The Technologies that Conquered Unconventional

The Technologies that Conquered Unconventional Reservoirs Jorge Ponce Completion and Stimulation Sr Advisor

Disclaimer: This document is a compilation and transcriptions in certain cases from different sources from the public domain and from comments received from different people. Neither I nor the company I work for (Wintershall), make any warranty, expressed or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe upon privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by me or the company I work for. The views and opinions of the author expressed herein do not necessarily state or reflect those of Wintershall thereof.

Initial quote: “This history will never be completed, there will always be something new to insert or correct” Donald Kennedy

Introduction: Mostly everybody recognizes that the success in the current development of unconventional reservoirs is the result of four technologies: horizontal drilling, hydraulic fracturing, multi-stage completion techniques and micro-seismic mapping. The technologies alone could not make it, so they needed someone to spark them up. The relentless perseverance of Mr. George Mitchell, who did not put his arms down when preliminary results were not good at all was the igniter! and the rest is history. Some time ago I was searching when these technologies were successfully introduced in the market and how they ended up together. Unfortunately, I could not find a good timeline, so I decided to ask the SPE’s community for help. I received plenty of feedback and amazing stories. In addition, I did my homework, I dug deeper in my personal library and the internet and I asked other friends and colleges for extra help.

As I got a lot of information, my initial project grew in scope, so I decided to share it with the community. Even if I did my best, if someone finds information that is wrong or disagree with certain opinions, feel free to correct them or propose alternative facts. The intention is to have an evergreen document to capture this amazing story and its history. I am not a professional writer, so please my apologies.

Background for the development of unconventional resources: The seed of shale gas boom was planted in the late 1970s when the US government decided to fund R&D programs and provide tax credits (and incentive pricing) for developing unconventional natural resources in response to the severe natural gas shortage at that time. These policies that stimulated the development of shale gas in the Appalachian and Michigan Basin helped in the end to develop some key technologies such as micro-seismic mapping and further extended the application of existing technologies tailored for unconventional resources such as hydraulic fracturing and directional drilling. Initially these policies set the stage for the increased production of tight gas and coalbed methane (harvesting of low-hanging fruits first!). As early as 1968, the US Bureau of Mines began to examine the issue on how to extract unconventional gas resources. Several major studies commissioned by the Federal Power Commission, the Energy Research and Development Administration (ERDA) and the US Department of Energy (DOE) in the late 1970s suggested that the resource base of unconventional gas could be very large and the efforts to develop those resources should be encouraged and subsidized. A federal law in 1974 created the Energy Research and Development Administration (ERDA) by merging several separate research programs. In October 1977, DOE was created to consolidate on one agency the responsibilities for energy policy and R&D programs including those of ERDA. The programs initiated by ERDA in 1976 and continued by DOE in 1978 has three components: The Eastern Gas Shale Program, the Western Gas Sands Program and the Methane Recovery from Coalbeds Program. The Eastern Gas Shale Program was the most pertinent to the advance of shale development. The passage of the Natural Gas Policy Act of 1978 (NGPA), required phased removal of wellhead price controls and provided incentive pricing for developing new natural gas including gas from unconventional sources. The Gas Research Institute (GRI), a nonprofit organization was established by the gas industry in 1976 and began full operations in 1978. Its objectives were planning, managing, and financing R&D programs in all segments of the natural gas industry. GRI was fully funded by a surcharge on interstate natural gas transactions until 1998

when phaseout of the mandatory surcharge began. GRI managed a Devonian-age Antrim shale R&D program in the Michigan Basin from 1989 to 1995 accelerating its development. GRI also managed a coalbed methane R&D program from 1982 to 1996 which was terminated in 1982. GRI was also involved in R&D on tight gas sands in east Texas and at the Multi-well experiment in Colorado. The wellhead prices for Devonian shale and coal seams were deregulated on November 1st, 1979 doubling the prices of regulated gas. Due to the 1979 oil crisis, in 1980, the Crude Oil Windfall Profit Act was passed, part of which provided tax credits for unconventional fuels. Now the scope was broader not only including gas but also oil from shale and other sources. Unconventional wells spudded between January 01st, 1980 and December 31th, 1992 were eligible for tax credits and production from eligible wells would continue receiving credits until December 31th, 2002. In 2001, Nuclear Regulatory Commission (NRC), assessed the benefits and costs of several DOE R&D projects including those related to unconventional gas programs. The assessment included the evaluation of the most important technological innovations in the 1980s and 1990s and the role of DOE in developing those technologies. Three technologies were identified as critical for shale gas development: horizontal drilling, 3-D seismic imaging and hydraulic fracturing. Microseismic mapping was not fully developed and not analyzed in that report. The Eastern Gas Shale Program revitalized the shale gas drilling and development in the Appalachian (Devonian), Illinois and Michigan Basins, helped initiating the development of other previously over-looked shale gas basins and took the lead in demonstrating much more efficient and lower-cost shale gas production and recovery technologies. As part of the Western Gas Sands program, from 1994 to 1996, DOE and GRI jointly funded a research project at the Multi-well experiment site to further develop and validate hydraulic fracture mapping technology (micro-seismic), assess hydraulic fracturing mechanisms and improve hydraulic fracturing stimulation models through a more complete physical understanding of the process. However, it was the private entrepreneurship of Mitchell Energy that played the primary role in developing the Barnett shale in Texas. Government-sponsored R&D programs did not target the Barnett shale and tax credits had a rather limited impact on Mitchell Energy.

A brief history of oil and gas discoveries and well drilling: Just for the sake of remembering these important milestones I want to put in context when oil and gas were discovered in the world and when wells were drilled for extracting those hydrocarbons.

The Chinese were the first people to drill wells, in around 2000 BC, using the cable tool percussion method to produce brine. A chisel on bamboo rods was lowered into the well on cables 1-4 cm thick and woven from Indian reed. The first wells in Russia (percussion-rod method) were drilled in the 9th century and were also used to produce a solution of common salt. Gas was discovered in late 1825 in Fredonia, Chautauqua County, New York from a shale formation (Dunkirk shale) at a depth of 27 ft. Gunsmith William Hart noticed gas bubbling out of the bed of Canadaway Creek. He dug a slaty rock, with pick and shovel into the Devonian shale. The gas provided the light of two good candles and shortly it expanded to two stores, two shops and a grist mill. Gas was transported by pipes built with small wooden pump-logs with tar-laden cloth over their joints for a distance of several rods.

Site of the first commercial gas well in Fredonia, NY. Well was drilled by local businessman and entrepreneur William Aaron Hart (1797 – 1865). The world’s first drilling of an oil well, to a depth of 21 metres, took place on the Absheron peninsula (in the Bibi-Heybat region of Baku) in 1846 by Russian engineer F. N. Semyenov. Major Alekseev, director of the Baku oil fields, supervised the operation which employed the percussion method, with wooden rods. Prince Mikhail Vorontsov, Viceroy of the Caucasus, confirmed, in notes dated 8-14 July 1847, the completion of the world’s first oil well on the coast of the Caspian Sea (Bibi-Heybat), with positive results. In 1857, Preston Barmore (1831 – 1862), with the backing of Elias Forbes, purchased a small parcel of land on the east side of Canadaway Creek on which to drill two gas wells. The first well failed to produce gas. In the fall of 1857 the well was

stimulated with 8 pounds of gunpower at a depth of 122 ft. This event happened almost two years before the Drake’s well came in. The explosion expelled water in the shaft, followed by a plentiful supply of gas as reported on December 16 th, 1857 by the Fredonia Censor newspaper. He used lead pipes to transport the gas to a gasometer that was installed in downtown Fredonia to feed from there other places including street lamps.

Map of Fredonia area, including Canadaway Creek, Hart’s well and Barmore’s wells and gasometer

Gasometer in Center Street, Fredonia, NY circa 1964. Preston Barmore portrait. The first metered use of natural gas was in 1858. It was charged at USD 4.00 / 1,000 cubic ft. The history of the oil shale industry in the United States goes back to the 1850s; it dates back farther as a major enterprise than the petroleum industry. But although the United States contains the world’s largest known resource of oil shale, the US has not been a significant producer of shale oil since 1861. There were three major past attempts to establish an American oil shale industry: the 1850s; in the years during and after World War I; and in the 1970s and early 1980s. Each time, the oil shale industry failed because of competition from cheaper petroleum. In Canada, in 1858 the first oil well is drilled at Oil Springs (Petrolia), Ontario. In 1859 natural gas is discovered in New Brunswick. In US oil was discovered in Titusville, Pennsylvania on August 29th, 1859 by ‘Colonel’ Edwin L. Drake (actually he had never been a colonel, just a railway conductor). He was hired by Seneca Oil in 1858 to investigate suspected oil deposits by drilling in the manner of salt well drillers. On August 27, 1859 Drake’s drill reached 69.5 feet deep. As it was Saturday, work was stopped. The next day crude oil was rising up in the hole. It is estimated that the well produced between 20 to 40 bopd and was sold at 75 cents per barrel. He and his driller, William “Uncle Billy” Smith, used steampowered cable tool technology, an advancement from the ancient spring-pole. To increase efficiency, Drake had invented a “drive pipe”. Drake failed to patent his drilling invention. On October 07th, 1859 the well erupted in flames, perhaps America’s first oil well fire. The fire at the first well site comes slightly more than a month after the discovery. “The first oil well fire was started by ‘Uncle Billy,’ who went to inspect the oil in the vat with an open lamp, setting the gases alight. It burned the derrick, all the stored oil, and the driller’s home. Edward A. L. Roberts came to Titusville several years after “Colonel” Drake. As Drake can be considered the father of oil drilling, then Roberts may be considered the father of hydraulic fracturing. He invented the “Roberts torpedo”.

Edwin Drake, right, stands with friend Peter Wilson of Titusville, Pennsylvania, at the drilling site – but not the original derrick – of America’s first oil well. From the Drake Well Museum collection. Modern picture of the reconstructed site. Just four days after completion of America’s first commercial oil well in Pennsylvania in 1859, a second attempt nearby resulted in the first “dry hole” for the young U.S. petroleum industry. 22-year-old John Livingston Grandin began drilling America’s second well to be drilled for petroleum. Despite not finding the oil-producing formation (later called the Vanango Sands), the Grandin well produced technology firsts for the young exploration and production industry, including: first dry hole, first well in which tools stuck and first well “shot” with an explosive charge. Grandin knew of petroleum seeps on Gordon Run of the nearby Campbell Farm and rode south of town to buy the land. He bought 30 acres surrounding the oil spring at $10 per acre. The well was drilled using the time-honored spring-pole method which would reach almost twice as deep as Drake’s cable-tool effort. Drilling with the axle as a chisel worked well enlarging the borehole – until it became stuck at 134 feet, “where it never saw daylight again!” as described in a contemporary account. All attempts to retrieve the axle drill bit failed. A drilling tool was lost down-hole for the first time. To free the tool one of the drilling guys put together several makeshift “torpedoes” from blasting powder and experimented with timing fuses in hopes of breaking things loose. The explosion was sensibly felt upon the surface. Nothing was recovered and with this noteworthy effort, the Grandin well was ruined in the first recorded “shooting” of an oil well – and its first failure.

Warren County roadside marker remembering the Grandin Well (first dry hole). In December 1859, less than four months after Edwin Drake’s first America’s first oil discovery in Pennsylvania, a similarly determined wildcatter named Lyne (Lynis) Taliaferro Barret began searching in an East Texas area known as Oil Springs. Indians and early East Texas settlers had long known the Oil Springs area for its seepage and used the crude for its purported medicinal benefit for both themselves and their livestock. On December 15, 1859, Barret leased 279 acres near Oil Springs, about 13 miles southeast of Nacogdoches, from Lucy W. Skillern. He began drilling. Before he could find oil, the Civil War forced him to postpone his search. Barret’s quest for oil was quickly underway again as he secured another drilling contract with the heirs of Lucy Skillern on October 9, 1865. By December, he had joined with Benjamin P. Hollingsworth, Charles Hamilton, John Flint, and John B. Earle to form the Melrose Petroleum Oil Company. Barret would begin “making hole” with a simple drilling technology. On June 9, 1866, he contracted with Benjamin T. Kavanaugh for use of “Butler’s Improved Auger for Boring Wells” and a $50-dollar purchase of two augers, on eight and a half inches in diameter or thereabouts, and the other six and a half inches in diameter or thereabouts, with a coupling for the set for connecting the augers with the stem or poles for boring. Throughout the summer of 1866, the Melrose Petroleum Oil Company continued drilling and on September 12, 1866, Lyne Barret’s tenacity was rewarded. At a depth of 106 feet, the “No. 1 Isaac C. Skillern” struck oil. The well yielded a modest 10 barrels per day but remains nonetheless the first commercially producing oil well in Texas.

Oil Springs is on Farm Road 226 southeast of Nacogdoches. The birth of the Russian oil industry dates to 1864, when Colonel Ardalion Novosiltsev drilled the first oil well (to a depth of 55 metres) in Kuban in the Kudako river valley, by mechanical cable tool percussion. The first oil gusher was registered in February 1866. Ohio shale (Big Sandy field) was discovered in 1880. It is part of the Devonian shale which produces gas and was part of R&D efforts in the 1990s. The first Texas oil boom arrived in June 1894 when the Corsicana oilfield (North Texas area) was discovered by a drilling contractor hired by the city (Corsicana Water Development Company) to find water in Navarro County which is relatively close to the Barnett area hit oil at 1,025 ft of depth. The well was later put on production in October 1895. A refinery was established and production peak by 1900 to 829,000 bopd. The Nacogdoches oilfield remained the first and oldest in Texas and as late as 1941 still recorded production of eight barrels a day from 40 wells. Some of these produced into the 1950s. The much acclaimed Spindletop discovery in southeast Texas did not occur until January 10th, 1901. A gas production well was launched in Surakhany near Baku in 1901 at a plant owned by Vasily Kokorev. One year later, gas extracted from a depth of 207 metres was used to heat the plant; the gas was also transported to other areas of the Absheron fields via pipelines. The Surakhany well was the first in the world to be drilled for gas. The birth of the natural gas in Texas is credited to the Petrolia field in 1906. In 1901, James William Lochridge (1842 – 1909) owned a farm southeast of the current location of Petrolia, Texas. About this time there was a drought and remembering that his home place in Georgia had water wells, decided to drill one here. Enlisting

the help of a local man with a drilling machine, he drilled down to 150 feet. The driller explained they had hit a dry hole, but he insisted on continuing. At about 156 feet, on August 15, 1901, they struck oil. Since the world was just coming into the machine age, there was no ready market for it. It was good only for killing mites on chickens and greasing wagon wheels. The story goes that while he was in Henrietta, and explaining what had happened, several un-scrupulous bankers hearing the story and realizing the potential, took him to a saloon, and after several hours of drinking persuaded him to sign over most of his mineral rights for virtually nothing. This was the discovery well, and the first in the Permian Basin area that included North Texas and Southern Oklahoma. Shortly thereafter, The Texas Company, represented by W.B. Corlett, descended on the area and bought up all the mineral rights, usually at about 50 cents an acre. Drillers and Roustabouts set up a shanty town they named Oil City in the area, and during its heyday the population reached an estimated 1200. Soon thereafter, the Wichita Falls & Oklahoma Railroad laid a track through the area and across land platted by the Byers Brothers and named Petrolia after an oil producing town in Pennsylvania. Most of the people planning a more permanent life here, moved closer to the railroad and the current site of Petrolia. The oil at this level, 100 to 500 feet, was soon depleted and the industry declined. Drilling continued, however, as the field turned out to hold the largest known reserve of natural gas in the state. The first gas well was brought in on May 5, 1907, from a depth of 1,410 feet. The Lone Star Gas Company was created by partners George Washington Crawford (1861 – 1935) and Milo Clinton Treat (1841 – 1925), with the help of attorney L. B. Denning of Ohio, established the enterprise in Dallas as a pipeline company allied with Corsicana Refining. At the time, Crawford and Treat owned a drilling company in Marshall, Texas, and operated successful gas wells in several states as well as the Petrolia field, which was Lone Star's major source for gas east of Dallas. By 1909 lines were laid into Wichita Falls, making it the first city in Texas with municipal gas service. By 1913 gas was being pumped to nearby cities and by 1913 was serving Dallas, Fort Worth, and twenty-one other towns. To manage his growing business, Brown formed the Lone Star Gas Company in 1909 (the predecessor to TXU Gas Company). The gas Brown pumped to nearby towns contained .1 percent helium. In 1915 the United States Army built the first helium extraction plant in the country at Petrolia, and for several years the field was the sole source of helium for the country. Helium gas production decreased after World War I, and the field ceased operations completely in 1921, when a better source was discovered north of Amarillo. In 1910, deeper drilling was started, and the industry revived due to major discoveries. On December 17, 1910, a true gusher blew in; Dorthulia Dunn No. One produced 700 barrels a day from a depth of 1,600 feet. The company was the J.M. Guffey Petroleum Company of Beaumont, which later became the Gulf Oil Corporation. The primary objective prior to 1910 had been to locate gas. By 1925 it was evident that the field was entering the final stages of depletion and the cost of extraction was becoming prohibitive. However, another field discovered in

December 1918 was the first one. The Amarillo Oil Company’s Masterson nº 1 was drilled on Gould’s John Ray Dome prospect in Northern Potter County, TX and came in at 15 MMscfgd at a depth of 1,670 ft. This was later called the Panhandle field. Texon was founded on May 23th, 1923 when oi was discovered and named for the Texon Oil and Land Company which drilled the first successful oil well in the Permian basin. Carl Cromwell, a driller working for Texon, brought in Santa Rita nº 1, the first gusher in the Permian Basin, on May 28th, 1923. The first truly commercial and massive shale development was the Barnett shale. The discovery well in 1981 was only tested because of it resemblance with the Devonian shale play of the Appalachian Basin. Although this play is a gas shale as development progressed some minor areas were found to be oil bearing.

