One role of the petrophysicist is to characterize the fluids encountered in the reservoir. Detection of a change in fluid type in the rocks while drilling is usually straightforward with the use of gas and chromatographic measurements. Gas shows and oil shows while drilling are time-honored indicators of zones that need further investigation through logs, testers, and cores. In the rare case of gas-bearing, high-permeability rock drilled with high overbalance, gas will be flushed from the rock ahead of the bit, will not be circulated to the surface in the mud, and will not produce a gas show. Because hydrocarbons are not always part of a water-based-mud formulation, sophisticated analytical chemical techniques can be used on the oil and gas samples circulated to the surface and captured to determine the properties of hydrocarbons in a given zone penetrated by the drill bit.

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]

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.

Evaluation of reservoirs as candidates for cold heavy oil production with sand (CHOPS) requires an assessment of the reservoir and an understanding of the key success factors for this technology. This article discusses what is known in these areas. The range of reservoir characteristics for CHOPS comes largely from Canadian experience. Table 1 contains the range of reservoir characteristics. Because Venezuelan heavy-oil deposits in the Faja del Orinoco represent a huge oil reserve, it is worth repeating that the physical properties and geological histories are similar.[1]

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).

If pore volume contraction contributes prominently to overall expansion while the reservoir is saturated, then the reservoir is classified as a compaction drive. Compaction drive oil reservoirs are supplemented by solution gas drive if the reservoir falls below the bubblepoint; they may or may not be supplemented by a water or gas cap drive. Compaction drives characteristically exhibit elevated rock compressibilities, often 10 to 50 times greater than normal. Rock compressibility is called pore volume (PV), or pore, compressibility and is expressed in units of PV change per unit PV per unit pressure change. Rock compressibility is a function of pressure.

Muskat defines primary recovery as the production period "beginning with the initial field discovery and continuing until the original energy sources for oil expulsion are no longer alone able to sustain profitable producing rates." This article provides an overview of types of reservoir energy and producing mechanisms (drive mechanisms). Primary recovery should be distinguished clearly from secondary recovery. Muskat defines secondary recovery as "the injection of (fluids) after the reservoir has reached a state of substantially complete depletion of its initial content of energy available for (fluid) expulsion or where the production rates have approached the limits of profitable operation." Because primary recovery invariably results in pressure depletion, secondary recovery requires "repressuring" or increasing the reservoir pressure.

Hydrocarbons occur in a variety of conditions, in different phases, and with widely varying properties, This page will cover the important geophysical properties of pore fluids. Pore fluids are fluids that occupy pore spaces in a soil or rock. Figure 1 shows schematically the relation among the different mixtures. For a single, constant composition mixture, as we vary temperature and pressure over a wide range, we would encounter the boundary between the single and multiphase regions. In contrast, if we restrict the temperatures and pressures to those typical of reservoirs, we could again move in this phase "space" by changing compositions.

Summary We propose a novel method for estimating average fracture compressibility during flowback process and apply it to flowback data from 10 multifractured horizontal wells completed in Woodford (WF) and Meramec (MM) formations. We conduct complementary diagnostic flow-regime analyses and calculate by combining a flowing-material-balance (FMB) equation with pressure-normalized-rate (PNR)-decline analysis. Flowback data of these wells show up to 2 weeks of single-phase water production followed by hydrocarbon breakthrough. Plots of water-rate-normalized pressure and its derivative show pronounced unit slopes, suggesting boundary-dominated flow (BDF) of water in fractures during single-phase flow. Water PNR decline curves follow a harmonic trend during single-phase- and multiphase-flow periods. Ultimate water production from the forecasted harmonic trend gives an estimate of initial fracture volume. The estimates for these wells are verified by comparing them with the ones from the Aguilera (1999) type curves for natural fractures and experimental data. The results show that our estimates (4 to 22×10psi) are close to the lower limit of the values estimated by previous studies, which can be explained by the presence of proppants in hydraulic fractures.

To understand production from shale reservoirs, the role of hydraulically induced fractures, natural fractures, and their interaction in a formation must be captured. Implementation of such approaches is data-intensive and is accurate only when the field is fully characterized. A model has been developed in which fractures are discretized explicitly and flow is coupled by use of simplified mechanics. The current view is that many unconventional reservoirs comprise well- developed natural-fracture networks with multiple orientations within which complex hydraulic-fracture patterns develop, as suggested by microseismic data. The unconventional-reservoir modeling process follows a multidisciplinary integrated approach that includes specific aspects of geophysics, geology, laboratory work, and reservoir engineering.