Petroleum Accounting(Chapter One part (2))

THE 1920s: THE AUTOMOBILE COMES OF AGE

With increased competition in the oil industry and an increased demand
for petroleum products (created by the growing number of automobiles),
many small companies were formed and soon joined the few large
companies in the search for and production of petroleum. New demands
for petroleum were created in the 1920s; petroleum products were used to
generate electricity, operate tractors, and power automobiles. The oil
industry was able to increase production to meet the greater demand
without a sharp rise in price.
The search by American companies for foreign oil began around 1920
and was encouraged by the United States government, which feared that a
shortage of oil was developing domestically. By the middle of the 1920’s
approximately 35 companies had invested upwards of $1 billion exploring
for and developing reserves in the Middle East, South America, Africa,
and the Far East. However, the discovery of the giant East Texas oil field
in 1930 created a world surplus of oil, and companies slowed their
operations in foreign countries. Some companies did continue to search
for oil in the Middle East during the 1930s, and significant discoveries
were made, especially in Saudi Arabia and Kuwait.

THE DEPRESSION: STATE CONTROL OVER PRODUCTION




When the depression began in the 1930s, the oil industry entered a
period of increased production with the discovery of the East Texas oil
field by an independent wildcatter. This field is the third largest in North
America; only the Prudhoe Bay field on the North Slope of Alaska and a
Mexican field are larger. The abundance of oil from the East Texas field
and the economic depression coupled to temporarily reduce oil prices by
90 percent to just ten cents a barrel.
In 1933 the Texas legislature recognized the need for conservation
measures to avoid wasting oil and, thus, gave the job of industry
regulation to the existing Texas Railroad Commission. Since that time
other oil-producing states have created agencies or commissions to
regulate the development and production of oil and gas reserves.
The 1930s also saw an increase use of gasoline, natural gas, and natural
gas liquids. While some shallow "offshore" drilling occurred as early as
the late 1800s, it was not until the late 1930s that wells were drilled from
structures resembling the offshore drilling platforms of today.

WORLD WAR II: PETROLEUM FOR DEFENSE

The United States started to recover from the economic depression by
the mid-1930s. The onset of World War II in 1939 accelerated the pace of
economic recovery. Compared with World War I, World War II used
more mechanized equipment, airplanes, automotive equipment, and ships,
all of which required huge amounts of petroleum. The industry easily met
the United States' and allies' demands for petroleum. However, as World
War II progressed, the U.S. and British governments feared an eventual
shortage of crude oil. In 1943 the U.S. government even proposed buying
from Chevron and Texaco the petroleum company that became Saudi
Aramco, now the world's largest oil producing company.
During and after World War II, huge capital investments were made to
further develop the enormous reserves found in the Persian Gulf area.
Chevron, joined later by Texaco, and still later by Exxon and Mobil,
owned the Arabian-American Oil Company or Aramco, which developed
the giant Saudi Arabian oil fields and downstream infrastructure. Today
the company is owned by Saudi Arabia and has been renamed Saudi
Aramco. Other companies explored, developed, and produced oil in other
countries, but in the first half of the twentieth century, the United States
typically produced and consumed from 50 percent to 75 percent of the
world's annual oil production.
AFTER WORLD WAR II: GROWTH OF THE NATURAL GAS AND
PETROCHEMICAL INDUSTRIES
At the end of World War II, two events contributed to the tremendous
growth in the natural gas industry. Natural gas had previously been
discovered in large quantities in Texas, Louisiana, and other southwestern
states; however, it was difficult to transport the gas long distances. This
problem was alleviated by the development of a new technique for
welding large pipe joints; gas under high pressure thus became
transportable to the heavily populated midwestern and eastern regions of
the country. Also, after World War II, the country witnessed the birth of
the petrochemical industry, which used natural gas liquids for some of its
basic raw materials.
THE 1950s AND 1960s: IMPORTED OIL AND THE FORMING OF OPEC
During the 1950s and the 1960s, there was ample world oil production,
with prices remaining stable and averaging approximately $3.00 per
barrel. However, these two decades also saw an increased U.S. reliance on
imported crude oil and refined products. In 1950 ten percent of oil used in
the United States was supplied by imported oil and refined products; by
1970 that percentage had increased to 23 percent.
In 1960 the Organization of Petroleum Exporting Countries (OPEC)
was formed by Saudi Arabia, Kuwait, Iran, Iraq, and Venezuela. Later,
eight other countries joined OPEC—the United Arab Emirates and Qatar
in the Middle East; the African countries of Algeria, Gabon, Libya and
Nigeria; and the countries of Indonesia and Ecuador. Ecuador withdrew in
late 1992. By 1973 OPEC members produced 80 percent of world oil
exports, and OPEC had become a world oil cartel. Member countries
began to nationalize oil production within their borders.
THE 1970s: OIL AND GAS PRICES SKYROCKET. U.S. IMPOSES PRICE
CONTROLS
Beginning in October 1973, Arab OPEC members cut off all oil exports
to the U.S. in response to the U.S.'s proposed $2.2 billion military aid
package to Israel, which was reeling from surprise attacks by Egypt and
Syria that month. The price for Saudi Arabian oil rose dramatically—
$1.80 per barrel in 1971, $2.18 in 1972, $2.90 by mid-1973, $5.12 in

