The goal of this paper is to present the philosophies for the qualification and flow loop testing of FCD nozzles as well as the macroscopic implementation and operations of FCDs in SAGD producer wells. A quantitative methodology to evaluate FCD nozzles to choke back steam will be presented. Flow loop testing data will be shown to illustrate the qualification process. We will also discuss if sand control screens should be put on the tubing deployed inflow control devices. Some modeling and field examples will be shown. In the end, field data of the SAGD producer wells installed with the FCDs will be presented. Experience to manage and operate the wells will be shared.
Performance comparisons of different tier friction reducers (FRs) using field water samples from the Delaware and Midland basins within the Permian Basin are discussed. The objective is to correlate them with their respective water mineralogy to identify the primary components affecting FR effectiveness, allowing a proper FR selection based on individual elements and not just by total dissolved solids (TDS). Identifying critical minerals that affect the proper FR selection enables making an educated FR selection not based on TDS count alone, which could potentially reduce the amount of testing and unsuccessful field trials. To zero in on the primary elements within the water that affect friction reduction behavior, extensive testing was performed. Traditional and inductive couple plasma (ICP) water analyses were performed to determine mineralogy, and flow loop testing was performed to determine FR performance. Additionally, specific parameters (i.e., hydration time, maximum FR percentage, and stability) were measured and compared to the multiple tests to determine trends between FR performance and water mineralogy. Understanding how a flow loop apparatus works is discussed, which helps when interpreting friction reduction performance. This is a fundamental component for understanding the behavior of the FR during testing and how it affects performance in the field. Additionally, this paper can be used as a basic guide for flow loop interpretation, and it attempts to identify possible causes of varying FR behavior in the field versus laboratory testing.
The Smart Autonomous Inflow Control Valve (S-AICV) technology is presented. This smart well sensor will prevent water and gas breakthrough and at the same time operate as a multiphase flow meter. The single compact system can be used in both mature and new field to map fluid flows along the well in oil reservoirs and at the same time autonomously controlling the production of unwanted fluid in the individual zones. This will provide the oil companies with detailed reservoir conditions data to have a better understanding of well production and drainage, and hence optimize future AICV well installations.
A multiphase flow model is developed which correlate the three pressures located inside the S-AICV (P1, P2 and P3) to flow rates of gas, water and oil going through the valve. At breakthrough of gas and/or water the S-AICV will detect pressure changes when the fluid composition changes. This model utilizes this pressure changes to distinguish between the different fluids and determine the flow rate and composition of inflowing fluid. The S-AICV application is designed for each specific field to achieve the desired functionality, and the user input parameters for this model need to be determined and individually adjusted accordingly to the fluid properties and the configuration of the valve.
This smart well sensor will extract data from the well and transfer the data to the surface via an optical fiber. The multiphase flow model will convert the signals to flow rates and composition, without compromising the autonomous and reliable AICV to meet the oil industry needs.
Existing measurement systems as tracers or various production logging tool are costly and complex. Separate multiphase flow meters can be installed in addition to the AICVs, but this is an expensive solution where only a fraction of the data can be gathered. The benefits of the S-AICV system are its ability to prevent water and gas production and at the same time continuously measure the flow rate and composition to register breakthrough within a low-cost package with maximizing data gathering.
Hussein, Ahmed (Exprogroup) | Alqassab, Mohammed (Exprogroup) | Atef, Hazem (Exprogroup) | Sirdhar, Siddesh (Exprogroup) | Alajmi, Salem Abdullah (KOC) | Aldeyain, Khaled Waleed (KOC) | Hassan, Mohamed Farouk (KOC) | Goel, Harrish Kumar (KOC)
Umm Gudair (UG) field is one of the major oil fields of West Kuwait asset. Wells are tested periodically using multiple conventional test separators and data is subsequently used to update Well Performance "Nodal analysis" and "Live Flow Line Surface Network Model".
A different approach was tested in 2018 for a mature oil field in the Middle East to evaluate the effectiveness of Clamp-On based SONAR Flow Surveillance solution against existing conventional portable test separator. The objective was to check the performance of the SONAR Flow Surveillance on black oil wells at different flowing conditions, and ultimately implement a new approach to increase the testing frequency, reduce any potential of hydrocarbon release, avoid well shutdown, optimize operating costs, and production optimization.
