Comparison of Measured and Predicted Pressure Drops in Tubing Predicted Pressure Drops in Tubing for High-Water-Cut Gas Wells Summary. A considerable number of deep >3000 m 10,000 A]) high-volume gas wells in northern Germany show signs of increasing water production (about 800X10-6 M3 /std M3 [135 bbl/MMscf). This paper presents results of tests in gas wells to measure the two-phase (gas/water) pressure drop i the tubing. Experimental data are evaluated and compared with the calculations from over 15 different pressure prediction schemes. Modifications proposed for some of the methods resulted in significantly improved predictions. Introduction In the past, the two-phase pressure drop in gas wells that produce free liquids has received relatively little attention produce free liquids has received relatively little attention in the literature, particularly gas wells that produce free water. For a long time, this was of no concern in the Federal Republic of Germany because there were no gas wells producing at high water cuts, at least not over an extended producing at high water cuts, at least not over an extended period. The start of free-water production in a gas well period. The start of free-water production in a gas well typically signaled the end of the well as a gas producer. This situation changed as more and more wells producing from the Rotliegendes formation went on line. At depths of 3000 m [10,000 ft] and more, this formation represents a major source of gas reserves for Germany. The upper Rotliegendes formation is composed of a sequence of numerous sand layers with intermittent shale breaks. The lower part contains the relatively thick and, in comparison with the overlying sands, rather uniform Haupt sandstone. In the East Hanover gas province, only the upper sands typically are gas-bearing, while the sand at the base is water-bearing even at the structurally highest positions. Fig. 1 shows the typical situation encountered positions. Fig. 1 shows the typical situation encountered in a Rotliegendes gas well. Conclusive evidence indicates that the lower water-bearing sand communicates with the upper gas sands in areas where seismic and geologic interpretations suggest major faulting. The result is a reservoir system consisting of a gas reservoir in excellent communication with an aquifer an order of magnitude larger than the reservoir. The Rotliegendes sands are highly stratified, with streaks of less than 1-md permeability next to streaks of 1,000-md or higher permeability. The initial Rotliegendes (appraisal) wells were all drilled through the gas/water contact and completed with a 13-cm [5-in.] liner for the lowermost string. A 13-cm [5-in.] liner cannot be centralized and is difficult to cement. Therefore, channeling behind the pipe is not uncommon. In the majority of the wells, more pipe is not uncommon. In the majority of the wells, more than one sand is perforated and production commingled. As a result, water problems are often observed very early in the life of a well. This does not mean, however, that the well will die soon thereafter, as illustrated in Fig. 2. This rather typical well experienced water breakthrough 6 years ago but continues to produce at rates above about 10X 103 M3/h [9 MMscf/D]. During this 6-year period, the well has produced in excess of 650X 106 M3 [24 Bscf). In the past, methods based on a single-phase model of the flow process were used for calculating tubing pressure losses. These methods underestimate the actual pressure loss. To forecast well deliverabilities and to optimize depletion from high-watercut gas wells, reliable two-phase pressure-drop correlations are needed to estimate the tubing pressure drop with reasonable accuracy and the advantages of lowering the wellhead pressure and of making operational changes (tubing-string optimization or gas lift). This work highlights investigations to identify correlations that would meet the above-mentioned requirements on Te baas of well test results for Rotliegendes gas wells producing at high water cuts. producing at high water cuts. Data Acquisition The data presented here were obtained from production tests and production control surveys. Such surveys are necessary for the reservoir engineer to plan production and to diagnose well problems; therefore, they are performed routinely. To have more reliable data on hand to performed routinely. To have more reliable data on hand to perform two-phase pressure-drop calculations, the perform two-phase pressure-drop calculations, the measurement effort of these routine operations was increased. Increased effort is necessary because during routine operations, not all parameters required to perform two-phase flow calculations are recorded; if they are recorded, some of the data typically lack the required accuracy. The following sections briefly describe the tested gas wells, the test types used to obtain the data, and the data. Note that volumes refer to German standard conditions, which are 0.1 MPa and 0C (1 atm and 32F) SPEPE p. 165

