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A wellhead choke controls the surface pressure and production rate from a well. Chokes usually are selected so that fluctuations in the line pressure downstream of the choke have no effect on the production rate. This requires that flow through the choke be at critical flow conditions. Under critical flow conditions, the flow rate is a function of the upstream or tubing pressure only. For this condition to occur, the downstream pressure must be approximately 0.55 or less of the tubing pressure.
Yusuf, Yishak (RGL Reservoir Management Inc, University of Alberta) | Roostaei, Morteza (RGL Reservoir Management Inc.) | Soroush, Mohammad (RGL Reservoir Management Inc.) | Rosi, Giuseppe (RGL Reservoir Management Inc.) | Berner, Kelly (RGL Reservoir Management Inc.) | Tegegne, Nathan (RGL Reservoir Management Inc.) | Mohammadtabar, Farshad (RGL Reservoir Management Inc.) | Izadi, Hossein (RGL Reservoir Management Inc. University of Alberta) | Zhu, Da (RGL Reservoir Management Inc.) | Mahmoudi, Mahdi (RGL Reservoir Management Inc.) | Fattahpour, Vahidoddin (RGL Reservoir Management Inc.) | Nobes, David S. (University of Alberta)
ABSTRACT The design of Flow Control Devices (FCDs) requires performance data of an FCD’s internal nozzle under a wide range of flow scenarios. The current study specifically considers the effect of nozzle diameter and wall profile on the induced pressure loss, and subsequently the recovery performance of an FCD. For this study, a flow measurement facility is developed to test the performance of different orifice/nozzle geometries. The flow of single- and two-phase fluid at various flow rates and mass fractions, is experimented. The pressure drop data from the experiments is used to produce performance curves that characterize pressure loss across the geometries. The pressure loss for two-phase flows are compared to their single-phase counterparts to characterize the performance of the tested geometries in the two scenarios. A detailed protocol for performance testing of FCDs is followed as per Advanced Well Equipment Standard (AWES: recommended practice3362). The testing protocol was utilized to characterize the performance of different FCDs geometries under single- and two-phase flow conditions. The results showed the pressure loss characteristic obtained from the flow loop experiments match the corresponding theories. The study has thus provided promising results for the successful application of direct flow loop testing to obtain reliable data which can be used in FCD design, performance investigation, and reservoir simulation.
Karam, Stéphanie (National Petroleum Construction Company) | Valand, Bhavesh N. (National Petroleum Construction Company) | Aggarwal, Rajdeep (National Petroleum Construction Company) | Singh, Harendra (National Petroleum Construction Company) | Kamal, Faris (National Petroleum Construction Company) | Takieddine, Oussama H. (National Petroleum Construction Company)
Liquid Product Recovery is an important metric to assess the quality of Gas and Oil Separation plant design and is required to be achieved at minimum CAPEX & OPEX to improve the overall economics. This paper presents a structured approach for an optimal solution to minimize loss of valuable components to the gas phase, thereby maximizing liquid recovery.
Ideal Liquid Recovery is defined as the theoretical maximum liquid recovery possible by successively separating the lightest components from the well-fluid until the crude oil specifications are met, i.e. separating all the Methane (C1) and Ethane (C2), just the right proportion of Water, Propane (C3) and H2S to meet the specifications. In real life separation systems, however, such sharp separation is unachievable, i.e. some amount of intermediate and heavier components are likely to migrate to the gas phase and some of the lighter components may end up in the liquid phase. Accordingly, %Liquid Recovery is defined as:
Oil and gas production is a complex process wherein many equipment and systems are closely coupled and interdependent. The art of designing an optimal process for Gas and Oil Separation plants lies in rigorous selection of appropriate process configurations and operating conditions. The design largely depends on several factors such as fluid compositions and properties, product specifications, etc. There is no single configuration or set of process conditions that can be the solution under all scenarios; thus each case requires to be analyzed independently.
This paper uses a structured approach to evaluate the impact of each parameter individually as well as collectively, to select the optimum process configuration for separation and stabilization of the crude oil. A Gas and Oil Separation plant with multiple stages and a stabilizer column is used to demonstrate that the liquid recovery for a specific well-fluid composition can be maximized by varying separator operating conditions, column operating parameters and process configurations. The focus of the paper is on the ‘Design Process’ to achieve and assure an optimal design as well as understand its limitations.