Horizontal drilling: The history… Horizontal drilling as we know it today, it is the conjunction of several technologies which include survey systems, bottom hole assemblies, MWD/LWD tools, bits, down-hole motors, mud, etc. With the advent of computerized downhole telemetry and durable downhole motors in the 1980s directional or horizontal drilling became widespread and economic viability was demonstrated by several projects such as Rospo Mare field in Italy (1982) by Elf Aquitaine, Prudhoe Bay field in Alaska (1984) by BP and ARCO, Austin Chalk in TX (1985 – 1987) by Oryx, Mobil, Amoco and Union Pacific Resources, Dan oil field in Denmark (1987) by Maersk and Bima and Arjuna fields in Indonesia (1996 – 1997) by ARCO. But it took a long way to reach the point we are at today. So to pave the road… In 1873, the American H.G. Cross patented a machine with a hydraulic single-stage turbine for well drilling and a turbine down-hole motor was constructed in 1883. However, neither invention was implemented. In 1890, Baku engineer K.G. Simchenko developed a turbo-drill (a rotational downhole hydraulic motor for rotary drilling). He received a patent for the invention five years later. In 1897 another engineer from Baku, V.N. Delov, developed a turbo-drill and later received a patent for his percussion electric drill on a cable. In the early 20th century, a Polish expert, Volsky, invented a rapid-percussion down-hole hydraulic drilling motor (ram of Volsky), which found a practical industrial application and became a prototype for contemporary down-hole hydro-percussions. Engineer M.A. Kapelyushnikov (1886-1959) elaborated and tested single stage turbo drilling with reduction gear in 1922-1923, marking a fundamentally new direction in the development of technology and techniques in oil and gas well drilling. The first 600m deep well was drilled in Surakhany in 1924 using Matvei Kapelyushnikov’s turbo drill. In 1938, N.V. Alexandrov and A.P. Ostrovsky developed an electro-drill in which the bit was rotated by a wholly new submersible motor. The first well drilled in 1940 using

Alexandrov and Ostrovsky’s advance was in the Azerbaijani Gala field. In 1936-1940 Eyub Taghiyev was one of a group of engineers who devised a strong, multi-stage, direct-drive, turbo-drill able to compete with rotary drilling and turbine drilling became predominant in the USSR. Professor Taghiyev was awarded the State (Stalin) Prize three times for his scientific work: in 1942 for the development of turbine drilling; in 1947 for directional side-drilling; and in 1952 for simultaneous drilling. The turbo-drills invented were to be significant in the drilling of deviating wells. In 1941, an oil well 2000m deep was drilled successfully by Aga-Neymatulla’s team in Ilyich bay by turbine directional drilling. Drilling a well starts with a bit so…in 1909, Walter Benona Sharp (1870 – 1912) and Howard R. Hughes, Sr. (1869 – 1924) were granted an US patent for the first twocone bit (US Pat 930,759). Around 1906 Hughes was conducting the first experiments to replace the fishtailbit. According to various histories, at least six other people did early work on their own versions of the invention, but Hughes' technical savvy, impulsive streak, legal acumen and Harvard connections helped him win the race to the patent office, affording him exclusive rights to a perfected dual-cone rotary bit. In 1908, the Hughes Tool Company was founded by business partners Walter Benona Sharp and Howard R. Hughes, Sr., father of Howard R. Hughes, Jr. That year, they developed the first two-cone drill bit, designed to enable rotary drilling in harder, deeper formations than was possible with earlier fishtail bits. They conducted two secret tests on a drilling rig in Goose Creek, Texas. In the finest tradition of oil-field secrecy, they boxed it, hid it in a burlap sack and ordered everyone off the well site while they attached it to the drill pipe. The drill pipe twisted off on the first test, but the second was extremely successful. Once the bit was lowered, the crew was called back in. In 11 hours, it cut a 1,000-foot well in a field otherwise deemed hopeless. The brutal efficiency of the tool earned it the name Rock Eater. In a 1915 presentation to the American Institute of Mining Engineers, Hughes showed how his device achieved a 75 percent reduction in drilling costs per foot. In 1933, Hughes Tool engineers created a tri-cone rotary drill bit, and from 1934 to 1951 Hughes's market share approached 100%. The Sharp-Hughes Rock Bit found virtually all the oil discovered during the initial years of rotary drilling. In 1959, Hughes introduced self-lubricating, sealed bearing rock bits. After collecting data from thousands of bits runs, Hughes introduced the first comprehensive guides to efficient drilling practices in 1960; in 1964 saw the introduction of the X-Line rock bits, combining new cutting structure designs and hydraulic jets.

First two-cone bit invented by Hughes and patented in 1909. Bit on the rig “substructure” Reuben Carlton "Carl" Baker, Sr. (1872 – 1957) received a patent in 1907 on a casing shoe (rotary casing shoe) that revolutionized well cementing and thus launched Baker Oil Tools. In 1921 he started working on an improved and simplified dump bailer and also a cement retainer.

R. C. Baker and H. R. Hughes, Sr. Since the invention of the carbide-supported polycrystalline diamond cutter (PDC) by General Electric in 1971 (US Pat 3745623A), this technology has impacted nearly all material removal industries. After being introduced into the drilling industry at HTC by GE Carboloy in late 1972, the PDC cutter and bit technology progressed slowly for several years. The major innovation was an “O” ring sealed journal bearing tungsten carbide insert (TCI). This bit provided a step-change in performance, with bit life and reliability increasing several folds. In July 1973, GE had arranged for the

first test run of one of its early bit designs to be made on an Exxon well on King Ranch in South Texas. Bit cleaning was thought to be an issue in portions of the run; three cutters failed at their braze joint, and two cutters broke through the carbide studs. Subsequently, a second bit with improved hydraulics to focus on the cleaning of the cutters was run in Hudson, Colo., where it was reported to have drilled fast in a sand-shale sequence, but it deviated significantly from the prescribed well path and again suffered several lost cutters due to suspected braze joint problems. In April 1974, the third bit was run in San Juan, Utah. It had an improved stud design and improved bit profile. It replaced three mill tooth bits on an offset well but suffered from a lost nozzle and damage to the bit, thought to have occurred at the end of the run from running into a hard formation or from the lost nozzle. A fourth bit, this time a mineral exploration core bit, was run in early 1974 in an iron mine in Upper Michigan, drilling into hematite strata, where the offsets were typically natural surface set diamond bits. Through 1974-76, cutter improvements were evaluated by established bit companies and entrepreneurs. Many of the issues that had been identified were addressed. The solutions were incorporated into the Stratapax product line of PDC cutters, which was introduced commercially by GE in December 1976. Several shapes and configurations became commercially available. It was a period of much innovation and learning, although the rate of penetration of PDC technology into the drill bit market was still slow. US Synthetic entered the PDC cutter market in 1983. Starting by working in collaboration with customer-driven proprietary cutter development programs focused totally on the drilling market from 1991 forward, they became the market share leader in 1997 and still hold that position. They are a leading supplier focused only on the drilling market. They were the first to commercialize a tough durable PDC cutter. The properties of the cutters were gradually improved, and the long substrate cutter that had been introduced was much more adaptable to the matrix-style bit technology that was adapted from the surface-set bits and became favored for this product line. The ability to predict where these bits would work best was gaining momentum as application expertise was improved. Today, most bit manufacturers use computational fluid dynamics (CFD) as a part of their bit hydraulics design process. Bits may be optimized for cleaning, erosion or cooling, depending on the demands of a particular application. The technology of horizontal wells itself can be traced back to September 08th, 1891, when the first patent was granted to John Smalley Campbell (patent number 459,152) for equipment to place a horizontal hole from a vertical well using flexible shafts. While the prime application described in the patent was dental, the patent also carefully covered use of his flexible shafts at much larger and heavier physical scales “... such, for example, as those used in engineer’s shops for drilling holes in boiler-plates or other like heavy work which covered oilfield applications. It can be considered the first short-radius drilling device.

Patent granted to J. S. Campbell for his flexible driving shaft. Bernard Granville of New York applied for patent coverage on drilling apparatus in 1919 for drilling horizontal holes extending out from a main bore. He hoped to reach a radius of several hundred feet with his apparatus. In 1929 and 1930 he received a patent protection on two types of heavy duty flexible drive shafts which were invented to drill lateral drain holes.

One of the patents B. Granville received for his invention. The first deliberately deviated wells were drilled in the late 1920s. Hardwood wedges were used, pushing the bit to one side of the hole and producing a deflection to direct the wells from vertical toward an intended direction. Between 1922 and 1931 four other patents were granted on different apparatus invented for the same purpose but all of them seemed impractical. Probably they all failed because they were not designed with sufficient strength to drill laterals successfully. In 1929, Cicero C. Brown founded Brown Oil Tools in Houston. In 1937, he filed for a patent which was awarded in January 1940 on the first liner hanger (US Pat 2,186,324) that allowed drillers to lengthen their casing strings without having the liner extend all the way to the surface saving capital cost and reducing the weight borne by rigs. The patent was titled packer and setting tool combination. In 1929, H. John Eastman introduced “controlled directional drilling” in Huntington Beach, California using whipstocks and magnetic survey instruments to deflect the drill pipe from shore-based rigs to reach oil deposits offshore. Prior to 1929, the Bureau of Mines was making certain experiments on the movement of oil in different reservoirs. Robert E. Lee from Coleman, Texas was attending the experiments. He had an idea to use an air actuated bit (percussion bit) to cut lateral holes. He designed and tested the apparatus and he filed for a patent in 1930. Fields tests showed that a rotary bit would be better, so Lee redesigned the apparatus and built an improved equipment. The new equipment was used to drill lateral holes in several wells in Texas fields. The assembly consisted of four main parts – a deflector section for forcing the bit to drill in a certain desired direction, an air driven bit and reamer for drilling the lateral, a set of drilling segments directly above the bit which flexed in one direction only and locked at the limit of the bend, and a similar set of non-locking segments run above the locking sections and connecting with the conventional drill stem. This BHA was successfully used to drill the first truly lateral holes in 1929 at Texon, Texas, for the Big Lake Oil Co. Two 5 ¼” lateral holes were drilled out 23 to 24 ft horizontally into the St. Andrews Lime at depth of about 3,000 ft. The well increased production approximately 40 times.

Lee tried to verify that the wells were horizontals, so he made the first survey of a drain hole in 1931. He used a set of acid bottles in short segmented barrels and from these drift records he established that the bit was forced to drill on a very short radius. In fact, one well turned upward to form a “U”. Sometime in 1939, Lee started to redesign his angular drilling tool to overcome the disadvantages proved by experience using air. Cutting removal was problematic and compressors expensive and dangerous. He modified the system, so the bit was driven by rotating the drill pipe at the surface like in conventional drilling. Drilling fluid was used to lubricate and cool the bearings on the drive shaft and universal joints, as well as to remove cuttings. This improved version was first tested in Brown County, Texas. Three 25ft lateral holes were drilled at a depth of 2,600 ft. Water was employed as circulating fluid. The 5 ¼” bit worked as planned and better than the previous model. Well increased production almost 7 times. In one well that produced oil, no increase on production was observed. It was theorized that maybe water was causing some problems, so he decided to use oil as circulating fluid. It would also serve as lubricant for the moving parts. In 1935 and 1936 a number of wells were worked out in Shackelford County, Texas using 30º gravity oil. Mostly all wells received 4 to 6 holes in the producing zone. Laterals extended out 12 to 15 ft. Lee continued enhancing the tool. In 1931 he proposed a new tool that allowed drilling two sets of lateral holes one above the other. A patent was awarded in 1931 for this invention. In 1941, Leo Ranney described a method for drilling horizontal holes, but the tool had to be sunk in a downhole chamber of sufficient size to accommodate the drilling equipment. This tool resembles a modern one to drill horizontal holes close to the surface like those used for river crossing (HDD). Another inventor, John Zublin, was also interested in drilling horizontal wells. He invented a novel type of rotary bit. First patent was filed in December 1941 on a tool to drill laterally from the main bore into

the productive zone. It consisted of two types of flexible drill pipe and a fluid operated turbine motor with a special bit. It was not planned to rotate the pipe. Each section was lined with high pressure hose which was riveted at the ends of the flexible pipe to conduct fluid without leakage. A special curved section was manufactured where a definite radius of curvature was machined, and the material was heat treated to retain its curved form. The turbine motor and bit assembly were as short as possible. Drilling mud of high viscosity was used to move the turbine motor which ultimately rotated the bit. The curved pipe forced the bit to bite into the wall of the original hole making a hole on it. This was the first system that did not use a whipstock to deflect the bit. Once the curved section was created, the assembly was pulled out of the hole and the curved section removed. Drilling was resumed with the bit on the flexible pipe. Zublin’s second patent covered a simple mechanism for forcing the bit to enter the mouth of the lateral recently or partially drilled. Drilling was not out of problems. Drilling fluid was very light mud or water. This equipment was field tried on two wells in the Midway-Sunset field in California’s San Joaquin Valley oil zones. Three drain holes were drilled in one well in lengths from 52 to 72 ft. In 1947, the helical slot cut in the pipe was redesigned to give it more strength. Sometime in 1948 the use of the turbine was abandoned, and the tools were redesigned once again. Ordinary bits could be used, motor was eliminated, and the flexible and curved pipe were made to rotate a tricone bit. Zublin’s drill guide and deflector had received attention to start lateral holes in hard formations. Eastman developed a set of tools that took ideas from directional drilling. A universal knuckle joint was used to force the drilling equipment to increase drift as it drills. At the time, 4 ¾” and 3 ¾” bits were used, and two different tool sizes were available as well. The system consisted of two separate assemblies; a whipstock and protective casing assembly and a drilling tool assembly. The whipstock forces the bit to increase angle at a uniform rate and ensure that the point of deviation is at the exact depth in the correct direction. This conceptual design is the same we use today. The drilling section consisted of several flexible collars, a universal knuckle joint, the bit and other sub-assemblies. Flexible collars were approximately 16 ft length sections. A special type of 3 lobe clover leaf cut is made through the collars. The cuts are done to provide the flexibility required for the task. The width can be adjusted for different radius of bending. Drilling process was like what we currently do, so I will not describe it here. I want to finalize this short paragraph with something anecdotical I found during my research, that CIA was interested in the different technologies related to deviated or lateral drilling. In 2011 a declassified document from 1957 (CIA-RDP78-03642A002400070001-7), called a “letter” and secret at the time, presented in some detail a summary of technologies developed for deviated or lateral drilling. It mentioned that the “letter” is consequence of a “task” but it is not described which it was. In the document copies from different public magazines related to the different technologies were attached. I am not going to make any assumptions why they were interested in…I will leave it to your imagination.

