acre (or even Acres!) by the time the 1-29 ran its course.
What had set the pumper running was that the liner in the well had failed, after which the well flowed uncontrolled for nearly five months. Some flow estimates ran as high as 100 million cubic feet of gas a day, but there was really no way to accurately gauge it. The torrent of gas created a growing hazard in which any spark could set off a huge fire and explosion, and an active railroad line a few hundred yards away heightened safety concerns.
Plugging the Blowout
After consulting with our team, the rig’s owners and the insurance company, we concluded that the safest course of action was to set fire to the well. We also brought in the well control company Boots and Coots from Houston, who were experts at killing blowouts. Over the months that followed, our drilling engineers and geologists developed and executed a remarkable feat. Their plan was to redirect a currently drilling deep development well a quarter mile away to intersect the 1-29’s 9 and 7/8-inch wellbore at a depth of 19,000 feet. Talk about threading the needle! They intersected the drill pipe with exacting precision, pumped in heavy mud and placed a cement plug, killing the 1-29 blowout.
With virtually no room for mistakes, they performed as utter professionals under extreme conditions. Their performance was recognized by everyone from the Wyoming Oil and Gas Commission to the BLM, the two lead agencies monitoring the efforts of our people and our insurance consortium led by Lloyd’s of London.
The cement plug was set in place and the well brought under control on Jan. 9, 1999, my 70th birthday. It was just what I wanted for a good birthday present, and I remember thinking to myself when blowing the candles out on my birthday cake, “I wish it would have been that easy with the 1-29 (although blowing out 70 candles at my age wasn’t without some effort!).”
As for the good and bad of it – the good news is that no one got hurt during those 149 days of the blowout and our insurance paid $25 million for the loss of the rig and re-drilling a new well. The bad news is that we lost 45 million cubic feet of daily production which, over the course of the well flowing uncontrolled, was an estimated loss of 15-20 BCFE of gross proven natural gas reserves. At the price of gas at the time, that was about $30-45 million worth of gas gone up in smoke – about enough to make a grown man cry.
It was hard to cry, though, when we looked at what we accomplished with the subsequent discovery and development of several hundred billion cubic feet of commercial natural gas reserves from the Cave Gulch field over the years. Cave Gulch was another company-maker.