The suggested design approach demonstrates that liquid recovery values in excess of 95% can be achieved in comparison to typical liquid recovery values of around 93% for low GOR oil production plants. Even two percent increase in liquid recovery is quite significant, as on a 100,000 STBOPD plant it translates to 2,000 STBOPD production gain which is equivalent to more than US$ 33 million per year in additional revenue at crude oil price of US$ 50/bbl. This should be read with a caveat that incremental absolute revenue will be lower in a smaller capacity unit and hence, additional CAPEX, if any, should be evaluated accordingly. Higher liquid recovery also contributes to improvement in API gravity of the crude, and thus further adds to its value.
Nader, Lukas (Upwing Energy) | Biddick, David (Upwing Energy) | Artinian, Herman (Upwing Energy) | Kulkarni, Pandurang (Equinor) | Van Hoy, Bob (Riverside Petroleum) | Zdan, Steve (Riverside Petroleum)
Unconventional oil and gas development revolutionized the energy sector in North America and has been transforming the world's energy markets. Notwithstanding the enormous potential, unconventional resource development presents unique challenges to production and long-term hydrocarbon recoveries. As market dynamics are shifting, technologies are advancing, opening up new opportunities in areas once considered out of reach. This paper describes a new technology, a subsurface compressor system, which simultaneously removes liquids, increases gas production, and improves recoverable reserves in gas wells. The subsurface compressor can reverse the vicious cycle of liquid loading, which decreases gas production from a gas well and leads to premature abandonment, by creating a virtuous cycle of increased gas and condensate production. The complete process from well analysis, performance projection, deployment, commissioning to operation are discussed. A recently completed the world's very first field trial in an unconventional shale gas well supports the mechanism of subsurface gas compression and its impacts and benefits on unconventional gas production.
This page provides an overview of the primary categories of natural gas compressor services and a description of the different classifications and types of compressors available to the industry. Adiabatic and polytropic compression theory are discussed with supporting definition of terminology. Major components and construction features of centrifugal and reciprocating compressors are emphasized. Installation, safety, and maintenance considerations also are discussed in their erspective pages. Compressors used in the oil and gas industry are divided into six groups according to their intended service.
Downhole gas compression (DHGC) in gas wells is a relatively new concept in production engineering, but it represents one of the most promising technologies to revive dead wells, to boost gas production and to maximize total gas production recovery. This technology could be analogous to electrical submersible pumps (ESPs) for oil wells, as it increases well production by reducing the back pressure at the wellbore sand face; this is achieved by providing boosting pressure to cover for outflow pressure requirements (i.e. tubing losses and well head backpressure). However, downhole wet gas compression applications are considerably more challenging than those for ESPs. The purpose of this paper is to describe step by step the procedures and workflows to evaluate downhole gas compression applications, from information preparation, to multiphase flow calculations and sensitivity analyses.
The applications of this technology are more complex than conventional pumping methods for oil wells. Calculations are more involved with considerations for gas compressibility, multiple flow regimes, liquid volume fraction at compressor intake, compressor pressure ratio requirements, liquid loading conditions, discharge pressure and discharge temperature, among other effects, which are some of the main factors to be measured for this type of application.
There is no standard methodology in the oil industry for gas well modeling and sensitivity analysis for DHGC applications. Just few publications can be found in the literature with some description of the evaluation process but missing some other relevant aspects of the application. This paper presents a systematic process to evaluate applications of DHGC including well performance modeling and compressor simulations.
A new comprehensive methodology has been used for downhole compression application in this study, using nodal analysis software for well performance modeling in combination with a process system simulator to model compressor performance.