The SONAR Surveillance approach is based on SONAR clamp-on flow meters deployed in conjunction with compositional (PVT) and multiphase flow models for oil and gas wells to interpret the measurements of the SONAR flow meters at line conditions (pressure, temperature, fluid stream composition), and output the gas, oil and water phase flow rates at both actual and standard conditions. The SONAR meter measures the bulk flow velocity (at line conditions), then a flow computer determines the individual phase volume fractions at actual conditions using a PVT model and water-cut. This provides a measure of the oil rate at actual conditions. A shrinkage factor calculated by the black oil model is applied to report oil rate at standard conditions. Gas and water are also inferred in a similar manner. The gas, oil and water flow rates thus determined at actual conditions are further processed and converted to standard conditions as well.
The field tests showed that the SONAR Flow Surveillance approach allowed more flexibility in terms of field installation and the measurements are made at actual production conditions unlike other devices that may introduce additional flow restrictions. The SONAR meters diagnostics also provided a more realistic representation of the well flow profile since the measurements are instantaneous versus the "averaging" effects observed when using gravity-based separators. This allows better production surveillance and understanding of changes in well behavior.
Oil flow rate testing is a crucial concept in oil fields where several methods facilitate well rate testing and measurement. Hundreds of multiphase flow meters (MPFMs) have been utilized to enhance the accuracy of testing measurement and provide reliable data for all fields. Even though these meters are of paramount importance, they require frequent preventive maintenance, calibration and manpower. In this paper, an Artificial Neural Network (ANN) model is developed as a backup tool to replace MPFM measurements when the device becomes defective or inoperable.
Several correlations have been established to facilitate oil well testing at minimal cost; relying on surface production parameters to allow enumerating the oil flow rate without installing expensive equipment. An ANN model was developed using real-time wellhead parameters measured from equipment installed at the surface to designate properties and characteristics per reservoir. The ANN model was calibrated, tested and validated to achieve the most accurate results. The model was further optimized to attain a reliable tool for real-time rate estimation.
In this paper, assessment of various correlations was conducted to compare the accuracy of each ANN-related empirical equation in five different datasets. The assessment also covers a wide range of data. More than thousands of data points from MPFM were compared to Towailib, Marhoun and Gilbert correlations, and showed highly deviated values with an average relative error of more than 40%. The same sets of data were tested using the newly developed optimized ANN model. The results from the model resulted in an average relative error of 3.7% compared with the MPFM rate measurements. Therefore, the new ANN model presented in this paper shows highly accurate results.
The developed model contributed to enhancing testing efficiency and optimizing production. Indeed, utilizing this model is an essential practice for production engineers to validate well tests if prompt outcomes are desired and another reliable tool to estimate real-time rate production when metering device is down.
In today's oil and gas industry, the importance of accurate measurement of wet gas flows has become paramount due to the recent growth in production costs and continuous fluctuation in crude oil prices. Typical wet gas applications have Gas Volume Fraction (GVF) ranging from 95 to 100 percent and hence the accurate measurement of the phase fractions, especially the water fraction at such low liquid flowrate is a serious challenge. Standard multiphase flow meters were found to be inadequate to operate in such conditions. Hence significant effort is taken by several manufacturers into research and development of'wet gas' flow meters which can accurately measure the three-phase flowrates. Taking on the challenge, an inline non-nuclear wet gas metering system was field tested in Argentina to measure the three-phase flow rates under existing field operating conditions and the results were compared to an existing conventional test separator readings to find out if it can serve as a reliable replacement to the expensive test separator.
Devarajan, Umakanth (National Petroleum Construction Company) | Chandrasekaran, Jagadesh (National Petroleum Construction Company) | Paul, Raju (National Petroleum Construction Company) | R. Kamal, Faris (National Petroleum Construction Company) | Takieddine, Oussama (National Petroleum Construction Company)
The Design, Installation, commissioning and handover of Custody metering system is very very critical for any project completion. This paper addresses major challenges and the corresponding mitigation methodologies in the design of a custody metering system in an unstabilized crude application in recent Buhasser FFD project. Custody meter is provided for measuring the Oil production from Bu Haseer Production Separator in Zakum plant at Das Island. The Custody meter is fiscal type and designed as a packaged unit. Custody meter package consist of one working, one standby arrangement and one common pipe proving system.
