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Although reserves estimates for known accumulations historically have used deterministic calculation procedures, the 1997 SPE/WPC definitions allow either deterministic or probabilistic procedures. Each of these is discussed briefly in the next two sections. Thereafter--except for another section on probabilistic procedures near the end--the chapter will focus on deterministic procedures because they still are more widely used. Both procedures need the same basic data and equations. Deterministic calculations of oil and/or gas initially in place (O/GIP) and reserves are based on best estimates of the true values of pertinent parameters, although it is recognized that there may be considerable uncertainty in such values.
This chapter addresses the flow characteristics and depletion strategies for gas reservoirs. The focus will be primarily on nonassociated accumulations, but much of the fluid behavior, flow regimes, and recovery aspects are also applicable to gas caps associated with oil columns. In this chapter, gas reservoirs have been divided into three groups; dry gas, wet gas, and retrograde-condensate gas. A dry-gas reservoir is defined as producing a single composition of gas that is constant in the reservoir, wellbore, and lease-separation equipment throughout the life of a field. Some liquids may be recovered by processing in a gas plant. A wet-gas reservoir is defined as producing a single gas composition to the producing well perforations throughout its life. Condensate will form either while flowing to the surface or in lease-separation equipment. A retrograde-condensate gas reservoir initially contains a single-phase fluid, which changes to two phases (condensate and gas) in the reservoir when the reservoir pressure decreases. From a reservoir standpoint, dry and wet gas can be treated similarly in terms of producing characteristics, pressure behavior, and recovery potential. Wellbore hydraulics may be different. Studies of retrograde-condensate gas reservoirs must consider changes in condensate yield as reservoir pressure declines, the potential for decreased well deliverability as liquid saturations increase near the wellbore, and the effects of two-phase flow on wellbore hydraulics. A comprehensive discussion of gas and condensate properties and phase behavior can be found in several chapters of the General Engineering section of this Handbook. Aspects of predicting wellbore hydraulics are covered in the Production Operations Engineering section of this Handbook . Lease equipment for processing gas and pipelining considerations are covered in several chapters of the Facilities Engineering section of this Handbook. The reader may want to refer to these chapters to understand some of the nomenclature and concepts referred to in the present chapter. Natural petroleum gases contain varying amounts of different (primarily alkane) hydrocarbon compounds and one or more inorganic compounds, such as hydrogen sulfide, carbon dioxide, nitrogen (N2), and water. Characterizing, measuring, and correlating the physical properties of natural gases must take into account this variety of constituents. A retrograde-condensate fluid has a phase envelope such that reservoir temperature lies between the critical temperature and the cricondentherm (Figure 1.1). As a result, a liquid phase will form in the reservoir as pressure declines, and the amount and gravity of produced liquids will change with time.
This chapter discusses the determination of lithology, net pay, porosity, water saturation, and permeability from wellbore core and log data. The chapter deals with "Development Petrophysics" and emphasizes the integration of core data with log data; the adjustment of core data, when required, to reservoir conditions; and the calibration and regression line-fitting of log data to core data. The goal of the calculations is to use all available data, calibrated to the best standard, to arrive at the most accurate quantitative values of the petrophysical parameters (i.e., lithology, net pay, porosity, water saturation, and permeability). Log analysis, cased-hole formation evaluation, and production logging are not covered here. The following topics are covered in this chapter: petrophysical data sources and databases, lithology determination, net-pay (or pay/nonpay) determination, porosity determination, fluid-contacts identification, water-saturation determination, permeability ...
This article presents brief summaries of detailed petrophysical evaluations of several fields that have been described in the SPE and Soc. of Professional Well Log Analysts (SPWLA) technical literature. These case studies cover some of the complications that occur when making net-pay, porosity, and water saturation (Sw) calculations. Prudhoe Bay is the largest oil and gas field in North America with more than 20 billion bbl of original oil in place (OOIP) and an overlying 30 Tscf gas cap. In the early 1980s, the unit operating agreement required that a final equity determination be undertaken. In the course of this determination, an extensive field coring program was conducted, which resulted in more than 25 oil-based mud (OBM) cores being cut in all areas of the field and some conventional water-based mud (WBM) and bland-mud cores in other wells.
The Kuparuk River oil field is west of the supergiant Prudhoe Bay oil field on Alaska's North Slope and was discovered in 1969. It has approximately 5.9 billion bbl of stock tank original oil in place (STOOIP) and covers more than 200 sq. The sandstone reservoir consists of two zones [A (62% of STOOIP) and C (38% of STOOIP)] that are separated by impermeable shales and siltstones. Sales oil is approximately 24 API with a viscosity at reservoir conditions of approximately 2.5 cp. The reservoir oil was approximately 300 to 500 psi undersaturated at the original reservoir pressure of approximately 3,300 psia.
The Haft Kel field is located in Iran. Its Asmari reservoir structure is a strongly folded anticline that is 20 miles long by 1.5 to 3 miles wide with an oil column thickness of approximately 2,000 ft. The most probable original oil in place (OOIP) was slightly 7 109 stock tank barrels (STB) with about 200 million STB in the fissures; numerical model history matching resulted in a value of 6.9 109 STB. The matrix block size determined from cores and flowmeter surveys varied from 8 to 14 ft. The numerical simulation model considered matrix permeabilities from 0.05 to 0.8 md.
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). 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.
Estimating resource and reserves crosses the disciplines between geoscientists and petroleum engineers. While the geoscientist may well have primary responsibility, the engineer must carry the resource and reserve models forward for planning and economics. Volumetric estimates of reserves are among the most common examples of Monte Carlo simulation. Consider the following typical volumetric formula to calculate the gas in place, G, in standard cubic feet. In this formula, there is one component that identifies the prospect, A, while the other factors essentially modify this component.
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).