Summary The objective of this paper is to present the development and application of a simple equation for calculating the asymmetric growth of the stimulated reservoir volume (SRV) in an anisotropic shale–petroleum reservoir using microseismic data, and the hydraulic diffusivities of the anisotropic shale. Calculation of the SRV is a problem tackled with solutions that involve different degrees of complexity. Because shale reservoirs are anisotropic, microseismic events generally develop 3D nonuniform asymmetric patterns around the injection points. This paper presents a new method with an easy–to–use analytic equation that allows for reproducing the asymmetric growth of microseismic events as a function of time by considering reservoir anisotropy. Asymmetric growth refers to the fact that propagation of the microseismic cloud in a given direction can be larger, equal, or smaller compared with the propagation in other directions. Accurate determination of the SRV asymmetric pattern is critical for use in specialized material–balance and reservoir–simulation models of shale–petroleum reservoirs. This determination allows for more–realistic projections of reservoir performance. The novelty of the method is the development of an easy–to–use approach for estimating SRV in a spatially nonuniform asymmetric anisotropic reservoir using octants in a coordinate system. The SRV is calculated from the volume of a symmetric ellipsoid divided by a constant value Vc. This is despite the fact that the point of injection of the fracturing fluids in the asymmetric reservoir can be at, close to, or far from the center of the ellipsoid. The development of Vc is presented in this paper. Use of the SRV calculation model is illustrated with real microseismic data of the Horn River Shale in Canada for a case where Vc is equal to 1.3722. Also presented are calculations of hydraulic diffusivities in this anisotropic shale.
The objective of this paper is to present the development and application of a simple equation for calculating the asymmetric growth of the stimulated reservoir volume (SRV) in an anisotropic shale-petroleum reservoir using microseismic data, and the hydraulic diffusivities of the anisotropic shale.
Calculation of the SRV is a problem tackled with solutions that involve different degrees of complexity. Because shale reservoirs are anisotropic, microseismic events generally develop 3D nonuniform asymmetric patterns around the injection points. This paper presents a new method with an easy-to-use analytic equation that allows for reproducing the asymmetric growth of microseismic events as a function of time by considering reservoir anisotropy.
Asymmetric growth refers to the fact that propagation of the microseismic cloud in a given direction can be larger, equal, or smaller compared with the propagation in other directions. Accurate determination of the SRV asymmetric pattern is critical for use in specialized material-balance and reservoir-simulation models of shale-petroleum reservoirs. This determination allows for morerealistic projections of reservoir performance.
The novelty of the method is the development of an easy-to-use approach for estimating SRV in a spatially nonuniform asymmetric anisotropic reservoir using octants in a coordinate system. The SRV is calculated from the volume of a symmetric ellipsoid divided by a constant value Vc. This is despite the fact that the point of injection of the fracturing fluids in the asymmetric reservoir can be at, close to, or far from the center of the ellipsoid. The development of Vc is presented in this paper. Use of the SRV calculation model is illustrated with real microseismic data of the Horn River Shale in Canada for a case where Vc is equal to 1.3722. Also presented are calculations of hydraulic diffusivities in this anisotropic shale.
Abstract Vertical upward multiphase flow through a blowout preventer (BOP) during a gas kick event produces complex fluid flow transients. Further complicating these transients is the fluid phase interactions during BOP closing event. The resultant pressure and flowrate transients are critical parameters that influence the BOP design and should be used to estimate if the BOP can close-on/control a kick event. In this paper, a hydro-mechanical two-phase flow model is developed to predict the fluid pressure and flowrate conditions for fully open and closing BOP during a gas kick. The case of a 20,000 psi reservoir is investigated along with a wel depth, from the rig floor to the borehole, ranging from 10,000 ft to 20,000 ft. The results illuminate the dependence of model-based BOP pressure rated design on the formation productivity index during a gas kick event. Furthermore, using a model-based approach for determining such information is essential in the development of next generation pressure control equipment standards and equipment certification, risk minimization to drilling crew and rig assets and reduction of well intervention frequency. High pressure definition based on pore pressure and/or BOP rated working pressure are discussed as well.
Liquefaction assessment of sand in sequenced earthquake motions was studied based on two series of stress-controlled, undrained hollow cylinder cyclic torsional shear tests. A high risk of liquefaction is expected under such conditions because of the accumulation of excess pore pressure by multiple seismic motions. The specimen with the residual excess pore pressure was exposed to various aftershocks that are (i) staged wave loading and (ii) irregular wave loadings with various waveforms and durations. The results of two loading tests are combined to draw a chart that tells the possibility of liquefaction depending on the level of the excess pore pressure remaining in the ground.