First-Hand:Reflections of a Production Engineer
Submitted by Ralph Veatch
I signed on in 1960 as a production engineer with Pan American Production (Amoco Production during most of my tenure; now British Petroleum). My initial hydraulic fracturing experience began in the early 1960’s. To design treatments in the northwest Louisiana, Pine Island field, 1800 foot deep, 200 foot thick, Annona Chalk formation. Four to five separate treatments per well, with 40 to 50 foot intervals between each treatment. For a couple of years before I got the assignment, they used a custom made pump-down bridge plug for isolation. After the treatments we had to wash down and fish each packer. Took about two to three days to get the wells on production. Not long after I got involved, the home office (Tulsa) noticed a drilling report – “Fishing Packers – What the ___ ?”. It hit the fan. What to do? That’s when we came up with “sand plug” isolation, perforating under pressure, and fracturing as soon as the perf gun pulled into the lubricator. Did that for the next 500 wells in the field. Worked well – Good isolation, took only about a half day to wash out the sand plugs, and no more threatening nasties from the home office.
I transferred to the Amoco Research Department in 1970, and in 1976 got assigned to a new initiative – Wattenberg, Colorado, Muddy-J, Tight Gas. The big conventional 60,000 gal treatments they were using didn’t cut the mustard. What to do? We needed really deeply (unheard of deeply) penetrating fractures. The answer - Massive Hydraulic Fracturing (MHF)! First job 180,000 gals, then bigger, then bigger, … . Used a new fluid – Polymer Emulsion (condensate/water), with stages of 100 mesh and 20/40 sand proppant. The fluid was great – good thermal stability, good proppant transport. On the third job during a big 100 mesh stage, we maxed out on surface pressure. We kept cutting injection rate. Got down to about 2 bpm. One pumper in compound gear, but still pumping. Field folks were yelling “Screen Out, Shut it down!” Engineers said “Keep Pumping”. Finally after about four to five hours at 2 bpm, things cleared up. Seems that the 100 mesh sand adsorbed the water out of the emulsion which sent the viscosity skyrocketing. Had to clear the casing of all that stuff before things got back on track. Didn’t pump anymore big stages of 100 mesh.
From there the industry took off with MHF. The perspective of “Bigger is Better” evolved to “Smarter is Better” as we moved into Wyoming, Utah, East Texas, New Mexico, etc. And, the industry better understood the old saying: “Good Judgment comes from Experience, and a lot of that comes from Bad Judgment”.
For many years, there was much contention between some of my colleagues – “Which is the better fracturing model, Perkins-Kern-Nordgren (PKN) or Geertsma-deKlerk (GdK)?” Feelings ran high. The Perkinicans versus the Geertsmocrats. No one would give an inch. Was at an SPE fracturing forum one time and mentioned this to Jahns Geertsma. His reply – “GdK applies where fracture heights exceed fracture lengths. PKN applies where fracture lengths exceed fracture heights. They both apply when fracture lengths nearly equal heights.” I asked Tom Perkins about this – “Confirmed”. Both said “It’s in the literature!”
I don’t know if the fracturing political party members have shaken hands yet. Doesn’t matter. New and improved fracturing models have come on the scene. They tell us exactly what we tell them to tell us when we give them the input data. Doesn’t seem to matter sometimes how credible that input data is. Regardless, those models spit out the “Ground Truth” in lightening speed, with animated propagation geometry and conductivity pictures – all in dazzling colors. No question about it – the “Ground Truth!”.
The friends I’ve made during my career in fracturing: Many friends – Great friends – Long time friends – Like family. We all agree on the same thing: “Hydraulic fracturing is a really stimulating technology”. And, sometimes that may be the only thing we agree on. But, I wouldn’t trade them for anything. Well, maybe one or two.
We’ve come a long, long way in our fracturing technology over the 50 years since I first got involved. Learned a lot. Big improvements – equipment, techniques, models, analytics, fluid systems, proppants, etc.
But, I’d still like to know some things about those fractures, like: How deeply they go?; How deeply in one direction versus the opposite direction?; How high they go?; How wide they are?; How many are there?; What they really look like?; And, well, maybe just one or two others?