US Petroleum Holdings, information about gas, oil and petroleum
The UK now exports quantities of crude oil and is acknowledged for expertise in the area of deep-water technology – using advanced engineering techniques for extracting a higher proportion of oil from each field. This technique was unknown twenty years ago. Consequently, UK specialists are in demand all over the world.
The UK Continental Shelf (UKCS) is facing significant challenges as the province matures. Recovering oil and gas from the North Sea and the Atlantic Margin (the area of water to the west of Shetland and the north of the Hebrides) is a highly technical, complex, dangerous and expensive job. As supplies from larger oil fields run out, smaller, more expensive fields are being exploited. UK oil companies have to be inventive and invest in safe and efficient techniques to remain competitive.
The UK still has substantial recoverable reserves of oil and gas, potentially exceeding the amount already produced. However, many existing, large producing fields are well into decline and discoveries are becoming fewer and smaller or have significant associated technical challenges.
Current trends
As the UK’s oil fields mature, the industry’s focus has shifted from searching for new oil discoveries to continuing the productivity of mature fields, as well as developing smaller fields that were not previously considered commercially viable. This trend has prompted major oil companies to begin selling some of their mature UKCS assets in favour of other regions of the world. Smaller, independent oil companies have been acquiring these UKCS assets.
Natural gas is the UK’s largest source of primary energy, supplying over 40% of the country’s total energy needs. It is used as both a domestic and industrial fuel. It generates electricity to provide heat and power for homes and industries, and is feedstock for chemicals, pharmaceuticals and other products.
The UK is currently the world’s fourth largest producer of natural gas and has more than 200 offshore fields in production around Great Britain. The greatest concentrations of gas are found in the southern sector of the North Sea, but significant volumes are also produced from the central and
Uses of Gas Oil
Us Petroleum Holdings Oil has many uses; it heats homes and businesses and fuels trucks, ships and some cars. A small amount of electricity is produced by diesel, but it is more polluting and more expensive than natural gas. It is often used as a backup fuel for peaking power plants in case the supply of natural gas is interrupted or as the main fuel for small electrical generators. In Europe the use of diesel is generally restricted to cars (about 40%), SUVs (about 90%), and trucks (virtually all). The market for home heating using fuel oil, called heating oil, has decreased due to the widespread penetration of natural gas. However, it is very common in some areas, such as the Northeastern United States.
Residual fuel oil is less useful because it is so viscous that it has to be heated with a special heating system before use and it contains relatively high amounts of pollutants, particularly sulfur, which forms sulfur dioxide upon combustion. However, its undesirable properties make it very cheap. In fact, it is the cheapest liquid fuel available. Since it requires heating before use, residual fuel oil cannot be used in road vehicles, boats or small ships, as the heating equipment takes up valuable space and makes the vehicle heavier. Heating the oil is also a delicate procedure, which is inappropriate to do on small, fast moving vehicles. However, power plants and large ships are able to use residual fuel oil.
Residual fuel oil was used more frequently in the past. It powered boilers, railroad locomotives and steamships. Locomotives now use diesel, steamships are still used however are not as common as they were previously due to their higher operating costs, (most LNG carriers use steam plants as boil off gas emitted from the cargo can be used as a fuel source), and most boilers now use heating oil or natural gas. However, some industrial boilers still use it and so do a few old buildings, mostly in New York City. Residual fuel’s use in electricity generation has also decreased. In 1973, residual fuel oil produced 16.8% of the electricity in the United States. By 1983, it had fallen to 6.2%, and as of 2005, electricity production from all forms US Petroleum Holdings of petroleum, including diesel and residual fuel, is only 3% of total production. The decline is the result of price competition with natural gas and environmental restrictions on emissions. For power plants, the costs of heating the oil, extra pollution control and additional maintenance required after burning it often outweigh the low cost of the fuel. Burning fuel oil, particularly residual fuel oil, also produces much darker smoke than natural gas, which affects the perception of the plant by the community.
