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Hole cleaning is the ability of a drilling fluid to transport and suspend drilled cuttings. Throughout the last decade, many studies have been conducted to gain understanding on hole cleaning in directional-well drilling. Laboratory work has demonstrated that drilling at an inclination angle greater than approximately 30 from vertical poses problems in cuttings removal that are not encountered in vertical wells. Figure 1 illustrates that the formation of a moving or stationary cuttings bed becomes an apparent problem, if the flow rate for a given mud rheology is below a certain critical value. The most prevalent problem is excessive torque and drag, which often leads to the inability of reaching the target in high-angle/extended-reach drilling.
Measurements of mass flow and the constituents of the mass produced are integral in the production of geothermal fluids. From regulatory and royalty payment issues to monitoring the condition of the resource and abatement of corrosive constituents in the geothermal fluid, physical and chemical measurements are a necessity for geothermal production and utilization. Depending on the phase being produced, the operator has a choice of many instruments for measuring flow. Conventional methods are typically used to measure flow for single-phase systems. The choice of flow element and meter initially depends on the mass and/or volumetric flow rate, turn-down ratio (range of flow to be measured), the pressure, temperature, and extent of flow surging.
Both the Rawlins and Schellhardt and Houpeurt analysis techniques are presented in terms of pseudopressures. Flow-after-flow tests, sometimes called gas backpressure or four-point tests, are conducted by producing the well at a series of different stabilized flow rates and measuring the stabilized BHFP at the sandface. Each different flow rate is established in succession either with or without a very short intermediate shut-in period. Conventional flow-after-flow tests often are conducted with a sequence of increasing flow rates; however, if stabilized flow rates are attained, the rate sequence does not affect the test. Fig 1 illustrates a flow-after-flow test.
This page walks through the suggested 9-step process for selecting and sizing an electrical submersible pump system for artificial lift. The process is manual for illustrative purposes. A number of computer programs are available to automate this process. Tubing pressure: 100 psi; casing pressure: 100 psi; present production rate: 850 BFPD; pump-intake pressure: 2,600 psi; static bottomhole pressure: 3,200 psi; datum point: 6,800 ft; bottomhole temperature: 160 F; minimum desired production rate: 2,300 BFPD; GOR: 300 scf/STB; and water cut: 75%. There were no reported problems. In this case, the maximum production rate is desired without resulting in severe gas-interference problems. The pump-intake pressure at the desired production rate can be calculated from the present production conditions.
The electrical submersible pump (ESP) is a multistage centrifugal type. A cross section of a typical design is shown in Figure 1. The pumps function is to add lift or transfer pressure to the fluid so that it will flow from the wellbore at the desired rate. It accomplishes this by imparting kinetic energy to the fluid by centrifugal force and then converting that to a potential energy in the form of pressure. In order to optimize the lift and head that can be produced from various casing sizes, pumps are produced in several diameters for application in the most common casing sizes.
Energy is the rate of doing work. A practical aspect of energy is that it can be transmitted or transformed from one form to another (e.g., from an electrical form to a mechanical form by a motor). A loss of energy always occurs during transformation or transmission. In drilling fluids, energy is called hydraulic energy or commonly hydraulic horsepower. Rig pumps are the source of hydraulic energy carried by drilling fluids.
Progressing cavity pumps are classified as single-rotor, internal-helical-gear pumps within the overall category of positive displacement pumps. The stator always has one more "tooth" or "lobe" than the rotor. Currently, the vast majority (i.e., estimated at 97%) of PC pumps in use downhole are of the single-lobe design and thus are the primary focus of this page. Other variations of these basic configurations include semi-elliptical rotor/stator geometries and uniform-thickness elastomer pumps. The geometric design of a single-lobe PC pump is illustrated in Figure 1.
To quantify formation damage and understand its impact on hydrocarbon production, one must have reasonable estimates of the flow efficiency or skin factor. Several methods have been proposed to evaluate these quantities for oil and gas wells. Multirate tests can be conducted on both oil and gas wells. In these tests, several stabilized flow rates, qi, are achieved at corresponding stabilized flowing bottomhole pressures, pwf. The simplest analysis considers two different stabilized rates and pressures.
If the problem is formation damage, then matrix acidizing may be an appropriate treatment to restore production. This page discusses ways to evaluate whether a well is a good candidate for acidizing. This plugging can be either mechanical or chemical. Mechanical plugging is caused by either introduction of suspended solids in a completion or workover fluid, or dispersion of in-situ fines by incompatible fluids and/or high interstitial velocities. Chemical plugging is caused by mixing incompatible fluids that precipitate solids.