Petroleum Development Original Idea... It has been said, "oil is first found in the minds of explorationists." Usually, this is the case. An explorationist, utilizing available data and information, will develop an idea that petroleum may be found underlying an area where it has never been found before, or may be found at a lesser or greater depth in an area with existing production. Preliminary Evaluation... The preliminary data on which such an idea is founded, are usually insufficient to warrant the expenditure of funds for acquiring leases on the oil and gas rights of the mineral estate owner, or to contract with a well drilling company to commence the drilling operations. The preliminary data are evaluated by a team of geologists, geophysicists, and petroleum engineers, who together determine what additional information and data are required to make a detailed evaluation and submit recommendations to company management. Lease Acquisition and Detailed Evaluation... The data may be available from commercial sources, state regulatory agencies, or may be borrowed or purchased from other companies that have previously evaluated the area, but whose interpretations did not result in the drilling or completion of a producing well. If it is found to be necessary to conduct surface exploration on the area of interest, the company may enter into a leasing arrangement with the mineral rights owner. When this has been completed, the company may begin to conduct seismic and other geophysical surveys on the area. In many states, it is also necessary to pay compensation to the surface estate owner for any damages that may occur to crops, livestock, or other property. When mineral rights are leased from an owner, the company usually pays a bonus for the lease, and will pay annual rentals until such time as a well is drilled, or the primary term of the lease expires. Included in the lease contract is a provision for payment to the mineral rights owner a percentage of any production received from a completed well. The production received by the mineral rights owner is referred to as royalty, and may be any agreed to amount, but frequently is 12.5% of the gross oil and gas produced. Leases may also be acquired from federal and state governmental entities, and Indian tribes. Such leases are usually acquired by the competitive bidding process. In some instances, another company may already hold a lease to the property of interest. In that event, the company evaluating the prospect may enter into an agreement with the lease holder to allow the company to conduct exploration activities, and, perhaps, drill a well. Such an agreement is called a "farm out" by the lease holder, and a "farm in" by the company conducting the exploration. The lease holder usually retains an interest in the oil and gas resources that may be found. Such an interest is called an overriding royalty interest, or simply, an override. Other arrangements are possible between the leaseholder and the company desiring to acquire access to the property. These include the retention by the leaseholder of a working interest in any wells drilled, whereby they will share in the costs of drilling and production, as well as any profits derived from production. After additional data are acquired, they are evaluated, and the exploration team makes their recommendations to company management. If the recommendation is to drill an exploratory well, management must decide whether the risk of capital is justified. Company Decision Time... Statistically, only about one in every eight exploratory or "wildcat" wells find oil capable of economic production. In addition to the cost of drilling and other risks, the company is also faced with paying the royalty to the mineral rights owner, an overriding royalty to a prior lease holder, and usually gross production taxes to the state in which the well is located. When all of these costs are taken off of the top of the revenue generated by oil and gas that may be produced,
it is not unusual for a company to be faced with keeping for itself less than 80% of the revenue from oil and gas recovered. Other factors to be considered are the costs of operation. In northern states such as Montana, Wyoming, and the Dakotas, the cost of operating during winter conditions can be very high. In addition, the disposal of wastes, including produced brines, may be very expensive. Division of Duties... If a decision is made to drill an exploratory well, company personnel are soon engaged in a number of activities. The land and legal department will be involved in checking titles of ownership, of the surface and mineral estate, leases, farm-out agreements, and any other legal instruments related thereto to ensure that the company has a legal right to conduct exploration on the property of interest. They will also prepare and file applications for required permits with all state and/or federal regulatory authorities. The engineering and drilling department will enter into contracts with drilling contractors, and service and supply companies. Contracts will be let for the preparation of the drill site and the construction of roads to the site. The production department will begin plans for surface facilities for the containment of oil and gas and produced brines. The exploration department will have developed a drilling program prognosis, and will assign geologists for the evaluation of data acquired during the drilling process. Exploratory Drilling... When all matters have been attended to, with particular emphasis on the acquisition of required permits and the filing of a performance bond, drilling may commence, or in oil field terms, the well is spudded in. During the drilling process, precautions are taken to prevent environmental damage from drilling fluids and wastes to fresh water resources, and the land surface. Protective pipe, called surface casing is set from the surface to below the deepest fresh water aquifer. Pits, either excavated into impermeable material, or lined with impermeable material, are used for the containment of wastes produced in drilling. After the setting of the surface casing, drilling continues, with interruptions for testing, until either a predetermined total depth has been reached, or the wellbore has encountered oil or gas. Evaluation of Data... During the drilling process, the geologist will examine the rock cuttings that are brought to the surface for the presence of hydrocarbons. Gas