Heavy fuel oils continue to be used in the boiler “lighting up” facility in every coal-fired power plant, of which there are a small number in the UK and dozens in China. Although on an enormous scale, it is analogous to lighting kindling to start a fire – without performing this simple function it is difficult to begin the large-scale combustion process.
The chief drawback to residual fuel oil is its high initial viscosity, particularly in the case of No. 6 oil, which requires a correctly engineered system for storage, pumping, and burning. Though it is still usually lighter than water (with a specific gravity usually ranging from 0.95 to 1.03) it is much heavier and more viscous than No. 2 oil, kerosene, or gasoline. No. 6 oil must, in fact, be stored at around 100°F (37.8°C) heated to 150°F (65.6°C)–250°F (121.1°C) before it can be easily pumped, and in cooler temperatures it can congeal into a tarry semisolid. The flash point of most blends of No. 6 oil is, incidentally, about 150°F (65.6°C). Attempting to pump high-viscosity oil at low temperatures was a frequent cause of damage to fuel lines, furnaces, and related equipment which were often designed with lighter fuels in mind.
(For comparison, BS2869 Class G Heavy Fuel Oil behaves in similar fashion, requiring storage at 104°F (40°C), pumping at around 122°F (50°C) and finalising for burning at around 194°F (90°C) / 248°F (120°C).)
Most of the facilities which historically burned No. 6 or other residual oils were industrial plants and similar facilities constructed in the early or mid 20th century, or which had switched from coal to oil fuel during the same time period. In either case, residual oil was seen as a good prospect because it was cheap and readily available, even though it provided less energy per litre than lighter fuels. Most of these facilities have subsequently been closed and demolished, or have replaced their fuel supplies with a simpler one such as gas or No. 2 oil. The high sulfur content of No. 6 oil– up to 3% by weight in some extreme cases– had a corrosive effect on many heating systems (which were usually designed without adequate corrosion protection in mind), shortening their lifespans and increasing the polluting effects. This was particularly the case in furnaces that were regularly shut down and allowed to go cold; the internal condensation produced sulfuric acid.
Environmental cleanups at such facilities are frequently complicated by the use of asbestos insulation on the fuel feed lines. No. 6 oil is very persistent, and does not degrade rapidly. Its viscosity and stickiness also make remediation of underground contamination very difficult, since it reduces the effectiveness of methods such as air-stripping.
When released into water, such as a river or ocean, residual oil tends to break up into patches or tarballs– mixtures of oil and particulate matter such as silt and floating organic matter- rather than form a single slick. An average of about 5-10% of the material will evaporate within hours of the release, primarily the lighter hydrocarbon fractions. The remainder will then often sink to the bottom of the water column.
Houston Farm Project
History
The Houston Farms #1 well was drilled by Midwest Oil Company US Petroleum Holdings in 1960 to a total depth of 16,085 ft. The Lower Frio, the main objective at 16,000 ft. was wet and non-productive, so the well was considered a dry hole. While drilling the well, core sample of various Upper Frio sands between 10,000 – 12,000 ft. were taken and indicated condensate (gas) pay. Prior to plugging and abandonment, several of these Upper Frio sands were tested and they showed to be productive. The well was never completed, most likely due to nominal gas prices and/or the lack of a gas market. With Natural Gas prices at the time only a few pennies per MCF of gas, it was not economical to set several miles of pipeline to transport for just one well. Consequently, the well was plugged and abandoned. US Petroleum Holdings
The Frio Deep-Seated Salt Dome Fields lie south and southeast of Houston in Brazoria, Ford Bend, Harris, Galveston and Chambers counties along the Texas coast, US Petroleum Holdings.
Collectively, the Frio Deep-seated Salt Dome Fields are significant because their cumulative yields exceed those of any other producing formation in Southeast Texas. From the early 1930’s through 1982, the fields reported a combined cumulative production in excess of 2.3 billion barrels of oil, and at the end of 1993, the figure surpassed 2.4 billion barrels.
Although the most prolific fields were found in the 1930’s (15 major discoveries), development of the play continued into the 1940’s and 1950’s, and centered in Chambers and Brazoria counties, US Petroleum Holdings, because of the proximity to the Danbury Dome, Hoskins Mound and the apparent deeper seated salt diaper over the Chocolate Bayou field.