October 1973, and $11.65 in December 1973. Thereafter, world crude oil
prices increased slowly through 1978 when Saudi oil sold for $12.70 per
barrel. The 1979 Iranian Revolution caused prices to again escalate
rapidly, peaking at $42 per barrel for some U.S. crude oil in December
1979.
During the 1960s and early 1970s, some people warned of petroleum
shortages, but their warnings went unheeded until the 1973 Arab oil
embargo. Because of the embargo, a large portion of the oil normally
imported by the United States was cut off for several months, and citizens
were faced with a shortage of gasoline and other petroleum products and
with increasing prices. The federal government created the Federal Energy
Administration in 1973 and gave it the power to control prices of crude
oil. The price regulations were complex, and compliance procedures were
not always clearly determinable, even after petroleum company personnel
consulted with officials of the Federal Energy Administration, predecessor
to the U.S. Department of Energy (DOE).
A two-tier oil pricing structure was established with a low price for
"old" or "lower-tier oil" and a higher price for "new" or "upper-tier oil."
Lower-tier oil generally came from properties that were producing prior to
1973, while upper-tier oil came from properties that began producing after
1972. Producers often had both kinds of properties and therefore sold
some oil at less than half the price of other oil of the same quality. By
1979 the U.S. allowed free market prices for U.S. oil from newly drilled
properties or properties producing less than 10 barrels per day per well.
However, on average, domestic oil was selling at only a fraction of the
price paid in this country for imported oil.
Foreign oil continued to be imported (at prices exceeding domestic oil
prices) to meet the continued growth in domestic demand. In 1977,
approximately 47 percent of the United States' needs were met by
imported oil.
THE WINDFALL PROFIT TAX (1980 TO 1988)
President Carter's call for phased decontrol of oil prices by late 1981
was coupled with enactment of the Windfall Profit Tax Act in March
1980. The Act levied a tax from 30 percent to 70 percent on windfall
profit, i.e., the excess of the selling price of a barrel of oil over the
adjusted base price for that barrel. The adjusted base price was an
inflation-adjusted average price of similar oil sold in late 1979. Congress
repealed the windfall profit tax in 1988 after oil prices had fallen so low
that no windfall profit was left to tax.
ALASKA NORTH SLOPE OIL
In 1968 Prudhoe Bay, the United States' largest oil field, was
discovered on the North Slope of Alaska bordering the Arctic Ocean. In
1969, the giant Kuparuk field adjacent to Prudhoe Bay was discovered.
Prior to the Prudhoe Bay discovery by Atlantic Richfield Company
(ARCO), seven very expensive, but unsuccessful, exploratory wells had
been drilled in the area, and ARCO almost canceled drilling the discovery
well. Even after discovery, Prudhoe Bay development was stalled until
the 1973 Arab oil embargo prompted Congress to allow the Trans Alaska
Pipeline System (or TAPS) to be built. Finally, in 1977 Prudhoe Bay and
Kuparuk crude oils were produced and marketed.
For Prudhoe Bay and Kuparuk, estimated ultimate oil production, i.e.,
all prior production plus estimated future production, is 13.2 billion and
2.6 billion barrels, respectively. Gas reserves approximate 4 billion
additional equivalent barrels. These North Slope fields are immense. In
the entire lower 48 states where over one million wells have been drilled,
only three discovered oil fields have ultimate oil production exceeding 2
billion barrels, and their combined ultimate production is only 10.9 billion
barrels. Alaska North Slope oil (ANS crude) made up approximately 18
percent of all 1998 U.S. oil production.
The North Slope infrastructure for production of Prudhoe Bay and
Kuparuk is used to economically produce some 20 smaller North Slope
reservoirs. However, the huge 32 trillion cubic feet (tcf) of recoverable
natural gas reserves from North Slope fields cannot now be economically
transported to the Lower 48 states. Advances in converting gas to liquids
(GTL, described on page 5) offer hope. Alternatively, the gas may
eventually be chilled as LNG and shipped to Asia’s Pacific Rim.
North Slope operations are an industry model for environmental
protection, far different from the typical Russian operation. A Russian
environmental scientist touring the Prudhoe Bay production facilities
declared that north slope production must be a government hoax because
he found no oil leaks or spills. Gas produced at Prudhoe Bay is not vented
into the atmosphere or burned as waste, but reinjected back into the
reservoir. Gas reinjection improves oil recovery and saves the gas for
potential future use. The North Slope’s Alpine field, the largest U.S.
onshore oil discovery in fifteen years, spans 40,000 acres; yet its oil
(70,000 barrels per day) will be produced from two 50-well gravel pads on
less than 120 acres. The Alpine field has no permanent roads or bridges.
In 1998 Alaskan oil production (nearly all from the North Slope)
provided 73 percent of the state government’s unrestricted general fund.
The oil royalty has provided a permanent and growing $25 billion trust
fund for the half million residents of Alaska.
Despite the industry’s success in safeguarding the North Slope
environment and adding to the nation’s wealth, and contrary to the wishes
of most Alaskans and local Inuits, the North Slope’s 19 million acre Arctic
National Wildlife Refuge (ANWR) remains closed by the federal
government to drilling and production. The federal government estimates
that the western half of ANWR’s 1.7 million acre coastal plain has
recoverable oil reserves of several billion barrels.
THE 1980s: BOOM AND BUST. MARKET FORCES PREVAIL
Several factors set the stage for a U.S. petroleum industry boom in
1981 and 1982:
♦ World oil prices had increased astronomically in 1973 and 1979.
These price increases improved exploration economics and created
an expectation of substantial price increases in the future.
♦ In January 1981, President Reagan removed U.S. price controls on
crude oil, which gave producers additional cash to reinvest. In the
1970s, Libya and several other countries seized U.S. companies'
interests in petroleum fields. These nationalizations encouraged a
preference for U.S. companies to explore within the United States.
♦ The Natural Gas Policy Act of 1978 created incentive pricing
schemes to stimulate the exploration and development of natural
gas reserves.
In 1981 U.S. tax laws were changed to reduce the highest individual
income tax rates from 70 percent to 50 percent and reduce windfall profit
taxes on new oil fields. Individuals investing in wells drilled in 1981
could earn a 40 percent profit, after income tax effects, on wells that had
no profit before income tax effects. Consequently, in 1981 and 1982, U.S.
individuals invested billions of dollars in limited partnerships for
petroleum exploration and production.
Figures 1-2, 1-3, and 1-4 present a history of annual production, prices,
and E&P expenditures from 1979 through 1999 that portray the boom and
bust of the 1980s.