detection equipment may have been installed which will detect the presence of gases in recovered rock cuttings or drilling fluids. The geologist will also be advised of any drilling breaks, that is, indications that the penetration rate of the drill bit has increased. Drilling breaks are indications that the rock being penetrated changed in character. Such changes could be in lithology (going from one rock type into another), or could mean that the rock is more porous and is more easily broken up by the bit. In either case, the geologist may determine that a drill stem test is warranted. A drill stem test is conducted by isolating the zone of interest by the use of packers in the wellbore, and a testing tool at the bottom end of the drill pipe which allows fluids from the tested interval to pass into the drill pipe. In some cases, sufficient fluid and pressure exists for the fluids to flow to the surface for collection. Frequently, the fluid, if any is recovered at all, will rise to a hydrostatic level determined by fluid density and reservoir pressure. As the drill pipe is extracted from the wellbore, the level of recovered formation fluid is determined. The testing tool also contains a vessel to collect formation fluid at reservoir pressure, and a clock and chart that determines reservoir or formation pressure, and the rate of pressure of buildup. The data thus acquired, enables geologists and engineers to determine the nature of the recovered fluid, reservoir pressure, and calculated permeability. The permeability is an indication of the ease by which the reservoir or formation fluids can pass through the rock and into the wellbore. During the drilling process, other testing methods may be implemented. Cores of rock are sometimes taken and analyzed to provide data on lithology (rock type), percentage of pore space or porosity, the nature of porosity (whether inter-granular or fractures), and permeability. When drilling operations have been completed, a series of geophysical well logs is usually run in the wellbore. Well logs frequently run include natural gamma ray radiation; electrical resistivity, electrical self potential; and a log called the gamma ray neutron and formation
density log. These logs enable the geologist and engineer to calculate estimates of porosity, the nature of fluids in place in the various formations (oil/gas/water ratios), and the percentage of oil in place which is recoverable. Decision Time Again... All of the data are evaluated, and company management is faced with the decision whether to attempt to complete the well for production, or to plug it with cement, and abandon it as a dry hole. Either decision will require the expenditure of additional funds, however, well completion costs may exceed the cost thus far for the drilling of the well. Well Completion... If the well is to be abandoned, cement plugs are placed within the wellbore at intervals determined by the oil and gas regulatory agency. Cement is also placed within the surface casing, and a steel plate is welded at the top. In cultivated areas, the casing will be cut off below plow depth prior to the final welding operation. If the well is to be completed as a producer, steel casing is inserted into the wellbore to a specific depth, and cemented into place. The casing is then perforated at intervals determined through the evaluation of all of the data acquired during the drilling process. If the reservoir fluids are of sufficient volume and under sufficient pressure to flow to the surface, the well is equipped with a series of valves and pipes called a Christmas tree. If reservoir pressures are insufficient to flow the fluids to the surface, a pump will be installed. Various types of mechanical pumps may be used, or gas lift valves may be installed which accomplish the movement of fluids to the surface through the injection of high pressure gas. Equipment is installed at the surface that will separate the reservoir fluids into its various components (oil, water, gas), and contain the products or transfer them to processing or disposal facilities A separator and treater are used to separate the fluids into its component oil, water, and gas streams. The oil usually is sent to a storage tank or tanks (tank battery), and is ultimately shipped to a refinery via tanker truck or pipeline. The gas may be utilized on site for the operation of pumping and treating equipment, or may be metered and sent via pipeline to a gas processing facility for separation into its various component gases, and eventual sale. Division of Income/Allocation of Costs... The division of monies received from oil and gas sales is the responsibility of the accounting department. Royalty interest owners are paid on the basis of gross production, and the percentage of royalty due them by virtue of lease agreements or other arrangements. They do not share in the cost of exploration or production. Working interest owners are paid on the basis of the percentage of interest in the well that is owned by them, and the net profit remaining after payment of costs. Exploiting the Resource... As the result of the initial successful exploration well, the company will probably drill additional wells in the area. Utilizing data available from drill stem testing, core analysis, and the brief production history of the initial well, company reservoir engineers and geologists determine the approximate extent of the area of the oil pool or reservoir. With the concurrence of the regulatory authority, usually after a public hearing, the company may decide to drill additional wells to adequately drain the reservoir. As the company continues to drill and complete wells, other companies may also drill wells into the same reservoir. With the additional wells producing fluids from the single pool, reservoir energy and production will begin to decline. By monitoring reservoir performance, the companies producing from the pool may become aware that the optimum recovery of oil and gas cannot be achieved under the existing production operations and policies. When production takes place which utilizes only the natural energy available in the reservoir, production is said to be in the primary phase. During this period, reservoir energy may be depleted without exacting the maximum production of oil per unit of pressure drawdown. For example, if reservoir pressure drops below the point (bubble point) at which reservoir gas begins to come out of solution with the oil (in a dissolved gas drive reservoir), the viscosity of the oil will increase, and its ability to move through connecting pore space to the wellbore will be diminished. The result will be that the ultimate recovery of oil will be less. Hopefully, prior to reaching this point, the various