Records from two wells drilled in Huntington Beach, California, in 1930 are the first records from directionally controlled boreholes drilled from an onshore location to oil/gas deposits under the ocean (offshore). In 1934, a blowout occurred in a field owned by Humble Oil Company of Conroe, Texas. A gas kick from a high-pressure zone ignited, and the entire rig was engulfed in flames. After many months and attempts to bring the fire under control, other nearby rigs had to be closed down and the entire field was threatened. H. John Eastman, with his experience using whipstocks and surveying instruments, used a mobile drilling truck to drill a directional relief well close enough to the blowout well, killing the blowout on the first attempt what we would consider today the world’s first relief well. Eastman gained notoriety and respect for directional drilling techniques. The oil industry subsequently accepted directional drilling as a reliable technique. In July 1955, J. S. McCune and W. E. Hanks filled for a patent (US Pat 27,955,752A) for a flexible drill collar which was granted in March 1952. The patent took ideas from two previous patents granted to B. Granville (US pat 1,739,756) granted in December 1929 for a flexible shaft and to J. A. Zublin (US Pat 2,515,366) in July 1950 for a heavy duty flexible drill pipe.

The first downhole drilling motors or mud motors were designed and manufactured by Dyna-Drill in 1958. The motor was based on the 1930 Moineau design for progressive cavity pumps. Mud motors were first used for directional control of boreholes in the 1960s. A bent sub (a short component for connecting two longer collars) was positioned directly on top of the mud motor. Positive displacement motors (PDM) are used to build inclination and frequently to drill the horizontal section of medium and long-radius horizontal wells using drilling mud as the power source. In the early 1990s, a positive displacement motor designed specifically for air drilling has been developed to operate without requiring lubrication. Experience shows that the motor is reliable, and it will become more effective through design improvement and experience. This technology led to the first air-drilled horizontal well with a PDM in 1986 (well Ret#1). In July 1966, R. H. Cullen et al. filled for a patent (US Pat 3,446,297A) for a flexible drill collar which was granted in May 1969.

Flexible drill collar patent extract depicting the idea and BHA design.

Evolution of directional drilling.

It’s likely that basic stabilized rotary bottom hole assembly (BHA) designs with drill collars for weight and stiffness, together with stabilizers precisely positioned for inclination control while drilling, originated in the 1940s. The modern history of short radius drilling began by the end of the 1970s. The introduction of improved articulated-collar systems allowed turning from vertical to horizontal plane in a small space but there were limitations mainly inherent to the design itself. The system was difficult to operate and somewhat inefficient. The articulated collars were difficult to handle, and plastic and rubber were quickly eroded by pressure, temperature and mechanical interactions. It was not possible to correct azimuth once the well was deflected from the whipstock and well direction could only be controlled within 20º of the proposed azimuth. Surveying was time consuming and it was difficult to apply weight on bit. Penetration rate was low. Horizontal displacement has a practical limit of about 600 ft. Despite the limitations, the system has been used to drill multiple horizontal wells. In 1988, five horizontal wells were drilled with this technology in the Antrim shale formation in Michigan. Mahlon Dennis, invented the PDC cutters that were used to build the world’s first PDC bit at Exxon in 1974. The bit was run on the King Ranch. It had started drilling three times as fast as a roller bit. It was called a drag bit because it has no moving parts. But there was a problem with it. The cutters, that were braced on the bit, tended to fall off occasionally. When the problem with the cutters was fixed a new company was created to commercialize PDC bits called Stratabit, the world’s first PDC bit company. In 1976 engineers from MERC patented an early directional drilling technique. The other innovation that really made ERD wells practical to drill was the Rotary Steerable System. The early VertiTrak and AccuTrak tools of Baker Hughes evolved into a means to achieve pinpoint control of the wellbore placement in the desired location. In the 2000's, this combined technology is what made it possible and practical to drill some of the world's most famous ERD wells at Wytch farm and Sakhalin Island, controlling the wellbore over thousands of feet horizontally, while maintaining the TVD in a +/- 3 feet window in the reservoir's sweet spot. At the start of this Wytch Farm operation there were no rotary steerable tools available at the time, but it brought to the development of systems like the Camco's RST (which was later taken over by Schlumberger). The first 10km step-out well was drilled entirely with "conventional" bent housing motors and a variable gauge stabilizer which worked well for inclination adjustments but with no control for azimuth. Robert Zilles pioneered many of the RSS drilling procedures for Baker Hughes Inteq and is considered the Grandfather of RSS technology. In 1993, Baker Hughes Inteq in partnership with Agip S.p.A. developed the Rotary Closed Loop System (RCLS).

Components of the RCLS system.

Control capabilities of the tool.

Timeline of the evolution of automated drilling systems as reported by Schlumberger. In 1997 AutoTrak Curve Rotary steerable system was introduced in the market. It can build high angles quickly. It eliminates the need of orienting or sliding for steering and minimizes the number of trips to change bottom hole assembly for different directional profiles.

9 ½” Autotrak G3 RCLS

Horizontal wells Primitive horizontal drilling technology appeared in the field in the late 1920s. In 1929, the first truly horizontal wells were drilled at Texon, Texas. In 1944 in the Franklin Heavy Oil field, Venango County, Pennsylvania a horizontal well was drilled

at a depth of 500 ft. Many horizontal wells were drilled in China as early as 1957 and the USSR during the 1950's and 1960's, with limited success. This was to change at the end of the 1970s: at that time Elf (now part of the Total Group) was faced with the challenge of developing Rospo Mare, offshore Italy, which was a heavy oil field in karstic formations, with very active aquifer. Building up on the previous Russian experience, Elf launched an R&D program with the support of IFP, so-called FORHOR ("Forage Horizontal", or Horizontal Drilling in French). This led to two pilot horizontal wells in 1980 on the Lacq field (South West of France), Lacq 90 and Lacq 91, to demonstrate drilling and completion feasibility; and then to the first-ever offshore development by horizontal wells in Rospo Mare in 1981-1983. In 1973, the first horizontal well in the Appalachian Basin was drilled by the Pittsburgh Bureau of Mines in Greene County, Pennsylvania, near the town of Jollytown, Pennsylvania. The 414 ft horizontal well was drilled for CBM degasification ahead of active mining operations. In 1978, at Cold Lake, Alberta, Canada, the first horizontal well was drilled. ARCO (American Richfield Co.) Oil and Gas drilled two horizontal wells in the Empire Abo unit located in the Empire Abo Pool of Eddy County, New Mexico. Reservoir rock was a dolomite known as the Permian (Lowe Leonard) Abo reef dolomite. Wells were drilled to evaluate the mechanical feasibility of the drilling process and the effect producing through the drain holes would have on the well’s tendencies to gas conning. The first well (K-142) was spudded in July 1979. Once the landing zone was identified by open hole logs and drill stem tests the bore was cased and cemented with 7” casing. A whipstock was used to deviate the well from the vertical. After drilling 106 ft the operations were halted due to increased torque caused by a corkscrewed hole. This was caused mainly by the system used to drill the lateral section: the flexible drill collars and a specially designed angle building bottom hole assembly. Surveys were taken with an Eastman Whipstock type A single shot. During the completion process, the well was swabbed for several days resulting in little recovery. A CT run was used to inject N2 in an attempt to clean the well out. The well flowed intermittently, after a few days it was flowing oil at very low flowing pressure to the test tank. A pump jack was installed by mid-October 1979 and the well was put on pumping without experiencing major gas conning. The well was never acidized as traditionally done in other previous wells to get production. Based on the results on the K-142, a second well (Empire Abo Unit J-213) was spudded in March 1980. Once the vertical section was drilled, based on open hole logs and drill stem tests, the landing zone was selected. The whipstock was set an oriented. After turning from the vertical to the horizontal, the well started climbing in angle but attempts to drop the angle were unsuccessful. After drilling 126 ft of drain hole, the drilling operations were suspended. The problem was identified as caused by the angle building bottom hole assembly that was drilling for a long time. This happened by the late May 1980.

The first horizontal hole longer than 1,000 ft was drilled as part of an ARCO project in 1984-85. In Austin chalk (Pearsall field near San Antonio in Frio County, TX), the first permit for a horizontal well was granted to Exxon in 1984 close to Giddings. The first modern horizontal holes were drilled in France by Elf Aquitaine as part of a research and development program with the Institut Francais du Pétrole: two in Lacq and one in Castéra-Lou as reported by Giger in 1984. A fourth well was drilled was drilled at Rospo Mare where Elf is operator for an association which includes Agip. These were land wells. The objective of the first two wells was to understand and develop the technology that was required for effective production of Rospo Mare reservoir, offshore Italy in the Adriatic Sea. The wells drilled at Lacq Supérieur were at a relative shallow depth of around 2,000 ft. First well was Lacq-90 drilled in 1979, and its horizontal section was 360 ft long and completed with an uncemented slotted liner. The second well was Lacq-91 and had a horizontal section of 1,120 ft long. Various completion techniques were tried in this well to isolate part of the well and to reduce water influx. The third well was Castéra-Lou-110 and was used to demonstrate the feasibility of drilling at a depth of 9,000 ft and to experiment with different completion techniques. This well had 490 ft of horizontal section. This well produced more than eight times compared to vertical wells thus proving the viability of the concept. Rospo Mare (RSM-6), the next horizontal well, was drilled in the main target of the research wells. Reservoir rock was a carbonate with very low porosity and permeability containing heavy oil. A 9 5/8” pilot was drilled first and an 8 ½” horizontal section was 2,000 ft long. The well produced more than twenty times that of the other existing wells in the same field. The next major development in horizontal drilling was led by Maersk Oil & Gas in Dan field. These wells presented multiple challenges not only in the drilling phase but also in the completion phase. Specialized tools, fracturing materials and techniques were developed. Issues were addressed and resolved through collaborative efforts between Maersk, Halliburton and Baker Oil Tools. First medium radius horizontal well was drilled in the Austin Chalk in May 1985 by ARCO. The John G. Hubbard nº 1 in Rockwall, TX was a 1,500 ft lateral well with 20º/100 ft build rate. In 1986, DOE, BDM Corporation and Eneger Corporation drilled a 2,000 ft horizontal well in Devonian shale in Wayne County, West Virginia. Total horizontal displacement was 3,186 ft from vertical. The well Ret-1 was drilled in the Cabwaylingo State Forest becoming the first and longest air-drilled horizontal well in the Appalachian basin. 660 ft of 16” casing followed by 2,024 ft of 11 ¾” casing was landed in the well. External casing packers were used to isolate different intervals for ulterior stimulation.

Atlantic Richfield Indonesia Inc. (ARCO) initiated a horizontal well drilling program in 1986 to develop the Bima field in the Java Sea. First well (ZUD-3) was drilled in January 1986 using a conventional drilling system. Although originally designed to be drilled with conventional rotary drilling, after drilling 13 wells by August 1986, it was sooner realized that due to changes into the pay zone dip and other complexities, it would be necessary a navigation system. It was decided to change the drilling system. An orientable tool was required. In addition, pipe conveyed logging technology was chosen for open hole logs. The system selected consisted of a bit, a positive displacement mud motor, a specially designed double tilted U-joint (DTU) and a MWD system. MWD also provided resistivity and gamma ray. This tool was called RGD standing for Resistivity-Gamma-Directional tool. The use of it became quickly and standard procedure to overcome the unpredictable behavior of the formation and to respond to changing lithology. After logging experience was gained, it was discovered that logs from MWD were enough and no other logs were necessary. The elimination of the conventional log suite and conveyance method provided substantial cost saving in terms of money and time and reduced risks. The assembly could be oriented in a similar way as a standard mud motor / bent sub combination to drill and arc or it could be rotated with the drill string to drill a straight hole segment. Horizontal sections as long as 2,351 ft were drilled during the first phase of the project that last from 1986 to 1987 where sixteen horizontal and high angle wells were drilled. Wells were designed using conventional long radius method. The adopted system provided substantial advantages and benefits. Wells were mostly completed with 7” uncemented pre-drilled liners and an acid stimulation (15 % ClH) on CT was the preferred completion methodology. While long radius drilling was being developed and refined in the Far East, medium radius horizontal drilling was being applied for the first time in North America in the Austin Chalk play in Central Texas. The Williston Basin has had the largest concentration of horizontal wells by 1990. Meridian and other operators in 1987 drilled medium radius horizontal wells in this area to develop the Bakken shale and Red River formations. Wells were drilled in 8 ¾” and horizontal length averaged 2,500 ft and often exceeded 3,000 ft. MWD systems were typically incorporated into BHAs for both angle build and horizontal section to guide the assembly to such thin target zones. In the Giddings field in the Austin Chalk, wells were drilled in 1987 – 1988 were drilled with the first medium radius wells which had non-rotating fixed angle build motors which had two or three bends, oriented in the same plane and were stabilized at the top and the bottom. Build rates of approximately 20º/100 ft were common following a curve with a 286 ft radius. Drilling proceeded at constant build angle. Tangent and horizontal sections were drilled with a steerable motor system incorporating a DTU of the same basic design as those used in long radius. PDC were used as bits. Typical TVD was about 8,500 ft. Operator at the time concluded that horizontal drilling is viable only when a team of experienced professionals from

both sides, company and service contractors, are involved in planning and execution. Anything new? We always reached the same conclusions no matter what year it is. In late 1989, horizontal drilling activity moved to the Pearsall field in South Texas. Wells were designed to achieve about 1,800 ft of horizontal displacement at an inclination angle of about 86º at TVD of 7,000 ft where some wells were drilled at shallow TVDs. No tangent sections were used at the time. Most Pearsall wells were drilled underbalanced. MWD systems were used on both fields for steering and surveying. Rick Stone, then with Oryx, is credited with beginning the horizontal drilling trend in the Chalk with the idea of drilling perpendicular to the natural fractures. This began a large drilling boom in the 80's and 90's. There were no majors there or even large independents. It was companies like Oryx, Chesepeake, Clayton Williams, etc. doing the drilling. This is also when Rick Stone founded Signa Engineering. Many wells were re-entered and kicked off with whipstocks, and when retrievable whipstocks were utilized to allow multi-laterals to be completed. In 1989 and 1990, a DOE-industry partnership drilled three horizontal wells that identified the technical barriers to widespread application of underbalanced drilling in the US. During early 1989 Maersk Oil & Gas drilled the first horizontal well (TEB-1) in the Tyra field, offshore Denmark. The Tyra reservoir is a gas bearing chalk that has extensive sub-vertical hairline fractures. Well was spud on December 19th, 1988 aboard the jack-up Glomar Moray Firth and took 70 days until the liner setting operations. The previous sections of the well, prior the pilot section, were drilled without major difficulties. The 8 ½” pilot-hole interval was logged down and up with a drill pipe-conveyed logging string. No difficulties were encountered even with the use of the wet connector and logs quality were acceptable. RFT, OB image logs and CBL/VDL were also run on the same conveyance method. Drilling of the 8 ½” horizontal section was completed at 13,660 ft MD leaving 3,276 ft of horizontal section and a departure from the vertical of 10,515 ft. The horizontal section was also open-hole logged with a drill pipe-conveyed logging string including standard logs and RFTs. No problems were detected during these operations. The bore was cased with 6 5/8” liner with a rotatable liner hanger. The liner was cemented in place with full returns and rotation throughout the operation. The quality of the cement was evaluated with different tools including segment bond tools showing fair to good cement along the interval. Well was perforated and acidized during completion. In February 1989, a five-well program of 6” horizontal reentries began in Piedras Coloradas, Mendoza, Argentina as three previous vertical wells proved fruitless. A fully retrievable MWD system, a double bend fully adjustable mud motor and a special PDC for long life and high build appliactions were used. All five wells were drilled in record time averaging a horizontal extension of about 985 ft and build rates of 12-14º/100 ft. Vertical depth ranged from 6,560 to 8,200 ft.

