A Wellbore/Reservoir Simulator for Testing Gas Wells in High-Temperature Reservoirs
- C.S. Kabir (Chevron Overseas Petroleum Technology Co.) | A.R. Hasan (U. of North Dakota) | D.L. Jordan (Chevron U.S.A. Production Co.) | Xiaowei Wang (U. of North Dakota)
- Document ID
- Society of Petroleum Engineers
- SPE Formation Evaluation
- Publication Date
- June 1996
- Document Type
- Journal Paper
- 128 - 134
- 1996. Society of Petroleum Engineers
- 5.6.4 Drillstem/Well Testing, 1.11 Drilling Fluids and Materials, 5.2 Reservoir Fluid Dynamics, 5.5.8 History Matching, 5.6.1 Open hole/cased hole log analysis, 1.6 Drilling Operations, 4.2.3 Materials and Corrosion, 5.1.5 Geologic Modeling, 5.5 Reservoir Simulation, 2 Well Completion, 2.2.2 Perforating, 1.14 Casing and Cementing, 4.6 Natural Gas, 1.2 Wellbore Design, 1.6.9 Coring, Fishing
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Gas wells frequently exhibit changing storage during a transient test because of high fluid compressibility. Further complications may arise due to beat exchange between the wellbore fluid and the formation, especially in high-temperature reservoirs. Thus, fluid temperature changes during a transient test, thereby complicating test interpretation when surface measurements must be used in a hostile downhole environment.
In this work we present a transient wellbore/reservoir model for testing gas wells that is particularly useful for high- temperature reservoirs. The model can be used in a forward mode, given reservoir and wellbore parameters, to predict pressure and temperature at any depth during a transient test. The wellbore model formulation involves the use of mass, momentum, and energy balances for a single-phase gas together with the PVT relation to generate the constitutive equations. The reservoir fluid flow is modeled using the standard analytic approach, including superposition effects. Heat transport in the wellbore accounts for conductive and convective heat flow through the annul us fluid and conductive heat transport through the tubulars and cement sheaths into the formation. The finite-wellbore radius solution of the thermal diffusivity equation accounts for heat flow in the formation. Energy balance for the fluid accounts for the Joule-Thompson expansion.
A sensitivity study provided some insights into the effect of process variables on wellbore pressure and temperature. As expected, fluid flow rate is shown to have a very significant impact on the wellhead pressure and temperature. Clearly, the temperature rating of surface equipment could limit the maximum production from some wells. Heat transport in the annulus between the tubing and casing also strongly influences wellhead fluid temperature. For example, a fluid with a low-heat transfer coefficient, such as a or oil-based mud, would allow the wellbore gas to retain much of the enthalpy, leading to high fluid temperatures at the wellhead.
Unlike previous formulations, this model accounts for the energy absorbed (or released) by the tubulars and the cement sheaths, which is a significant fraction of the energy exchange between the wellbore and the formation at early times. A consequence of accounting for heat capacity of the wellbore system is that rapid temperature rise or fall during a test is dampened, mimicking the actual field response.
A routine well-test interpretation or forward modeling invokes the well-known constant-storage model. When a test is associated with either increasing or decreasing storage, one could use the Fair or the Hegeman et al. model. These wellbore models are popular because they are operable in Laplace space and, therefore, can be linked easily with most analytic reservoir models whose solutions are also available in Laplace space.
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