By 1982, engineers set recoverable reserves for Frio reservoirs of the deep-domes play at nearly 4 billion barrels of oil. By the end of 1993 the fields had yielded more than 2.4 billion barrels.
In the 1950’s three new areas became productive and were called Chocolate Bayou Upper Frio (Brazoria County, 1950), Trinity Bay Frio 12 (Chambers County, 1951), and Chocolate Bayou Alibel (Brazoria County, 1952).
During the last half of the 20th century, the Chocolate Bayou Field has increased in aerial extent and multiple sand packages stacked all the way down to the 15,000 ft. Lower Frio Marker. Several major oil companies and numerous independent exploration companies have discovered over 55 different horizons (pay zones) within the Chocolate Bayou Field. The cumulative production of both gas and oil within this field is ENORMOUS!
Multiple Oligocene Frio Gas Sands have been identified in the well by log and core analysis. Sands are located within the existing casing between 10,000 and 12,200 ft. The primary objective is to complete the 12,000 ft. series of sands. A future plugback would complete the 10,000 ft. series of sands.
A second well on the property will be drilled to the Miocene Gas Sands between 5,100 and 7,000 ft. These sands show as productive as in the Houston Farms #1 well. The well will “twin” the Houston Farms #1 location for the shallower objectives.
Geological estimation of total reserves: 350,000 barrels of oil and 15 Billion cubic feet of Natural Gas.
Estimated Payout: somewhere between 100 – 120 barrels of crude oil per day.
Bissonet Humble Petroleum
Bissonet Lease at Humble Salt Dome Field
History
Humble Salt Dome Field was discovered in the early 1900’s. Bubbles of oil were first observed seeping from the ground near the San Jacinto river in 1887. Humble became an oil boomtown in the early 1900’s when oil was first produced here. The first oil was produced a couple years earlier after the famous Spindletop discovery in Beaumont Texas.
In the fall of 1902, George Hart spudded a well in the field on evidence of escaping gas in the area. His operation was halted by a blowout, an unexpected volume of gas under pressure, that forced the drilling equipment out of the hole. Blowouts were encountered in several wells in the part of the field later called “the hill” and drilled in the summer of 1904 by C.E. Barrett of Houston. Despite the menace of blowouts, some success was found in the early field when Higgins Oil and Fuel Company brought in a large-volume gas well half a mile Southeast of Barrett wells in October 1904. By the end of the year, Humble field reported two sporadically-producing oil wells that had yielded 2,000 barrels of oil. Since none of the crude had been sold, it was stored in earthen tanks for use in the field. Even though blowouts hampered field development, their threat was minimized by the invention of a blowout preventer in 1905. D.R. Beatty used the blowout preventer on the #2 Fee Well which gave up the first gusher with a potential of 8,500 barrels of oil a day from a depth of 1,012 feet.
From 1905 through 1913, development of the field concentrated on the caprock of the salt dome, producing at depths of 1,100 – 1,200 ft. When deep production was found on the dome flanks at Sour Lake Field, operators in Humble field drilled into zones below 2,500 ft., hoping to emulate the success at Sour Lake. In November 1913 the effort was rewarded when Producers Oil #11 Carroll cam in with a potential 10,000 barrels of oil per day at a total depth of 2,700 ft. Forty-six wells were completed before the end of the year, and production reached nearly 2.8 million barrels of oil. In 1935 the Wilson Oil House Well #1 came in at 1500 bopd from the 2,500 ft. sand on the north flank of the field.
Geological estimation of total reserves: 50,000,000 barrels of oil.
Estimated Payout: somewhere between 100 – 300 barrels of crude oil per day.