Petroleum Accounting(Chapter One part (1))

AN INTRODUCTION TO THE
PETROLEUM INDUSTRY

BASIC TERMS AND CONCEPTS
Petroleum refers to crude oil and natural gas or simply oil and gas.
These are mixtures of hydrocarbons which are molecules, in various
shapes and sizes, of hydrogen and carbon atoms found in the small,
connected pore spaces of some underground rock formations. These
petroleum reservoirs are generally thousands of feet below the surface.
Crude oil and natural gas are believed to be the remains of plants and
animals, mostly small marine life, that lived many millions of years ago.
Oil and gas are discovered and produced through wells drilled down to
the reservoirs. An exploratory well is one drilled to discover or delineate
petroleum reservoirs. A development well is one drilled to produce a
portion of previously discovered oil and gas. A large producing reservoir
may have one or more producing exploratory wells and several producing
development wells.
Estimated volumes of recoverable oil and gas within the petroleum
reservoir are called oil and gas reserves. Reserves are classified as
proved, probable, or possible, depending on the likelihood that the
estimated volumes can be economically produced.
From petroleum we get numerous useful products:
♦ Transportation fuels, such as gasoline, diesel fuel, jet fuel,
compressed natural gas (or CNG) and propane;
♦ Heating fuels, such as propane, liquefied petroleum gas, heating
oil, and natural gas burned to heat buildings;
♦ Sources of electricity, such as natural gas and residual fuel oil
burned to generate 14 percent of U.S. electricity (with coal, nuclear
energy, and renewable sources generating the rest); and
♦ Petrochemicals from which plastics as well as some clothing,
building materials, and other diverse products are made.
Different mixtures of hydrocarbons have different uses and different
economic values. It is necessary to recognize some basic types of
hydrocarbon mixtures to understand portions of this book. Crude oil refers
to hydrocarbon mixtures produced from underground reservoirs that are
liquid at normal atmospheric pressure and temperature. Natural gas refers
to hydrocarbon mixtures that are not liquid, but gaseous, at normal
atmospheric pressure and temperature.
The gas mixtures consist largely of methane (the smallest natural
hydrocarbon molecule consisting of one carbon atom and four hydrogen
atoms). Natural gas usually contains some of the next smallest
hydrocarbon molecules commonly found in nature:
Ethane (two carbon, six hydrogen atoms, abbreviated C2H6),
Propane (C5H8),
Butane (C4 H10), and
Natural gasolines (C5H12 to C10H22).
These four types of hydrocarbons are collectively called natural gas
liquids (abbreviated NGL1) which are valuable feedstock for the
petrochemical industry. When removed from the natural gas mixture,
these larger, heavier molecules become liquid under various combinations
of increased pressure and lower temperature. Liquefied petroleum gas
(abbreviated LPG) usually refers to an NGL mix of primarily propane and
butane typically stored in a liquid state under pressure. LPG (alias bottled
gas) is the fuel in those pressurized tanks used in portable "gas" barbeque
grills. Sometimes the term LPG is used loosely to refer to NGL or
propane.
In the United States natural gas is measured in two ways, both
important in petroleum accounting:
♦ by the amount of energy or heating potential when burned,
generally expressed in million British thermal units (abbreviated
mmBtu) and
♦ by volume, generally expressed in
- thousand cubic feet (abbreviated as mcf),
- million cubic feet (abbreviated as mmcf),
- billion cubic feet (abbreviated as bcf), or
- trillion cubic feet (abbreviated as tcf).
In many other parts of the world, gas volumes are measured in cubic
meters (kiloliters) and energy is measured in gigajoules. A kiloliter (or
cubic meter) approximates 1.31 cubic yards and 35.3 cubic feet. A
gigajoule (or a billion joules) approximates 0.95 mmBtu.
Gas volumes are necessarily measured at a standard pressure and
temperature, typically at an atmospheric pressure base of 14.65 to 15.025
pounds per square inch absolute (or psia) and a temperature of 60 degrees
Fahrenheit.2
The ratio of mmBtu (energy) to mcf (volume) varies from
approximately 1:1 to 1.3:1. The more natural gas liquids in the gas
mixture, the higher the ratio, the greater the energy, and the "richer" or
"wetter" the gas.
For various economic reasons, wet gas is commonly sent by pipeline to
a gas processing plant for removal of substantially all natural gas liquids.
The NGL are sold. The remaining gas mixture, called residue gas or dry
gas, is over 90 percent methane and is the natural gas burned for home
heating, gas fireplaces, and many other uses.
As wet gas is produced to the surface and sent through a mechanical
separator near the well, some natural gasolines within the gas condense
into a liquid classified as a light crude oil and called condensate. Crude
oil is measured in the U.S. by volume expressed as barrels (abbreviated as
bbl).3 A barrel equates to 42 U.S. gallons. In some other parts of the
world, crude oil is measured by weight, such as metric tons, or by volume
expressed in kiloliters (equivalent to 6.29 barrels). A metric ton of crude
oil approximates 7.33 barrels of crude oil, but the ratio varies since some
crude oil mixtures are heavier per barrel than others.
Volumes of crude oil and natural gas combined are often expressed in
barrels of oil equivalent (abbreviated boe) whereby gas volumes in mcf
are converted to barrels on the basis of energy content or sales value. In
general, approximately 5.6 mcf of dry gas have the same 5.8 mmBtu
energy content as one average U.S. barrel of oil. However, one mcf of gas
might be selling for $1.50 when oil is selling for $15 per barrel whereby
ten mcf equate to one barrel of oil, based on the given sales prices. For
one million boe of gas, the corresponding mcf are shown below for the
aforementioned conversion ratios.
Note that many companies use an energy conversion ratio of 6 mcf per
barrel, which is the required ratio for certain income tax rules in Internal
Revenue Code Section 613A(c)(4).
Crude oil can be many different mixtures of liquid hydrocarbons.
Crude oil is classified as light or heavy, depending on the density of the
mixture. Density is measured in API gravity as explained in Chapter
Eleven. Heavy crude oil has more of the longer, larger hydrocarbon
molecules and, thus, has greater density than light crude oil. Heavy crude
oil may be so dense and thick that it is difficult to produce and transport to
market. Heavy crude oil is also more expensive to process into valuable
products such as gasoline. Consequently, heavy crude oils sell for much
less per barrel than light crude oils but weigh more per barrel.
Both natural gas and crude oil may contain contaminants, such as
sulphur compounds and carbon dioxide (CO2), that must be substantially
removed before marketing the oil and gas. The contaminant hydrogen
sulfide (H2S) is poisonous and, when dissolved in water, corrosive to
metals. Natural gas and crude oil high in sulfur compounds are called
sour gas and sour crude oil as opposed to sweet crude oil or intermediate
(between sour and sweet). Some crude oils contain small amounts of
metals that require special equipment for refining the crude.
The petroleum industry, commonly referred to as the oil and gas
industry, has four major segments:

