If you are interested in oil and gas investing there are many things to consider. Here are few things you should consider when evaluating oil and gas prospects.
Company Management: When evaluating an oil and gas drilling project, you must first look first at the company to identify how long they have been in the oil business and in what capacities. Second, you need to find out who the operator is on the wells and look at what their success has been in the past. You should also make sure there is a experienced geologist involved, who will look at the geology and related data on a project and give their evaluation of its likeliness for success. This criterion will help keep you out of projects with people who are inexperienced and less likely to manage the project properly.
Project Structure: Regardless of the project's structure or complexity, two simple questions must be answered: Who gets what percent of the revenue over the life of the project? Are the anticipated costs within a reasonable range? Most oil and gas projects have the following parties share revenues from a producing well — the owner of the oil and gas mineral rights, the operator, and the working interest owners. Traditionally, the mineral owner receives a royalty interest of 12.5% to 25% of the total production revenue of a well, and the remainder of the revenue is divided up between the operator and the working interest owners. When you are evaluating different projects look to see how much net revenue interest is being offered per one percent of working interest. You also need to make sure that your net revenue interest doesn’t decrease once you have received the pay out of your initial investments.
Contracts: Before you sign any contract it is extremely important to read it thoroughly. Read all of the fine print and be sure you like what it says. Don’t sign anything that you don’t agree with. The best thing you can do is have your attorney review any contractual agreement about your investments before you sign them. An attorney will find any holes or problems with a contract and may be able to help work out any details that need to be changed.
Research. The most important thing you can do when you choose oil investments is to do plenty of research. Know everything about your investment before you make your decision. Research everything you can about the location of the drill site, the company doing the drilling, and more. The more you know about the gas investments, the more comfortable you will be with your decision.
Price Volatility. Oil and gas investing has many factors but the profit relies on the market prices of the oil and gas. It is common for prices to be volatile. When this occurs it can have a major impact about the profitability.
Successful oil and gas companies and operators can make monthly returns which allow private partners investing in oil and gas exploration and drilling projects the potential to receive their original capital back in less than a year or two after new wells are completed, and placed into production. In addition to the income potential, oil and gas investments also offer substantial tax benefits, which the U.S. government has designed to encourage domestic drilling. The Tax Reform Act of 1986 and other Acts specifically exempt oil and gas Working Interests from being classified as “Passive Income.” Direct participation programs in oil and gas are one of the few remaining investments that allow investors to shelter income, making it one of the most tax-advantaged investments today. *Below, is a general summary of certain items in the U.S. Internal Revenue Code relating to oil and gas exploration.
For more detailed information regarding the tax codes of oil and gas investments, please visit www.irs.gov.
o Intangible Drilling Costs include everything but the actual drilling equipment. labor, chemicals, mud, grease and other miscellaneous items necessary for drilling are considered intangible. These expenses generally constitute 65-80% of the total cost of drilling a well and are 100% deductible in the year incurred per IRC Section 469 (c)(3).
o Tangible Drilling Costs pertain to the actual direct cost of the drilling equipment and generally constitute 20-35% of the total drilling cost. These expenses are also 100% deductible, but must be depreciated over seven years per IRC ACRS depreciation.
o Depletion Allowance is perhaps the most enticing tax break for small producers and investors. This incentive, excludes from taxation 15% of all gross income from oil and gas wells. This special advantage is limited solely to small companies and investors.
o Alternative Minimum Tax includes All excess intangible drilling costs which have been specifically exempt as a "preference item" on the alternative minimum tax return.
o Dry Hole includes all dollars invested are written off as an ordinary loss against ordinary income in the year incurred.
The well is created by drilling a hole 5 to 50 inches (127.0 mm to 914.4 mm) in diameter into the earth with a drilling rig that rotates a drill string with a bit attached. After the hole is drilled, sections of steel pipe (casing), slightly smaller in diameter than the borehole, are placed in the hole. Cement may be placed between the outside of the casing and the borehole. The casing provides structural integrity to the newly drilled wellbore, in addition to isolating potentially dangerous high pressure zones from each other and from the surface.
With these zones safely isolated and the formation protected by the casing, the well can be drilled deeper (into potentially more-unstable and violent formations) with a smaller bit, and also cased with a smaller size casing. Modern wells often have two to five sets of subsequently smaller hole sizes drilled inside one another, each cemented with casing.