US Petroleum holdings a Recent Outlook
Official Energy Statistics from the U.S. GovernmentTrends in energy supply and demand are affected by many factors that are difficult to predict, such as energy prices, U.S. economic growth, advances in technologies, changes in weather patterns, and future public policy decisions. It is clear, however, that energy markets are changing gradually in response to such readily observable factors as the higher energy prices that have been experienced since 2000, the greater influence of developing countries on worldwide energy requirements, recently enacted legislation and regulations in the United States, and changing public perceptions of issues related to the use of alternative fuels, emissions of air pollutants and greenhouse gases, and the acceptability of various energy technologies, among others The Energy Information Administration projects increased consumption of biofuels (both ethanol and biodiesel), growth in coal-to-liquids (CTL) capacity and production, growing demand for unconventional transportation technologies (such as flex-fuel, hybrid, and diesel vehicles), growth in nuclear power capacity and generation, and accelerated improvements in energy efficiency throughout the economy.
Despite the rapid growth projected for biofuels and other nonhydroelectric renewable energy sources and the expectation that orders will be placed for new nuclear power plants for the first time in more than 25 years, oil, coal, and natural gas still are projected to provide roughly the same 86-percent share of the total U.S. primary energy supply in 2030 that they did in 2005 (assuming no changes in existing laws and regulations). The expected rapid growth in the use of biofuels and other nonhydropower renewable energy sources begins from a very low current share oftotal energy use; hydroelectric power production, which accounts for the bulk of current renewable electricity supply, is nearly stagnant; and the share of total electricity supplied from nuclear power falls despite the projected new plant builds, which more than offset retirements, because the overall market for electricity continues to expand rapidly in the projection.
Classfication of oil for US Petroleum Holdings
. Brent Crude, comprising 15 oils from fields in the Brent and Ninian systems in the East Shetland Basin of the North Sea. The oil is landed at Sullom Voe terminal in the Shetlands. Oil production from Europe, Africa and Middle Eastern oil flowing West tends to be priced off the price of this oil, which forms a benchmark.
. West Texas Intermediate (WTI) for North American oil.
. Dubai, used as benchmark for Middle East oil flowing to the Asia-Pacific region.
. Tapis (from Malaysia, used as a reference for light Far East oil)
. Minas (from Indonesia, used as a reference for heavy Far East oil)
. The OPEC basket used to be the average price of the following blends:
o Arab Light Saudi Arabia
o Bonny Light Nigeria
o Fateh Dubai
o Isthmus Mexico (non-OPEC)
o Minas Indonesia
o Saharan Blend Algeria
o Tia Juana Light Venezuela
OPEC attempts to keep the price of the OPEC Basket between upper and lower limits, by increasing and decreasing production. This makes the measure important for market analysts. The OPEC Basket, including a mix of light and heavy crudes, is heavier than both Brent and WTI.
In June 15, 2005 the OPEC basket was changed to reflect the characteristics of the oil produced by OPEC members. The new OPEC Reference Basket (ORB) is made up of the following: Saharan Blend (Algeria), Minas (Indonesia), Iran Heavy (Islamic Republic of Iran), Basra Light (Iraq), Kuwait Export (Kuwait), Es Sider (Libya), Bonny Light (Nigeria), Qatar Marine (Qatar), Arab Light (Saudi Arabia), Murban (UAE) and BCF 17 (Venezuela).
