This page discusses various aspects of gas reservoir performance, primarily to determine initial gas in place and how much is recoverable. The equations developed can used to form the basis of forecasting future production rates by capturing the relationship between cumulative fluid production and average reservoir pressure. Material-balance equations provide a relationship between original fluids in place, cumulative fluid production, and average reservoir pressure. This equation is the basis for the p/z-vs.-Gp Reservoir engineers have often used pressure contour maps or some approximate methods to determine field average reservoir pressure for p/z analysis. Usually, however, individual well pressures are based on extrapolation of pressure buildup tests or from long shut-in periods. In either case, the average pressure measured does not represent a point value, but rather is the average value within the well's effective drainage volume (see Estimating drainage shapes).

Formation damage in gas/condensate reservoirs can be caused by a buildup of fluids (condensate) around the wellbore. This reduces the relative permeability and therefore gas production. This page discusses condensate banking and how to overcome its effects. As shown in Figure 1[1], gas/condensate reservoirs are defined as reservoirs that contain hydrocarbon mixtures that on pressure depletion cross the dewpoint line. In such instances as when the bottomhole pressure is reduced during production, the dewpoint pressure of the gas is reached in the near-wellbore region.

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.

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.

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 acquisition of bottomhole pressure and temperature data can be planned and executed in a cost-effective manner with a minimum disruption to normal operating routines. In many cases, early on-site interpretation is useful in guiding decisions about continuing the acquisition program. Measurements can be transmitted to the surface, usually via an electric cable, or recorded in downhole memory powered by batteries. SRO has the obvious advantage of providing data in real time. Real-time readouts are especially beneficial for transient measurements that require time for the pressure to stabilize and radial flow to develop.

Pseudo-steady state (or pseudo steady-state), is also referred to as "stabilized," or as "steady state in a bounded drainage area." This type of reservoir flow occurs much more frequently than steady-state flow or unsteady-state flow with an expanding drainage radius.[1] Pseudo-steady state (PSS) flow occurs during the late time region when the outer boundaries of the reservoir are all no flow boundaries. This includes not only the case when the reservoir boundaries are sealing faults, but also when nearby producing wells cause no flow boundaries to arise. During the PSS flow regime, the reservoir behaves as a tank.

This commentary has been prepared by the SPE Reservoir Advisory Committee (RAC) to provide high-level insights for the discussion on the potential consequences of long-term shut-ins on conventional and unconventional reservoirs. The RAC comprises 61 subject matter experts (SMEs) covering the domain of reservoir technical discipline. The views presented in the commentary are the opinions of the SMEs and do not constitute an official position of the SPE on the subject matter. From a completions, production, and facilities perspective, there are significant, and potentially devastating, effects for the long-term shut-ins of wells. Everything we leave in the well and the surface facilities will be subject to corrosion, deterioration, and other chemical/mechanical effects. Perforations and the well itself may become plugged and deformed and the pumps and bottomhole assemblies may be rendered dysfunctional due to the settlement of sand and other debris/contaminants. Moreover, scale buildup and wax and asphaltene precipitation in and around the wellbore are well-known potential problems during shut-ins. The oil and gas industry has a very long history of well surveillance, well maintenance, and well remediation--but as an induction, we have not had any circumstances on the scale of the current situation.