An experimental study of a gravity-driven downhole separator for a pumped horizontal or deviated well is presented in this study. It considers the effects of the upstream flow, gas and liquid flow rates and deviation angles on the global separation efficiency and the free gas at the pump intake. The efficacy of downhole separators is typically tested under steady-state conditions where the fluids are injected above the separator. A new outdoor facility, which allows the injection of a two-phase mixture below the separator was designed, constructed, and used in this study. Gas and liquid flow rates and deviation angle are varied to study the liquid holdup in the liquid-rich outlet and the separator efficiency. The experimental results demonstrate the effects of the operation conditions and deviation angle on the behavior of downhole separators. It is found that the separator has two regions of performance; namely, high efficiency region and a region where the efficiency decreases with the liquid flow rate. Moreover, the effect of the deviation angle affects the results. The findings provide conditions under which and where the separator can be operated efficiently in the field.
Onur, Mustafa (The University of Tulsa) | Galvao, Mauricio (Petrobras) | Bircan, Davut Erdem (The University of Tulsa) | Carvalho, Marcio (Pontifical Catholic University of Rio de Janeiro) | Barreto, Abelardo (Pontifical Catholic University of Rio de Janeiro)
The objectives of this study are to (i) provide analytical transient coupled wellbore/reservoir model to interpret/analyze transient temperature drawdown/buildup data acquired at both the producing horizon (sandface) and a gauge depth above the producing horizon (wellbore) and (ii) delineate the information content of both transient sandface and wellbore temperature measurements. The analytical models consider flow of a slightly compressible, single-phase fluid in a homogeneous infinite-acting reservoir system and provide temperature-transient data for drawdown and buildup tests produced at constant rate at any gauge location along the wellbore including the sandface. The production in the wellbore is assumed to be from inside the production casing. The models account for Joule-Thomson (J-T), adiabatic fluidexpansion, conduction and convection effects as well as nearby wellbore damage effects. The well/reservoir system considered is a fully penetrating vertical well in a two-zone radial composite reservoir system. The inner zone may represent a damaged (skin) zone, and the outer (non-skin) zone represents an infinitely extended reservoir. The analytical solutions for the sandface transient temperatures are obtained by solving the decoupled isothermal (pressure) diffusivity and temperature differential equations for the inner and outer zones with the Boltzmann transformation, and the coupled wellbore differential equation is solved by Laplace transformation. The developed solution compares well with the results of a rigorous thermal numerical simulator and determines the information content of the sandface and wellbore temperature data including skin zone effects. The analytical models can be used as forward models for estimating the parameters of interest by nonlinear regression built on any gradient-based estimation method such as the maximum likelihood estimation (MLE).
Atadeger, Aykut (The University of Tulsa) | Batur, Ela (The University of Tulsa and Turkish Petroleum Corporation) | Onur, Mustafa (The University of Tulsa) | Thompson, Leslie G. (Cimarex Energy Company)
In this study, we provide a detailed review and comparison of the various graphical methods, available in the literature, to interpret/analyze rate and pressure transient data acquired from multistage hydraulically fractured horizontal wells (MHFHWs) completed in unconventional gas reservoirs. The methods reviewed are based on transient matrix linear flow (
Sand transport in multiphase flow has recently gained keen attention of the oil and gas industry owing to the negative effects associated with it. These include partial pipe blockage, pipe corrosion, excessive pressure drop and production decline. To date, no comprehensive literature review and models evaluation have been published, which compare the experimental data collected for the prediction of the critical sand deposition velocity under intermittent flow with the related model predictions. This study can be used by engineers and researchers to determine the conditions under which the developed models perform the best.
The intermittent flow critical sand deposition velocity data acquired by
The experimental data of
System instability prediction is essential when designing a production system and/or providing operational adjustment to maintain a stable production. The conventional system Nodal Analysis articulates that the system is unstable to the left of the minimum of the Outflow Performance Relationship (OPR) curve where the well loads up. However, recent data shows that there are stable production points on the left of the minimum of the OPR curve, especially for low permeability shale plays. In this work, a new practical model is presented for both conventional and unconventional wells using Nodal Analysis with a novel approach.
The new approach is based on the derivative analysis of the inflow performance relationship (IPR) and OPR at a nodal point of the bottom hole. Perturbation analysis is used to facilitate the explanation of the new model. It shows that the system is stable when the absolute value of slopes or derivatives of the IPR is greater than that of OPR. To evaluate this concept, transient numerical simulations were conducted using a commercial transient simulator at various IPR conditions, including different permeabilities, for both vertical and horizontal wells. Meanwhile, the concept is also compared with available experimental and field data.