To drill the well
· The drill bit, aided by the weight of thick walled pipes called "drill collars" above it, cuts into the rock. There are different types of drill bit; some cause the rock to disintegrate by compressive failure, while others shear slices off the rock as the bit turns.
· Drilling fluid, a.k.a. "mud", is pumped down the inside of the drill pipe and exits at the drill bit. Drilling mud is a complex mixture of fluids, solids and chemicals that must be carefully tailored to provide the correct physical and chemical characteristics required to safely drill the well. Particular functions of the drilling mud include cooling the bit, lifting rock cuttings to the surface, preventing destabilisation of the rock in the wellbore walls and overcoming the pressure of fluids inside the rock so that these fluids do not enter the wellbore.
· The generated rock "cuttings" are swept up by the drilling fluid as it circulates back to surface outside the drill pipe. The fluid then goes through "shakers" which strain the cuttings from the good fluid which is returned to the pit. Watching for abnormalities in the returning cuttings and monitoring pit volume or rate of returning fluid are imperative to catch "kicks" early. A "kick" is when the formation pressure at the depth of the bit is more than the hydrostatic head of the mud above, which if not controlled temporarily by closing the blowout preventers and ultimately by increasing the density of the drilling fluid would allow formation fluids and mud to come up through the annulus uncontrollably.
· The pipe or drill string to which the bit is attached is gradually lengthened as the well gets deeper by screwing in additional 30-foot (9 m) sections or "joints" of pipe under the kelly or topdrive at the surface. This process is called making a connection. Usually, joints are combined into three joints equaling one stand. Some smaller rigs only use two joints and some rigs can handle stands of four joints.
This process is all facilitated by a drilling rig which contains all necessary equipment to circulate the drilling fluid, hoist and turn the pipe, control downhole, remove cuttings from the drilling fluid, and generate on-site power for these operations.
After drilling and casing the well, it must be 'completed'. Completion is the process in which the well is enabled to produce oil or gas.
In a cased-hole completion, small holes called perforations are made in the portion of the casing which passed through the production zone, to provide a path for the oil to flow from the surrounding rock into the production tubing. In open hole completion, often 'sand screens' or a 'gravel pack' is installed in the last drilled, uncased reservoir section. These maintain structural integrity of the wellbore in the absence of casing, while still allowing flow from the reservoir into the wellbore. Screens also control the migration of formation sands into production tubulars and surface equipment, which can cause washouts and other problems, particularly from unconsolidated sand formations of offshore fields.
After a flow path is made, acids and fracturing fluids may be pumped into the well to fracture, clean, or otherwise prepare and stimulate the reservoir rock to optimally produce hydrocarbons into the wellbore. Finally, the area above the reservoir section of the well is packed off inside the casing, and connected to the surface via a smaller diameter pipe called tubing. This arrangement provides a redundant barrier to leaks of hydrocarbons as well as allowing damaged sections to be replaced. Also, the smaller cross-sectional area of the tubing produces reservoir fluids at an increased velocity in order to minimize liquid fallback that would create additional back pressure, and shields the casing from corrosive well fluids.
In many wells, the natural pressure of the subsurface reservoir is high enough for the oil or gas to flow to the surface. However, this is not always the case, especially in depleted fields where the pressures have been lowered by other producing wells, or in low permeability oil reservoirs. Installing a smaller diameter tubing may be enough to help the production, but artificial lift methods may also be needed. Common solutions include downhole pumps, gas lift, or surface pump jacks. Many new systems in the last ten years have been introduced for well completion. Multiple packer systems with frac ports or port collars in an all in one system have cut completion costs and improved production, especially in the case of horizontal wells. These new systems allow casings to run into the lateral zone with proper packer/frac port placement for optimal hydrocarbon recovery.
The production stage is the most important stage of a well's life, when the oil and gas are produced. By this time, the oil rigs and workover rigs used to drill and complete the well have moved off the wellbore, and the top is usually outfitted with a collection of valves called a Christmas tree or Production trees. These valves regulate pressures, control flows, and allow access to the wellbore in case further completion work is needed. From the outlet valve of the production tree, the flow can be connected to a distribution network of pipelines and tanks to supply the product to refineries, natural gas compressor stations, or oil export terminals.
As long as the pressure in the reservoir remains high enough, the production tree is all that is required to produce the well. If the pressure depletes and it is considered economically viable, an artificial lift method mentioned in the completions section can be employed.