1. Exploration and Production, or E&P, by which petroleum
companies (referred to as "oil and gas companies" or simply "oil
companies") which explore for underground reservoirs of oil and
gas and produce the discovered oil and gas using drilled wells
through which the reservoir's oil, gas, and water are brought to the
surface and separated (Figure 1-1)
2. Hydrocarbon Processing by which crude oil refineries and gas
processing plants separate and process the hydrocarbon fluids and
gases into various marketable products (Figure 1-1). Refined
products and NGL may be processed further in "petrochemical
plants" for making petrochemicals. Some petrochemicals may, in
turn, be sent to the crude oil refineries for mixing or processing with
other liquid hydrocarbons to make various refined products, such as
gasoline.
3. Transportation, Distribution, and Storage by which petroleum is
moved from the producing well areas to the crude oil refineries and
gas processing plants. Crude oil is moved by pipeline, truck, barge,
or tanker. Natural gas is moved by pipeline. Refined products and
natural gas are similarly transported by various means to retail
distribution points, such as gasoline stations and home furnaces. In
unusual cases, African, South Pacific, and Caribbean countries are
exporting natural gas across the oceans and seas by chilling the
mixture to a liquid state at -160 degrees centigrade for hauling in
special tankers with high pressure, cryogenic containers. This
chilled gas is called liquefied natural gas (abbreviated LNG).
4. Retail or Marketing which ultimately markets in various ways the
refined products, natural gas liquids, and natural gas to various
consumers.
Variations of new, but promising, processes (not illustrated in Figure
1-1) convert natural gas to liquids equivalent to refined product fuels,
such as diesel. This gas-to-liquids (GTL) approach may enable
substantial gas reserves in remote areas to be profitably produced,
transported, and sold. Several petroleum companies are conducting
pilot tests of such processes.