Oil Production by Country:
. Saudi Arabia (OPEC) – 10.37 MMbbl/d
. Russia – 9.27 MMbbl/d
. United States 1 – 8.69 MMbbl/d
. Iran (OPEC) – 4.09 MMbbl/d
. Mexico 1 – 3.83 MMbbl/d
. China 1 – 3.62 MMbbl/d
. Norway 1 – 3.18 MMbbl/d
. Canada 1 – 3.14 MMbbl/d
. Venezuela (OPEC) 1 – 2.86 MMbbl/d
. United Arab Emirates (OPEC) – 2.76 MMbbl/d
. Kuwait (OPEC) – 2.51 MMbbl/d
. Nigeria (OPEC) – 2.51 MMbbl/d
. United Kingdom 1 – 2.08 MMbbl/d
. Iraq (OPEC) 2 – 2.03 MMbbl/d
In order of amount exported in 2003:
. Saudi Arabia (OPEC)
. Russia
. Norway 1
. Iran (OPEC)
. United Arab Emirates (OPEC)
. Venezuela (OPEC) 1
. Kuwait (OPEC)
. Nigeria (OPEC)
. Mexico 1
. Algeria (OPEC)
. Libya (OPEC) 1
Though still a member, Iraq has not been included in production figures since 1998
Science of Oil
Most geologists view crude oil, like coal and natural gas, as the product of compression and heating of ancient organic materials over geological time scales. According to this theory, it is formed from the decayed remains of prehistoric small marine animals and algae. (Terrestrial plants tend to form coal.) Over millennia this organic matter, mixed with mud, is buried under thick sedimentary layers of material. The resulting high levels of heat and pressure cause the remains to metamorphose, first into a waxy material known as kerogen, and then into liquid and gaseous hydrocarbons in a process known as catagenesis. Because hydrocarbons are less dense than the surrounding rock, these migrate upward through adjacent rock layers until they become trapped beneath impermeable rocks, within porous rocks called reservoirs. Concentration of hydrocarbons in a trap forms an oil field, from which the liquid can be extracted by drilling and pumping.
Geologists also refer to the “oil window”. This is the temperature range that oil forms in-below the minimum temperature oil does not form, and above the maximum temperature natural gas forms instead. Though this corresponds to different depths for different locations around the world, a ‘typical’ depth for the oil window might be 4 – 6 km. Note that oil may be trapped at much shallower depths, even if it is not formed there. Three conditions must be present for oil reservoirs to form: a rich source rock, a migration conduit, and a trap (seal) that concentrates the hydrocarbons.
The reactions that produce oil and natural gas are often modeled as first order breakdown reactions, where kerogen breaks down to oil and natural gas by a large set of parallel reactions, and oil eventually breaks down to natural gas by another set of reactions.
FORMATION OF OIL: Abiogenic theory
The idea of abiogenic petroleum origin was championed in the Western world by astronomer Thomas Gold based on thoughts from Russia, mainly on studies of Nikolai Kudryavtsev. The idea proposes that large amounts of carbon exist naturally in the planet, some in the form of hydrocarbons. Hydrocarbons are less dense than aqueous pore fluids, and migrate upward through deep fracture networks. Thermophilic, rock-dwelling microbial life-forms are in part responsible for the biomarkers found in petroleum.
According to the following authors; V. A. Krayushkin, T. I. Tchebanenko, V. P. Klochko, Ye. S. Dvoryanin from the Institute of Geological Sciences, Kiev, Ukraine, the modern Russian-Ukrainian theory of deep, abiotic petroleum origins is by no means simply an academic proposition. After its first enunciation by N. A. Kudryavtsev in 1951, the modern theory was extensively debated and exhaustively tested. Significantly, the theory not only withstood all tests put to it, but it also settled many previously unresolved problems in petroleum science, such as that of the intrinsic component of optical activity observed in natural petroleum. It also demonstrated new patterns in petroleum, previously unrecognized, such as the paleonological and trace-element characteristics of reservoirs at different depths. Most importantly, the modern Russian-Ukrainian theory of deep, abiotic petroleum origins has played a central role in the transformation of Russia (then the U.S.S.R.) from being a “petroleum poor” entity in 1951 to the largest petroleum producing and exporting nation on Earth, principally with the drilling and development of the oil and gas fields in the Dnieper-Donetsk Basin.
However, this theory is very much a minority opinion, especially amongst western geologists. It often pops up when scientists are not able to explain apparent oil inflows into certain oil reservoirs. However, most of these “abiotic” fields are explained as being the result of geologic quirks. No western oil companies are currently known to explore for oil based on this theory.
ALTERNATIVE MEANS OF PRODUCING OIL
As oil prices continue to escalate, other alternatives to producing oil have been gaining importance. The best known such methods involve extracting oil from sources such as oil shale or tar sands. These resources are known to exist in large quantities; extracting the oil at low cost and without too deleterious an impact on the environment remains a challenge.It is also possible to transform natural gas or coal into oil (or, more precisely, the various hydrocarbons found in oil).
