|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
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.
Early estimates of gas well performance were conducted by opening the well to the atmosphere and then measuring the flow rate. Such "open flow" practices were wasteful of gas, sometimes dangerous to personnel and equipment, and possibly damaging to the reservoir. They also provided limited information to estimate productive capacity under varying flow conditions. The idea, however, did leave the industry with the concept of absolute open flow (AOF). AOF is a common indicator of well productivity and refers to the maximum rate at which a well could flow against a theoretical atmospheric backpressure at the reservoir. The productivity of a gas well is determined with deliverability testing.
Steady-state-, pseudosteady-state-, and transient-flow concepts are developed, resulting in a variety of specific techniques and empirical relationships for both testing wells and predicting their future performance under different operating conditions. The basis for all well-performance relationships is Darcy's law, which in its fundamental differential form applies to any fluid--gas or liquid. However, different forms of Darcy's law arise for different fluids when flow rates are measured at standard conditions. The different forms of the equations are based on appropriate equations of state (i.e., density as a function of pressure) for a particular fluid. In the resulting equations, presented next, flow rate is taken as being positive in the direction opposite to the pressure gradient, thus dropping the minus sign from Darcy's law. When multiple-line equations are presented, the first will be in fundamental units, the second in oilfield units, and the third in SI units.
Ezabadi, Mehdi Ghane (PETRONAS Carigali Sdn. Bhd.) | Ataei, Abdolrahim (PETRONAS Carigali Sdn. Bhd.) | Liang, Tan Kok (PETRONAS Carigali Sdn. Bhd.) | Motaei, Eghbal (PETRONAS Carigali Sdn. Bhd.) | Othman, Tg Rasidi (PETRONAS Carigali Sdn. Bhd.)
Abstract Production Data Analysis (PDA) has been widely accepted as a valuable analytical tool for well performance evaluation, production forecasting and reservoir characterization. It is fast, practical, and inexpensiveand it can answer many questions about the connected volume to the well, flow regime, average permeability and skin, as well as any boundary within the radius of investigation of the well. It becomes even more important in the case of complex systems such as finely laminated sand reservoirs, or highly heterogeneous multi-stacked reservoirs where sometimes numerical simulation model miscarries in predicting the reservoir performance. Analytical approaches for PDA are variants and require different levels of details in the input. Each is established based on certain assumptions and concepts, and comes with specific limitations. Despite overlap amongst the various methods, each has an advantage in particular application over the others. Therefore, one must be vigilant to use each method for the right purposes in addition to confirm the results and unveil possible uncertainties through using several different methods. This paper integrates basic production and reservoir data through different platforms and methods. Diagnostic plots, General Material Balance (GMB), Pressure Transient Analysis (PTA), deconvolution, nodal analysis, Rate Transient Analysis (RTA), and Flowing Material Balance (FMB) are extensively used to explain the reservoir behavior through PDA. It validates RTA and FMB as an approach for reservoir characterization and reserve estimation without the need to shut-in the well, and defer the production. The benefit of continuously monitoring Flowing Bottom Hole Pressure (FBHP) using Permanent Downhole Gauge (PDG) and applying deconvolution to detect well interference and reservoir boundaries is also discussed. We have also looked at the limitation and advantage of each method and how the integration of those can provide a full picture and enhance the results. We have studied several gas fields. The results of analysis provided an accurate perception and understanding of reservoir behavior and characteristics, well interaction and interference, potential for infill wells, production issues and well constraints, estimation of the connected volume, and eventually led to generation of a reliable analytical reservoir model for the production forecast. The estimated connected volume was tested and proved to be reliable based on infill drilling. The workflow focuses on examining the data quality, confirming the validity of work, and achieving the maximum possible insight through integration of different analytical methods. An integrated workflow is introduced for PDAand successfully applied on different cases of highly heterogeneous conventional gas reservoirs with huge complexities. The paper demonstrates one of the case study as example. The proposed workflow shows to be very powerful particularly when large volume of data from pressure downhole gauges (PDG) is available. It saves significant time for the study team in determining the potential value of a project.
