First-Hand:Jacques L. Elbel
Submitted by Jacques L. Elbel
I was born in San Antonio and raised in New Braunfels, Texas. I attended Rice University from 1949-1951 and the University of Texas from 1951-1954 and joined the Student chapter of the AIME Petroleum branch (SPE) in 1952. I interviewed Dowell Division of the Dow Chemical Co in 1954 curious to find out how they would use geologists and they said they were looking for people to train in application of a new technology called hydraulic fracturing. It sounded interesting and after passing a psychological test I was offered a job as a service engineer trainee in Kilgore Texas. I was mainly an observer on my first job near Corsicana and it was not completed. When I asked why they said “we screened out”. I didn’t know what that meant but it didn’t sound good. We screened out two more wells that same day. The jobs were designed for 3000 lb sand and 3000 gal frac oil injected at 2-3 BPM using an acid pump and sacks of sand being mixed in a 1000 gal paddle mixer and I helped pass the sacks of sand to the sack cutter on top of the tank as he timed his cutting and pouring to maintain about 1 ppa/gal. My crew peers asked if I had studied sand handling in college.
1954-1960 North East Texas- Louisiana, South Arkansas and Mississippi, Service Supervisor[edit | edit source]
Treatments sizes were as low as 1000 gal of fluid and 1000 lb sand and often a frac crew would perform several in a day. We experienced many screenouts but fortunately the production results were usually good. Reflecting, we probably were getting tip screenouts across damage zones as pads were not part of the design. Some operators would swab the well down before injecting the sand slurry, not wanting to inject unnecessary fluid in the well. The treatment sizes increased and the practice of pumping into the well to ‘break down’ the formation and test the integrity of the tubing prior to injecting the sand became standard. Fortunately, but unknowingly, this would also serve as a pad and we began to recognize better success with increased volumes were needed to “breakdown” a formation. There were many different opinions on what was happening down hole such as the question of horizontal or vertical fractures and what was causing the screen outs.
Fracturing was booming in West Texas and Kansas where the trend was for larger treatments and higher injection rates. Those areas had priority on new frac equipment. The results seen there did influence the local operations.
Several of the major operators had research departments working on fracturing. A major operator’s research group was on location a one frac treatment and gave me a prop schedule divided into 100 gallon and 0.1 ppa/gal increments. I said we could not follow that schedule precisely with our 1000 gal paddle mixer and they approved our make shift plan to start out with light and gradually increase sand concentration until we get the 45 sacks of sand in 3000 gal of frac oil. West Texas probably had a blender with a small mixing tank.
In East Texas there were many independents, who, by nature had their own ideas on what might be happening in the formation during fracturing and were acceptable to new ideas. I got comfortable in that environment for exchanging ideas. There appeared to be a time lag of several years for basic research to be published in the trade journals and then even longer to be applied in the field.
1960 Tulsa R&D, Development Engineer[edit | edit source]
I worked in development of abrasi-jetting and implosion devices and also participated testing hypergolic fluids for enhanced fracturing;the fuel and igniter had to be mixed down hole in the hydraulic fracture. It was not commercialized.
I helped in introducing a low pressure, hesitation cement squeeze procedures in some new areas of operation.
In 1950 G.C. Howard and C.R. Fast discussed the advantage of controlling filtration in cement squeezing. Another major research company successfully expanded this concept. Our research department had recently developed an excellent product for this as we were expanding cementing operations. I participated in the introduction of a low pressure hesitation squeeze cementing process in some new areas. The purpose was to place cement in the perforation tunnel and channel behind the pipe without fracturing the formation. We would spot cement across the perforations and a number of short injections were made applying pressure but staying below the frac gradient. Hesitation periods would be form 10 minutes to as long as an hour. The cement was retarded accordingly and the filtrate control prevented dehydration allowing the slurry to be reversed out of the hole.
1961-1962 Tehran, Mid-East Technical Representative[edit | edit source]
When Schlumberger and Dowell formed a joint company for pumping operations outside of North American I was transferred to Tehran, Iran to evaluate stimulation potential in the Middle East. Most of the wells in southern Iran were prolific producers; often requiring choking the wells back and there was no incentive to increase production at the time. The National Iranian Oil Company, operating in northern Iran with a couple of drilling rigs, had its own cement pumps. We furnished supervision and training for their operations. We were able to demonstrate the success of large acid fracture treatments. However, due to the rapid growth of fracturing in other world regions a decision was made to delay entry in the Middle East.
