Petroleum Exploration & Production Preliminary Evaluation. Most petroleum development projects begin with an examination of existing geological information for an area of interest. The goal is to evaluate if petroleum might be found where it has never been found before, or might be found at a lesser or greater depth in an area with current production. Existing data are often not sufficiently complete or reliable to justify the risks and costs of proceeding. If the opportunity appears promising based on the initial review, a team of geologists, geophysicists, and petroleum engineers will work together to determine what additional information is required to support a sound investment decision. A report is then submitted to the company’s management. Lease Acquisition and Detailed Evaluation. If management decides to proceed, data will be obtained from commercial sources or state regulatory agencies, or borrowed or purchased from other companies that have previously evaluated the area but did not proceed to production. If surface exploration is necessary, the company may enter into a leasing arrangement with the mineral rights owner. (Many states also require compensating surface owners for damage to their property.) Seismic and other geophysical surveys can then commence. A company usually pays a bonus to initiate a mineral lease and then pays annual rentals until such time as a well is drilled or the primary term of the lease expires. The lease contract provides for paying to the mineral rights owner a share of any production received from a completed well. This production share is called a royalty. It 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 from Indian tribes. Such leases are usually acquired by competitive bidding, and they will impose their own royalty formulas.

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. 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 any oil or gas production. Such an interest is called an overriding royalty interest, or simply an override. Other arrangements include retention by a 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. The exploration team evaluates the additional data and recommends a plan to company management. If drilling an exploratory well is recommended, management must decide whether the risk and expense are justified. The risk is real, because only about one in eight exploratory or "wildcat" wells finds oil capable of economic production. Even if oil is found, operating costs may be prohibitive unless the production rate is high and the field’s operating life is long. In northern states such as Montana, Wyoming, and the Dakotas, wintertime operations can be especially expensive. Disposal of produced brines and other wastes is also costly. And the company must pay royalties to the mineral rights owner and any prior lease holders, and usually gross production taxes to the state in which the well is located. It is not unusual for a company to keep less than 80% of the revenue from any petroleum recovered. All these factors must be carefully considered and compared with those of other development opportunities. Division of Duties. If a decision is made to drill an exploratory well, personnel from several company departments are soon engaged. The land and legal department must identify the owners of the surface and mineral estates, draft leases, and investigate farm-out agreements and any other related legal instruments to ensure that

the company has a legal right to explore the property of interest. They will also prepare and file applications for permits with state and federal regulatory authorities. The engineering and drilling department will hire drilling contractors and service and supply vendors. Contracts will be let to prepare the drill site and construct access roads. The production department will begin planning surface facilities to contain the oil and gas and any produced brines. The exploration department will design a drilling program and assign geologists to evaluate the data. Exploratory Drilling. When all permits and plans are in place and a performance bond has been filed, drilling may commence, or in oil field terms, the well may be spudded in (Fig. 1). Precautions are taken to protect the environment and the land surface from being damaged by drilling fluids and wastes. Pits, either excavated into impermeable material, or lined with impermeable material, are created to contain drilling wastes. Protective pipe called surface casing is set from the surface to below the deepest fresh water aquifer. Drilling continues, with interruptions for testing, until either a predetermined depth is reached or petroleum is encountered. Evaluation of Data. Geologists will examine rock cuttings that are brought to the surface for the presence of hydrocarbons. Gas detection equipment will detect the presence of gases in the cuttings or the drilling fluids. Geologists will also be advised of any drilling breaks –indications that the penetration rate of the drill bit has increased. Drilling breaks indicate that the rock being penetrated has changed in some way. The changes could be in lithology (going from one rock type into another) or they could mean that the rock is more porous and is more easily broken up by the bit. In either case, a geologist may determine that a drill stem test is warranted. A drill stem test is conducted by isolating the zone of interest by inserting packers in the wellbore and a testing tool at the bottom end of the drill pipe. The tool allows fluids from the tested interval to pass into the drill pipe. If the downhole pressure is sufficient, fluids may flow to the surface for collection and testing. Sometimes fluid will only rise part way up the pipe, to a hydrostatic level determined by fluid density and reservoir pressure. That level

can be determined as the drill pipe is extracted from the wellbore. The testing system includes a vessel to collect formation fluid at reservoir pressure, and a clock and chart that records reservoir or formation pressure and the rate of pressure buildup. The data thus acquired enables geologists and engineers to calculate permeability, which is an indication of the ease by which the reservoir or formation fluids can pass through the rock and into the wellbore. High permeability is one of the keys to economical production. Cores of rock are sometimes taken and analyzed to determine lithology (rock type), percentage of pore space or porosity, the nature of porosity (whether inter-granular or fractures), and permeability. When drilling has been completed, a series of geophysical well logs is usually run in the wellbore. The common types of logs include natural gamma ray radiation, electrical resistivity, electrical self potential, and records of gamma ray neutron and formation density. These logs enable geologists and engineers to evaluate porosity, the nature of fluids in place in the various formations (oil/gas/water ratios) and the percentage of oil in place which might be recoverable. Management must decide whether to attempt to complete the well or to plug it with cement and abandon it as a dry hole. Well completion will be much more expensive, but more money must be spent either way. 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 on the top. In cultivated areas, the casing will be cut off below plow depth before the plate is welded on. If the well is to be completed, steel casing is inserted into the wellbore to a specific depth and is cemented into place (Fig. 2). The casing is then perforated at intervals determined by the characteristics of the formation (Fig. 3). If the reservoir fluids are of sufficient volume and under sufficient pressure to flow to the surface, the well is equipped with a collection of valves