The E&P segment is sometimes called upstream operations, and the
other three segments are downstream operations. Companies having both
upstream and downstream operations are vertically integrated in the
petroleum industry and, hence, are called Integrated. Other companies
involved in upstream only are referred to as Independents. The several
largest integrated petroleum companies are called Majors.
In this book, petroleum accounting focuses on United States generally
accepted accounting principles (GAAP) for financial reporting of the
exploration and production of petroleum. Chapter Twenty-Five introduces
accounting for international operations. Chapters Twenty-Six and Twenty-
Seven touch upon accounting for income tax reporting of petroleum
exploration and production.

AN OVERVIEW OF PETROLEUM EXPLORATION
AND PRODUCTION
Preliminary Exploration. Before an oil company drills for oil, it first
evaluates where oil and gas reservoirs might be economically discovered
and developed (as explained more fully in Chapter Five).
Leasing the Rights to Find and Produce. When suitable prospects
are identified, the oil company determines who (usually a government in
international areas) owns rights to any oil and gas in the prospective areas.
In the United States, whoever owns "land" usually owns both the surface 

rights and mineral rights to the land. U.S. landowners may be individuals,
corporations, partnerships, trusts, and, of course, governments. A
landowner may sell the surface rights and then separately sell (or pass on
to heirs) the mineral rights. Whoever owns, (i.e., has title to), the mineral
rights negotiates a lease with the oil company for the rights to explore,
develop, and produce the oil and gas.
The lease requires the lessee (the oil company), and not the lessor, to
pay all exploration, development, and production costs and gives the oil
company ownership in a negotiated percentage (often 75 percent to 90
percent) of production. The lessor owns the remaining portion of
production. Leasing is explained further in Chapter Seven.
The oil company may choose to form a joint venture with other oil and
gas companies to co-own the lease and jointly explore and develop the
property as explained in Chapter Ten.
Exploring the Leased Property. To find underground petroleum
reservoirs requires drilling exploratory wells (as discussed in Chapter
Eight). Exploration is risky; two-thirds of U.S. exploration wells for 1998
were abandoned as dry holes, i.e., not commercially productive.4 Wildcat
wells are exploratory wells drilled far from producing fields on structures
with no prior production. Consequently, 80 to 90 percent of these wells
are dry holes. Several dry holes might be drilled on a large lease before an
economically producible reservoir is found.
To drill a well, a U.S. oil company typically subcontracts much of the
work to a drilling company that owns and operates rigs for drilling wells.
Evaluating and Completing a Well. After a well is drilled to its
targeted depth, sophisticated measuring tools are lowered into the hole to
help determine the nature, depth, and productive potential of the rock
formations encountered. If these recorded measurements, known as well
logs, along with recovered rock pieces, i.e., cuttings and core samples,
indicate the presence of sufficient oil and gas reserves, then the oil
company will elect to spend substantial sums to "complete" the well for
safely producing the oil and gas.
Developing the Property. After the reservoir (or field of reservoirs) is
found, additional wells may be drilled and surface equipment installed (as
explained in Chapters Eight and Eleven) to enable the field to be
efficiently and economically produced.
Producing the Property. Oil and gas are produced, separated at the
surface, and sold as explained further in Chapters Eleven and Twelve.
Any accompanying water production is usually pumped back into the reservoir or another nearby underground rock formation (Figure 1-1).
Production life varies widely by reservoir. Some U.S. oil and gas
reservoirs have produced over 50 years, some for only a few years, and
some for only a few days. The rate of production typically declines with
time because of the reduction in reservoir pressure from reducing the
volume of fluids and gas in the reservoir. Production costs are largely
fixed costs independent of the production rate. Eventually, a well's
production rate declines to a level at which revenues will no longer cover
production costs. Petroleum engineers refer to that level or time as the
well's economic limit.
Plugging and Abandoning the Financial Property. When a well
reaches its economic limit, the well is plugged, i.e., the hole is sealed off
at and below the surface, and the surface equipment is removed. Some
well and surface equipment can be salvaged for use elsewhere. Plugging
and abandonment costs, or P&A costs, are commonly referred to as
dismantlement, restoration, and abandonment costs or DR&A costs.
Equipment salvage values may offset the plugging and abandonment
costs of onshore wells so that net DR&A costs are zero. However, for
some offshore wells, estimated future net DR&A costs may exceed $1
million per well due to the cost of removing offshore platforms,
equipment, and perhaps pipelines.
When a leased property is no longer productive, the lease expires and
the oil company plugs the wells and abandons the property. All rights to
exploit the minerals revert back to the lessor as the mineral rights owner.

ACCOUNTING DILEMMAS

The nature of petroleum exploration and production raises numerous
accounting problems. Here are a few:
♦ Should the cost of preliminary exploration be recorded as an asset or an
expense when no right or lease might be obtained?
♦ Given the low success rates for exploratory wells should the well costs
be treated as assets or as expenses? Should the cost of a dry hole be
capitalized as a cost of finding oil and gas reserves? Suppose a company
drills five exploratory wells costing $1 million each, but only one well
finds a reservoir and that reservoir is worth $20 million to the company.
Should the company recognize an asset for the total $5 million of cost,
the $1 million cost of the successful well, the $20 million value of the
productive property, or some other amount?
♦ The sales prices of oil and gas can fluctuate widely over time. Hence,
the value of rights to produce oil and gas may fluctuate widely. Should
such value fluctuations affect the amount of the related assets presented
in financial statements?
♦ If production declines over time and productive life varies by property,
how should capitalized costs be amortized and depreciated?
♦ Should DR&A costs be recognized when incurred, or should an estimate
of future DR&A costs be amortized over the well's estimated productive
life?
♦ If the oil company forms a joint venture and sells portions of the lease to
its venture partners, should gain or loss be recognized on the sale?
As will be explained in this book, the nature, complexity, and
importance of the petroleum E&P industry have caused the creation of an
unusual and complex set of rules and practices for petroleum accounting
and financial presentation