Abstract When analyzing well performance in carbonate reservoirs, the traditional approach usually requires the best practices from pre and post stimulation analysis. Most techniques require an understanding of production performance, which can be divided into two categories. The first is related to reservoir performance away from the wellbore i.e. permeability, fracture network, reservoir pressure, boundaries and secondly, the near wellbore and zonal contribution i.e. permeability-thickness, skin, oil and water influx from individual producing zones. In order to develop a full picture of how these two categories contribute to production performance, a detailed analysis should be conducted to understand their interaction. Low permeability carbonates and chalk fields often require long multi-stage frac'ed horizontal wells which further complicates the analysis due to lack of measured data in each stage. The Ekofisk filed development is a mature water flood, which includes both deviated and horizontal wells. Deviated wells are placed in the more crestal location, while the horizontal wells are generally placed towards the flanks where reservoir properties are of lower quality as compared to the field's crest. Production performance and optimization is largely dependent on efficient zonal stimulation, well and reservoir management. Understanding the distribution of fluid phases along the well, especially the water influx, may enable timely executed water shut-offs to mitigate water breakthrough. The traditional technique of understanding where and how much oil and water are being produced, require well intervention through production logging (PLTs). Well interventions are often difficult to execute due to limited access to platforms, the high cost of wells and production deferments. All of these factors limit efficient production optimization due to the inability to collect data in a timely manner for analysis. Furthermore, experiences from the Ekofisk field indicate that PLT data often gives inconclusive results due to known challenges of interpreting PLT data from horizontal wells. An intervention free and cost efficient approach using inflow tracers has been piloted to acquire early time data, in addition to acquiring well and reservoir understanding throughout the well life. This approach was successfully developed and tested in a newly drilled horizontal Ekofisk field producer. The well was equipped with inflow tracers permanently installed in the completion string to identify individual zone's production contribution including the split by oil, gas and water. In addition, unique intra well tracers were injected into each zone during stimulation to gain knowledge of the stimulation efficiency. During well start up, clean out, transient and post transient production periods extensive sampling programs were executed. As a result, sufficient data has been acquired in order to complete reservoir characterization analysis together with traditional Pressure Transient Analysis (PTA), and then followed by production optimization. The acquired tracer data and interpretation has been compared with conventional PLT interpretation to verify the former. This is the first integrated application using permanently installed inflow tracers, injected intra well tracers and pressure data interpretation solution for reservoir characterization and production optimization performed.
Abstract Description of layered reservoirs is important from a reservoir evaluation and management standpoint because layering affects primary and secondary oil recovery and large variations in permeability-thickness product or skin in different layers have great influence on well performance and production. Commingled reservoirs, where each layer has the same initial pressure without crossflow and layers may have distinct values for thickness, permeability, porosity, fracture half length and skin factor, have been investigated by many authors. Most of research work in multilayered well test analysis focus on estimating individual layer permeabilities, skin factors, fracture half length and formation pressures from well test data. But previous research work indicated that conventional buildup and drawdown(or falloff and injection) testing for wells in commingled reservoirs is only used for determining average reservoir parameters and could not be used for determining individual layer parameters in the absence of the use of the entire history of wellbore pressure and layer production. This paper presents new testing and analysis techniques without using entire history of wellbore pressure and layer production to obtain individual layer permeabilities, skin factors, racture half length and formation pressures for a well in commingled reservoirs by using stabile flow rate data from flow profile tests acquired with production logging tools at the top of each layer before shutting-in the well and conventional pressure buildup or falloff data from the well. Before making any multilayer analysis, conventional well test analysis or type-curve analysis using log-log and derivative methods should be performed to estimate average permeability, ,fracture half length and skin factors of the total system. It can then be used as initial input values for simultaneous interpretation using an analytical model combined with nonlinear least squares estimation and type curves to estimate individual-layer permeabilities, skin factors, fracture half length and reservoir pressures. But If we use entire history of wellbore pressure and layer production, we can reduce the multiple solutions, to enhance the reliability of interpretation results.
