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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.
Abstract Material-balance (MB) analysis for in-place volume estimation in gas reservoirs has been in practice for decades. Nonlinear responses from geopressure reservoirs with or without aquifer influx present special interpretation challenges. One of the main challenges of in-place volume estimates involves the estimation of average-reservoir pressure with production. To that end, modern pressure sensors installed at bottomhole and/or surface largely help establish a given well's dynamic performance by way of rate-transient analysis. This paper explores the applicability and limitations of the standard analytical tools in volumetric, geopressure, and waterdrive systems for a diverse array of fluids, from dry gas to near-critical gas/condensate. The systematic approach presented in this paper attempts to increase accuracy in results by ensuring consistency in solutions from multiple methods used to first assess the average-reservoir pressure from production performance data, followed by in-place volume estimation. In this context, we examined analytical tools, such as the pav/z vs. cumulative gas production (Gp) plot, and cumulative reservoir voidage vs. cumulative total expansion plot. Both pot aquifer and unsteady-state Carter-Tracy aquifer models were considered to account for water influx. Besides the use of Cole and drive indices plots, two diagnostic log-log plots are introduced involving total expansivity and change in average-reservoir pressure. In addition, we sought solution objectivity by introducing a diagnostic tool in the Walsh and Yildiz-McEwen MB plots. Both MB methods involve plotting of cumulative reservoir voidage (F) vs. cumulative total expansion (Et), whereas the diagnostic tool consists of plotting F/Et vs. Et on the same graph. Initially, synthetic data helped us understand the overall system behavior and instilled confidence in the solutions obtained for various combinations of drive mechanisms. Statistical design of experiments prompted us to explore independent variables, such as aquifer-to-hydrocarbon PV ratio, production rate, degree of overpressure, and the aquifer source. Those learnings were validated with published and new field data encompassing an array of reservoirs with various drive mechanisms and fluid type.
This page explores the fundamental relationships underlying gas reservoir performance and presents some simple techniques for forecasting production rate vs. time. One way to envision the different factors affecting the performance of a gas reservoir is to define the production "system" with three components: Rate vs. time behavior is governed by the combined effect of these three parts, which in turn have performance characteristics that vary with pressure and production rate. If these relationships are plotted on the same presentation, the resulting graph will look like Figure 1. At low flow rates, the equipment-performance curve is nearly horizontal, reflecting the small flowing frictional pressure drops in the system. If there is liquid holdup in the production tubing, multiphase-flow calculations can show the curve bending upward at low production rates.
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 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.
Injecting water into a low-pressure gas reservoir nearing abandonment will displace gas and increase ultimate recovery. This paper examines the theory and reports the results of a case history. Water was injected into a southern Louisiana gas reservoir for more than 10 years, successfully increasing recovery by 25 Bcf [710×106 m3]. This paper also discusses the importance of considering all possible producing mechanisms early in a reservoir's life to predict future performance properly and shows that straight-line p/z performance does not necessarily indicate that a gas reservoir has a depletion drive, as is frequently assumed in practice.
Natural gas is a major source of energy production and consumption in the U.S. As reserves decline, investigators are studying the potential of increased supplies from several unconventional sources1 and from waterdrive reservoirs with high production rates in the gas zones2,3 and the aquifers.4 Production at high rates from a waterdrive reservoir is an attempt to reduce reservoir pressure to a low value, thereby minimizing the actual gas volume occupying residual pore space. A reservoir with little water influx that depletes to low pressure has the opposite problem because all the pore space is still filled with gas.
This paper shows that increased recovery can be obtained by waterflooding a low-pressure gas reservoir and discusses an actual field case. The Discorbis 1 reservoir (Reservoir D-1) in the Duck Lake field of southern Louisiana (St. Martin Parish) initially produced by limited aquifer influx. Water injection was initiated after reservoir pressure had fallen below 1,000 psi [6.9 MPa] and continued for 11 years. An incremental recovery of 25 Bcf [710×106 m3] was attributed to water injection. This project was primarily a low-cost expansion of the field's existing saltwater disposal system, providing a unique opportunity for an economic project at the gas prices of the 1970's, which were about 15% of current prices.
Analysis of Reservoir D-1 also provides the opportunity to show that straight-line p/z performance does not necessarily mean that a gas reservoir has a depletion drive. Theory showing that depletion-drive gas reservoirs will exhibit a straight-line p/z plot has been developed. The corollary - that a straight-line p/z plot proves the existence of a depletion drive - has not been proven, although it is frequently assumed in practice.
If a gas reservoir produces strictly by pressure depletion, hydrocarbon pore space at abandonment pressure should be equal to that at initial pressure. A significant amount of gas, however, can remain in the reservoir. Injecting water at abandonment pressure displaces a fraction of the PV to production wells, leaving a residual gas saturation that contains a minimal standard volume because of the low trapping pressure. Thus, the good features of pressure depletion and water displacement are combined in a controlled production mechanism to maximize recovery.
Craft and Hawkins5 showed that recovery for a waterdrive reservoir can be expressed as
and that recovery for a depletion-drive reservoir can be expressed as
For imbibition fluid displacements, Naar and Henderson6 concluded that residual nonwetting-phase saturation should be about one-half the initial nonwetting-phase saturation, so that
Substituting Eq. 3 into Eq. 1 and subtracting Eq. 2 yields
Eq. 4 presents a simple means to calculate a theoretical incremental recovery, as a percentage of original gas in place (OGIP), that results from waterflooding a gas reservoir that is pressure depleting. This recovery factor is representative of a homogeneous reservoir where permeability is uniform areally and vertically, and water coning is neglected.