Analysis of Tight Gas Well Production Histories in Production Histories in the Rocky Mountains Summary Monthly production records on more than 6,000 gas wells are analyzed to determine expected behavior of additional wells and to compare actual performance with theoretical performance as described by many authors. The wells analyzed are in the Rocky Mountains, ranging from the Green River basin of Wyoming to the San Juan basin of New Mexico. Most of these wells produce from low-permeability reservoirs and have been hydraulically fractured. Production trends are studied with three different techniques: conventional semilog rate vs. time analysis, logarithmic rate vs. time analysis, and linear flow decline-curve analysis. The primary purpose of this study is to forecast future rates and reserves. The impact of well downtime and pressure variations on observed flow rates is reviewed. Introduction Standard gas production reports for most pipeline companies show monthly and, in some cases, weekly or daily production levels. At best, 2 weeks of test data are production levels. At best, 2 weeks of test data are collected each year. On many wells, test data are not regularly collected. Testing procedures vary from state to state. Therefore, wellhead production data make a more widely usable data file than annual well test files. These data are available on all producing wells and represent actual operating conditions rather than optimum conditions that normally prevail during tests. Standard production reports include wellhead volumes, average purchase-meter flowing pressures, and hours of measurable flow each month. This paper shows how to use these monthly production records to determine reserves, how to estimate stable producing rates with observed flush production data producing rates with observed flush production data following well downtime, and how rates are impacted by surface pressures and downtime for gas wells in the Rocky Mountain region. Fig. 1 shows the location of wells used in this study. With the exception of Almy/Mesaverde production in Wyoming and Dakota/Morrison production in the Grand County, UT, and Bar X, CO, area, most gas wells are tight and are productive as a result of either hydraulically induced or naturally occurring fractures. Fracture damage is common. Multiple zones produce in many wells, making pressure-buildup analysis complex. The complexities of reservoir properties and production problems are not fully understood. A simplified analysis of problems are not fully understood. A simplified analysis of production data, however, reveals much of what is production data, however, reveals much of what is needed to manage these wells. Exponential or Constant-Percent Forecasting Exponential (constant-percent) decline has long been used to determine gas well reserves. However, most wells have hyperbolic declines. This means that the decline rate is not constant and will normally decrease as a well ages. The corresponding reserves will be underestimated because of the decreasing decline rate. Figs. 2 and 3 show production curves for 11 groups in the study area in semilogarithmic format for exponential analysis. All show reductions in the decline rates, especially during the first 48 months following initial delivery of the wells. After 48 months, production rates continue to flatten but at a lower rate. The following exponential decline equations relate reserves to flow rates: (1) (2) and (3) Eq. 1 relates the current flow rate, Q, to the initial flow rate, Qi, the age of the well, t, and the reserve life ratio or exponential loss factor, F. In Eq. 2, Np is cumulative production or reserve, Qi is the initial rate, and Qa is production or reserve, Qi is the initial rate, and Qa is the abandonment rate. In Eq. 3, F is the reserve life ratio and d is the decline rate. The major difference in the 11 areas, as shown in Figs. 2 and 3, is not the declines but the magnitude of the rates. Rates vary substantially from group to group with all groups having similar performance trends. The Frontier/ Muddy wells of Wyoming have the highest average rate and the Colorado/Utah wells the lowest average rate. Reserves and rates can be forecast by measuring F in Fig. 2 or 3 and then using Eq. 1 to forecast reserves or Eq. 2 to forecast rates. P. 310
Summary A set of elliptical equations is developed for use in understanding and evaluating vertically fractured gas wells in low-permeability gas sands. The equations are designed for use with short-term flow tests at either constant-rate or constant-pressure test conditions. Introduction Much new Rocky Mountain-area gas is being produced from tight gas sands. These wells often prove uneconomical unless they are fractured hydraulically. After the wells are fractured, testing generally is required to ensure that sustained production will justify the cost of a pipeline connection. Current practice generally involves a flow test ranging from several hours to several days. A corresponding pressure buildup often ranges from a day to a week or more. Using a well test involving hours to forecast many years' performance can be very misleading if not done with care.A basic understanding of elliptical equations can yield a great deal of useful information from short flow and buildup tests. It also helps set limits on what information can and cannot be expected from tests. Elliptical Equation The elliptical flow equations result from the basic fluid flow equations in porous media with fracture geometry. The fracture is characterized by the distance it extends from the wellbore. It extends from -Xf to +Xf for a total length of 2Xf. Gas flows from the formation into the fracture and is conducted