The transient simulation and the available data presented in this study demonstrate that there are stable production operating points on the left of the minimum of the OPR curve. The system stability also depends on the reservoir permeability, i.e., the flow rate corresponding to the onset of instability decreases with decreasing permeability. The new approach predicts this trend well. Overall, the new model matches well with observation from the experiments, field data, and the transient numerical simulations.
The paper provides analytical and semi-analytical solutions to predict the temperature transient behavior of a vertical well producing slightly compressible fluid under specified constant-bottom-hole pressure or rate in a two zone, radial composite no-flow reservoir system, where the inner zone could represent the skin zone, whereas the outer zone represents non-skin zone. The solutions are obtained by solving the decoupled isothermal diffusivity equation for pressure and thermal energy balance equation for temperature for the inner and outer zones by using the finite-difference and Laplace transformation. They be used to simulate temperature transient behavior for the general cases of specified variable bottom-hole or rate production represented by piecewise constants in specified time intervals. The convection, conduction, transient adiabatic expansion and Joule-Thomson heating effects are all considered in solving the temperature equation. Graphical analysis procedures for analyzing such temperature transient data jointly with pressure or rate transient data are also discussed. The results show that sandface temperature first decreases due to adiabatic expansion and then increases due to Joule-Thomson heating for both constant rate and constant bottomhole pressure production cases during infinite-acting flow. During boundary dominated flow, sandface temperature decreases linearly with time due to pore-volume expansion of the fluid over the entire no-flow reservoir system. The time rate of decline is governed by the ratio of the adiabatic-expansion coefficient of the fluid to the volumetric heat capacity of the saturated medium and the pore volume. However, these flow regimes are not well-defined for the constant bottomhole production case because the sandface rate decreases continuously during the infinite-acting radial flow and boundary dominated flow periods and distorts the flow regimes which are well defined on the temperature behavior if the well were produced at a constant rate. Sandface temperature data under specified variable rate or bottom-hole pressure show complicated behaviors and require more general automated history matching methods based on simultaneous use of both sandface temperature and rate transient data sets for parameter estimation.
Important decisions in the oil industry rely on reservoir simulation predictions. Unfortunately, most of the information available to build the necessary reservoir simulation models are uncertain, and one must quantify how this uncertainty propagates to the reservoir predictions. Recently, ensemble methods based on the Kalman filter have become very popular due to its relatively easy implementation and computational efficiency. However, ensemble methods based on the Kalman filter are developed based on an assumption of a linear relationship between reservoir parameters and reservoir simulation predictions as well as the assumption that the reservoir parameters follows a Gaussian distribution, and these assumptions do not hold for most practical applications. When these assumptions do not hold, ensemble methods only provide a rough approximation of the posterior probability density functions (pdf's) for model parameters and predictions of future reservoir performance. However, in cases where the posterior pdf for the reservoir model parameters conditioned to dynamic observed data can be constructed from Bayes' theorem, uncertainty quantification can be accomplished by sampling the posterior pdf. The Markov chain Monte Carlos (MCMC) method provides the means to sample the posterior pdf, although with an extremely high computational cost because, for each new state proposed in the Markov chain, the evaluation of the acceptance probability requires one reservoir simulation run. The primary objective of this work is to obtain a reliable least-squares support vector regression (LS-SVR) proxy to replace the reservoir simulator as the forward model when MCMC is used for sampling the posterior pdf of reservoir model parameters in order to characterize the uncertainty in reservoir parameters and future reservoir performance predictions using a practically feasible number of reservoir simulation runs. Application of LS-SVR to history-matching is also investigated.
An Electric Submersible Pump (ESP) is studied experimentally with oil-water emulsion. Emulsion rheology inside the ESP is also studied and modeled at different oil and water fractions, ESP rotational speeds and temperatures, using a dimensional analysis on a set of parameters contributing to the emulsion rheology. Density and mass flowrate are measured using the mass flowmeter, while the emulsion effective viscosity is initially derived from the pipe viscometer (PV) installed downstream of the ESP. Effective viscosity values at the stage condition are corrected using an oil of known viscosity by correlating its viscosity to ESP average temperature. Watercut at the inversion point increases in case of contamination presence which directly affects the interfacial tension.