Summary The low-permeability (1 to 100 mu d) sand members of the Rotliegendes and the Carboniferous formations are a major source of gas reserves in West Germany. To establish commercial production from the limited number of deep (+13,100 ft [ +4000 m]) Rotliegendes and Carboniferous wells drilled to date, stimulation of the wells with massive hydraulic fracturing (MHF) treatments is necessary. A great deal of effort was directed not only at the design and performance of these MHF stimulation jobs, but also at the interpretation of buildup data obtained from the treatments and at the integration of the results into a model for future production forecasts. This paper reviews the available hand-applied methods used to analyze the postfracture behavior of wells stimulated with the MHF technique. These methods analyze buildup data collected during the past 5 years from three wells, each producing from more than one horizon. The results of these analyses include the length and conductivity of the fracture created during the MHF treatment. Introduction Recent estimates of gas reserves in West Germany amount to about 10.6 × 1012 scf [300 × 10 std m3]. Similar reserves are anticipated from future discoveries, which will probably occur in the Rotliegendes and Upper Carboniferous formations and are expected to be deep, low-permeability reservoirs. We estimate that at least one-third of the predicted discoveries can be produced economically if MHF stimulation treatments are applied. For an economic evaluation of the high cost of the development of deep, low-permeability gas reservoirs, it is necessary to predict the long-term flow behavior of MHF wells. This prediction requires realistic estimates of the length and the conductivity of the fracture system created in an MHF treatment, estimates of the formation permeability, and estimates of other reservoir parameters. permeability, and estimates of other reservoir parameters. This study updates Brinkmann et al.'s 1980 work, which reviewed the "hand-applied" methods that were available and used them to analyze the early data for three MHF wells and to obtain estimates for the fracture parameters. Since then, more data and methods have parameters. Since then, more data and methods have become available for the analysis. Data comparisons give some indication of the long-term behavior of the fracture properties. The new methods are suited for the analysis properties. The new methods are suited for the analysis of fractures intercepting multilayer reservoirs and result in improved estimates for the properties of the multihorizon/ multifracture system typically encountered in the Rotliegendes and Upper Carboniferous wells. The locations of the gas fields and the analyzed wells in northern West Germany are shown in Fig. 1. Each well produces from more than one horizon. The horizons were produces from more than one horizon. The horizons were separated by thick shale layers and were individually fracture stimulated. The well log for Goidenstedt Well Z7, shown in Fig. 2, is typical for all the wells. The available pressure/production performance results for the wells are shown in Fig. 3. Massive Hydraulic Fracturing The purpose of MHF is to expose a large surface area of the low-permeability formation to flow inside wellbore. This is achieved technically by generating fractures that extend far into the formation and by filling them with proppants to keep the fractures open and to ensure a high proppants to keep the fractures open and to ensure a high conductivity. A low-permeability formation is characterized as having an in-situ permeability of 1 to 100 mu d. At depths of +13,100 ft [+4000 m], a two-wing vertical fracture is created and is assumed to be symmetrical around the wellbore. Fig. 4 illustrates the influence of a two-wing vertical fracture by showing a three-dimensional representation of the pressure distribution in one quadrant of the drainage area of the MHF gas well Hamwiede Well Z2 (lower interval). Table 1 lists the reservoir parameters. After 1 year of production, the cumulative production amounted to about 636 ⨯ 10 scf [18 ⨯ 10 std m3 ] corresponding to 3% of the gas initially in place within the drainage area. Fig. 4 shows the influence of the fracture on the flow behavior in the reservoir. The flow is no longer radial to the wellbore; instead, it is almost linear in the region nearest the fracture. Radial flow is primarily away from the fracture. Therefore, conventional radial flow theory, as described in Refs. 2 through 4, is inadequate for analyzing low-permeability MHF gas wells. To make realistic predictions for the rates and reserves of MHF wells and to evaluate the long-term effectiveness of the stimulation, a theory explicitly accounting for the fracture system created in the MHF treatment was used. JPT P. 2173

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The Kurunda Field, Tirrawarra sandstone is a low permeability, lean gas condensate reservoir located in the Cooper Basin of South Australia. Prior to production consideration was given to the need for gas cycling to maximize liquid recovery. Early long-term production tests, however, showed a much larger drop in liquid-gas-ratios than expected. A study was undertaken to determine the cause of this drop and the implications with respect to future operational policy. A comparison of field observed performance and laboratory data indicated a reservoir fluid composition intermediate between that measured on two laboratory samples. Field observed performance together with results from a simplified model of retrograde gas condensate reservoir behavior further indicated that the observed liquid-gas-ratio correlated more closely to the bottomhole flowing pressure rather than the average reservoir pressure. This liquid-gas-ratio behavior was found to result from the near wellbore region of the reservoir acting as a separator and preventing the recovery of liquids originally entrained in the gas. This separation effect which continues for the life of the reservoir adversely effects liquid recovery for both primary and pressure maintenance operations, and prevents the economical application of the latter activity.

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