The best-known such method is the Fischer-Tropsch process. It was a concept pioneered in Nazi Germany when imports of petroleum were restricted due to war and Germany found a method to extract oil from coal. It was known as Ersatz (“substitute” in German), and accounted for nearly half the total oil used in WWII by Germany. However, the process was used only as a last resort as naturally occurring oil was much cheaper. As crude oil prices increase, the cost of coal to oil conversion becomes comparatively cheaper.
The method involves converting high ash coal into synthetic oil in a multistage process. Ideally, a ton of coal produces nearly 200 liters (1.25 bbl, 52 US gallons) of crude, with by-products ranging from tar to rare chemicals.
Currently, two companies have commercialized their Fischer-Tropsch technology. Shell in Bintulu, Malaysia, uses natural gas as a feedstock, and produces primarily low-sulfur diesel fuels. Sasol in South Africa uses coal as a feedstock, and produces a variety of synthetic petroleum products. The process is today used in South Africa to produce most of the country’s diesel fuel from coal by the company Sasol. The process was used in South Africa to meet its energy needs during its isolation under Apartheid. This process has received renewed attention in the quest to produce low sulfur diesel fuel in order to minimize the environmental impact from the use of diesel engines.
An alternative method is the Karrick process, which converts coal into crude oil, pioneered in the 1930s in the United States.
More recently explored is thermal de-polymerization (TDP). In theory, TDP can convert any organic waste into petroleum.
History of oil
Invest in oil or in gas
- U.S. domestic oil production increased throughout the 1950’s and 1960’s. Writing in the 1950’s, American geologist M. King Hubbert predicted that the production of U.S. oil fields would peak in the early 1970’s. It happened that U.S. production began to decline in 1970. Hubbert’s key insight was that production peaks once half the oil in any field has been extracted. Far more oil is extracted in the early stages of production than later on. In 1970, the U.S. satisfied about 70% of its needs from domestic oil production. Now, however, the picture is much bleaker, as the U.S. satisfies about 35% of its needs from domestic production and imports the rest.
- Since 1969, the North Sea utilizing advanced technology has produced about 15 billion barrels of oil, helping Norway become rich, and Britain to shed its status as a third rate economy. Production in the British sector, however, has already started to decline and Norway close to peak production. The North Sea has shown that technology is a double-edged sword by extracting more oil up front, but hastening the day of reckoning when production starts to decline.
- Princeton professor Kenneth S. Deffeyes, a colleague of Hubbert, sought to apply Hubbert’s geological precepts on a worldwide basis. Other geologists have made the same effort, and while they do not all agree on the same year, the general conclusion is that world oil production is now close to peaking!
- The reserves of the OPEC countries are overstated. Quotas for the members are determined by production capacity, and production capacity is directly related to reserves. In 1988 for example, Iraq announced that their reserves had more than doubled to 100 billion barrels. This was a miraculous feat, despite continued production and the total absence of exploration. The Saudis, Iraq, and Iran have all engaged in overstating reserves.
- China’s economy is growing by leaps and bounds, and has an insatiable thirst for energy. If China’s per capita energy consumption comes anywhere close to that of the U.S., their need for oil will surpass that of the U.S.
- Present world oil production is around 77 million barrels per day, and the International Energy Agency projects that world oil production will peak at around 80 million barrels per day.
- Oil from new exploration, including any efforts to open up the Arctic National Wildlife Refuge, will barely make a dent in our growing need for energy.
- Oil prices are set to soar! The only question is whether they do so rapidly and abruptly sending the economy and financial markets into a tailspin, or gradually, triggering high and rising inflation.
- Considering the peak reached in 1981, and adjusting for present demand and inflation, some reliable sources have predicted that oil could reach $100 per barrel by the end of the decade.
- Natural gas is also in short supply in the U.S. Over the next decade, U.S. demand for natural gas is expected to grow by over 30%. Even after natural gas prices soared in 2000, generating record drilling, natural gas production increased only 2% in 2001- not enough to meet one year’s growth in demand.
- Alternative energy sources (wind, solar, nuclear etc.), are not positioned to replace fossil fuel demand any time in the near future. Coal is not an acceptable alternative because of the environmental problems associated with burning coal.