HISTORY OF THE PETROLEUM INDUSTRY IN THE
UNITED STATES
In order to understand the importance and nature of financial
accounting and reporting in the petroleum industry, it is helpful to briefly
review the industry's history, particularly in the United States over the past
twenty years.5 Several exhibits will be presented to show how the
industry's economic characteristics have changed over the years and to
portray the industry's current economic status.
In ancient history, pitch (a heavy, viscous petroleum) was used for
ancient Egyptian chariot axle grease. Early Chinese history reports the
first use of natural gas that seeped from the ground; a simple pipeline
made of hollowed bamboo poles transported the gas a short distance
where it fueled a fire used to boil water.
Seventeenth century missionaries to America reported a black
flammable fluid floating in creeks. From these creeks, Indians and
colonists skimmed the crude oil, then called rock oil, for medicinal and
other purposes. Later, the term rock oil would be replaced by the term
petroleum from petra (a Latin word for rock) and oleum (a Latin word for
oil). Eventually, the term petroleum came to refer to both crude oil and
natural gas.
By the early 1800s, whale oil was widely used as lamp fuel, but the
dwindling supply was uncertain, and people began using alternative
illuminating oils called kerosene or coal oil extracted from mined coal,
mined asphalt, and crude oil obtained from surface oil seepages. At the
same time, U.S. settlers were drilling wells to produce salt brine for salt
production and occasionally encountered crude oil mixed with the
produced brine. In 1856, George Bissell, an investor in the Pennsylvania
Rock Oil Company, surmised that similar wells could be drilled to find
and economically produce crude oil from which valuable kerosene could
be extracted.
The petroleum exploration and production industry may be said to have
begun in 1859. While there is mention of an oil discovery in Ontario,
Canada, in 1858, it is generally recognized that Bissell's company had the
first commercial oil drilling venture in 1859 near Titusville, Pennsylvania.
Colonel Edwin L. Drake, a retired railroad conductor, supervised the
drilling activity on behalf of the Pennsylvania Rock Oil Company. A
steam-powered, cable-tool rig with a wooden derrick was used to drill the
69-foot well, which produced approximately five barrels of crude oil per
day.
Soon after the Drake well began oil production, other wells were drilled
in the Titusville area using cable-tool rigs, and the supply of oil increased
dramatically, causing a decline in the price of crude oil from $10 per
barrel in January 1860 to about ten cents a barrel two years later. Shortly
thereafter, a number of refineries began distilling valuable kerosene from
crude oil, including facilities that had previously extracted kerosene from
other sources.

THE INDUSTRIAL REVOLUTION AND THE GROWTH OF "BIG OIL"

At the start of the U.S. Civil War, approximately 200 wells were
producing over one-half million barrels annually. The introduction of
petroleum-based lamp fuel was only the beginning of an increasing variety
of uses for crude oil and its refined products. For example, the Industrial
Revolution and the Civil War created a demand for lubricants as a
replacement for turpentine. By the year 1870, annual total production of
petroleum exceeded 25 million barrels.
Transportation of crude oil was a problem faced from the earliest days
of oil production. The coopers’ union constructed wooden barrels (with a
capacity of 42 to 50 gallons) that were filled with oil and hauled by
teamsters on horse-drawn wagons to railroad spurs or river barge docks.
At the railroad spurs, the oil was emptied into large wooden tanks that
were placed on flatbed railroad cars. The quantity of oil that could be
moved by this method was limited. However, the industry's attempts to
construct pipelines were delayed by the unions whose members would
face unemployment and by railroad and shipping companies who would
suffer from the loss of business by the change in method of transportation.
Nevertheless, pipelines did come into existence in the 1860s; the first line
was made of wood and was less than a thousand feet long.
Growth in the physical production of petroleum corresponded with
growth in the size and investment of corporations engaged in producing
and refining petroleum. One of the companies involved in the petroleum
industry was partially owned by John D. Rockefeller; in 1865 he acquired
the entire interest in the company. In 1870 Rockefeller merged his firm
with four other companies to form the Standard Oil Company. His original
goal was to become paramount in the refining, transporting, and marketing
of petroleum; but shortly after the merger, he also moved into the area of
oil production.6
Rockefeller's plan for dominance succeeded, and during the 1880s
Standard controlled approximately 90 percent of the refining industry in
the country and dominated the global petroleum industry. Standard's
control of refineries as well as its ownership of railroads, pipelines, and
marketing outlets forced most petroleum customers in the United States to
purchase their products from the company.7
Standard's dominance did not escape federal and state antitrust
regulators. After the discovery of the prolific Spindletop field near
Beaumont, Texas, in 1901, the Texas legislature passed laws preventing
Standard's involvement in Spindletop. As a result, other companies were
formed, and some evolved into vertically integrated companies, such as
Texaco, organized in 1901. In addition to state antitrust laws, federal
legislation had a great impact on Standard Oil Company and led to its
break-up in 1911-1915 into several companies that today have a combined
market value exceeding $200 billion. They include:
♦ Standard Oil of New Jersey (i.e., Exxon) and Standard Oil of New
York (i.e., Mobil) that merged in 1999 to form ExxonMobil, the
largest U.S. petroleum company and a world giant;
♦ Standard Oil of California (now Chevron, the second largest U.S.
petroleum company);
♦ Standard Oil of Indiana (subsequently renamed Amoco) and
Standard Oil of Ohio, both now a part of BP Amoco, following
merger with or acquisition by British Petroleum to create a world
giant rivaling ExxonMobil;
♦ Continental Oil (now Conoco, eighth largest U.S. oil company).8
After the breakup of the Standard Oil Company, Europe's Royal
Dutch/Shell Group succeeded Standard Oil as the world's largest oil
company. The group was an unusual amalgamation that was owned 60
percent by the Netherlands’s Royal Dutch Company and 40 percent by
England's Shell Transport and Trading Company. Royal Dutch had made
its fortunes in oil production in the Dutch East Indies, now Indonesia.
Shell had prospered in global oil trading and transportation before
expanding into production and refining.