and pipes called a Christmas tree. If reservoir pressures are not sufficient, a pump will be installed (Fig. 4). Various types of mechanical pumps may be used, or gas lift valves may be installed which move fluids to the surface by injecting gas under high pressure. Separation and treatment equipment (Fig. 5) will be installed on the surface to separate the reservoir fluids into oil, water, and gas fractions and transfer those fractions to processing or disposal facilities. Oil usually is sent to storage tanks (the “tank battery” (Fig. 6)) and then shipped to a refinery by tanker truck or pipeline. Gas may be utilized on site in pumping and treating equipment, or it may be piped to a gas processing facility, where it will be separated into its various components and eventually sold. Allocation of Income & Costs. Allocating revenues and expenses is the responsibility of the accounting department. Owners of royalty interests do not pay any costs of exploration or production. They are paid based on gross production, according to the sharing agreements contained in leases or other contracts. Owners of working interests receive their agreed-upon shares of the net profit which remains after costs are paid. Exploiting the Resource. If an initial exploration well is successful, reservoir engineers and geologists will use data from drill stem tests and core analyses, and from the brief production history of the initial well, to determine if it is practical to drill more wells in the same area. The areal extent of the reservoir is estimated, and a drilling plan is prepared. With the concurrence of regulatory authorities, and usually after a public hearing, the company may decide to drill the additional wells required to drain the reservoir. Other companies may also drill wells into the same reservoir. With many wells producing from the same pool, reservoir energy and production will begin to decline. As the decline occurs, the producing companies may alter their strategies to optimize the total recovery and to use enhanced recovery if this appears economical. When only the natural energy in a reservoir is utilized, production is said to be in its primary phase. Reservoir energy may be depleted before the maximum amount of oil is produced. In a

dissolved gas drive reservoir (Fig. 7), for example, reservoir pressure will eventually drop below the bubble point (the pressure at which reservoir gas begins to come out of solution with the oil). When this happens, viscosity of the oil will increase, the ability of the oil to move to the wellbore will be diminished, and the ultimate recovery of oil will decrease. Before this point is reached, the producing companies may agree to unitize the pool and to initiate a pressure maintenance program to enhance production. Unitization. Unitization must be approved by the regulatory authority. Hearings are held to help the regulator understand the proposed pressure maintenance program and to demonstrate that unitization will conserve resources while protecting the rights of the various parties. If the plan is approved, the regulator will designate the unit operator and specify formulas for sharing the production volumes and the operating costs. Pressure maintenance applies a second source of energy to the reservoir and is referred to as secondary recovery. The specific means for maintaining pressure is chosen based on the characteristics of the reservoir and the availability of a pressure maintenance medium. Water and natural gas are the two most commonly utilized media. If gas is used, it is usually injected through wellbores into the crest of the reservoir, in hopes of stopping or delaying the decline in reservoir pressure, in order to maintain it above the bubble point. If water is used (Fig. 8), the water is injected either around the periphery of the reservoir, or through wells interspersed with production wells. Water injection is intended to sweep oil toward the producing wells and thereby increase total recovery. In some reservoirs, a third stage of enhanced oil recovery – tertiary recovery – may be justified. This also requires regulatory approval, so more public hearings are held, more proposals are examined, and more determinations are made. Tertiary recovery involves injection of liquid or gas into the reservoir to push oil toward the producing wellbores. Carbon dioxide is often the preferred medium. When carbon dioxide is injected into the producing interval, it is absorbed into solution with the oil, reducing the

viscosity of the oil and increasing its ability to flow toward the producing wellbores. Reservoir pressure is also maintained, which increases ultimate recovery, so more oil is produced more quickly. Carbon dioxide is separated from the produced oil at the surface and is injected back into the reservoir to repeat the cycle. Abandonment and Restoration. Eventually, production declines to the point that costs exceed revenues. When this occurs, the field reaches its economic limit. The wells are then plugged and abandoned, in a manner approved by the regulatory authority, to ensure that reservoir fluids will remain in place and will not pollute 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. Weighted fluid is left between the cement plugs. In cultivated areas, the casing will be cut off below plow

depth and then sealed. If some instances, the casing is cut off at a deeper level, and the free casing is removed from the wellbore. Cement plugs are then set across the perforations, at the top of the casing stub, and at the base of the surface casing. Cement and a welded steel plate are used to seal the top of the surface casing. Notice of abandonment and a plugging report must be filed with the regulatory authority. The authority serves as a repository for all reports and records on each well and often maintains a library of geophysical well logs, cores, and well cuttings. The library is 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 the regulatory authority, the company’s performance bond may be returned.

Figure 1. Drilling Rig.

Figure 2. Cementing a Production Casing

“A” Illustrates cement being pumped down the casing. The casing shoe facilitates 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.

Figure 3. Arrangement of Casing, Tubing, and Packer in a Flowing Well

Figure 4. Rod Pumping Components.

Figure 5. Cutaway View of a Vertical Heater-Treater

Figure 6. Flow Diagram for a Typical Tank Battery

Figure 7. Drive Mechanisms – Water drive, solution-gas drive, and gas-cap drive

Figure 8. Secondary Recovery

In a water flood (illustrated here), water injected into the producing horizon pushes the oil towards the producing wells.