The Multilayer Transient Test is a well-testing technique designed to determine formation properties in multiple layers, and it has been proved effective during the past two decades. To apply the Multilayer Transient Test, a combination of rate profiles from production logs and transient rate and pressure measurements are required at multiple surface rates. Therefore, this method can be time consuming and may involve significant The inverse model is formulated by incorporating the forward model to solve formation properties using nonlinear least-square regression. For the hypothetical cases, the proposed new multilayer testing method has successfully been applied for investigating formation properties in commingled multilayer reservoirs. Layer iv permeability, damaged permeability, and damaged radius can be uniquely determined using single-point transient pressure data and multipoint transient temperature data at appropriate locations. Due to the proposed data acquisition scheme, only one surface flow rate change is needed to implement this testing approach, which significantly reduces the test duration compared to the standard multilayer transient testing approach using a series of flow rate changes. Of special interest, this is the first test design that shows promise for determination of the damaged radius, which can be useful for well stimulation design. In addition, temperature resolution, data noise, and data rate impacts have been studied along with a data filtering approach that enable selection of suitable pressure and temperature sensor technologies for applying the new testing method.
Multilayer transient testing is designed for determining individual layer properties (permeability and skin) for multiple layers commingled in a well. Traditional multilayer transient testing requires a combination of rate profiles from production log and transient rate and pressure measurements acquired at multiple surface rates. This method can be time consuming and may involve significant errors depending on the accuracy of the transient flow rate measurements. Today, many wells are equipped with downhole sensors that provide distributed or multipoint temperature measurements along the wellbore. Using these data to determine formation properties can minimize time and disturbances in well production. This paper presents a forward model to investigate the possibility of evaluating formation properties from transient temperature and pressure measurements. The model couples wellbore and reservoir models for simulating transient temperature and pressure for single-phase flow. The wellbore model was developed based on mass, momentum, and energy balance. The reservoir model consists of a reservoir thermal model and a pressure/flow-rate transient model. Besides heat conduction and convection, it considers viscous heating and temperature variation due to fluid and rock expansion/compression. Wellbore and reservoir models are solved numerically to predict transient temperature and pressure behavior. Comprehensive experiments reveal the sensitivities of transient temperature to individual layer permeability and skin values in multilayer systems. The results indicate that there are two main mechanisms governing wellbore transient temperature behavior; formation heating/cooling and wellbore fluid mixing at entry points, and that permeability and skin affect transient temperature and pressure differently. Examples in the paper show that the transient temperature response can distinguish between low permeability and high skin factor as reasons for low productivity in any layer. Additionally, this work revealed that the transient temperature behavior is sensitive to the radius of the damaged zone, suggesting for the first time a mechanism to quantify the damaged radius. The observations show promise of using transient temperature and pressure to determine multilayer formation properties. Introduction Multilayer formation properties are necessary information for reservoir development. Distinct layers in multilayer reservoirs usually have different thickness, porosity, permeability, and skin factor that tend to cause differential depletion during reservoir development. Therefore, multilayer reservoir characterization has been attracting interest for many years. Since the first rigorous mathematical model derived by Lefkovits in 1961, there have been numerous studies of the behavior of multilayer reservoirs. A complete literature review of the analytical model developed between the 1960s and the 1980s can be found in Ehlig-Economides (1987a). This study showed that individual layer properties in multilayer reservoirs cannot be determined from conventional drawdown or buildup tests. Kuchuk et al. (1986) introduced a quantitative modeling and testing technique combining stabilized rate profiles with transient rate and pressure measurements described briefly in Ehlig-Economides (1987b) as "layered reservoir testing". The layered reservoir testing" models have been enhanced by some authors (Kuchuk et al., 1991; Spath, 1994; Larsen, 1999; Prats, 1999), and the testing method has proven effective during the past two decades. However, a series of step-wise surface rate changes are still required during the test, with the production logging tool stationed above each layer to be characterized to record the transient rate variations during each rate step. This method is time consuming and may involve significant errors depending on the accuracy of the transient flow rate measurements.
As the consumption of oil and gas resources is increasing, secondary exploitation in old wells and unconventional oil and gas exploitation methods are becoming increasingly important. As a result of complex reservoir environments and the reservoir properties, such as ultralow porosity and permeability, hydraulic fracturing is an important means to achieve effective recovery. Temporary plugging fracturing is currently an efficient fracturing technology and is suitable for refracturing of old wells and multi-stage fracturing in unconventional reservoirs, which is conducive to constructing complex fracture networks and increasing production. Recently, in the field of temporary plugging fracturing, how to design the operation parameters of temporary plugging fracturing still remains ambiguous and empirical. In this paper, a numerical simulation study of the liquid–solid two-phase flow of the temporary plugging agents and the fracturing fluid was conducted using two physical models: a wellbore flow model and a wellbore–fracture temporary plugging model. The transport processes of the temporary plugging agents along with fracturing fluid in a vertical wellbore, in a horizontal wellbore, and at a fracture position were simulated. Simulations that coupled computational fluid dynamics and the discrete element method were used in the simulation process. The effects of the temporary plugging agent concentration, particle size, particle size ratio, fracturing fluid rate, and fracturing fluid viscosity on the migration process of the temporary plugging agent were investigated. The simulation results show that a higher concentration and viscosity of a temporary plugging agent help to sustain the flow stability in the vertical wellbore, while the viscosity and flow rate of the fracturing fluid have an impact on whether sedimentation of the temporary plugging agent occurred in the horizontal wellbore. In addition, the particle size ratio and concentration of the temporary plugging agent are the key factors for a successful bridging and plugging. For a specific field application in Longmaxi Formation, Sichuan Province, the operation parameters of temporary plugging fracturing have been designed and achieved a successful refracturing treatment.
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