Petroleum Economics and Legalizations

BASIC TERMS AND CONCEPTS
-Petroleum refers to crude oil and natural gas or simply oil and gas. These are mixtures of hydrocarbons which are molecules, in various shapes and sizes, of hydrogen and carbon atoms found in the small, connected pore spaces of some underground rock formations.
-petroleum reservoirs are generally thousands of feet below the surface. Crude oil and natural gas are believed to be the remains of plants and animals, mostly small marine life, that lived many millions of years ago.
From petroleum we get numerous useful products:

 In the United States natural gas is measured in two ways, both important in petroleum accounting:

WELL CONTROL COURSE SECTION A

SECTION A
KEY DEFINITIONS


Drilling Ahead






WHAT IS A KICK?

IT IS AN INFLUX OF FORMATION FLUID
THAT CAUSES THE WELL TO FLOW.


 
WHAT IS A BLOWOUT?

AN UNCONTROLLED EXIT OF THE FORMATION FLUIDS
AT THE SURFACE



 Hydrostatic Pressure

Hydro- means a fluid
Static- means at rest

Hydrostatic in the wellbore is from the mud

MUD HYDROSTATIC
         VERTECAL  WELL      

STANDERED FORMULA  WITH  FT., PPG AND PSI
MUD HYDROSTATIC  HP  = 0.052 X MUD WEIGHT X DEPTH
MUD GRADIANT   =  0.052  X MUD WEIGHT           PSI\FT.
Pressure (psi) = Mud Weight x .052 x TVD
Pressure Gradient (psi/ft) = Mud Weight, ppg x .052
Pressure Gradient (psi/ft) =Pressure, psi ¸ TVD, ft
Mud Weight, ppg = Pressure Gradient ¸ .052
Mud Weight (ppg) = Pressure ¸ TVD ¸ .052
TVD (ft) = Pressure (psi) ¸ Mud Weight (ppg) ¸ 0.052

FORMATION FLUID 
Fluid present in the pore space of the rock.
FORMATION PRESSURE
 
The pressure of the formation fluids.

  What is formation fluid pressure?
Formation Pressure: is the fluid pressure in the pore spaces of the formation.
BOTTOM HOLE PRESSURE 
IT  IS THE TOTAL  PRESSURES  EXERTED AT THE  BOTTOM  OF  THE WELL.
Balance
 
Mud Hydrostatic =Formation Pressure
Overbalance
 
Mud Hydrostatic >  Formation Pressure


Underbalance
  
Mud Hydrostatic <  Formation Pressure

 
WHAT IS WELL CONTROL?

1-PREVENTING A KICK
PRIMARY

2-SHUTTING IN THE WELL AFTER A KICK HAS BEEN TAKEN
SECONDARY
  
Primary control
Secondary Control
Blowout Preventers


 
WELL CONTROL CYCLE




HOW CAN KICKS HAPPEN?

Mud Hydrostatic and Formation Pressure
Always Remember that HP and FP are two opposite forces.
 

suker rod pump con't 2

Selection of the Proper Pumping Mode

The pumping mode of a sucker-rod pumping system is defined as the combination of pump size, polished-rod stroke length, pumping speed, and rod string design.
the optimum design is based on the value of lifting efficiencies and the one with the maximum ηlift is selected.
Maximizing the lifting efficiency coincides with the case of setting the polished rod power, PRHP, to be a minimum.
for a given hydraulic power
lifting efficiency and PRHP are inversely proportional.
A pumping system design made by this principle results in minimum operation cost and in a maximum of system efficiency.
If the best mode is selected, the energy input at the polished rod is only slightly greater than the pump’s hydraulic power, ensuring a lifting efficiency of over 94%.
The worst mode, on the other hand, requires almost three times as much energy as the best one for lifting the same amount of liquid from the same depth.


