The relationship between seismic velocities and mechanical properties is a strong one. Moduli, such as bulk modulus (and its inverse, compressibility), rigidity (or shear modulus), and Young's modulus, can be determined either from static (very slow) experiments or dynamic experiments, involving the passage of a seismic wave through the sample. Eqs. 1 and 2 are correct only for isotropic media and are strictly appropriate only for moduli measured at the same frequency and amplitude as the seismic wave. Investigators often ignore these distinctions and use the seismically determined moduli to approximate the static moduli sought by reservoir or completions engineers for compaction drive estimates or hydraulic-fracture design. When properly calibrated, the spatial or temporal variations in velocity-derived moduli can often be used to indicate changes in static moduli.[1]

Diagnostic plots are a log-log plot of the pressure change and pressure derivative (vertical axis) from a pressure transient test vs. elapsed time (horizontal axis). They are typically divided into three time regions: early, middle, and late. Two different method types, one using data from the middle-time region and the second using data from the late-time region (LTR), are commonly applied in estimating average reservoir pressure. The middle-time region methods are the Matthews-Brons-Hazebroek (MBH) method[1] and the Ramey-Cobb method. The MTR methods are based on extrapolation of the middle-time region and the correction of the extrapolated pressure.

Proper sizing and selection of an electrical submersible pump (ESP) system is essential to efficient and cost-effective performance. Selection and sizing of proper ESP equipment for a particular application should be based on a nine-step design procedure. This nine-step procedure helps the engineer design the appropriate submersible pumping system for a particular well. Each of the nine steps is explained below, including gas calculations and variable-speed operations. Specific examples are worked through in ESP design. The design of a submersible pumping unit, under most conditions, is not a difficult task, especially if reliable data are available.

In artificial lift with electrical submersible pumps, the surface controller provides power to the ESP motors and protects the downhole ESP components. There are three types of motor controllers used on ESP applications and all are generally specifically designed for application with ESPs. They include the switchboard, soft starter, and the variable speed controller. All units vary in design, physical size, and power ratings. Normally, all utilize solid state circuitry to provide protection, as well as a means of control for the ESP system. Motor controller designs vary in complexity from the very simple and basic to the very sophisticated, which offer numerous options to enhance the methods of control, protection, and monitoring of the ESP operation. The selection of the type of controller and optional features depends on the application, supporting economics, and the preferred method of control. The switchboard, fixed-speed controller, or across-the-line starter consists of a manual fused disconnect switch or circuit breaker, a motor starter, and a control power transformer. Because this controller is only a switch and does not modify the input voltage or current, it provides full-rated, instantaneous voltage to the downhole ESP system.

Typically, it is banded or clamped to the production tubing from below the wellhead to the ESP unit because it is not designed to support its own weight. It is a specially constructed three-phase power cable designed specifically for downhole well environments. The cable design must be small in diameter, protected from mechanical abuse, and impervious to physical and electrical deterioration because of aggressive well environments. They are available in a wide range of conductor sizes or gauges. They can be manufactured in either round or flat configurations, using several different insulation and metal armor materials for different hostile well environments.

There are components provided by the ESP manufacturers and other suppliers that provide additional mechanical and electrical protection, monitoring, or performance enhancements in the operation of an artificial lift system using electrical submersible pumps. Installation of such components on all wells may not be justified, but their use on key wells should be carefully considered. Because the ESP operates in a hostile and confined environment, monitoring how it operates is very difficult. Additionally, it is also difficult to find sensors and electronics that operate reliably and long term under the range of downhole conditions required. The ESP's reliability or run-life is directly related to the continual monitoring of its operating parameters and the wellbore conditions. Not only is this information critical to the run-life, but it is also important for the evaluation of the application design of the ESP system in the hole.

The ESP motor is a two-pole, three-phase, squirrel cage, induction design. It operates on three-phase power at voltages as low as 230 and as high as 5,000, with amperages between 12 and 200. Generally, the length and diameter determines the motor's horsepower (HP) rating. Because the motor does not have the power cable running along its length, it can be manufactured in diameters slightly larger than the pumps and seal-chamber sections and still fit in the same casing bores. Typical diameters and rated HP ranges are shown in Table 1.

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.

The Empire Abo field, located in New Mexico, US, covers 11,000 acres (12.5 miles long by 1.5 miles wide) and contains approximately 380 million stock tank barrels (STB) of original oil in place (OOIP).[1][2] This reservoir is a dolomitized reef structure (Figure 1) with a dip angle of 10 to 20 from the crest toward the fore reef. The oil column is approximately 900 ft thick, but the average net pay is only 151 ft thick. The pore system of this reservoir is a network of vugs, fractures, and fissures because the primary pore system has been so altered by dolomitization; the average log-calculated porosity was 6.4% BV. Numerical simulations of field performance and routine core analysis data have indicated that the horizontal and vertical permeabilities are about equal.