In 1989, Amoco initiated a project to develop a short radius lateral drilling system with the objectives of developing a system that was easy to operate, low cost, easy to repair, able to drill a predictable and consistent radius of curvature in a desired direction, capable of being operated using a power swivel and able to work in small casing diameters (4 ½”). Following development of prototypes, more than 200 wells were drilled at Amoco’s Catoosa test facility near Tulsa, OK. After initial testing, several wells were drilled at Amoco’s Levelland Unit. The system was known as the “Rotary Steerable System” and was introduced commercially. Since 1995 hundreds of wells have been drilled. The system was purely mechanical. There were no mud motors or expensive electronics downhole. Bit rotation is derived from the power swivel with continuous pipe rotation throughout the curve and lateral drilling process. Radius of curvature generally ranged from 30 to 100 ft. In the late 1980s, in the Continental Deep Drilling (KTB) project in southern Germany, the first system to control deviation while drilling was tested. Initial development work started in 1979. It was designed for vertical drilling by Schwing Hydraulik Elektronik and Deutsche Montan Technologie (DMT) as a joint venture. The system measured the inclination continuously during drilling process and corrected minor deviations from plumb by immediate counter steering. A similar system for mining, tunneling and civil engineering had been in use worldwide since 1984 but for depths up to 600 m. Based on this initial development, the automatic drilling system for vertical deep-drilling to a depth of 4,000 m was commenced in 1988. The project concluded in June 1990 with the completion of a prototype called ZBE 5000. Dome Petroleum drilled a short radius well in Drumheller in 1987 with "wigglies" - an interesting project, presented at the CADE/CAODC Spring Drilling Conference in April 1989, and subsequently in OGJ. One of the two Directional Drillers, Scott, is the son of John Zublin, who did much of the early work (in the USA) on horizontal drilling, along with H.John Eastman, in the 1950s and 1960s. During winter 1987 several wells were re-entried in the Neuquén and Mendoza basin (Argentina). At the same time and with the same equipment several wells were reentried in US. The drilling assembly consisted of a diamond bit, high speed motor with a bent housing, mule-shoe orienting sub with a built-in float valve, non-magnetic survey collars and slick drill pipe. All wells were cased with slotted liners. In 1987, when the oil industry recession hit its low, Maersk (partnership with Moller, Total and Texaco) began experimenting in its Dan field in the Danish sector of the North Sea. The reservoir was a low permeability chalk that produced oil. Production had begun in 1972. Production from deviated and hydraulically fractured wells declined rapidly. Following the lead of Shell researchers in The Hague, The Netherlands and of F. M. Giger at the Institut Francais du Petrole, reservoir engineers compared expected PI from horizontal boreholes with conventional designs which provided the initial insight to test horizontal wells as a potential

solution to increase oil production. In 1978, however, few horizontal wells had been drilled anywhere, and none had been fractured. Cementing and perforating conventional liner in a horizontal well, necessary to isolate zones for hydraulic fracturing, was regarded as too difficult at the time. By 1986, Maersk considered that cementing a liner was something technically feasible and it decided to attempt the industry’s first horizontal, hydraulically fractured well. Initial commitment was to drill and evaluate three horizontal wells. The first well, MFB-14, was planned to tap a horizontal drain of 1,000 ft in the most permeable of the Dan field formation (upper Maastrichtian chalk). The intended stimulation was acid fracturing. It was a long radius well, so conventional tools could fit down the hole. Trajectory was planned to minimize torque and drag. The well was drilled using a steerable motor. It performed flawlessly except in the lower chalk that overlies the Maastrichtian where chert stringers deviated the bit causing a high angle. Well was plugged back and the well was drilled with a super stiff BHA to keep the hole on track. Well was cemented using Dowell Schlumberger’s latex based cementing formulations. Hole was 8 ½” and cased with 5 ½” liner, with multiple centralizers to ensure proper centralization. The liner was also rotated while cementing. Cement bond tools showed adequate cement along the interval. Tough Logging Condition (TLC) tool showed that the well was out of the formation after been drilled about 330 ft. The well trajectory was at the right position, but formation was dipping causing a deviation out of the zone of interest. Despite the problems encountered while drilling, the well produced triple the rate of the best conventional well. Production declined steeply during the first three months. Production logs on CT showed that most of the production was coming from the two fractures in the more productive zone. Except for the problem of chert stringers, drilling had been relatively uneventful. The next well, MFB-15, went out 2,500 ft. A 7” liner was run and cemented in place without problems in 1988. Drilling proceeded on schedule using a pilot well to adjust landing zone. The last well of the series was MFB-13, which was drilled without a pilot well. Drilling of the 2,600 ft lateral drain proceeded without incidents. Well was put on production in June 1988. Shell in UK set a record at the time with the Cormorant A-13 well with a departure of 4.7 km in 1988. Shell’s Tern A-5 well achieved a departure of 5 km while Galleon well PN-02 achieved a departure of 5.7 km. In 1989 began the development of horizontal drilling in Entre Lomas, Tapera Avendaño, Medanito, Puesto Hernández and Chihuido de la Sierra Negra fields in Neuquén basin (Neuquén province) and Piedras Coloradas field in Cuyana Basin (Mendoza province), all in Argentina. In all cases well were designed for mediumradius trajectories (build angles of 8 – 12º/100 ft. Horizontal sections ranged from 984 ft to 1,968 ft. Horizontal sections were cased with 5 ½” casing or tapered strings combining 7” and 5 ½” casing. In Norway in 1989/1990, Statoil and Norsk Hydro drilled C-10 well which achieved 5 km departure. The first 6 km (6.1 km) departure well in the industry was achieved by Stafjord well C3 in 1991.

Before 1990, horizontal drilling was not a popular technique. The oil industry only drilled horizontal wells in difficult situations as a last resort. The global total for 1989 was just over 200 horizontal wells. In 1990, that total leapt to almost 1,200 wells, with nearly 1,000 of these drilled in the US.

Number of horizontal wells drilled on a yearly basis.

Ultra-short-radius drilling systems’ milestones Oryx Energy Co., Dallas, held the displacement record for medium radius wells in the 1990 survey with 4,164 ft at 2 Stroman-Harris in Pearsall field, Texas. Oryx earlier in March 1990 broke that record at 1 Haley, in Zavala County, Tex., where displacement was 4,242 ft. The first well they drilled was a complete mechanical failure, the second got out about 200 ft and next got out even more. The success of Mobil Erdgas-Erdöl GmbH's (MEEG) first horizontal well, the Siedenburg Z17 in 1990, promoted the widespread use of short, ultra-short, and medium-radius drilling technologies in North Germany by the time. Initial production

was a six-fold increase compared to a vertical offset. Since then, MEEG drilled more than 20 horizontal wells in North Germany. True vertical depths (TVDs) for these wells range from 270 to 4,940 m, with build rates of 92°/30 m for ultra-short radius to 3-5°/30 m for long-radius wells. In total, MEEG drilled 10 short-radius and ultrashort radius wells in North Germany from 1990 to 1996. The 7-in. liner, set through the boundary of the Tertiary clay/Cretaceous pay zone proved to be a critical welldesign issue concerning proper zonal isolation. The liner was rotated during cementation. In addition, an inflatable external casing-packer was run near the casing shoe to provide a contingency for any problems encountered during the cement job. The wells were drilled with a common small oil field rig, ITAG's National 108. The only additional equipment needed was a hydraulic top-drive, necessary for drilling the horizontal sections. The short-radius BHAs was the one developed by Baker Hughes Inteq. A near-bit inclination sensor located 1.6 m behind the bit made the steering process much easier. Modifications of the short-radius BHA allowed a change from fully oriented "snake" drilling (sliding) to rotary drilling with a slow rotational speed of 10-12 rpm. This method, combined with the use of the near-bit inclination sensor provided excellent steerability and led to a straight, smooth well path in the horizontal section. It was possible to increase the horizontal section length beyond 600 m. Platform Irene well #A-21 was completed in July 1991 in the Pt. Pedernales Field, offshore California operated by Unocal with Amoco Corp., Chevron Corp., Elf Aquitane, Exxon Corp. and Mobil Corp. as partners. The well broke two records at the time, the longest horizontal displacement at 14,671 ft and the longest pay zone section at 5,990 ft. The fact that this displacement was achieved at a true vertical depth (TVD) of only 5,033′ makes the accomplishment of this feat even more significant. The wells were not truly horizontal - they followed the Monterey shale which was the producing formation. A-21 reached 71.1º deviation. They were at the extreme of extended reach for the time, however. Some of the work was presented by John Hood in a 1992 technical paper. In November 1991, Maersk O&G completed the world’s longest horizontal well at the time at Tyra West Bravo field, TWB-11a in the Danish sector of the North Sea. The horizontal extension record was 2,500 m. Cliff O&G drilled the deepest horizontal well at the time in the North Bayou Jack field in Louisiana in September 1991. The well reach TD at a TVD of 4,675 m. Unocal drilled the well C-29, drilled from platform C in the Dos Cuadras field offshore Santa Barbara channel in California in 1991 with the greatest DDI of 3.95 at the time. In July 1991 from the Irene platform offshore California, the well A-21 was drilled to a total lateral reach of 4,472 m and had the longest pay zone section of 1,826 m. Woodside in 1991, drilled a long ERD gas well from North Rankin A platform in Australia. The well reached 5009 m and a MD of 6,180 m.

Following a failed ERD attempt in 1991 (Arbroath T-14 well), Amoco UK drilled well T-19 achieving a departure of 4.6 km in 1992. That achievement was extended with the SEER-T-12 which achieved a departure of 6.4 km in 1993. Designer wells are another well geometry. These wells were drilled in geological complex Gullfaks field in the Norwegian sector of the North Sea. The field has complex reservoir, which many normal and reverse faults. Typically, the designer well path involves a strong change in the horizontal plane (30 to 150º degrees azimuth) at high deviation combined with turns to both sides (right and left) with turns not restricted by inclinations and the ability to be placed as dictated by geology. The second well, Spirit Energy 76 Sweet Lake, had a complex trajectory starting a section at 33º and then dropping 2.5º/100 ft while turning 182º and building back to 55º inclination at 3º/100 ft.

Examples of a Designer well drilled in Gullfaks field. In 1992, well A-36 reached 5 km departure in the Gullfaks field resulting in a June 1992 ratio of 2.79 which was among the highest at that time. In 1993, BP began the ERD campaign in Wytch Farm. M-2 well was drilled to a departure of 6760 m in late 1994 and M-3 well to 6818 m in early 1995. The first ERD well (M-5) was drilled in Wytch Farm with a length of 8,715 mMD using RSS from Camco Ltd. The second well (M-11) set a record mark of 10,658 mMD.

Well design of the first ERD drilled by BP in Wytch Farm, UK. In 1992/1993, Statoil’s 33/9-C-2 well set a record and broke the 7 km (7.29 km) departure barrier for the first time in the industry. Prior to this record the first three ERD wells (33/9-C-10, 33/9-C-3 and 33/9-C-24) had horizontal reachs of 5006 m, 6086 m and 5679 m. Prior to this well, well 34/10-B-14 was the first well drilled with a displacement greater than planned. The well 34/10-B-14A was died-tracked from 34/10-B-14. The well was completed in March 1991 with a MD/TVD ratio of 2.08. Foinaven was the first field to be developed in the deep water, West of Shetland. The discovery well 204/24A-2 was drilled in the autumn of 1992. Most of the development wells had extended reach horizontal or high angle sections. Horizontal lengths reached about 3,280 ft. Wells were drilled using a steerable system which included a MWD system tied into the gyro survey. First production occurred in November 26th, 1997. Wells were completed with open hole completions including sand screens and external casing packers (ECP) to isolate the various sand bodies. In 1994 Maersk Qatar set several world records with its wells Al Shaheen 2 and 3. The wells involved horizontal sections of 3.1 km and 3.9 km for total departures around 3.8 to 4.6 km. DDI were 3.2 to 4.3. In 1994, Norsk Hydro’s C-26 well extended this achievement further and set a new record for well departure reaching 7.85 km. In 1995, Total Austral Argentina, Deminex (currently Wintershall-Dea), and Pan American Energy drilled their first extended-reach well, the HNP-7, into one of the satellite fields of Hidra. Located near the Ara, Kaus, and Canadon Alfa fields along the east coast of Tierra del Fuego, this well achieved a South and North American extended-reach record by drilling to a measured depth (MD) of 6,982 m with a horizontal departure (HD) of 6,253 m. Two additional wells were drilled in this area. Because of the success of these wells in terms of cost and production, a seven-well onshore campaign was initiated from mid-1997 to late-1998 to develop oil and gas

accumulations in the Ara and Kaus fields. Three of these wells reached at least 8,000 m (MD) while the next to last well, the Cullen Sur No. 1 (CS-1), reached a TD of 8,687 m MD (8,107 m HD) in 83 days. After 3 months of fast-track engineering and procurement, this well was drilled and completed in 142 days, including a geological sidetrack. Located at the southern tip of South America in Tierra del Fuego, the Cullen Norte No. 1 set a world record 10,585 m of horizontal displacement, reaching a TD of 11,184 m in March 1999. A horizontal pickup-laydown machine allowed Total and Forasol to overcome space limitations associated with racking back 11 km of drill pipe in the derrick. This may be the first onshore application of this technology.

Well profiles for different ERD wells drilled by the consortium. The pilot-project Soehlingen Z10, drilled in 1994, was designed to produce gas from the Rotliegendes formation's Main sandstone. The goal was to combine two existing technologies: horizontal drilling and hydraulic fracturing. By drilling a 1,000 m horizontal section at 4,780 m TVD and casing it off with a cemented 7-in. liner, the gas should be produced through four hydraulic fracs perpendicular to the well bore axis. Build rates in the Rotliegendes formation were designed at 4.5°/100 ft, which later proved to be an acceptable value for directional work in these formations. Directional assemblies consisted of Navidrill Mach 1C positive displacement motors with an AKO Bent Housing set at 1.2-1.5° for the build section and 0.9-1.2° for the hold sections. For proper frac isolation in the horizontal section, perfect cementation of the 7-in. liner was essential. Oil-based mud (OBM) was used to lower the risk of differential sticking. The Soehlingen Z10 well broke several world records, including deepest horizontal well, deepest cemented liner, and deepest sidetrack at the time. In the horizontal section, the plug-back and sidetrack operations were carried out successfully. Production began in early 1995. All four fracs produced 33% more than expected. The project was an overall success. The first horizontal well in Argentina was a re-entry from an existing vertical well into the Mulichinco formation. The SCh-17 was drilled in the Sierra Chata gas field in the Chihuidos exploration block located in the Neuquén basin by Petrolera Santa Fé (a Devon Energy Corp subsidiary). On May 10th, 1999, the window was cut at 1,600 m depth and a medium radius system with a downhole motor and MWD was used to drill to 2975 m MD on June 15th, 1999, leaving 1,005 m of lateral drain exposed into

the formation. The well was cased with a 5” pre-perforated liner which became stuck at 2310 m where it was left. Well was perforated on TCP and put on production in July 1999. In May of 2008, Maersk Oil Qatar completed drilling its BD-04A - a horizontal well with a staggering length of 35,770 ft MDRT. It was reported that this well sets records for both the longest well, at 40,320 ft measured depth from the rotary table (MDRT) and the longest along hole departure of 37,956 ft MDRT. In 2017, Rosneft, as a member of Sakhalin-1 Consortium, successfully completed drilling of the world's longest well (O-14) from Orlan platform at Chaivo field in the Sea of Okhotsk using an extended reach technology known as “Fast Drill”, developed by US major ExxonMobil, who is a Consortium’s partner. The length of the well with horizontal completion is 15,000 m. This well has a DDI (Directional drilling index) of 8.0 and 14,129-m step-out.