by increasing the pump size the attained maximum lifting efficiency values increase for all tapers.
Therefore, use of bigger plungers with correspondingly slower pumping speeds is always useful and results in lower energy requirements.
Also use of the heavier rod strings  increases the power requirement for smaller pump sizes.
OPTIMUM COUNTERBALANCING OF PUMPING UNITS

ideal counterbalance conditions are desired that can have many beneficial effects on the operation of the sucker-rod pumping system:
 Gearbox size can be reduced when compared to an unbalanced condition,
 The size of the required prime mover is smaller, and
   The smoother operation of a properly balanced speed reducer lowers maintenance costs and increases equipment life.
the mechanical Cyclic Load Factor (CLF). It can be calculated from the variation during the pumping cycle of the net torque on the reducer as the ratio of the root mean square and the average net torques:
These methods try to find the maximum counterbalance moment satisfying one of the following criteria:
The peak motor currents are equal during the up-, and downstroke,
 The peak net torques on the up-, and downstroke are equal,
 The required mechanical powers for the up-, and downstroke are equal, or
 A minimum of the cyclic load factor is achieved.
 
The CLF value valid for this case is greater than the minimum CLF achieved by the recommended optimization model.

PITFALLS IN ROD STRING DESIGN 


Rod string design aims at the determination of:
• The rod sizes to be used in the string,
• The lengths of the individual taper sections, and
• The rod material to be used.
The two basic problems in rod string design concern:
(1) how rod loads are calculated, and
(2) what principle to use for the determination of taper lengths.
At the time of design, rod loads are not known, and they also depend on the taper lengths that are about to be determined. Therefore, one has to rely on approximate calculations to find probable rod loads that will occur during pumping

Design Principles
Early rod string design methods utilized the simplifying assumption that the string was exposed to a simple tension loading. An examination of the rod loads during a complete pumping cycle, however, shows that the rod string is under a cyclic loading.
The nature of the loading is pulsating tension because the whole string is under tension at all times, but rod stress levels change for the up-, and the downstroke.
sucker-rod strings should be designed for fatigue endurance.
CONCLUSIONS


The pumping system’s energy efficiency depends primarily on the amount of downhole power losses.
  Maximum system efficiency is ensured by achieving a maximum of lifting efficiency.
 The proper selection of pumping mode can ensure maximum lifting efficiency and thus a most energy-efficient sucker-rod pumping system.
 Optimum counterbalancing of pumping units has many beneficial effects.
Minimizing the CLF is the preferred method for finding optimum counterbalanceconditions.
 Available rod string design procedures can have many pitfalls. Proper designs should provide a uniform fatigue loading of all rod taper sections.

SUCKER ROD PUMP con't

WAYS TO DECREASE PRODUCTION COSTS
FOR SUCKER-ROD PUMPING 
-roughly two-thirds of the producing oil wells are on this type of lift.
-To maximize profits from these wells in the ever-changing economic situation with rising costs of electric power, installation designs must ensure optimum conditions.
IMPROVING ENERGY EFFICIENCY 
energy losses both downhole and on the surface
      must be minimized.

1- Downhole Energy Losses

2- Surface Losses 







-The sources of down-hole energy losses in the
 
sucker-rod pumping system are :
 
-the pump, the rod string, and the fluid column.
 
The energy required for operating the polished
 
rod at the surface  is thus 
 
-the sum of the useful hydraulic work
 
performed by the pump and the downhole 
 
energy losses.
 
-This power is called the polished rod power or 
 
PRHP.
 
-The energy efficiency of the downhole 
 
components of the sucker-rod pumping system can
 
be known by the relative amount of energy
 
losses in the well.
 
This is called Lifting Efficiency.
 
 
 
Surface Losses 
 
 
mechanical energy losses Starting from the polished rod:

frictional losses arise in the stuffing box, in the pumping unit’s

structural bearings, in the speed reducer
 
(gearbox), and in the

 belt drive.
the electrical power taken by the motor is always greater than

 the mechanical power developed at the motor’s shaft.

The power losses in an electric motor are classified as mechanical

         and electrical.

Mechanical losses occur in the motor’s bearings
 
due to friction.

other losses include windage loss consumed by air surrounding the

 rotating parts.

an overall efficiency ηmot is used to represent
all losses in the

 motor, which, for average electric motors,
 
lies in the range of 85% to 93%.  
 
Optimum Energy Efficiency 
 
 
the energy efficiency is found from: 
 
 
Where : 
 
A more detailed formula
 
 
 


—the possible values of both the surface mechanical efficiency, ηmech, 
 
and the motor efficiency, ηmot, vary in

quite narrow ranges.

—At the same time, their values are not easy to improve upon; that is 
 
why. their effects on the system’s total efficiency are not very significant.

—On the other hand, lifting efficiency can be considered as the 
 
governing factor since it varies in a broad range depending on the pumping 
 
mode selected.

—Thus considerable improvements on the pumping system’s overall 
 
energy efficiency can only be realized by achieving a maximum of lifting 
 
efficiency.

—lifting efficiency mainly depends on the pumping mode selected (i.e.
 
the combination of plunger size, stroke length, pumping speed, and rod 
string design).