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Russian Oil & Gas Exploration & Production Technical Conference and Exhibition held in Moscow, Russia, 16-18 October 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited.
An approximate method for simulation of the multilayer well operation is considered. The essence of the approach lies in the extension of nodal analysis method where transient flow is acting in the formation and the start of production from different layers is not simultaneous. An example of using this approach for modeling unsteady processes occurring after involving into development of new layers is given. The constructed model can be used for incremental production planning, evaluation of interstratal crossflows, as well as candidates selection. Introduction A large number of wells in West Siberian region are multulayered. Each of the layers has its effective thickness, permeability distribution, porosity, as well as reservoir pressure and other reservoir properties. In this regard, there are difficulties in simulation of the multilayer well operation and identify the optimal parameters of some technical operations in such wells. For the successful modeling of processes occurring in multilayer systems, you should: 1) to solve the problem of unsteady interaction of well with a set of layers, to take into account the consistency of the fluid movement in the borehole and its filtration in each of the layers, 2) take into account the specifics of the technical operations.
Abstract The analysis of production data in unconventional reservoirs to determine well/reservoir properties, completion effectiveness, and estimate future production has become popular in recent years. However, production analysis in unconventional reservoirs is a challenging task because of the non-uniqueness associated with estimating well/reservoir properties. Various analysis methodologies exist in the literature, but no single methodology is robust enough to characterize the production data and forecast production. Therefore, from a conceptual standpoint, we believe that production analysis in unconventional reservoirs should not be a "single-method based" application. Instead, multiple analysis techniques combined with diagnostic tools have to be utilized, and challenges associated with the analysis have to be recognized. This work attempts to provide a review of the existing production analysis and diagnostic techniques as well as to identify the challenges associated with production analysis in unconventional reservoirs. We present an extensive evaluation of the diagnostic tools for assessing data viability, checking data correlation along with flow regime identification. Based on diagnostics and analysis results, we demonstrate the use of forward modeling (simulation) to predict future performance of single/multiple well(s) for various production/completion and field development scenarios. Field examples from a wide range of unconventional reservoirs are used to describe the application of the methodology.
Abstract Currently in the oil industry, pseudo-steady state productivity equations for a multiple wells system are used in all reservoir systems, regardless of the outer boundary conditions. However, if the reservoir is under edge water drive or with infinite lateral extension, pseudo-steady state is no longer applicable. When producing time is sufficiently long, productivity equations based on the steady state are required. This paper presents steady-state productivity equations for a multiple-wells system in homogeneous, anisotropic sector fault reservoirs and channel reservoirs. Taking fully penetrating vertical wells as uniform line sinks, and solving a square matrix of dimension n, where n is the number of wells, simple, reasonably accurate multiple-wells system productivity equations are obtained. The proposed equations which relate the production rate vector to the pressure drawdown vector provide a fast analytical tool to evaluate the performance of multiple wells, which are located arbitrarily in a sector fault reservoir or a channel reservoir. This paper also gives an equation for calculating skin factors of each well. It is concluded that, for a given number of wells, well pattern, anisotropic permeabilities, skin factor, pressure difference between reservoir outer boundary and flowing bottomhole pressure, have significant effects on single well productivity and total productivity of the multiple-wells system. In a sector fault reservoir, the production rates are increasing functions of the sector angle; in a channel reservoir, the production rates are increasing functions of the reservoir width. Introduction Well productivity is one of primary concerns in field development and provides the basis for field development strategy. To determine the economical feasibility of drilling a well, petroleum engineers need reliable methods to estimate its expected productivity. We often relate the productivity evaluation to the long time performance behavior of a well, that is, the behavior during pseudo-steady state or steady-state flow.