Image from Merlin ERD Ltd web site. Accessed Oct 23th, 2018. Cuadrilla finished drilling the UK’s first horizontal shale gas well in April 2018 at Preston New Road, near Blackpool. The well was drilled at a depth of approximately 2,300m below ground and extended for about 800m. Well was spud on 11 January 2018. Cuadrilla reported by the end of Nov, 2018, that the well was making the first shale gas at very low rates.

Barnett Shale C. W. Slay No. 1 vertical well near Newark in Wise County, TX was drilled and completed in 1981. Originally the well was drilled to the Viola Limestone to a depth

of 7,856 ft and due to bit problems the well did not reach TD at 7,950 ft. The target formation proved unproductive after acidizing and the well was plugged back. The well was then perforated in the lower Barnett and after acidizing it showed a slight show of gas. Mud logging also indicated the presence of gas. Log looked encouraging when compared to the Devonian shale in the Appalachian basin. A stimulation job with nitrogen was performed creating a short fracture network. The well was put on production in 1982 with an initial potential of 246 Mscfgd. Production rate after cleanup was 120 Mscfgd in June 1982. In 1983, the well was reperforated and refractured with carbon dioxide foam. Production jumped to 274 Mscfgd but completion costs were prohibitive. Subsequent wells were stimulated with bigger nitrogen assisted gelled frac jobs. Initial potentials were reported in the range of 730 – 1,100 Mscfgd. Larger stimulation designs did not always result in consistent results. Still completion costs were high for big jobs. After multiple failed attempts, Mitchell Energy engineer’s Nick Steinsberger, finally successfully used a slick water frack on his fifth well, the S.H. Griffin nº 4, located near Ponder, Texas on June 11, 1998. He used twenty tanks of water and twelve powerful pumps to open the bedrock pores. Two tanks supplied the chemical additives: a friction reducing gel to make water more slippery and a bactericidal substance to kill micro-organisms that could have got into the waste liquid. No less than one million gallons (3.78 million liters) of water were pumped. After one-hour, fine sand was pumped. The water column had 2,500 meters, making an enormous pressure on the bottom of the well on the Barnett shale. The results were astonishing: while normal wells were producing 1-2 million cubic meters of gas during the first 90 days of production, the S.H. Griffin #4, massively fractured with water, produced in the same interval 3.3 million cubic meters. First horizontal well drilled and completed in Barnett shale was an isolated joint project with GRI in late 1991 (Thomas P. Sim “B” 1H) with poorer production than vertical wells. It was completed as a cased and cemented well with external casing packers. Acidizing and ulterior frac stimulation were not successful. The next attempt was in 1998. A horizontal well of 1,700 ft of lateral drain and a MD of 8,628 ft was drilled in 1998 (L. B. Wilson GU nº 1) perpendicular to the induced frac direction and it was planned to have three frac stages from a re-entry of the Petty A-1 vertical well which was cased with 7” casing. The well was cased with 4 ½ in casing and was cemented. Originally it was designed as an uncemented completion but shale plugging issues in the T. P. Sims B-1 changed the decision. The well experienced high treatment pressure and it was considered that only the perfs close to the toe were effectively stimulated. It performed better than the first horizontal and in addition decline seemed to be much lower than in vertical wells. While this completion was not a complete success it was recognized as an excellent beginning. Based on the previous results another well (L. B. Wilson GU nº 2) with 2,700 ft of lateral drain parallel to the induced frac orientation was drilled as a new well in 1998. A single LSF stage was pumped but production results were unacceptable. An

attempt to drill a third horizontal well with a flexible string was not successful and no more horizontal wells were drilled by Mitchell Energy until Devon purchased the company. The merger took place on January 28 th, 2002. Devon agreed to pay Mitchell’s assets for 3.1 billion in cash and stocks and to assume 400 million in Mitchell’s debt. Six to ten wells were required to prove production results were encouraging.

White dots depict vertical wells and blue dots represent horizontal wells in the Barnett shale. In 1992 the first well was drilled and completed. LaFollette, 2010. In 2002 Mitchell Energy was bought by Devon Energy, a company based in Oklahoma City. The engineers working with Devon (Steinsberger among them) have come up with another revolutionary idea: the horizontal drilling. Until then all drillings were done vertically. In June and July 2002 Devon drilled its first horizontal well (Veale Ranch nº 1H) into the Barnett shale. The well was then fractured using 4,500 cubic meters of water. In October the same year Devon performed a second horizontal drilling, Graham Shoop nº 6. After 2002 horizontal drilling has become standard procedure for wells exploiting shale gas by hydraulic fracturing. The first horizontal well drilled by Devon was the Veale Ranch nº 1, W. Robinson survey, A-1274 in southwest Tarrant County. This was followed by two more: C. J.

Harrison A-2, D. Love survey, A-518 and the O. H. McAlister nº 16, Branlett & Ryan survey, A-123 both in the Wise County. All proposed wells were spudded in 2002 and by April 2003 all were on production. Initial production data was under substantial security measures by Devon but eventually they came up to the public domain. Production results were outstanding when compared with previous wells.

In 2007 multi-well pads in the Barnett shale. In subsequent years multiple companies were drilling and completing wells in different shales. First companies to jump in were mostly independent producers but later on, majors joined the pack. For example, in 2008 XTO (Exxon subsidiary) drilled its first four horizontal wells in the Haynesville shale portion located in Texas. The wells were put on production in 2009. Wells were drilled with OBM and cased and cemented. 10 to 15 frac stages per well using plug and perf methodology. Hybrid frac fluid design.

Multilaterals The first multilateral technology patent was filed in 1929 by Leo Ranney and was followed by additional patents and rudimentary attempts to drill multilateral wells in the 1930s. Some sources credit Leo Ranney with being the first to try horizontals and multilaterals in the United States. Ranney, a Canadian, was a consulting

engineer in Texas and Oklahoma. In 1925, he developed the Ranney method of using horizontal wells to extract oil from exhausted fields. Standard Oil Company of New Jersey bought out his patent and made him president of Ranney Oil and Mining Company, a subsidiary of Standard Oil from 1930 to 1938. In 1939, Ranney drilled an 8 ft (2.44 m) vertical shaft in Ohio, put men and equipment in the bottom of the hole and drilled a horizontal section. He is also reported to have drilled in a horizontal radial pattern like the spokes of a wheel, establishing probably the first multilateral with horizontal sections. After the war, an inventor, John A. Zublin, drilled horizontal “drainholes” for operators in California. In 1945, Zublin sidetracked a well with eight drainholes. He eventually re-entered about 250 vertical wells in California, West Texas, and Wyoming, with an average of two laterals. The first true multilateral well, 66/45, was drilled in 1953 by Alexander M. Grigoryan (1914 – 2005) in the Ishimbainefti field at Bashkiria, now Bashkortostan, Russia. Grigoryan graduated as a petroleum engineer from the Azerbaijan Industrial Institute in 1939. Two years later, he drilled one of the world’s first directional wells, the Baku 1385, using only a downhole hydraulic mud motor to drill the entire well bore. This is the first time a turbodrill was used for drilling both vertical and deviated sections of a borehole. The significant increase in reservoir exposure over vertical wells resulted in a corresponding significant increase in production and led to many more successful horizontal wells in the USSR. Grigoryan’s success in drilling innovation led to his promotion to department head at the All-Union Scientific Research Institute for Drilling Technology (VNIIBT) in Moscow, where he developed a new sidetrack kickoff technique and a device for stabilizing and controlling curvature without deflectors. In 1949, Grigoryan, expanding on the theoretical work of an American scientist, L. Yuren, proposed branched boreholes to increase production in the same way a tree root extends its exposure to the soil. He tested his theory in 1953 when he drilled Well 66/45 using only turbodrills without rotating drill strings, cement bridges, or whipstocks. The well had nine branches, each extending 262.5 ft to 984 ft (80 m to 300 m). From 1953 to 1980, 110 more multilateral wells were drilled in East Siberia, West Ukraine and near the Black Sea. Thirty of these wells were drilled by Grigoryan, who is recognized as the father of multilateral technology. In the 1980s, Grigoryan moved to Los Angeles, Calif., and opened a company named Grigoryan BranchedHorizontal Wells. Grigoryan received recognition in 2003 as a Technology Pioneer by Offshore Energy Center’s Ocean Star Offshore Drilling Rig and Museum. Thanks to the pioneering efforts of Grigoryan, Multilaterals began to take off in the United States in the 1980s. Arco drilled the K-142 dual lateral well in New Mexico in 1980, and UPRC drilled 1,000 multilaterals in the Austin Chalk from the 1980s to 1998. In June 1988, Pluspetrol decided to re-enter the R-15 well located in the Ramos field, in the Northwestern basin in the Salta province in Argentina. The intention was to drill a multilateral well into the naturally fractured quarzitic sandstones in Huamampampa, Icla and Santa Rosa formations that produced gas. The re-entry work drilled 1,148 ft of horizontal section being the first horizontal well in the area. A dual completion was run and the well put on production. The KOP for the first branch

was at 9,235 ft with a length of 3,284 ft. The KOP for the second branch was at 9,065 ft with a length of 3,120 ft. The well was completed with a MLT level 3. Previously, in 1997 the well R-1006 was drilled horizontally with an extension of 3,610 ft. As the results were poor a second lateral from the same pilot was drilled with an extension of 2,296 ft. During 1998, the R-1008 was horizontally drilled with an extension of 1,968 ft. This well was the first step in drilling a multilateral well from an existing vertical well. Between 1998 and 1999, the R-1010 was drilled with two sub-horizontal branches into the Huamampampa formation becoming the first multilateral well in the area. The first leg was completed with a 7” slotted liner. The liner was not cemented. The second branch was cased with a 7” slotted liner. The completion was run without major problems and the well was put on production. It was in the 1990s when “modern” multilaterals began as systems were built to create multilateral junctions that went beyond simply sidetracking a well and provided new capabilities. Modern multilateral systems fall into categories of Level 3 through Level 6, and significant milestones with these systems came in quick succession: • 1993 – 1st Level 3 multilateral, Shell, Alberta, Canada. • 1994 – 1st Level 4 multilateral, Shell, Alberta, Canada. • 1995 – 1st Level 5 multilateral, BP, Gulf of Mexico, US. • 1996 – 1st through-tubing multilateral intervention. • 1997 – Technical Advancement of Multi-Laterals (TAML) formed. With such growth in the number of multilateral systems, installations and well complexities, a Shell Expro engineer, Eric Diggins, decided to form an operators group to share worldwide multilateral experiences, establish an informal network of contacts, and provide a more unified direction for the development of multilateral technology. The kick-off meeting was held in the Expro offices in Aberdeen, Scotland in March 1997. Participants included BP, Norsk Hydro, Statoil, Esso UK, Exxon, Mobil, Phillips, Maersk, Texaco, Total, Chevron, Shell Oil, Shell International E&P and Shell UK Expro. One of the new group’s tasks was to create a Classification System for Multilaterals. The results were published in 1998 and included two tiers, a complexity ranking and a functionality classification. The higher the ranking, the higher the complexity. In 2002, some minor changes were made to the complexity ranking definitions to accommodate new multilateral systems that had entered the market. While the organization began as an operators’ forum, service companies were included in a portion of the face-to-face meetings. In 2001, a service company hosted a TAML meeting for the first time, and membership eventually became open to operators, service companies, and academia. With input from TAML and the continued effort of the service companies to provide improved tools, the evolution of multilateral technology has continued with additional milestones: • 1998 – multilaterals started evolving toward intelligent wells.

• 1998 – 1st deepwater Level 5 from a floating rig, Petrobras, Brazil. • 1999 – 1st Level 6, AERA Energy, California. • 1999 – 1st intelligent multilateral, Level 2, BP, UK. • 2002 – 1st multilateral system floated in, Level 3, Chevron, China. • 2002 – 1st intelligent Level 6, CNOOC, Indonesia. More than 50 years after that first multilateral by Grigoryan, the estimated number of multilateral junctions installed through the end of 2006 is estimated to be greater than 8,000. Level 1 and 2 multilaterals have become so common that those numbers are no longer tracked by the industry, and the actual number of installations could be as high as 10,000. While all countries in which Level 1 and 2 installations cannot be determined, there are a minimum of 29 countries on six of the seven continents covered by the remaining levels. Multilateral technology is neither new nor emerging, but even with global numbers in the thousands, it is still not considered mature by the industry. Multilaterals have not yet reached the acceptance level of horizontal wells, but with the economic incentives the technology offers in terms of reduced well count and equal or greater number of penetrations into the reservoir, it makes sense to evaluate projects for possible candidates, especially where horizontals are already being drilled. The challenges of multi-fracturing of each leg in unconventional reservoirs has been field tested by several operators, but it did not reach a full development, because costs and risks were extraordinarily high. The first comprehensive plan for a multilateral well was prepared by a joint team comprised of Mobil Germany and Halliburton European Research Centre. The target was the deep gas field in Soelingen, Germany. These were HPHT wells. The plan was approved by the European Community under the Joule-Thermie project. Joule/Thermie initiative was focused on the cost-effective, environmentally-friendly and targeted demonstration and promotion of clean and efficient energy technologies. These consist of: renewable energy technologies; rational use of energy in industry, buildings and transport; and cleaner and more efficient use of solid fuels and hydrocarbons. Essentially, the program, supported actions which aim to prove both the technological and economic viability and validity of energy technologies by highlighting their benefits and by assuring a wider replication and market penetration both in the EU and globally. The objectives of the project were to drill and complete a dual lateral well with commingled production, at minimum risk and cost, and to monitor and report the production performance. The major step change was the installation of a cemented junction with connectivity, isolation and re-entry capabilities that was not done before. However, the complex nature of the field caused the plan to be replaced to drill the multilateral off of a well in Forties field offshore UK, operated by BP. This multilateral was later executed in 1996 (well FA12). The well was deviated from a 9 5/8” main bore and after drilling it was cased and cemented with a 7” liner. The junction was cemented with a new sealant called M-seal. The lateral bore reservoir section was drilled and completed with 4 ½” liner.

After some well conditioning, the access tools were tested and both bores successfully entered. The well was perforated and put on production in 1997. Norsk Hydro, Halliburton and Weatherford completed successfully the first multilateral well in Oseberg C-12C in the central North Sea in April 1996. Discussions about multilaterals well construction were initiated by December 1994 and technical requirements were defined by late January 1995 and sent out to all potential service providers. The well had a 9 5/8” main bore located in the slanted part of the well and the lateral had an 8 ½” bore cased and cemented with a 7” liner. The well was drilled to 4,734 mMD (1,150 m of lateral drian) but it was cased to 4,662 mMD due to due the presence of tight spots that caused well pack-off during wiper trips. The junction needed to satisfy the requirements for connectivity, isolation and access for future interventions. Halliburton developed a system in record time which was designed and tested just in time for the running process. The liner was tied back into the main bore above the junction and cemented. A special cement formulation was developed in the junction area to increase junction resistance to impacts caused by moving tools string through it. The lateral bore was drilled using a retrievable solid whipstock which was removed once the lateral drain was drilled and replaced with a hollow whipstock. To enter the lateral, a fullbore diverter was designed which included a full gage diverter, orienting lock key, and a lock mechanism that could be run either on CT or wireline. Many obstacles were overcome during the planning and execution phases through team work and full dedication. The success of this project formed the launching for many new and more innovative multilaterals. Norsk Hydro decided to drill three additional multilaterals wells in 1996 based on these results. The dual-lateral Siedenburg Z6 was completed in 1996. It was designed to produce a largely depleted sour gas field. The first lateral had an ultra-short build section of 98°/30 m and a turning radius of 18 m. The second lateral had a short-build section of 57°/30 m with a turning radius of 30 m. Because of budget restraints, only 41 m of the planned 150 m of the ultra-short build section were drilled. The second lateral used a retrievable whipstock in order to cut a casing window. After drilling the shortradius curve, 370 m of horizontal section was drilled without severe problems. The retrievable whipstock could not be recovered, and the entry to the first ultra-short radius lateral could not be reopened. The acidizing job was done by bullheading the formation. Despite this drawback, the well was economical. There was a six-fold increase in production as compared to a vertical well.