- Obviously, given the current level of drilling activity both in the U.S. and overseas, oil and gas development can be a very profitable investment at today’s prices. Looking to the future, the financial picture becomes even brighter, and suggests that now more than ever is the time to get involved and ride the crest of the wave.
- In the mid 1990s technological breakthroughs, enabled the industry to evaluate seismic survey data in three dimensions. A 3-D seismic survey, versus a 2-D seismic survey, is rather like looking at a CAT SCAN versus a regular X-RAY. In certain geological formations, 3-D seismic can accurately identify accumulations of oil or gas. This has given the smaller independent oil companies the ability to compete with the majors, particularly on the smaller lease plays. In turn, this has benefited private capital and the individual investor by affording the ability to invest in oil and gas prospects, previously considered the domain of the majors.
- The 1990s also saw technological breakthroughs in the use of horizontal drilling techniques. Horizontal drilling in areas, such as the Austin Chalk in Texas, has boosted the production rates of wells, making them more economical to drill and providing a faster return on investment.
Houston Farm Project
History
The Houston Farms #1 well was drilled by Midwest Oil Company in 1960 to a total depth of 16,085 ft. The Lower Frio, the main objective at 16,000 ft. was wet and non-productive, so the well was considered a dry hole. While drilling the well, core sample of various Upper Frio sands between 10,000 – 12,000 ft. were taken and indicated condensate (gas) pay. Prior to plugging and abandonment, several of these Upper Frio sands were tested and they showed to be productive. The well was never completed, most likely due to nominal gas prices and/or the lack of a gas market. With Natural Gas prices at the time only a few pennies per MCF of gas, it was not economical to set several miles of pipeline to transport for just one well. Consequently, the well was plugged and abandoned.
The Frio Deep-Seated Salt Dome Fields lie south and southeast of Houston in Brazoria, Ford Bend, Harris, Galveston and Chambers counties along the Texas coast.
Collectively, the Frio Deep-seated Salt Dome Fields are significant because their cumulative yields exceed those of any other producing formation in Southeast Texas. From the early 1930’s through 1982, the fields reported a combined cumulative production in excess of 2.3 billion barrels of oil, and at the end of 1993, the figure surpassed 2.4 billion barrels.
Although the most prolific fields were found in the 1930’s (15 major discoveries), development of the play continued into the 1940’s and 1950’s, and centered in Chambers and Brazoria counties because of the proximity to the Danbury Dome, Hoskins Mound and the apparent deeper seated salt diaper over the Chocolate Bayou field.
By 1982, engineers set recoverable reserves for Frio reservoirs of the deep-domes play at nearly 4 billion barrels of oil. By the end of 1993 the fields had yielded more than 2.4 billion barrels.
In the 1950’s three new areas became productive and were called Chocolate Bayou Upper Frio (Brazoria County, 1950), Trinity Bay Frio 12 (Chambers County, 1951), and Chocolate Bayou Alibel (Brazoria County, 1952).
During the last half of the 20th century, the Chocolate Bayou Field has increased in aerial extent and multiple sand packages stacked all the way down to the 15,000 ft. Lower Frio Marker. Several major oil companies and numerous independent exploration companies have discovered over 55 different horizons (pay zones) within the Chocolate Bayou Field. The cumulative production of both gas and oil within this field is ENORMOUS!
Multiple Oligocene Frio Gas Sands have been identified in the well by log and core analysis. Sands are located within the existing casing between 10,000 and 12,200 ft. The primary objective is to complete the 12,000 ft. series of sands. A future plugback would complete the 10,000 ft. series of sands.
A second well on the property will be drilled to the Miocene Gas Sands between 5,100 and 7,000 ft. These sands show as productive as in the Houston Farms #1 well. The well will “twin” the Houston Farms #1 location for the shallower objectives.
Geological estimation of total reserves: 350,000 barrels of oil and 15 Billion cubic feet of Natural Gas.
Estimated Payout: somewhere between 100 – 120 barrels of crude oil per day.