companies producing from the pool will have a meeting of minds, and take steps necessary to unitize the pool, and initiate a pressure maintenance program. Unitization... The unitization of production from an oil pool requires the approval of the regulatory authority. This is done through the hearing process, during which the regulatory authority must determine that the resource will be conserved; the correlative rights of all parties will be protected; and that the proposed pressure maintenance program will result in the recovery of significant additional quantities of oil to justify the effort and expense. The regulatory authority will also designate the unit operator, approve a formula for the equitable sharing of production and a plan for allocating unit operation costs. Pressure maintenance is referred to as secondary recovery. In a sense; a second source of energy is applied to the reservoir. Various types of pressure maintenance programs may be considered. The final selection of method is usually based on reservoir characteristics, and the availability of the pressure maintenance medium. Water or natural gas are the two most commonly utilized media for pressure maintenance. If gas is to be used, it is usually injected through wellbores into the crest of the reservoir. The hoped for effect is to stop or reduce the rate of reservoir pressure decline, maintain or restore reservoir pressure at or to some pressure above the bubble point, and result in the recovery of significant additional quantities of oil that would not have been possible under primary operations. If water injection is implemented, water is injected either around the periphery of the reservoir, or the injection wells are located in a pattern that is interspersed with production wells. Water injection endeavors to sweep oil in the reservoir toward the producing wells, thereby resulting in the recovery of additional quantities of oil. During the secondary recovery phase, company engineers continue to monitor the performance of the reservoir. If the necessary media are available, the participants in the unit may decide to implement an enhanced oil recovery program. Referred to as tertiary recovery, the program cannot be initiated without the approval of the regulatory authority. Following public hearing, the regulatory authority must make essentially the same determinations as for a secondary recovery program. Tertiary recovery methods involve the injection of fluid or gas into the reservoir in such a manner as to enhance the ability of oil to be moved toward the producing wellbores. Carbon dioxide, when available, is frequently the media of choice. The carbon dioxide, when injected into the producing interval, is absorbed into solution with the oil, thereby reducing its viscosity and increasing its ability to flow toward the producing wellbores. The process also results in the maintenance of reservoir pressure, and an increase in the ultimate recovery of oil reserves. The carbon dioxide is separated from the production stream at the surface, and is injected back into the reservoir to repeat the cycle. Abandonment and Restoration... Eventually, production from the well or wells will decline to the point that production costs approach or exceed income received. When this occurs, the well or wells are said to have reached their economic limit. It then becomes necessary to abandon the wells, and restore the surface that has been disturbed by their operations. Wells must be plugged and abandoned in a manner approved by the regulatory authority, to ensure that reservoir fluids will remain in place, and will not adversely affect fresh water resources or the land surface. Plugging is usually accomplished by placing cement across the perforated interval in the well casing, and at prescribed intervals from the perforations to the surface. The casing is left with weighted fluid between the cement plugs. A cement plug is set at the surface of the casing, and a steel plate is welded on top. In cultivated areas, the casing will be cut off below plow depth prior to the final welding operation. If some of the casing is retrieved from the well, the casing is cut off at a prescribed depth and the free casing is removed from the wellbore. Cement plugs are set across the perforations, at the top of the casing stub, and at the base of the surface casing. Cement is placed at the top of the surface casing, and a steel plate is welded in place.
Notice of abandonment and a plugging report must be filed with the regulatory authority. The regulatory authority serves as the repository for all reports and records on each well, and often maintains a library of geophysical well logs, cores, and well cuttings that are made available for study by researchers and the petroleum industry. Restoration of the surface to its original condition and productivity is required by the regulatory authority. When this has been accomplished., and the site has been inspected by representatives of the regulatory authority, the performance bond may be returned to the company. Figure 1 A drilling rig. From: Petroleum Exploration
Figure 2 Cementing production casing. A.) Illustrates cement being pumped down the casing. The casing shoe facilitates the insertion of the casing into the hole. The float collar prevents drilling fluid from entering the casing. The bottom plug precedes the cement down the casing. The top plug follows the cement and precedes the displacement fluid. B.) Illustrates the completed cementing operation. From: Brostuen
Figure 3 Casing, tubing, and packer arrangement in a flowing well. From: Fundamentals of Petroleum
Figure 4 Rod pumping components. From: Fundamentals of Petroleum
Figure 5 Cutaway view of vertical heater-treater.
From: Fundamentals of Petroleum Figure 6 Typical tank battery flow diagram. From: Amoco
Figure 7 Drive Mechanisms. A.) Water drive reservoir. B.) Solution-gas drive reservoir. C.) Gas-cap drive. From: Fundamentals of Petroleum
Figure 8 Secondary recovery. A water flood is illustrated here. Water injected into the producing horizon increases reservoir pressure and pushes the oil towards the producing wells. From: Brostuen