1963-Paris, France, Headquarters; 1964-65 Libya, Technical Engineer[edit | edit source]
Hydraulic fracturing was just starting in Libya. Some engineers with the operating companies had gained stimulation experience while working for the parent companies in the US. The service companies supplied only the equipment and frac treatments were performed with the materials available. Small acid treatments 1000 gal were standard in the completion. Availability was a problem and each drilling rig had portable storage tanks with several hundred gallons of concentrated acid. The largest operator had experimented with increasing acid volumes up to 5000 gal and found that there was no additional benefit. Drill-stem-tests were being performed on all new wells in order to determine reservoir pressure and fluid characteristics for the reservoir engineers for their reserve calculations.
Both H.K. van Poolen and Mike Prats had published papers on well testing and productivity increases. I was able to apply these with other new technology to estimate benefits and limits of matrix treatments. Our research department had developed a method to determine the penetration of unspent acid which allowed estimates of additional benefits of fracturing.
I proposed a ‘cook book’ procedure for treating and testing exploratory wells. It consisted of a Drill-Stem Test, a 1000gal matrix treatment and a short production period and another transient pressure test. If damage was still present, a 5000 gal acid treatment followed by a production period and transient test. If test shows more stimulation is possible perform a 20000 gallon acid treatment. This would take several weeks.
I was not aware the plan had been approved in the Tripoli office. The tool pusher on a drilling rig got the procedure and notified our field camp to start hauling 26000 gal acid for the job. Our camp manager said we did not have that much acid on hand The tool pusher notified his superior and it went on up to the country manager and then to our manager who had guarantied the we would always have enough materials to supply our services. (here to for, only the oil operator could import materials and now we were going through the transition of the service company supplying them) On that Sunday morning my manager came to my house and what I had recommended. I told him that we should enough acid for first two treatments and it would be weeks before they would need all the acid and that they would probably want to move the rig off and get a work over rig. He sent out to the desert to get that resolved but voice communication between the field camps and Tripoli offices was difficult and it was also a holiday. In the meantime our manager was making arrangements to gather acid from any source, even acid in 20 gallon glass jugs from a battery company was flown to the desert in DC-3 airplanes. I had gone to our camp but could not communicate with the rig camp so I drove to the rig and told them to communicate with their office in Tripoli for confirmation which also was difficult. More than a day had gone by and we had assembled 20000 gallons of acid at our camp and had started transporting location before the proper communications clarifying the procedure were completed.
The time spent in Libya provided the opportunity to learn and apply developing evaluation techniques.
1965 – 1977 South Texas, Area Engineer[edit | edit source]
I had engineering and training assignments for fracturing, acidizing and cementing in the Texas Gulf Coast. Oil at $3/bbl and wells having low production did not support the well testing that I had gotten accustomed to in Libya. Production after stimulation, good or bad was usually attributed to the frac fluid and this presented a challenge.
I participated in the field development and proper application of new fluids; a viscous heated oil/water dispersion (SuperSandFrac), a poly-emulsion (SuperSandFrac K-1 or SSFK-1), and gelled and thickened diesel or crude oil. Water systems normally had 40lb/1000 gal polymer and were ‘improved’ to be super thick by increasing the polymer loads up to 100lb/1000 gal and/or cross linking. They all had unique mixing and pumping problems and later the water based fluids were shown to have cleanup and fracture damage problems. I was involved with all these fluids and championed increasing proppant concentrations and minimizing gel loadings. Cooke’s published work helped reverse the trend of high loadings.
Foam frac was a popular service for lower temperature wells but the sand concentration in the foamed slurry was limited because sand was only be added to the gelled water phase, about 30 percent of the slurry. The water phase was often 2% HCl to break the gel in the wellbore and improve cleanup. We were successful in eliminating the need for gel and could increased the sand concentration using a manifold recirculation method to keep high concentration of sand suspended prior to addition of nitrogen.
High sand concentrations were desired but were blamed for most of the treatment terminations caused by screenouts or reaching a surface pressure limit. The service supervisor had the responsibility to make sure the wellbore was flushed of the proppant at the end of the job. The surface treating pressure was often erratic and an unusual rise in pressure was believed to the start of a screenout; sand concentration was reduced in an attempt to prevent it. He usually based his decision on his experience with treating pressure patterns from other jobs. PRE NOLTE SMITH. The sand concentration being injected at the time was often used as a maximum for subsequent treatments. Later it became a common practice to calibrate the fluid loss coefficient to the value required for geometry models to predict a screen out.