Logging and Surveying Earliest survey systems were used in late 1890 for mining applications based on the acid bottle principle. The initial single shots were mechanical drift indicators. A sharp pin when hitting a paper made a mark on it giving the deviation from the vertical. As the devices were

not originally oriented the deviation was just absolute without knowing to what geographical orientation. In 1926, Sun Oil enlisted Sperry Corporation to use gyroscopic-based technology to make survey instruments for accurately measuring borehole inclination and direction. Elmer Sperry developed the first gyro system for oilfield applications. In 1929 John Eastman developed the first magnetic single-shot and multi-shot instruments, which measured both inclination and direction. In 1933 this technology was used on well D.W. Hardin nº 8 located in Hobbs, New Mexico. Gearhart Industries was an independent oil well service company that was founded by Marvin Gearhart and Harrold Owen in 1955 and based in Fort Worth, Texas, United States. Gearhart and Owen had been employees of Welex Jet Services, also located in Fort Worth. Gearhart had been the Chief Logging Engineer while Owen was the Chief Explosives Engineer. It was Welex who had developed the explosive lined shaped charge used for well perforation. As now competitors to Welex, GO was unable to buy perforating charges and in turn developed their own, with a lawsuit by Welex being the result. In 1962, the court's ruling went in favor of GO, but only after the United States Justice Department stepped in and eased the apparent constraint of trade. Being forced to manufacture their own perforating line was apparently a positive step for GO, as they grew to be the largest supplier of jet charges in the world. The Perforating Supply Company (PSC) was formed as a subsidiary of GO, and made perforating supplies readily available to other independent wireline companies. Over the next six years, many perforating companies were started, with GO providing both the technical and financial aid. In 1964, GO bought Electronic Instruments and the company's name was soon changed to Gearhart-Owen Industries (GOI). By the early 1970s with Harrold Owen going in the direction of explosive manufacturing, Marvin Gearhart had decided that he wanted to crack the lucrative open-hole logging market that was dominated by Schlumberger, Dresser-Atlas, and Welex. A man named Ralph Spinnler with Teleco started working on the MWD (Measurement While Drilling) systems in 1972. During the same year, Gearhart began development of a new series of open hole tools and computer system to analyze the findings. In only 14 months the system was completed and entered its test phase. The new Direct Digital Logging (DDL) system surpassed by leaps and bounds the current analog systems employed by its competition and went into service in 1975 creating large revenues for the company. During the 1970s Fort Worth had now become a research and development center. Gearhart researchers were concentrating on a new technology called Measure While Drilling (MWD). This new product was being developed for market by the same team that had given life to DDL earlier. MWD was what made controlled directional horizontal drilling possible. MWD saved time and money over the traditional methods of wireline logging by eliminating the wireline. After a few years of testing, Gearhart and its Canadian affiliate, Computalog, were gaining advances over their

competition. MWD had now become a process desired by competing companies. By 1983, as an investment, General Electric had bought 25% of Gearhart's stock with rumors of a total buyout of the company. Instead GE informed him that its shares in the company had been sold to Smith International, a competitor to some of Gearhart's divisions. Smith now made a move to buy just enough stock to gain control of the company. Gearhart decided to fight that move, at first through unsuccessful court appeals and later by acquiring the large geophysical company, Geosource. Geosource's size rivaled Gearhart's and the merger indebted Gearhart to the point it was no longer attractive to Smith. In 1986, Gearhart had become the world's third largest wireline logging company. After over 30 years of fulfilling his dream, Marvin Gearhart's company was up for sale. Late in 1987, its Canadian partner Computalog had signed a letter of intent with Gearhart providing for the possible restructuring and whole acquisition of the company. By February of the following year it was ready and told the Gearhart management of the plan. On February 24, 1988 it was announced that Gearhart was entering into a buyout agreement with oilfield service giant Halliburton Company. Within Halliburton it was merged with Welex Jet Services to become Halliburton Logging Services completing the circle which began 33 years earlier. Also, Halliburton later in 1993-94' also acquired the division of Smith International, DataDril, that was to have originally been combined with Gearhart's MWD division. In 1977, the first surface recording gyros were introduced where accelerometers replaced mechanical plumb bobs and resolvers tracked gyro orientation. It was developed per a request of a major operator in the North Sea who wanted to drill from a 60-well-slot jacket and had concerns about well separation. In 1978, the first MWD system was deployed. Magnetometers replaced mechanical compasses and accelerometers replaced angle units. Data was converted to binary and sent to surface as pulses for quick interpretation. Mud-pulse telemetry is currently the most common method of transmitting measurement-while-drilling (MWD) and logging-while-drilling (LWD) data. Advances in downhole sensing for drilling optimization and formation evaluation are placing heavy demands on equipment to provide faster data rates from greater depths. As a result, mud-pulse telemetry rates have improved to more than 20 bits/sec (bps) at depths shallower than 20,000 ft, and more than 3 bps from depths of more than 36,000 ft. In 1978, a typical data rate was 0.4 bps. Various telemetry systems are in use: wired pipe, mud pulse, electromagnetic, and acoustic. Mud-pulse telemetry has proven to be reliable and cost-effective and is the most common MWD telemetry system. The earliest telemetry patent was issued in 1929, but current mud-pulse telemetry systems date from work by J.J. Arps published in 1964. Earliest reference to actual attempts to log continuously while drilling through telemetry went back to the 1930s when J. C. Karcher of Geophysical Service Inc. in Dallas insulated the drill bit from the drill string with a section made of Bakelite of about 4 – 5 ft long and provided an electrical conduit to the surface by mounting insulated conducting rods

in each section of the drill pipe. Appropriate electrical connectors were used to link rods. At the top an insulated slip ring with a brush provided the electrical connection to surface equipment such as an ohmmeter. Continuous resistivity was recorded in core drilling and reported as successfully at the time. D. G. Hawthorn and J. E. Owen of Amerada’s Geophysical Research Corp. in Tulsa, in the 1930s, developed an insulated steel drill collar and a new type of drill pipe which had an electrical cable permanently brazed inside each pipe joint and a special connector as well. Bakelite was also used for insulating purposes. To overcome the inherent problems of both systems, D. Silverman of Stanolind Oil & Gas Co’s Research Dept. in Tulsa designed a connector that allowed running a cable inside the drill pipe and pulling it back out again. Several jobs were performed in the Seal Beach field in California. The main drawback was the need of running and pulling out the cable each time a drill pipe was added. The numerous challenges of these technologies led to the use of other methods such as the electromagnetic waves in their different wave types that do not need a cable to be transmitted. Although waves provided more flexibility, there were other problems such as signal attenuation that was a severe issue for deep wells or for certain formations such the Gulf Coast. One attempt, that was patented, was the transmission of acoustic or seismic signals through either the drill pipe, the earth or the mud stream. Very high acoustic noise level at surface was the weaknesses of the method. To enhance the transmission, another patent proposed to install relay stations along the drill string. In the same period several patents disclosed a method to carry the information signal in the form of electrolytically released radioactive tracers, hydrogen or radioactive pellets. These methods were not introduced commercially at the time but the idea of installing relays or similar devices to improve signal transmission has been used by Halliburton in its commercial system to send data from downhole devices to surface. Arps Corp’s developed a system that used acoustic waves which were generated by the modulation of mud flow thorough a specially designed valve. As the pulses generated by the throttling valve are very low in pressure and last only momentarily, they do not affect the pressure of the system. This system has been the preferred method ever since. Teleco introduced the first commercial MWD mud-pulse tool in 1978. This tool transmitted directional information to surface at about 0.4 bps. Data rates stabilized in the 1980s and 1990s at 0.4 to 3 bps. This rate was sufficient to transmit reliably MWD and LWD data at that time. In the 1990s, development of new LWD tools and introduction of rotary steerable drilling systems and real-time drilling dynamics tools placed considerable pressure on the ability of this transmission link to maintain data density. In response, engineers developed a reliable MWD telemetry system that was delivering unprecedented raw data rates by the close of 2007. In the early 1960s, Mobil Oil published a patent (Godbey, John K., US Patent 3309656, “Logging-while-drilling system,” published Mar. 14, 1967) for an LWD system using a rotary valve to transmit data to the surface called the “screamer”. This transmitter used a continuous wave up to 24 hz and transmitted data by phase-shifting the signal to encode the data. The system had a source signal amplitude of 100 psi and was successfully tested at

rates up to 3 bps downhole. Schlumberger adapted this idea of using a rotary valve in the development of its “Mud Siren.” In 1978, the first commercial MWD system marketed by Teleco Oilfield Services Inc. (Stone, Frederick A., US Patent 4266606, “Hydraulic circuit for borehole telemetry apparatus,” published May 12, 1981 contained a hydraulically driven poppet valve, powered by a powerful multistage turbine and oil pump. In contrast to the small signal amplitudes of rotary valves, the Teleco pulser created strong, discrete signals easily detected on surface, even from deep wells or in situations with high pump noise. This pulser achieved data rates up to 2 bps in commercial applications. Dresser Industries developed another commonly used mud-pulser system, especially suited to the low electrical power consumption required of battery-powered MWD systems (Jeter, John D., US Patent 3065416, “Well apparatus,” published Nov. 20, 1962. The initial system monitored the revolutions of a downhole turbine and Spinnler, at Teleco, used an electrically driven pilot valve to drive a main valve for mud-pulse telemetry (Spinnler, Ralph F., US Patent 3958217, “Pilot operated mud-pulse valve,” published May 18, 1976. Design optimizations continued after the 1992 merger of Eastman Christensen and Teleco. These companies were incorporated into Baker Hughes INTEQ in 1993. These pulser systems provided sufficient telemetry data rate to deliver the required data density to surface when there was relatively low availability of real-time formation evaluation services and relatively low ROP. With the introduction of rotary closed coop drilling systems, penetration rates increased dramatically. The available telemetry data rates led to ROP restrictions or low data density. In addition, an expansion of LWD and MWD services put severe demands on the available MWD transmission data rate. In 1977, the US Energy and Development Administration published a report giving a broad overview of the available MWD and telemetry systems. By the early 2000s, not much had changed in terms of data rate or mudpulse systems, although the systems had been optimized for reliability.

A rotationally oscillating shear-valve pulser tool can generate discrete pressure pulses and continuous wave signals in borehole fluids. The existing systems delivered either strong, discrete pulses or low- amplitude continuous waves. Engineers needed a new pulser combining both options to ensure independence from the highly variable drilling environment: deep or shallow wells, oil- or water-based mud systems, complex or simple bottomhole assemblies, high or low drilling rates or, indeed, any combination of these conditions. An oscillating shear valve pulser driven by a precise motor controller is able to fulfill these needs. Designed as a self-oscillating system, such a pulser is capable of delivering a

telemetry bandwidth of 40 hz or more with low power consumption. The oscillating movement has various advantages. The system can self-oscillate with low power consumption at high speeds. Phase or frequency can be changed instantaneously for efficient telemetry modulation, providing high telemetry data rates. Oscillating valves can be adapted to flow rate and mud weight changes. The pressure signal can be reduced by shaping the motor speed profile, or the shape of the pressure pulse can be fully controlled to create sinusoidal, trapezoidal, rectangular, or any other shaped signals to enable maximum signal pressure at the source and optimum downhole signal quality for high decoding quality at surface. Oscillating systems are also less prone to jamming from foreign bodies within their moving components. The same year, the first full inertial platform FINDS tool was introduced which had 3 gyro giving extremely high accuracy, but it was huge in size and was quickly removed from service. In the late 1980’s the Cretaceous Austin Chalk was a big play in Texas and Louisiana. Vertical drilling made occasional good wells but there were also many dry holes. Lateral drilling through the reservoir was quite successful in some fields but less so in others. It was thought that lateral wells could better connect with the natural fracture networks which had a strong vertical component. Eventually these wells came to be often steered with gamma ray in the new technique of logging-whiledrilling (LWD), or measurement-while drilling (MWD). Incidentally the source of Austin Chalk oil is now thought to be the prolific Eagle Ford Shale below it, although it was once thought to be self-sourced. Some of the horizontal gas wells in the deeper Austin Chalk trend in Texas had phenomenal production, some exceeding 50MMCF per day in line. During this period the first company devoted to geosteering as a specialty, Horizontal Solutions International (HSI), came about in the mid1990’s. Horizontal drilling of coal bed methane wells became common in the late 1990’s and early 2000’s. CBM wells in the Appalachian Basin were drilled on air, mainly to de-gas the coals before mining the same seams. MWD helped to stay within the zone when dip was changing along the pay zone. The interpretation was actually an integration in terms of ROP, gamma ray from MWD, and samples. Getting survey and log data is one thing but the interpretation was tedious, complex and slow, mainly in complex structures, at the very beginning as no softwares were available. By the late 2000’s geosteering had become well established in the shale plays and the structural, depositional, and petrophysical variations of each play were becoming apparent. With better well control the regional and local dips were getting a little more predictable but in some plays like the Niobrara, Woodford, Marcellus, and others, small faults undetectable by seismic resolution had to be interpreted by the geosteerer, typically after a significant amount of section had been drilled past the fault. In addition, since the survey and gamma are typically close to 50 ft. behind the bit this means that by the time the post-fault correlation could be determined some hole was necessarily drilled out of zone before adjustments could be made. In some cases, it was worse in the Marcellus as high dips, sometimes very high dips

up to 45 degrees, could be encountered near reverse faults, or high-angle thrusts. These zones were typically avoided but sometimes they were not seen on old 2D seismic and sometimes the curve was drilled in the fault zone to try and maximize lateral well length between the large fault zones. This made geosteering quite challenging at times as unexpected dip changes and folds were not uncommon. Some plays and areas of plays are relatively calm geologically. In those areas it is of course easier to maximize in-target footage even in small target windows. In 2006, Dr. Mike Stoner, created SES software to help geosteering analysis and interpretation. MWD changed directional drilling in 1980-81, with at least 5 commercial ventures available (Teleco, ExLog, Gearhart, Schlumberger, Vec-Tel, Baroid, and others.). Geosteering changed that, because the guidance in horizontal drilling changed from Absolute Navigation to Relative Navigation. One of the first such products was the NorTrak tool from Norton Christensen in the mid 1980's, which coupled resistivity and dual gamma sensors around a drive shaft to the bit. The bend above allowed steering the bit in response to the gamma and resistivity measurements from beds above and below. In early 1980, there was a need for a non-wireline, non-mud-based communication system to be used in air-drilling applications in either deviated or horizontal wells. Problems with existing or alternative technologies led to the interest in electromagnetic telemetry (EMT) using drill string to earth as media. DOE in a partnership with Geoscience Electronics Corp (GEC), developed a small diameter prototype designed originally for non-field applications. In 1986, it was tested for 10 hr. in air-drilled horizontal wells successfully in a well drilled in the Devonian shale in Wayne County, WV. From 1988 to 1993 the tool was ruggedized and was able to operate for 100 hr. without failure. GEC sold the prototype to Sperry-Sun. In 1995, DOE partnered with Sperry-Sun to develop and integrated underbalanced directional drilling system which included the EM-MWD and downhole motor. Sperry started offering commercial integrated systems to clients in California and Saskatchewan for underbalanced directional drilling markets. Frank Schuh was a key pioneer for Horizontal Drilling (and Extended Reach) in the 1980's and 1990's. Frank was instrumental in organizing the DEA joint research project DEA-44 "Extended-Reach and Horizontal Well Technology". DEA-44 was conducted by Bill Maurer (Maurer Engineering) in the mid-1980s. Maurer engineering was founded in 1974. In 1981, the first north seeking gyro system entered into the market. New technology allowed eliminating sighting errors. In addition, it provided significant increase in accuracy. Still required to stop drilling to record stationary surveys.

