TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractAlthough production analysis (PA) for reservoir characterization is approaching the popularity of pressure transient analysis (PTA), there are few consistent diagnostic methods in practice for the analysis of production data. Many of the "diagnostic" methods for production data analysis are little more than observation-based approachesand some are essentially "rules of thumb."

Material balance calculations for determining oil- or gas-inplace require static reservoir pressures, which can only be obtained when the well is shut in. In a previous publication(1) titled "The ‘Flowing’ Gas Material Balance," it was shown that the reservoir pressure could be obtained from the flowing pressure for wells producing at a constant rate. The "Dynamic Material Balance" is an extension of the "Flowing Material Balance" and can be applied to either constant or variable flow rates. Both methods are applicable for gas and oil. The "Dynamic Material Balance" is a procedure that converts the flowing pressure at any point in time to the average reservoir pressure that exists in the reservoir at that time. Once that is done, the classical material balance calculations become applicable, and a conventional material balance plot can be generated. The procedure is graphical and very straightforward:knowing the flow rate and flowing sandface pressure at any given point in time, convert the measured flowing pressure to the average pressure that exists in the reservoir at that time; and,use this calculated average reservoir pressure and the corresponding cumulative production, to calculate the original oil- or gas-inplace by traditional methods. The method is illustrated using data sets. Introduction The material balance method is a fundamental calculation in reservoir engineering, and is considered to yield one of the more reliable estimates of hydrocarbons in place. In principle, it consists of producing a certain amount of fluids, measuring the average reservoir pressure before and after the production, and with knowledge of the PVT properties of the system, calculating a mass balance as follows: Remaining hydrocarbons-in-place = initial hydrocarbons-inplace − produced hydrocarbons At face value, the above equation is simple; however in practice, its implementation can be quite complex, as one must account for such variables as external fluid influx (water drive), compressibility of all the fluids and of the rock, hydrocarbon phase changes, etc. In order to determine the average reservoir pressure, the well is shut in, resulting in loss of production. In high permeability reservoirs, his may not be a significant issue, but in medium to low permeability reservoirs, the shut-in duration may have to last several weeks (and sometimes months) before a reliable reservoir pressure can be estimated. This loss of production opportunity, as well as the cost of monitoring the shut-in pressure, is often unacceptable. It is clear that the production rate of a well is a function of many factors such as permeability, viscosity, thickness, etc. Also, the rate is directly related to the driving force in the reservoir, i.e., the difference between the average reservoir pressure and the sandface flowing pressure. Therefore, it is reasonable to expect that knowledge about the reservoir pressure can be extracted from the sandface flowing pressure if both the flow rate and flowing pressure are measured. If, indeed, the average reservoir pressure can be obtained from flowing conditions, then material balance calculations can be performed without having to shut in the well.

Tight gas is becoming an increasingly important asset for petroleum companies. Proper reservoir evaluation and development planning is critical to the success of a tight gas play. To date, the "best practices" for evaluating tight gas performance have not been well defined, and many companies use unreliable or unnecessary methods. As a result, analysts commonly misinterpret (and incorrectly book) tight gas reserves. Furthermore, the development of tight gas reservoirs is often conducted inefficiently, either through overcapitalization (too many wells, too quickly) or ineffective recovery (overly sparse spacing). This paper presents a straight forward and technically sound approach for evaluating and planning the development of tight gas reservoirs. The critical step in the process is proper identification of the dominant reservoir flow regime. Without this step, we cannot choose the correct analysis plot to use. The techniques detailed in this paper are designed for production data sets ranging from about 3 months and upward. The reservoir and production characteristics (permeability, xf, flow regime) are determined using pressure/rate transient analysis, as are the drainage region and its expansion rate. The resulting model predicts well performance and the rate of increase of accessible recovery over time. Superposition of the appropriate economic model and well constraints allows the analyst to identify a practical range of EUR values that is more reliable than that provided by conventional decline curves. This process can be applied to reserve evaluation as well as optimizing well spacing in the reservoir. The analysis is performed through interpretation of a diagnostic plot paired with an appropriate recovery plot (using well constraints and economics). It is validated using simulated and field examples. Introduction Tight gas is often defined by reservoir permeabilities below 0.1 millidarcies. In the context of this work, tight gas implies a formation that is not productive without some kind of mechanical intervention. In this paper, we limit our discussion to completions consisting of vertical wells with induced hydraulic fractures. However, most of the concepts can be easily extended to horizontal or more complex completions. The major publications in this field are shown in the references 1–16. Best Practices In the following, we describe what we consider to be best practices for evaluating performance data from tight gas reservoirs. The purpose is twofold:To establish reliable and timely estimates of expected ultimate recovery (EUR)To enable effective planning and development of tight gas fields To accomplish the above, a general procedure will be developed, as follows:Use a diagnostic plot (log-log) to characterize the dominant reservoir flow regime(s)Use analysis plots to interpret region-of-influence (ROI), drainage volume (OGIP), and transient properties. These analysis plots are well documented in the literature by Fetkovich 16, Blasingame 1, Agarwal 2 and Wattenbarger 3Use analytical forecast models and recovery plots to assess expected ultimate recovery (EUR) and its associated uncertainty range (new concepts introduced)Use Spacing Optimization plots to establish optimum well spacing (new concepts introduced).

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