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.

A wellhead choke controls the surface pressure and production rate from a well. Chokes usually are selected so that fluctuations in the line pressure downstream of the choke have no effect on the production rate. This requires that flow through the choke be at critical flow conditions. Under critical flow conditions, the flow rate is a function of the upstream or tubing pressure only. For this condition to occur, the downstream pressure must be approximately 0.55 or less of the tubing pressure.

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.

In a dynamic calculation, there are two effects not considered in steady flow: fluid inertia and fluid accumulation. In steady-state mass conservation, flow of fluid into a volume was matched by an equivalent flow out of the volume. In the dynamic calculation, there may not be equal inflow and outflow, but fluid may accumulate within the volume. For fluid accumulation to occur, either the fluid must compress, or the wellbore must expand. When considering the momentum equation, the fluid at rest must be accelerated to its final flow rate.

As with most technology, proper candidate selection is key to success. The economics are often determined by the number of and locations of the wells and by the overall geographical development plan. It is important to recognize that downhole processing is not a substitute for prudent profile control of wells through workovers, gel polymer treatments, cement squeezes, and so on. The following discussion applies to both gas/liquid and water/oil processing, followed by sections that discuss screening criteria specific to each. From an equipment standpoint, gas/liquid separation is much easier than oil/water separation. This generally means that it is a more robust application. All separation and pump equipment has an expected lifetime that is typically much shorter than the lifetime of the well. The cost of replacing or repairing the equipment must be considered as well as the initial capital cost.

The key technical considerations and decisions involved in selecting a progressing cavity pump(PCP) for a particular application include pump displacement, pressure capability, geometric design, elastomer type, and rotor coating characteristics. Other factors, such as local vendor choice and economics can also affect pump selection. Figure 1 provides a flow chart of the key decisions. When selecting a PC pump, the two most critical requirements are adequate displacement capacity and pressure capability to ensure that the pump can deliver the required fluid rate and net lift for the intended application. It is typical to select pumps with a design (i.e., theoretical) flow rate that is somewhat higher than the expected fluid rate to reflect pump inefficiencies during production operations.

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.

This article summarizes the fundamental gas-flow equations, both theoretical and empirical, used to analyze deliverability tests in terms of pseudopressure. The four most common types of gas-well deliverability tests are discussed in separate articles: flow-after-flow, single-point, isochronal, and modified isochronal tests. Deliverability testing refers to the testing of a gas well to measure its production capabilities under specific conditions of reservoir and bottomhole flowing pressures (BHFPs). A common productivity indicator obtained from these tests is the absolute open flow (AOF) potential. The AOF is the maximum rate at which a well could flow against a theoretical atmospheric backpressure at the sandface.

The refrigeration process is used in gas plants to remove heat from certain process streams. Refrigeration in natural gas treating is a process that serves a dual dewpoint control function--namely, it is used to meet the hydrocarbon dewpoint as well as the water dewpoint specification for residue or sales gas. The temperature to which the gas is cooled depends first on meeting these dewpoint specifications. This is the minimum cooling requirement. Cooling the gas to lower temperatures than the minimum temperature for dewpoint control has to be justified by the economics of liquefied petroleum gas (LPG) recovery. This requires a cost analysis of the value of additional LPG recovery versus increased capital and operating costs. Refrigeration is basically pumping heat from one medium to another.

Monitoring and managing oil and gas production and technologies for improving outputs can be enhanced by using the real-time data that is provided by the sensors in modern wells[1].