I had been working on a pressure build up test from a fractured well using a new published technique but with little success when I attended my first ACT in San Antonio. Dr H. Ramey presented a paper that showed “fracture type curves” that were used to determine fracture orientation of underground nuclear tests. The ‘dimensionless type curves’ included fracture length which made it possible to obtain that value. I made a match with the small type curve in the paper. Some data from other wells did not. I called Ramey to ask for a copy and mentioned that fracture conductivity was often not infinite. He knew that and said he would send curves for finite conductivity. I got good matches and became hooked on type curves. Short courses on their use became available several years later.
I was involved in development of fracturing with large volumes of 28% HCl (Super X) with intermixing with pads and fluid loss control agents and the use of saturated gelled salt plugs for diversion and in re-acidizing.
Some time was devoted to problems in cementing 1000 ft liners in deep hot, 300+F, and over-pressured wells. The slurry weight to balance the pore pressure was very near the weight to fracture the formation. Mixing of cement slurry and drilling mud at their interface and causing gellation added to the problem.
I worked on identifying reason for problems in tubingless completions:cementing multi-strings of tubing in open hole by spotting cement with the first string and then inserting the next one or two strings. This required good fluid loss control and retardation of sufficient times to run the other strings, up to 12 hour and jobs were usually successful.
1977-1997 R&D Tulsa Engineering Specialist[edit | edit source]
In 1977 I was transferred to the R&D center in Tulsa with the same task of developing and transferring new technology to the field operations, but now on a broader scale affording more opportunities and contacts with others in industry working on these technologies. Our mechanical engineering department was assembling a computerized treatment-monitoring unit to monitor equipment performance and material blending ratios of liquid and solid additives along with the normal rate and treating pressure. This was about time Ken Nolte and Mike Smith introduced the four slopes of net treating pressure for fracture growth interpretations and the concept of treatment efficiency for pad determination. We were able to incorporate this technology on location with our pilot monitoring unit. Using this knowledge allowed higher sand concentrations to be injected, with little risk of screenout, while treating pressures were rising. It also pointed out the need for improvements in material mixing.
A stimulation of the Cotton Grove formation in central Oklahoma provided an opportunity evaluate the benefits of information gathered with the monitoring unit. An objective was to have a high final prop concentration of final stage of the treatments. When tip screenouts were recognized sand concentrations were ramped up and injection continued from 18-40 minutes on the seven wells. Indications of the four modes of fracture growth were all seen in this study. The first well appeared to have fissures and the use of 100 mesh sand in the pad to control leakoff was used in subsequent designs. Analysis during the study indicated that the tip sreenout could be attributed to 100 mesh sand remaining in the main fracture and not going into fissures. On later treatments the pad size ahead of the 100 mesh sand was increased allowing more proppant to be placed.Paper
Prior to the accessibility of reservoir simulators I developed various procedures demonstrating the utility of type curves in the optimization of treatments and post treatment evaluation and demonstrated how type curves can be used to better understand the sensitivity and importance of the various parameters such as a simple method to show the span of possible FcD-fracture length combinations that match prop volume injected with the post frac production Paper and how rectangular x/y dimensions and spacing affect production rates and reserve recovery. Paper 
I made a study of refracturing Paper comparing treating pressures of initial and refracture treaments. Lower treating pressures due reservoir pressure depletion, and higher net pressures due better height containment were seen. An example showed that height containment could have caused a screenout because of lower efficiency. A common belief has been that screenouts during refract treatments, even when occurring after sand had already been injected, were due to the presence of proppant from the initial treatment. This study found no prop interference during initial injections of fluid or proppant, an indication of a possible separate fracture plane.
The presence of a highly conductive fracture, indicated by a negative one half-slope of production on a type curve, is a poor candidate for refracturing. This was seen in an area were refracs were unsuccessful. However, in another area a well having such a fracture, identified by several transient tests, was refractured and produced at a much higher rate. This helped gather support for an investigation into refracture reorientation.
The growth of fracture geometry modeling to include height growth over multilayers having different mechanical properties but with entry in only one layer led me to develop model to show the injection rate distribution with multi-fractures. This also was used to improve ball-out designs. Paper
I retired from Schlumberger in 1997 and on occasions have been a consultant for them. Even though my focus did not change much during my career my knowledge sure did so it has not been boring. I have had the opportunity through Schlumberger, the SPE and a large number of clients worldwide to be involved in the many changes in the knowledge and application of hydraulic fracturing.