First-Hand:The Rise and Fall of Dual Wells
Submitted by Joe Clegg
In 1958 there was trouble in Cotton City and economic problems in the Texas oil fields plus difficulties in general with dual wells. There was a surplus of oil and it sold for only $3.00 per barrel. The Middle East production had steadily increased after World War II and the US demand for oil was meager. The Texas Railroad Commission (TX RRC) was attempting to stabilize oil prices for the world by limiting production in Texas. This effort was not working very well. Daily oil allowables for each well were set by the TX RRC based on acreage, well depth, and other significant factors plus the TX RRC could reduce the number of producing days. The number of producing days (as set by the TX RRC) was reduced to 8 days in early 1958. Thus the monthly allowable was severely reduced-- (the monthly oil allowable was only the daily allowable times eight.) Everybody was scrambling to cut costs.
A number of operators cut cost by reducing the casing size and by instigating the use of dual wells. The drillers were bragging on reducing drilling costs. Why drill two wells when one well could be used? The roughnecks said “We cut development cost in half. Can you roustabouts cut operating costs as much?” Of course completions costs were slightly higher for dual wells and no one knew what the operating cost per barrel would eventually be during dual artificial lift. No one talked about making money—only about cutting costs. Often the best way to make more money is to increase the production. Not easily done for dual wells with limited casing size.
Dual wells had to be completed (Texas Law) so that the production from each reservoir was kept separate—no commingling. The first duals required down-hole packers, separate flow paths in the well, separate flow-lines and separate tank batteries. There were cases where the royalty ownership in the reservoirs at various depths was different and the surface rights belonged to someone else. Cordial relations with a rancher who owns all the royalty is usually a piece of cake. Relations with the surface owner (who does not own the oil and gas royalty) and the oil operator are often strained.
As long as both zones flowed, the operating cost for a dual well was relatively low. The problems usually started when one zone died and required artificial lift. When both zones died there were serious artificial lift problems. Numerous dual pumping wells were installed with dual sucker rod equipment. (There were even a few triple sucker rod beam pump equipped wells.) The most successful were wells equipped with 7-inch casing and parallel strings of 2 3/8-inch tubing. The upper zone could be produced much like a single well. However; dual pumping normally requires the lower zone to be produced under a packer where gas cannot be easily vented. (Small vent strings were not found effective.) Thus pump efficiency was bad and the production rate was severely curtailed. For such reasons, dual gas-lift was often recommended. A high GOR just makes gas-lift easier. There is no problem in producing the gas from the reservoirs from under a packer if gas-lift is used. But there are problems for dual gas-lift.
The “Humble” approach to cutting costs was to drill “tubingless” completions. Rather than drilling wells with expensive 7-inch casing, wells were completed with three strings of cemented 2.875 inch tubing. After drilling to total depth, three small “casing” strings were individually run to total depth and cemented. No tubing was run; thus tubing-less as defined by the TX RRC. Permission was required from the TX RRC if no tubing was run. The lower zone was first completed. Extra care was used on perforating each zone to prevent perforating the other two strings. The overall technology was good. Again flowing wells (such as gas wells) only had minor operating problems and were generally successful. However, oil zone in small casing (tubing-less) that required artificial lift had big problems.
How do you artificially lift a well with 2.785-inch casing? Sucker rod pumping required hollow sucker rods to vent the gas. This approach proved inefficient. Gas-lift required running small tubing and using special gas-lift valves and mandrels. Pressure losses down the annulus caused problems and reduce the production rate. Offset single wells with larger casing (4.5 inch OD and larger) usually significantly out produced the 2.785-inch casing “tubing-less” completions. Most operators who tried the “tubing-less” approach became unhappy with such completions.
The dual gas-lift wells that were completed with 7-inch casing and parallel strings of 2.375 inch OD EUE tubing had better success... Side-pocket mandrels (developed in the 1950’s) were used with wire-line retrievable 1-inch gas-lift valves. In west Texas the wells were relatively low volume (<200 BPD); therefore intermittent gas lift operation was usually better than continuous flow. Special techniques were required to produce both zones simultaneously. One problem with dual gas-lift is that the weak zone robs all the gas and the strong zones produce little to nothing. A method called “snap, crackle and pop” valves was sometimes used. These were basic spring “fluid” valves with added features. Fluid pressure had to build up in the tubing to cock the valve. Then the surface casing pressure was increased to open the bottom hole lower gas-lift valve. (Normally a set time period of 1 to 3 minutes). The slug of fluid in the tubing sped to the surface at up to 1000 feet per minute. The gas to the annulus was shut-off and casing pressure gradually bled down so that the bottom hole gas-lift valve would hopefully close. This procedure caused surging surface pressures that popped the separator relief valves and made good gas measurement impossible. This cycle procedure was repeated once or twice per hour depending on the achieved production rates. Hopefully this procedure worked on both zones.
Did this procedure work? It often worked for short time periods before adjustments were required. Various methods and procedures were tried. In general, field operations were difficult and smooth operations were seldom achieved. A common field approach was to alternate well zone operation on a daily basis. Produce one zone of the dual for one day and then the other zone the following day. This method often produced nearly the same monthly production and was not as labor demanding.
Over time most duals on artificial lift were eliminated. It became apparent that duals were best suited for relatively low rate wells. Flowing wells caused few problems. Dual artificial lift resulted in many problems that affected economics. Most oil wells eventually need artificial lift. Having the producing formations near the same depth and having close to the same bottom whole pressure made operations and workovers much easier. The success of duals was often found marginal if operating problems resulted in higher lift costs and lower production rates. Workovers were more complicated and often expensive. The low pressure zone would drink the completions fluids and the high pressure zone would then blow out. Offset single wells often out produced any dual well. Over time the production allowables were increased which made single wells more economically viable. Unitization of reservoirs for water flood project projects often made dual wells undesirable. Two different operators for one well could cause problems. Operating practices in the oilfield were changing. High rate single wells became the completion vogue. Oil prices were increasing. Dual wells lost favor and gradually faded away. Life and economics would be better in the years to follow all the way to 1985.