In 1985 a new technology called ring laser gyro was introduced which used a laser path instead of a spinning wheel. This new tool provided very high accuracy. It was costly at the time of the introduction and was sooner removed from service. Much credit goes to Christian Wittrisch from IFP who helped develop the SIMPHOR (Systeme d’Instrumentation et de Mesure en Puits Horizontaux) system, the predecessor to the TLC system. The system had 3 main components that were integrated with suite of normal logging tools. These components were: a) a set of 5/1/2" liner sleeves that surrounded standard logging tools that allowed the logging tools protected, while "pushed" down the wellbore. A non-metallic fiberglass sleeve surrounded the induction tool and windows were cut in steel sleeves surrounding the density pad and caliper. The neutron and GR tools remained inside the sleeve assemblies, with set screws along the entire logging assembly to position the sensors where they were needed for best borehole measurements, b) a set of male and female hepta-cable wet connectors were used to provide a downhole electrical connection when the wireline was pumped down the drill pipe mate to the downhole tools, and c) a side entry sub was installed in the drill string at the casing shoe allowing the wireline to move from outside of the drill string to the inside and connect to the logging string, ensuring a continuous electrical connection with the surface acquisition system. In approximately 1985, the 1st logging string deployed in a medium radius well was a 4-armed dipmeter using the Simphor system. This well was drilled by ARCO in the Sprayberry formation in West Texas, under the project leadership of Frank Schuh (as noted in the previous article by Mr. Dew). The dog leg severity approached 16 deg./100 feet in a 6.5" borehole and no protective sleeves could be run to protect the logging assembly. The logging job was very successful, with no damaged equipment and good dip and direction results. In this specific case, at least 3 knuckle joints and a swivel head were used between various sondes and cartridges to maintain robust pad contact with the wellbore and minimize the maximum rigid length of any one component. The advent of the Auxiliary Measurement sonde was soon developed and introduced to measure tool compression/tension during the descent in the wellbore. This provided real time compression measurements during the tool descent, preventing tool damage due to compression, especially critical with logging tools using nuclear sources. Even though SIMPHOR system was used in multiple horizontal wells, this system still relied on side entry subs, unreliable wet connectors, and a workover rig being over the well. A second option based on the use of CT unit, with an internal logging cable inside it, as a conveyance method was introduced in 1985 on the Berkhoepen 2001 horizontal well of Preussag Oil and Gas. After the first well 11 wells were immediately logged showing the advantages of the system at the time. An 11/16” CT was used for the task with a 15/32” cable inside the CT. The cable was a 7-conductor one insulated with polypropylene. In 1988, Elf Aquitane for its Rospo Mare project offshore Italy made one of the first recorded attempts to log a cased horizontal well with PL tools. The horizontal well

had more than 1,970 ft of horizontal section. Elf wanted to understand well production behavior from the horizontal and teamed up with Schlumberger to develop a system fit for purpose. The PL tools were attached to a stiff upper section – a stinger – outfitted with swab cups for locomotion (we would call today a pump down). Pressure applied to the top of the stinger forced the tool out the bottom of the well. The PL tool remined inside the stinger until it was released close to TD. The operation was successful providing essential information for field development. Other options such as wired CT were tested at the time like in Chayvo field by Exxon Mobil which realized the technique was very expensive and data questionable. In the 1990s, tractors were another option instead of CT adding flexibility, efficiency and cost savings. The pump down logging technique is currently used mostly for open hole logging operations rather than for cased hole ones but the idea was out there for moving tools down the well in the horizontal section by pumping. When Rospo Mare pilot project was originated, it was required to run production logs to understand production behavior along the horizontal. As standard wireline logging was not an option for horizontal wells, a new method was conceived in which logging tools were pushed out of the tubing string in front of the interval of interest by a rigid stinger that in turn would be pumped along the hole. To record flow profiles, a dual completion was required to provide a means of pumping the logging tools down a service tubing while the well was flowing through the production tubing. This technology was very successful at Rospo Mare 6, where operations ended by December 1984, after a trial run in the onshore horizontal well Lacq 91 in July 1984, which had been worked over to reproduce the conditions at Rospo Mare 6. The method used 1 11/16” regular logging tools and a 0.46” logging cable.

Survey technology timeline. Len Duncan. ISCWSA. 2016.

Evolution of directional drilling. IADC Drilling Manual

Hydraulic fracturing: While artificial induced fracturing has been used since 1866 when the first nitroglycerin “torpedo” was patented (U.S. Patent No. 59,936, expired in 1879) by Edward A. L. Roberts (1829 – 1881), modern hydraulic fracturing was introduced in 1947. Roberts was a lieutenant-colonel who made an interesting discovery: he came up with the concept of using water to “tamp” the resulting explosion of shells. Roberts thought of implementing this principle to the oil drillings in Pennsylvania by placing an explosive device on the bottom of a well filled with water. The water would tamp horizontally the bedrock instead of acting vertically. Roberts torpedo was the very first device of rock fracturing. He brought six bombs to Titusville. Torpedoes consisted of canisters filled with gunpowder and automatic percussion cap. Workers lowered the torpedo into the well with a long wire. One on the bottom, a metal piece, more like the weight of the fishing rod, was lowered on the wire, hitting the percussion cap to detonate the gunpowder. The new method had a considerable success for new wells as well as for the old ones, with low production. Soon enough gunpowder was replaced by nitroglycerin.

E.A.L. Roberts’s elongated shell or torpedo. Images from Drake Well Museum.

Pouring nitroglycerin was risky enough in late 19th century oilfields. Doing it for an illegal well “shooting” led to the term “moonlighting.” He charged USD 100 to 200 per torpedo plus royalty 1/15th of incremental production at 1200 %. He spent about USD 250,000 to protect his patent hiring the Pinkerton detective agency and filing numerous lawsuits to other practitioners. Upon Roberts death, business was sold to employees forming the Independent Explosives Company. In 1896 German born chemist Herman Frasch (1851 – 1914) was granted a patent (US Pat 556,669) for a method to increase the flow of oil in a well. The method was intended to rejuvenate old wells. In PA the most common method was to use nitroglycerin (torpedo) to shatter the surrounding rock by explosion thus promoting new flow of oil (stimulated area around the wellbore). In IN and OH due to the depth of the wells and the type of rock rendered this process inapplicable. He used hydrochloric or sulphuric acid according to specified conditions to be poured down the well and the mouth securely plugged. The generation of gases due to chemical reactions acted to shatter the surrounding rock and open cavities. Most likely the second effect was actually happening. In 1895, the first acid treatment (65 bbl of HCl) were pumped in Ohio Oil Company’s Crosley Farm lease in Lima, OH. Oil increased 300 %. This technique took hold in the industry during the 1930s. Today we would call this acid stimulation or at least it was the precursor of modern acid stimulation.

Patent granted to H. Frasch for a method to increase the flow of oil. The next important step in extracting oil from the bedrock took place in 1932, when Dow Chemical started injecting hydrochloric acid to dissolve the rocks and dig channels for the oil. The main difference with the Frasch’s method was the fact that the treatments were pumped instead of poured. The first test took place at Pure Oil Co (Amoco)’s well Fox nº 6 in Midland, Michigan, near the headquarters of the company. 500 gallons (about 1,900 liters) of acid with arsenic inhibitor in order to prevent the steel pipes’ corrosion was used as treatment. The acid was stored in a 3 ft x 12 ft wooden tank on a wagon. The acid was transferred to the well by siphoning through a garden hose. Treatment was displaced with oil. The new procedure was a success, as the oil production increased threefold. Next year, in northern Texas, another company decided to inject pressurized acid into the wellbores. This time 750 gallons (about 2,800 liters) of acid were used, followed by crude oil in order to force the acid into the limestone. Before applying the procedure, the well was producing 1.5 barrels a day. After the procedure the production increased almost 80 times to 125 barrels a day! (one barrel = 159 liters). Nevertheless, the use of acid has limited applications because it is successful only in the case of calcareous rocks with high concentration of calcium which is eliminated after the reaction with the hydrochloric acid. The method’s limitations have raised serious problems, as most oil reserves are formed in sandstones and the acid has no reaction. The engineers needed to find something else to crack the rocks and increase the wells’ production.

Early acidizing operations by Dowell, a division of Dow Chemical established in 1932 After WWII, Riley “Floyd” Farris (1911 – 2003) who was working for a prominent local company in Tulsa called Stanolind was intrigued by a mystery, Stanolind was set up in 1911 after the Supreme Court ordered the split of John D. Rockefeller’s empire (Standard Oil). Stanolind (later Amoco and then part of the British Petroleum). He was working as cementing specialist. He had noticed that in some wells once the cement went into them, part of it was vanishing. As cement was not cheap at the time (nor it is today) due to the losses, the drilling costs were rocketing. up to five tanks of cement more. What was going on? Why do some wells ‘swallow’ more cement than the calculations anticipate? Where was the cement going to? Farris carried out systematic studies on 115 well files and, by correlating the pressure exerted by the cement’s weight with the drilling depth, he reached the conclusion: the cement’s weight and other liquids’ weight were crashing the rocks causing fracturing. When the cement is pumped down the well, part of it was going into the fractures. What if he would try to fracture the bedrock by pumping liquid? Unlike the cement, the liquid could be taken out of the wellbore after fracturing the rocks. Once the liquid is removed, maybe more oil and gas would leak out of the bedrock, he thought. One of Farris’s colleagues, Clarence Robert “Bob” Fast (1921 – 2008), decided to verify the hypothesis of fracturing the bedrock by injecting liquid. His experiment took place in Klepper #1 well on the Hugoton gas field in south-west Kansas which was completed in November 1946. The treatment took place early in 1947. Colonel Roberts operated the fracturing with explosives, while Fast and Farris operated the first fracturing with liquid. As water involved friction and implied using several pumps to inject it into the bedrock, Fast was looking for a way to reduce friction. He needed a liquid to play the role of lubricant (having low viscosity) and to get mixed with water, while not being scarce. Fast had chosen napalm, leftover from WW II, when it had been used for flame throwers and incendiary bombs dropped over Japan. Fast pumped into the well 1,000 gallons (3,780 liters) of gasoline thickened with napalm, followed by another 2,000 gallons (7,650 liters) of gasoline (3 perforated zones + 1 open hole) using cup-style straddle packers. He repeated the procedure four times at different depths. He claimed he fractured the limestone. Due to fire hazards all units were 150 ft apart. When the napalm and the gasoline were recuperated, the gas erupted from the well. However, it was the same quantity of gas as the one obtained by using the hydrochloric acid (the conventional method to acidize the well). The first attempt for fracturing proved to be a failure.

Stanolind’s first hydraulic fracturing test, 1947, Grant County, Kansas. From Society of Petroleum Engineers, JPTOnline The research carried out by Stanolind was named ‘hidrafrac treatment’ and it wasn’t meant to serve only pure science. The company wanted to make the wells more productive. By the middle of the 20th century, finding rich oil and gas fields had become a major problem for the US companies. During WW II the steel was used for building tanks, canons, machine guns and other military devices. A deep well (for example 1,300 meters) needed 61 tons of steel for drill pipes and tubes. The oil industry faced a dilemma. It needed to increase production to meet the war demands but could use limited quantities of steel. They turned back to the old wells, abandoned due to low production. Until the ‘40s the American companies had drilled more than one million wells. More than half of them had no more production or insignificant ones. Fast and his colleagues believed fracturing could bring back to life the old wells, while new wells could become more productive. Fast and Farris succeeded in proving the reservoir bedrock could be fractured with cement. They also realized that using water raised a problem. Why not use the water mix with sand to maintain the fracturing open, they asked themselves? The first attempt took place in eastern Texas in a well producing less than one barrel a day. A mixture of sand, oil, soap and metals was pumped into the well and kept there for 48 hours. The soap washed away the oil from the bedrock. After the mixture was taken out, the well started producing 50 barrels a day. The production, 50 times larger, continued for a long time (several months).

Farris submitted a request for patent for hydraulic fracturing in May 1948. The license was granted to HOWCO, Halliburton Oil Well Cementing Company. On March 17, 1949 Halliburton conducted the first two commercial fracturing treatments in Stephens County, Oklahoma, and Archer County, Texas. First treatment cost about USD 900 and the other about USD 1,000. In 1953, the license was extended to all qualified service companies.

The first commercial hydraulic fracturing of an oil well took place in 1949 about 12 miles east of Duncan, Oklahoma. The first paper devoted to hydraulic fracturing (hydrafrac at the time) was by J. B. Clark in 1949. He worked for Stanolind Oil and Gas company in Tulsa, OK. The title of the paper was “A Hydraulic Process for Increasing the Productivity of Wells”. Mr Clark also credited R. F. Farris, C. R. Fast, G. C. Howard, J. A. Stinson and other members of the company in his paper. It was presented at the American Institute of Mining Engineers, Petroleum Division Fall Meeting, that held in Dallas, TX from October 1-4, 1948. At the time of the publication, the Hydrofrac process had been applied to 23 wells in 7 different fields, with sustained increase in production in 11 wells. The process was applied to wells partially depleted, but it was also remarked that new wells could improve their productivity by application of the process. The concluding statement by Clark in his paper was “It is significant that the value of the oil and gas produced to date through the benefits of this process has already exceeded the combined cost of research, development, and all field tests”. The hydraulic fracturing began evolving fast. By the middle of the ‘50s the drilling companies had begun using more water and less chemical additives as fracturing liquid. It was recommended to avoid using water as it could affect the underground deposit and could affect oil and gas extraction. The first test on the field infirmed these preconceived ideas and higher quantities of water were used, becoming common practice. More than that, injection rates increased 20 times, pumping more fluid to put higher pressure on the bedrock and lead to more fractures. New innovations helped the pumping equipment add more horse-power to the hydraulic fracturing. Bob Fast and his colleagues at Stanolind continued to research hydraulic fracturing for many years. The company became interested in using more powerful explosives

made up by rocket fuel in order to get more fractures. This idea proved fatal. On November 11, 1970 a team drilled a well to test the fuel as fracturing liquid. A piece of equipment was coupled to an electric line and accidentally led to an explosion. Eight workers were killed on the spot. Fast was not at the site, although he used to supervise the works. He was on a leave. Two years after the accident he retired. In 1950, hydraulic fracturing was firstly used in Canada. In the Soviet Union, the first hydraulic fracture was pumped in 1952 in the oilfield of Krasnodar area. Russia had developed many oilfield technologies independently of their Western counterparts. Fracturing theory was developed by S. A. Khristianovich and J. P. Zheltov theoreticians and reported in papers in 1955. The model described vertical fractures propagation. On the Western side, Geerdtsma and De Klerk (GdK) developed another model in 1969 while Perkins and Kern and later Nordgren (PKN) developed another model that was initially presented in 1961. As the GdK model is similar to the russian model, in the literature is referred as KGD. First fracturing treatments in Russia were performed on injection wells without proppant to achieve higher injection rates. As the next step, production wells were treated with natural frac sand from the river streambed (up to 130 Tn/well and on average 20 – 50 Tn/well). Peak activity was in 1958 – 1962 with 1,500 operations/year approximately, only in 1959 there were 3,000 frac jobs/year. Main areas were Krasnodar, VolgoUral district, Tatarstan (Romashkinskoe oil field, Tujmazinskoe oil field), Kujbyshev, Chechnya, Azebajdzhan, Dagestan. In the 1980s, there was almost no activity related to hydraulic fracturing as high production fields were considered out of need. By late 1980s when reserves structure was re-estimated, a new age of fracturing was reinitiated. In Ukraine the technology of hydraulic fracturing (hydraulic fracturing of coal deposits) has been used for the first time in 1954 within the underground coal gasification project, which foresaw extraction of combustible gases – the products of underground coal oxidation. In 1958-1962 hydraulic fracturing technology has been actively developed and used on the deposits of Ukraine. Hydrofracturing was mainly used for the injection well completion and in some cases on oil wells. An ad from 1956 claimed that Riverfracs used un-thickened water as a fracturing fluid. It also claimed that in some formations, successful treatments had been pumped without the use of sand as propping agent. Additives can be used in zones previously considered incompatible with water. An old report mentioned that Tennessee Gas Transmission Company’s well Thomas Lease nº 1 located northwest of Big Spring, TX on February 14, 1957 was fractured using a “Riverfrac” that involved 320,000 gal of “Riverfrac”, 7,500 gal of emulsifying agent and 225,000 lbs of sand. Pumping time was 90 min. “9 mobile Dowell units were used. Eight Allison and the new Dowell electric unit generated more than 15,000 horsepower. Hydraulic horsepower totaled 6,080. Water for the job was stored in two polyethylene lined pits 50x70x7 ft. Thirty-five “Dowellers” were required to operate the equipment and there were more than 35 spectators. Average pumping rate was 71 bpm with a

surface working pressure of 3,500 psi. Any similarity with current slick water fracs is just a mere coincidence!