The continually evolving water management practices of liquids-rich tight oil operators (for optimizing the water use and costs of their water life cycle) is a topic of major impact. One area during the produced water phase of the water life cycle, is the less understood effect of different water cut fractions of the total fluids production from the formation on both the producing three-phase flow rate trends on surface as well as the downhole multiphase flow conditions, in particular, lateral to bend slugging and loading tendencies. This paper quantifies this effect of varying water cut production in a variety of operational conditions. In order to quantify the effect of varying water cut production, the methodology of this work involves first understanding the basic differences between gas-and-water (100 % water cut) and gas-and-oil (0% water cut) multiphase production in terms of their averaged slip behaviors, and therefore, total pressure gradient observations. We utilize published lab-scale flow loop experiments and a few actual, field-scale wells to demonstrate the different reported behaviors. An analytical multiphase flow simulator is then validated against these observations. Once verified, we then use the simulation tool to perform downhole calculations of flowing bottomhole pressure, gas volume fraction (gas-liquids slip), wellbore flow pattern, difference in wellbore and critical gas velocities and slugging flow characteristics (slugging frequency, velocity and lengths) for a given set of surface operating conditions. The workflows presented in this work will enable a deeper insight into the differences between gas and liquids slip under varying water cut fractions in both lighter condensate fluids as well as denser black oil fluids production. This work adds an improved understanding of the effect of water cut fractions on the total pressure gradient behaviors and downhole multiphase flow slugging and loading behaviors in liquids-rich tight oil developments.
Unconventional reservoirs, characterized by their ultra-low permeability and porosity, have complicated production mechanisms yet to be fully understood. Gas produced from unconventional oil reservoirs are majorly classified as the secondary product, with the focus on oil. However, gas plays a vital role in the production of oil from unconventional plays and can be economically beneficial as well. Therefore, while oil production forecasting is highly important, it is equally imperative to figure out ways in which solution gas production can be forecasted. There has been very little information in the literature about forecasting solution gas production. The huge question is - can we possibly forecast gas-oil ratios and ultimately, solution gas production? And if we can, can we do that with some reasonable level of certainty? This paper attempts to answer these questions by exploring the use of an Asymmetrical Sigmoid Model (ASM) to forecast gas-oil ratios (GOR) and solution gas production.
Asymmetrical sigmoid functions have been applied in several fields of study such as biology, finance, agriculture, etc. Research into the possibility of employing the use of this type of function for predicting future GOR values, arose from studies and observation of the nature of GOR profiles of wells in unconventional oil reservoirs. This paper presents a new approach to forecasting gas-oil ratios and solution gas production - the Asymmetrical Sigmoid Model (ASM).
A commercial compositional reservoir simulator was used to simulate 30 years of production from multi-fractured horizontal wells (MFHW) with different reservoir fluids. Further, ASM was used to forecast producing gas-oil ratios from the wells with production histories ranging from six months to 3 years. The results were compared to simulated GOR data. Solution gas production were then calculated from the estimated producing gas-oil ratios using the trapezoidal rule and compared to simulated solution gas production data as well. This methodology was similarly applied to field data from various wells in different shale oil reservoirs and the results were compared to the available historical field data.
In recent years, factors such as limited production data, complex flow mechanisms of liquid-rich shale reservoirs, production pattern of producing gas-oil ratios among others, have made the task of forecasting GOR and solution gas production difficult. However, ASM enables us to have a simple functional approach that empiricallymimicsthe basic pattern of producing GOR profiles in unconventional oil reservoirs quite well. ASM also helps to forecast gas-oil ratios and solution gas production with reasonable measures of accuracy. After the application of ASM to available historical data, and comparing the results with simulated and field data, there were relatively low error percentages in majority of the cases considered.
Due to the continuous rise in global demand for energy, and its corresponding economic implications, the importance of research focused on improving and finding new ways of accurately forecasting oil and gas production cannot be downplayed. This work presents aninnovative and easyway offorecasting gas-oil ratios and solution gas production from unconventional oil plays. It is a valuable contribution to the ongoing efforts of research into better and simpler ways of forecasting production from unconventional reservoirs. Findings from this work can help to improve reserves estimation, reservoir management, field development planning and overall project economics.
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.