Workovers are often necessary in older wells, which may need smaller diameter tubing, scale or paraffin removal, acid matrix jobs, or completing new zones of interest in a shallower reservoir. Such remedial work can be performed using workover rigs – also known as pulling units, completion rigs or "service rigs" – to pull and replace tubing, or by the use of well intervention techniques utilizing coiled tubing. Depending on the type of lift system and wellhead a rod rig or flushby can be used to change a pump without pulling the tubing.
Enhanced recovery methods such as water flooding, steam flooding, or CO2 flooding may be used to increase reservoir pressure and provide a "sweep" effect to push hydrocarbons out of the reservoir. Such methods require the use of injection wells (often chosen from old production wells in a carefully determined pattern), and are used when facing problems with reservoir pressure depletion, high oil viscosity, or can even be employed early in a field's life. In certain cases – depending on the reservoir's geomechanics – reservoir engineers may determine that ultimate recoverable oil may be increased by applying a waterflooding strategy early in the field's development rather than later. Such enhanced recovery techniques are often called "tertiary recovery".
Fossil-fuel wells come in many varieties. By produced fluid, there can be wells that produce oil, wells that produce oil and natural gas, or wells that only produce natural gas. Natural gas is almost always a byproduct of producing oil, since the small, light gas carbon chains come out of solution as they undergo pressure reduction from the reservoir to the surface, similar to uncapping a bottle of soda pop where the carbon dioxide effervesces. Unwanted natural gas can be a disposal problem at the well site. If there is not a market for natural gas near the wellhead it is virtually valueless since it must be piped to the end user. Until recently, such unwanted gas was burned off at the wellsite, but due to environmental concerns this practice is becoming less common. Often, unwanted (or 'stranded' gas without a market) gas is pumped back into the reservoir with an 'injection' well for disposal or repressurizing the producing formation. Another solution is to export the natural gas as a liquid. Gas to liquid, (GTL) is a developing technology that converts stranded natural gas into synthetic gasoline, diesel or jet fuel through the Fischer-Tropsch process developed in World War II Germany. Such fuels can be transported through conventional pipelines and tankers to users. Proponents claim GTL fuels burn cleaner than comparable petroleum fuels. Most major international oil companies are in advanced development stages of GTL production, e.g. the 140,000 bbl/d (22,000 m3/d) Pearl GTL plant in Qatar, scheduled to come online in 2011. In locations such as the United States with a high natural gas demand, pipelines are constructed to take the gas from the wellsite to the end consumer.
Another obvious way to classify oil wells is by land or offshore wells. There is very little difference in the well itself. An offshore well targets a reservoir that happens to be underneath an ocean. Due to logistics, drilling an offshore well is far more costly than an onshore well. By far the most common type is the onshore well. These wells dot the Southern and Central Great Plains, Southwestern United States, and are the most common wells in the Middle East.
Another way to classify oil wells is by their purpose in contributing to the development of a resource. They can be characterized as:
· wildcat wells are those drilled outside of and not in the vicinity of known oil or gas fields.
· exploration wells are drilled purely for exploratory (information gathering) purposes in a new area.
· Development wells are drilled in a proven producing area for the production of oil or gas. A development well is drilled to a depth that is likely to be productive, so as to maximize the chances of success.
· appraisal wells are used to assess characteristics (such as flow rate) of a proven hydrocarbon accumulation.
· production wells are drilled primarily for producing oil or gas, once the producing structure and characteristics are determined.
At a producing well site, active wells may be further categorized as:
· oil producers producing predominantly liquid hydrocarbons, but mostly with some associated gas.
· gas producers producing almost entirely gaseous hydrocarbons.
· water injectors injecting water into the formation to maintain reservoir pressure, or simply to dispose of water produced with the hydrocarbons because even after treatment, it would be too oily and too saline to be considered clean for dumping overboard offshore, let alone into a fresh water resource in the case of onshore wells. Water injection into the producing zone frequently has an element of reservoir management; however, often produced water disposal is into shallower zones safely beneath any fresh water zones.
· aquifer producers intentionally producing water for re-injection to manage pressure. If possible this water will come from the reservoir itself. Using aquifer produced water rather than water from other sources is to preclude chemical incompatibility that might lead to reservoir-plugging precipitates. These wells will generally be needed only if produced water from the oil or gas producers is insufficient for reservoir management purposes.
· gas injectors injecting gas into the reservoir often as a means of disposal or sequestering for later production, but also to maintain reservoir pressure.