Old picture from a “Riverfrac” treatment pumped in 1957.

Ad from 1956 depicting the “Riverfrac” stimulation technology by Dowell (currently Schlumberger). The first patent on the borate-crosslinked guar fluids (US patent 3,058,909) was filed in 1957 and granted in October 1962 to L. R. Kern with Sinclair (later ARCO). Metalbased crosslinking agents developed by DuPont for plastic explosives applications were found to be useful for manufacturing fluids for high temperature applications. The first patent (US Pat 3,163,219) on borate gel breakers was issued to Tom Perkins, also with Sinclair, on December 29th, 1964. In Argentina on September 23rd, 1959, the first well (NG-10) that was hydraulically fractured was located in Sierra Barrosa field operated by YPF (Sierras Blancas Formation). The final report from the well mentioned that the packer was at 5978 ft, but there is no record of perforations. At the time Halliburton pumped the frac job. About 20,000 lbm of sand were pumped. By 1959 the oil industry had become interested in using nuclear energy. It was proposed to use atomic bombs to fracture the wells. Edward Teller, the father of the Hydrogen bomb, organized a meeting that year at Lawrence Radiation Laboratory – now Lawrence Berkeley National Laboratory, to discuss the peaceful using of nuclear energy. Teller suggested it could be used for mining and excavations. The US Atomic Energy Commission agreed and set up Project Plowshare. The program focused at the beginning on using the ‘friendly atom’ as a gigantic excavator. An agreement has been nevertheless concluded for cooperation between the government and El Paso Natural Gas company. Scientists co-opted in the Plowshare project wanted to find out if using nuclear explosions for bedrock fracturing is possible and cost efficient. In 1967 scientists detonated a 29-kiloton bomb somewhere near Farmington, New Mexico in a dedicated well drilled on purpose. The nuke had 13 feet by 18 inches Hailed by political leaders and state officials, the bomb had been lowered 1,200 meters into a well dug in clayey bedrock, which resulted in a 50 meters diameter cavity. Called Project Gasbuggy the detonation was a success, but the resulting gas contained a too high level of radioactive Tritium and other isotopes.

Nuke used in project Gasbuggy and drilling site in New Mexico.

Researchers decided to test a more powerful bomb, aiming to produce more gas and recoup the millions of dollars invested in creating the bombs. The next blast was called Rulison, after a town in Colorado. It had a power of 43 kilotons and exploded

deeper in the well in September 1969. Measurements indicated the bedrock had been fractured on a radius of 76 meters. When the gas began to flow into the well it had high quantities of Tritium and Kripton-85. The Atomic Energy Commission carried studies on people’s exposure if the gas would have been pumped through pipelines to the population. Two cities would have received the highest dose of radiation from burning gas in the kitchens and in the fireplaces, Rifle and Aspen (a US ski resort en vogue). The dose would have been low, but it concerned only one well. These attempts to crack the bedrock to extract hydrocarbons drew the attention of the White House. During a speech delivered in 1971, President Richard Nixon said that finding increased quantities of natural gas will be one of the most urgent energy needs for the following years. He expressed support for nuclear simulation tests to produce natural gas from geological compact bedrock that could not be exploited at that moment. Getting the high-level go-ahead Project Plowshare continued. The next test had included the simultaneous detonation of three bombs, each one bigger than the one used for Gasbuggy. They were placed afar so that the impact area would create a huge vertical gas column. The project’s supporters believed the method would solve the energy deficit for the US. They were hoping nuclear fracturing would become a common technology to be used every day and anywhere a gas well is drilled. The Rio Blanco explosion was detonated in western Colorado in May 1973, during a period of time when the market faced low natural gas supply. The three bombs created individual vertical columns, unconnected. The gas flow came only from the above blast. Instead of ten-year reserves the main inheritance remains an official plate on the site warning against digging or drilling the soil without the governmental approval.

Picture and schematic drawing of the Plowshare project. Not getting intimidated, the Project Plowshare planners became even more ambitious. The next test, called Project Wagon Wheel, involved 500 kiloton devices. This was only the beginning. If successful, the Atomic Energy Commission and El Paso company were planning some forty-fifty blasts a year in south Wyoming (Pinedale area). However, this time they found their match. Locals got organized to

put the project to a halt. People were concerned by the impact of ground shaking on local roads and irrigation network. The economic part of using nuclear bombs was put under scrutiny. The Energy Department subsequently said USD 82 billion was spent for the project and even if the gas would have flowed for the next 25 years the amount was not to be cleared off. It is unclear how Project Wagon Wheel was cancelled but in January 1973 the funds for Project Wagon Wheel were cut from the federal budget. The Plowshare program endured from 1958 to 1975. 27 separate experiments resulting in 35 nuclear detonations took place from 1961 to 1973. During early 1960 to early 1970 individual projects pertaining to fracturing were carried out and other were never executed using nukes. Mostly all tests were performed in Nevada but also took place in the oil and gas fields of New Mexico and Colorado. As interest for hydraulic fracturing vanished, the concerns for energy security have increased. In November 1973 President Nixon vowed to eliminate oil imports by 1980. It was to no avail. He resigned in August the following year. The natural gas reserves have diminished to such a degree that the Congress adopted in 1978 a law calling illegal the building of gas-fired power plants. Until the law was repealed, the US had built many coal-fired power plants. The government officials had no choice. The newly discovered gas fields had low production volumes, about four out of every five wells proved to be unproductive. Facing an unfolding energy crisis, the government was looking for solutions. Attempts to stimulate energy offers were made. In 1976, The Department of Energy launches the Eastern Gas Shales Project, a joint research project among state, federal and private industrial organizations to research "unconventional" natural gas resources. A less known program could be included in these attempts: Unconventional Gas Research Program – UGR. The funds for the program were relatively low – USD 30 million was its best year. Starting in 1977 and continuing in the following years, most of the funds went to the research unit in Morgantown, West Virginia, which was carrying studies on shales in the Appalachian Mountains. The energy industry was aware of the gas reserves in the shale layers, but the drillings were made at shallow depths and production was unpredictable. The energy companies drilled only those shallow strata that could be naturally fractured. UGR wanted to change the situation. Geologists were sent to the sites in the region to study the shale layer characteristics. Furthermore, several wells were drilled. UGR attempted fracturing by chemical blasts and even by congealing the bedrock using cryogenic substances. Al Yost was one of the most talented researchers being included in the UGR program. Over more than ten years he tested lots of new technologies that would represent the framework for developing the hydraulic fracturing. In order to study its consequences Yost and his colleagues placed minuscule cameras inside the wells to understand what was going on down there and used seismic waves to chart the resulting fractures. For the first time they tested massive hydraulic fracturing – a technology that would become common only 20 years after being tested by Mitchell Energy company.

The next step in hydraulic fracturing history was to be written in Texas and Oklahoma. George Mitchell graduated as oil engineer the Texas A&M University and settled in Houston in 1946. Together with his brother Johnny he started an oil exploration company. In 1952 he drilled the first well - D. J. Hughes #1 – and found gas (sixty years later the gas was still flowing out of the well). The next ten wells were productive as well. Boonsville Bend, the area where he registered success, was part of the Dallas - Fort Worth metropolis. He rushed to lease land up to 130,000 hectares. Following the promising start, finding out that Stanolind had successfully used well fracturing, he immediately started to fracture his new drillings in Boonsville Bend area. In June 1982, upon Mitchell’s insistence, his engineers had fractured the bedrock in the Boonsville Bend area – the Barnett shale. Several years ago a governmental program tested massive hydraulic fracturing in a well close to Mitchell’s leased land. A mixture of water and oil as gelatinous emulsion called ‘Super K-frac’ was used. The pressure broke the drilling column and a 1,600 meters deep cavity resulted. A month of labor was needed to localize the rupture and cement it. Pessimistic reactions surfaced: a governmental official wrote in his report that “probably this approach is not economically efficient.” Mitchell chose another fracturing method: he poured 42,000 cubic meters of nitrogen in the wellbore. Then, in 1983, he tested again fracturing by using carbon dioxide and water. The main result? The fractured shale produced almost 7,000 cubic meters per day, a nonconvincing result. For comparison, nowadays a fractured well in the Barnett shale could produce about 142,000 cubic meters of gas per day. The S. H. Griffin well, fractured fifty-two years after Stanolind had tested the first “hydrafrac” marked a landmark on the way of claiming the hydraulic fracturing as the most important technological discovery of the latest decades. As stated by Clark in his paper from 1949, the “hydrafrac” process consists of injecting a viscous liquid containing a granular material such as sand under high hydraulic pressure to fracture the formation and causing the viscous liquid to change from high to low viscosity, so it may be readily displaced from the formation. At the time 32 jobs were performed on 23 wells resulting in a sustained increase in production in 11 wells. The viscous fluid was an oil such as crude oil or gasoline to which a bodying agent was added. Napalm which was a war-surplus due to availability and price was used in most of the experiments. Napalm was used in the war to make “jellied gasoline”. A viscosity of 50 to 150 cp is considered adequate for the task but napalm can produce viscosities up to considerably over 300 cp. The paper also claims that water base fluid might be used as well, being more economical particularly in formations not appreciably contaminated with argillaceous materials. Napalm gels are relatively unstable, so the viscosity of the solution can revert after the fracture is pumped. 0.5 to 1 % of water added to the napalm-gasoline gel cause reversion within 8 to 24 hr. If salt is added the time is reduced. It is also possible to break these gels in a few minutes using a 2 % solution of petroleum sulphonates in gasoline or crude oil.

Interestingly, although a table in the paper shows that mostly all wells were treated with proppant there is no indication about the amount, mesh size, source or even concentration.

Drawing depicted in Clark’s paper from 1948 related to “hydrafracs”. As part of DOE’s initiatives (gas shale program), Massive Hydraulic Fracturing (MHF) was introduced in the Eastern Devonian shales. It is not clear in the literature if the word massive refers to the length of the fracture wing or to the volume of fracturing fluids. MHFs were used before in tight gas wells and most likely by analogy its application was extended to shale gas. Foam fracturing was another technology introduced by the shale gas program. In the first four years of the program, more than 50 cost-shared demonstration treatments were pumped. Previously, Devonian shale gas wells were stimulated in open-hole completions either with explosives or with water fracs. Foam fractures reduced the volume of water by 75 to 90 % as compared to conventional fracs. The incremental cost of the foam fracs was offset by reduced well cleanup costs and improved productivity. The 1960s saw the first use of a process called “massive hydraulic fracturing” which involves injecting treatments of very high-volume fluids and proppants. This first treatment was also done in Stephens County, Oklahoma and occurred in 1968. It was conducted by Pan American Petroleum. In the 1970s, this method was being used in the Piceance Basin, the San Juan Basin, the Denver Basin, and the Green River Basin. The 1970s was the large-scale rise and proliferation of massive hydraulic fracturing. The process began to be used in thousands of gas wells all over the Piceance Basin, San Juan Basin, Denver Basin the Green River Basin to recover

natural gas from low permeability sandstone. In addition to these basins the ClintonMedina Sandstone, and Cotton Valley Sandstone plays also benefited from the improved economy of using massive hydraulic fracturing. By the late 1970s the practice had also spread outside of the US and was being used in western Canada, Germany, the Netherlands, and the United Kingdom. In December 1963, Halliburton (S. Swight et al.) filled for a patent for multiple fracturing in a well. Patent was granted in December 1966. This invention relates to hydraulic fracturing in a well and, more particularly, to a method for successively fracturing formations at two or more selected elevations in a well (vertical well). Between 1986 and 1988, Mobil Oil Corporation filled for several patents mainly dealing with the creation of sequential fractures from deviated wells (US Pat 4,687,061A), Multiple sequential hydraulic fractures (US Pat 4,718,490A), simultaneous hydraulic fracturing (US Pat 4,830,106A) and others related to associate topics which were the basis for the multi fracturing of horizontal wells. By the mid-1960s, propped hydraulic fracturing had replaced acidizing as the preferred stimulation method in the Hugoton field. Some operators started fracturing in East Texas with waterfracs based on the experience they had in the Austin chalk formation. High injection rates, anywhere from 40 to 100 bpm, are used to minimize pumping time, minimize leak-off rate and maximize proppant transport. Friction reducer is added to water to reduce friction in tubulars and thus reducing wellhead pressure and hydraulic horse power. Proppant concentration reached a maximum of 2 to 3 ppg. It was very common to use sweeps to prevent proppant settling and enhance proppant transport. In fact, in the San Juan basin slick water treatments were the prevailing type of treatment to be utilized, pre-1968, and have continued to be so today. Prior to the introduction of crosslinked gels in 1968 low viscosity treatments were a very large segment of fracture treatments. With the development of crosslinked fracturing fluids and all their attributes, low viscosity fracs were considered low technology and became a small segment of treatments pumped. The age of crosslinked gels was started by an Exxon subsidiary (Humble Oil and Refinery Co) when a technique called SuperFrac was introduced in the late 1960s which was quickly followed by crosslinked guars. The trend lasted for the last 35 to 40 years but it has been reversed to similar approach used in the 1970s. SuperFracs used a dispersion of oil and water and a small amount of surfactant to create a viscous frac fluid (no polymers were used at the time). The main targets were to pump coarser mesh sizes (8-12) way further inside the fracture and to decrease the friction pressure while pumping. Frac jobs were initially pumped in The Rocky Mountains, California area, Illinois and Michigan basin, Oklahoma and Texas Panhandle area, West Texas area, Gulf Coast of Texas area, Mississippi, Louisiana and Alabama.

In the early 1970s, massive hydraulic fracturing was introduced successfully in the industry. By 1973, Massive Hydraulic Fracturing (MHF) was used in thousands of gas wells in the San Juan Basin, Denver Basin, the Piceance Basin, and the Green River Basin, and in other hard rock formations of the western US. Other tight sandstone wells in the US made economically viable by massive hydraulic fracturing were in the Clinton-Medina Sandstone (Ohio, Pennsylvania, and New York), and Cotton Valley Sandstone (Texas and Louisiana). Frac fluids range from the more common gelled waters to the more complex fluids such as foam and crosslinked gel systems. Foam fracturing fluid consisted mostly of 80 % nitrogen + 20 % water with a foaming agent (surfactant). Conventional fracturing fluids, such as water gelled with 20 to 30 lbm of guar or chemically modified guar per 1000 gal was the most common fluid at the time. The history of the use of foams in the oilfield dated from the 1960s due to their versatility and special for some applications. In 1966, Anderson, Harrison and Hutchison reported the development of foams for drilling and wellbore cleanup. The earliest foam fracturing treatment was performed in Jan 1968. This treatment placed approximately 2,041 kg (4,500 lbm) of 12/20 mesh glass beads proppant with approximately 83 to 85 % quality foam to stimulate the Brown shale formation in Lincoln County, WV. Virtually no other use of foam stimulation was reported until the latter half of 1973. At this time the technology spread across several basins including Canadian operations. Most foam treatments performed during 1973-1976 were small volume (