Modeled effective viscosity values for emulsion with medium viscosity are within 5% deviation from the experimental values. However, when low oil viscosity is used, the deviation becomes larger, mainly due to the instability of the emulsion which leads to inaccurate measurement of the effective viscosity at the PV. Instability is confirmed from the PV results, density measurements and visual observation through the transparent pipe or during sampling.
Further improvement of the model is needed by changing the parameters in a wider range, and possibly by including non-considered parameters such as salinity. Most of the parameters affecting the emulsion rheology are combined in one term which can be considered as a factor that corrects the effective viscosity of the emulsion.
This paper studies the effects of system pressure in oil-gas low-liquid loading flow in a slightly upward inclined pipe configuration using new experimental data acquired in a high-pressure flow loop. Flow rates are representative of the flow in wet gas transport pipelines. Results for flow pattern observations, pressure gradient, liquid holdup and interfacial roughness measurements are presented and compared to available predictive models. The experiments were carried out at three system pressures (1.48, 2.17 and 2.86 MPa) in a 0.155 m ID pipe inclined at 2° with the horizontal. Isopar-L oil and nitrogen gas were the working fluids. Liquid superficial velocities ranged from 0.01 to 0.05 m/s while gas superficial velocities ranged from 1.5 to 16 m/s. Measurements included pressure gradient and liquid holdup. Flow visualization and Wire-Mesh Sensor (WMS) data were used to identify the flow patterns. Interfacial roughness was obtained from the WMS data.
Three flow patterns were observed: pseudo-slug, stratified and annular. Pseudo-slug is characterized as an intermittent flow where the liquid does not occupy the whole pipe cross-section as the traditional slug flow does. In the annular flow pattern, the bulk of the liquid was observed to flow at the pipe bottom in a stratified configuration, however, a thin liquid film covered the whole pipe circumference. In both stratified and annular flow patterns, the interface between the gas core and the bottom liquid film presented a flat shape. The superficial gas Froude number, Fr
Zhong, Huiying (Northeast Petroleum University) | Yang, Tingbao (Northeast Petroleum University) | Yin, Hongjun (Northeast Petroleum University) | Fu, Chunquan (Northeast Petroleum University) | Lu, Jun (The University of Tulsa)
Chemical combination flooding technique especially alkali/surfactant/polymer (ASP) flooding has proven to be an indispensable way to enhance oil recovery (EOR). The progress of this flooding technique in Daqing Oilfield (China) shows that it is promising to keep production from falling and help oil companies make profit in a low-oil-price era. However, the ASP chemicals chromatographic separation and loss in sandstone formation are still the weaknesses in the promotion of ASP flooding.
Laboratory investigations for characterizing the behavior and distinction of chemicals loss in sandstone reservoir with strong base (NaOH) and weak base (Na2CO3) ASP flooding were recently carried out. The experiments were designed to pointedly study the chromatographic separation, and consumption loss behaviors of alkali and surfactant in sandstone reservoirs with ASP flooding. Furthermore, the incremental oil recovery factor in heterogeneous sandstone reservoirs with strong base (NaOH) and weak base (Na2CO3) ASP flooding process was evaluated and compared. The loss rates of chemicals and the permeability damage degree in various experiments were determined respectively, the consumption loss mechanism and influencing factors were discussed, and the formulation composition and slug combination patterns were also optimized. Then, the role of ASP chemicals loss in sandstone formation during ASP combination flooding EOR process was worked out.
The results indicated that the chemicals loss behaviors could be weakened and the chemicals chromatographic separation phenomenon could be alleviated in weak base (Na2CO3) ASP flooding, and the average loss rate of alkali and surfactant could drop 9.61% and 15.67% respectively in heterogeneous sandstone reservoirs comparing to strong base (NaOH) ASP flooding. The profitable EOR effect could also be obtained with weak base (Na2CO3) ASP flooding, and the enhanced oil recovery could still reach 20% or more. Moreover, an approximately 15% reduction in permeability damage rate could be realized in the weak base (Na2CO3) ASP flooding instead of strong base (NaOH) system, and the reservoir flow assurance issues related to chemicals loss behaviors could be addressed. The optimal design of ASP formulation and slug combination pattern could technically and economically achieve high oil recovery in sandstone reservoirs with weak base (Na2CO3) ASP flooding.
The results are beneficial to well understand the chemical combination flooding mechanism and can contribute to the existing knowledge in the chemicals super additive effects during EOR process, and it is also significant to further improve the oil displacement efficiency and reduce the injection cost in heterogeneous sandstone reservoirs with weak base (Na2CO3) ASP flooding process.