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Results
Multiphase Flowing Material Balance for Well Groups
Thompson, Leslie (Whitson AS) | Ruddick, Barry (Whitson AS) | Carlsen, Mathias Lia (Whitson AS) | Whitson, Curtis Hays (Whitson AS)
Abstract We extend the multiphase flowing material balance (FMB) method proposed by Thompson & Ruddick (2020) to multi-well problems, i.e., multiple wells draining one reservoir volume. As in the original method, analysis of well groups for the total pore volume drained and initial in-place volumes relies only on commonly available production data as well as black oil PVT data. Estimation of original hydrocarbons in place is a fundamental responsibility of a practicing reservoir engineer and is essential for constraining production forecasts and reserves estimates within physically reasonable bounds. In traditional reservoir engineering, most non-empirical reserves estimation techniques are based on single-phase pseudo-steady-state flow theory. Many researchers have extended these single-phase techniques to multiphase flow through the introduction of pseudo-pressure and pseudo-time transformations. For multiphase flow, definition of these transformations is not unique, and different researchers have proposed alternative methods of computing pseudo-functions with varying degrees of success. A major difficulty with the pseudo-function approach is that a relative permeability-saturation model must be selected for the system of interest; in our experience, system relative permeability curves are seldom known. Most modern wells drilled and completed in tight unconventional reservoirs communicate, or interfere, with other offset wells, however, few methods exist to deal with the combination of multiphase flow and multiple well problems. Our proposed method addresses both these issues. We illustrate the method by applying it to both synthetically generated data and actual field data form the Permian basin. Introduction Flowing material balance (FMB) techniques can be used to estimate a well’s contacted pore volume from production and PVT data. Accurate determination of this volume is crucial for the planning and optimization of production from oil and gas reservoirs. In complex reservoirs, such as those with multiple wells producing in close proximity to each other, it can be challenging to accurately estimate this due to well interference. In this paper, we aim to extend the multiphase flowing material balance method developed by Thompson & Ruddick (2022) to account for well interference and adjust the drainage volume as operating conditions change. Our motivation stems from the observation that many wells appear to share drainage volume with their neighbors, and their production performance can be influenced by each other.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
Numerical RTA in Tight Unconventionals
Carlsen, Mathias Lia (Whitson AS) | Bowie, Braden (Apache Corporation) | Dahouk, Mohamad Majzoub (Whitson AS) | Mydland, Stian (Whitson AS) | Whitson, Curtis Hays (Whitson AS) | Yusra, Ilina (Whitson AS)
Abstract We extend the numerically-assisted RTA workflow proposed by Bowie and Ewert (2020) to (a) all fluid systems and (b) finite conductivity fractures. The simple, fully-penetrating planar fracture model proposed is a useful numerical symmetry element model that provides the basis for the work presented in this paper. Results are given for simulated and field data. The linear flow parameter (LFP) is modified to include porosity (LFPꞌ=LFP√φ). The original (surface) oil in place (OOIP) is generalized to represent both reservoir oil and reservoir gas condensate systems, using a consistent initial total formation volume factor definition (Bti) representing the ratio of a reservoir HCPV containing surface oil in a reservoir oil phase, a reservoir gas phase, or both phases. With known (a) well geometry, (b) fluid initialization (PVT and water saturation), (c) relative permeability relations, and (d) bottomhole pressure (BHP) time variation (above and below saturation pressure), three fundamental relationships exist in terms of LFPꞌ and OOIP. Numerical reservoir simulation is used to define these relationships, providing the foundation for numerical RTA, namely that wells: (1) with the same value of LFPꞌ, the gas, oil and water surface rates will be identical during infinite-acting (IA) behavior; (2) with the same ratio LFPꞌ/OOIP, producing GOR and water cut behavior will be identical for all times, IA and boundary dominated (BD); and (3) with the same values of LFPꞌ and OOIP, rate performance of gas, oil, and water be identical for all times, IA and BD. These observations lead to an efficient, semi-automated process to perform rigorous RTA, assisted by a symmetry element numerical model. The numerical RTA workflow proposed by Bowie and Ewert solves the inherent problems associated with complex superposition and multiphase flow effects involving time and spatial changes in pressure, compositions and PVT properties, saturations, and complex phase mobilities. The numerical RTA workflow decouples multiphase flow data (PVT, initial saturations and relative permeabilities) from well geometry and petrophysical properties (L, xf, h, nf, φ, k), providing a rigorous yet efficient and semi-automated approach to define production performance for many wells. Contributions include a technical framework to perform numerical RTA for unconventional wells, irrespective of fluid type. A suite of key diagnostic plots associated with the workflow is provided, with synthetic and field examples used to illustrate the application of numerical simulation to perform rigorous RTA. Semi-analytical models, time, and spatial superposition (convolution), pseudopressure and pseudotime transforms are not required.
Backpressure Equation for Layered Gas Reservoirs
Juell, Aleksander (NTNU) | Whitson, Curtis Hays (NTNU/PERA)
Abstract This paper presents a backpressure equation (BPE) for wells producing from layered gas reservoirs with or without communication. The proposed BPE handles backflow between the layers through the wellbore for non-communicating layered systems, and accurately describes performance of wells experiencing differential depletion. The proposed multi-layer BPE has the same form as the familiar backpressure equation for single-layer gas reservoirs, where the correct averages are defined for reservoir pressure and backpressure constants. The BPE is validated against numerical simulation models, as well as field data which include decades of historical production performance and annual shut-in pressures. All numerical models and field data used to validate the BPE are publicly available. This paper gives guidelines on welltest design to quantify reservoir parameters in layered systems, based on systematic studies with numerical simulation models.
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)