This publication compiles the history of the four major technologies that were able to conquer the unconventional reservoirs. History, memories and other facts are provided

1. 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.

2. 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

3. 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. Micro-
seismic 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.

4. 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

5. 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 16th, 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

6. 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 steam-
powered 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”.

7. 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.

8. 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.

9. 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

10. 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

11. 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 down-
hole 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

12. 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 two-
cone 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.

13. 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

14. 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.

15. 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.

16. 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.

17. 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 25-
ft 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

18. 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.

19. 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.

20. 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.

21. Flexible drill collar patent extract depicting the idea and BHA design.
Evolution of directional drilling.

22. 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).

23. Components of the RCLS system.
Control capabilities of the tool.

24. 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

25. 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.

26. 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.

27. 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

28. 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.

29. 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 re-
entried 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

30. 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 medium-
radius 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.

31. 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

32. 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 ultra-
short 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 well-
design 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.

33. 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.

34. 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

35. 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

36. 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

37. 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

38. 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 28th, 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.

39. 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

40. 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 kick-
off 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 Branched-
Horizontal 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

41. 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.

42. • 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 FA-
12). 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.

43. 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 short-
radius 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

44. 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