Leslie G. Thompson

Well Testing for Radially Heterogeneous Reservoirs Under Single and Multiphase Flow Conditions

In this work, the authors examine the behavior of pressure-transient data for single and multiphase flow in radially heterogeneous reservoirs. To illustrate multiphase flow behavior in these systems, they focus on heterogeneous gas-condensate reservoirs; however, they also consider other multiphase flow problems. It is well known that in some instances, e.g., water injection/falloff in homogeneous reservoirs, pressure-transient data from buildup (or falloff) tests cannot be obtained by superposition of drawdown (injection) pressure responses. In fact, drawdown and buildup reflect properties in different regions of the reservoir. This behavior is common to most occurrences of multiphase reservoir flow and is exaggerated in the presence of radial heterogeneity. This theoretical work describes the information contained in transient pressure derivative data and explains the fundamental difference in behavior between multiphase drawdown and buildup pressure-transient data in radially heterogeneous reservoirs. The authors show that multiphase buildup data may be treated like single-phase buildup data, but drawdown data is most indicative of properties in that region of the reservoir where mobility is changing most rapidly with time.

Analysis of pressure buildup data influenced by wellbore phase redistribution

Using a theoretical model recently proposed by Fair, this work considers the influence of wellbore phase redistribution effects on the analysis of pressure buildup data. In the first major part of this work, the authors first show that the pressure responses, observed when phase redistribution effects exist, consist of three distinct types, and delineate the conditions under which each of these types exist. Second, they investigate the reliability of using Fairs type curves for analyzing pressure data. Third, for each of the three types of pressure responses, we provide rules for determining when the conventional semilog straight line will begin on a semilog plot of pressure data versus time. In the second major part of this work, they consider general procedures based on Duhamels principle for analyzing pressure data when sandface flow rates are also available. The application of these methods to analyze pressure data influenced by wellbore storage effects and investigate the effect that errors in the measured sandface rate have on the analysis is discussed.

Horizontal Well Productivity and Risk Assessment

A fast and accurate method was developed for predicting long term horizontal well performance. Heterogeneous, anisotropic geology close to the wellbore were considered in addition to pressure loss through the completion. Speed and accuracy were achieved by replacing the well and reservoir simulation with a semi-analytical network approach, and by upscaling reservoir properties for radial flow. Comparison to fine grid reservoir simulations verify that both total well productivity and flux profile along the well are maintained for the simplified approach. Computational efficiency and comprehensive treatment of the horizontal well problem make the method suitable for complete incorporation of uncertainties connected to the completion, the near wellbore geology and formation damage. The procedure was applied to illustrate how uncertainties in geology and completion efficiency affect the distribution of total well productivity for finite and infinite conductivity horizontal wells of different lengths. The method proved to be very efficient for this type of study, and indicated positively skewed (log-normal like) productivity distributions for short wells, normal distributions for long wells and a tendency for negative skewness of the productivity distribution from pressure loss in the wellbore.

Modeling of Flow in a Near-Wellbore Network

We consider steady-state multiphase flow in the near-well region of a completed horizontal well. The flow topography in this system is such that many alternate paths are available for fluid to travel from the reservoir to the producing vertical wellbore. Predicting and controlling this flow is essential to optimizing recovery from the reservoir. We treat the system as a pipe network. We decouple the mass conservation and pressure equations and solve for the phase splits at each junction in the network under the assumption that there is complete mixing at each branch point. Thus, the gas-liquid ratio (GLR) and water oil ratio (WOR) of each stream exiting a given network junction is constant and is determined by the quality of the streams entering the junction. (This assumption is reasonable since the flow paths in the “network” are short.) We use Newton iteration to solve the pressure equations. The resulting algorithm is fast and robust, so that it is well suited for coupling with a reservoir flow simulator. We illustrate the method by presenting an example.Copyright

Severe Slugging Attenuation for Deepwater Multiphase Pipeline and Riser Systems

Exploitation of offshore petroleum reservoirs has recently moved to ever-increasing water depths. Production from fields in water deeper than 1800 m is now a reality. The use of long deepwater risers that conduct production from multiple wellheads on the sea-floor to the surface predisposes the system to severe slugging in the riser for a wide range of flow rates and seabed topography. When one considers the length of the deepwater risers, the problem is expected to be more severe than in production systems installed in shallower waters. Severe slugging could occur at high pressure, with the magnitude of the pressure fluctuations so large as to cause a shorter natural flow period with subsequent consequences, such as premature field abandonment, loss of recoverable reserves, and earlier-than-planned deployment of boosting devices. In this study, a novel idea to lessen or eliminate severe slugging in pipeline/riser systems has been thoroughly investigated. This idea was first proposed by Barbuto 1 and later developed independently by Sarica and Tengesdal. 2 The principle of the technique is to transfer pipeline gas to the riser at a point above the riser base. The transfer process will reduce both the hydrostatic head in the riser and the pressure in the pipeline, consequently lessening or eliminating severe slugging by maintaining steady-state two-phase flow in the riser. An experimental study has been conducted with a 7.62-cm-inside-diameter (ID) riser (14.63 m high) and pipeline (19.81 m long) system. A broad range of data was collected from the facility in both the severe slugging and stable regions. It was found that the severe slugging models currently available do not predict the region accurately for larger-diameter pipes. Data acquired with the external gas bypass have proved the proposed elimination technique.

A Design Approach for a "Self-Lifting" Method To Eliminate Severe Slugging in Offshore Production Systems

Oil production from fields in water depths greater than 1800 m is a reality. The use of long deepwater risers that conduct production from multiple wellheads on the seafloor to the surface predisposes the system to severe slugging in the riser for a wide range of flow rates and seabed topography. Transferring the pipeline gas to the riser at a point above the riser base can reduce both the hydrostatic head in the riser and the pressure in the pipeline, consequently lessening or eliminating the severe slugging by maintaining the steady-state two-phase flow in the riser.