by the fracture to the wellbore. For an infinite conductivity fracture, the inner boundary is one of uniform pressure along the fracture face. Flow may be either at a constant rate, a constant pressure, or a combination of the two.Three points on a given isobar demonstrate steadystate elliptical geometry. Two points are at a distance of +A and -A from the wellbore. The third is at a distance B from the wellbore (Fig. 1). Conformal mapping with the coordinate transformation w = arcsin (Z) is used to transform the X-Y plane into a U - V plane. The transformed system is linear with known solutions for the given conditions. At the external boundary parallel to the fracture, Ve = A′ = B' = arccosh (A) = arcsinh (B). Rearranging this equation yields Ve = ln (A + B) = -ln (A-B) or A2 - B2 = Xf2. This defines an ellipse. The steady-state isobars are concentric ellipses. A is a major semiaxis. B is a minor semiaxis. In this paper, A and B refer to the external ellipse that defines the drainage area. Axf and Bxf refer to the inner ellipse that is the fracture. Fluid flow occurs along the streamlines that are orthogonal to the ellipses. The driving force is the real gas pseudopressure. Steady-State Elliptical Flow Equations Development of steady-state equations will solve few problems but lends to an understanding of unsteady-state problems. The generalized steady-state equation is (1) Expressed in X - Y coordinates, the equation is (2a) Boundary conditions are (2b) JPT P. 2489^
The Barnett Shale play in north central Texas has 14,382 wells which were originally primarily vertical wells. Currently 68% of the wells are horizontal wells. This Barnett Shale has significant changes in performance and quality as produced fluid type changes, as the depth changes, and as the thickness changes. Completion type is known to have a significant impact on well productivity. This review relates peak month rate to reservoir performance. The peak month rate is shown to be impacted in a predictable manner by horizontal wellbore length, by lateral azimuth, by completion depth, by gross pay interval, and by type of fluid being produced, which ranges from dry gas to oil. A P10/P90 ratio is used to measure the relative uncertainty in performance for the various subsets of the Barnett Shale reviewed.
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Various methods have been used to define the reserves for the Frontier/Muddy formations of the Big Piney Gas Field. This paper reports the results of a Piney Gas Field. This paper reports the results of a study based on production histories interpreted with constant pressure type curves. Over 80 wells were studied in detail with resulting data used to develop relationships between rate, permeability, and net pay. Using these empirical relationships, reserves for the field were determined. Gas-in-place was calculated for each well as well as effective drainage area and recovery efficiency. Individual well deliverabilities were calculated. A relationship between effective well spacing and recovery was developed. The results of the study generally agree with previous work. The type curve approach should prove previous work. The type curve approach should prove useful in providing details about effective gas-in- place and drainage area. This is not easily obtained from conventional testing. It also provides a link to analyzing newer tight gas wells by showing that type curve solutions are valid over the life of a well. Introduction An effort has been made to estimate reserves for the Frontier-Muddy formations of the Big Piney, Wyoming gas field. Because of the age of the field and extensive production history, the study attempted to link production performance with theory of flow through a production performance with theory of flow through a porous media to estimate reservoir properties which porous media to estimate reservoir properties which will control future behavior and reserves. Results show that as of June, 1980, remaining reserves of 1.94 TCF, (55 giga M), excluding the Birch Creek Unit, existed. OGIP is shown to be 5.37 TCF (153 giga M). Recovery efficiency, with no additional development, will be 45.4% of the original gas-in-place and will increase to 57.8% if the number of net producing completions doubles. Discussion The fluid flow equation used is the standard diffusivity equation:(1) The rate equation is: (2) The solution for a no flow outer boundary and a constant pressure inner boundary is given in Figure 1. It was selected because it matches production characteristics of tight gas wells. It also allows curve matching to determine reservoir properties based on the well's age and production history. Important assumptions are:The difference between initial reservoir pseudopressure and flowing wellbore pseudopressure is constant;The reservoir is homogeneous and isotropic;Wellbore damage is constant over the life of the well;The average drainage area is equal to the average well spacing;The log-log decline slope shown in Figure 1 can be approximated by a straight line for a "short" period of time not to exceed three years;Well period of time not to exceed three years;Well performance corresponds to that predicted by Equations performance corresponds to that predicted by Equations 1 and 2. Theoretical solutions to the tight gas performance problem must include the effects of fracturing. problem must include the effects of fracturing. Fractures, either natural or artificial, can normally be represented by a single vertical fracture in an elliptical reservoir (Figure 2). The fracture is centered at the wellbore, W, and extends from -Xf to +Xf. P. 123
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