This paper describes an approach to design the well clean-up operations by modelling the process with transient simulator. The paper will discuss the challenges with well clean-up with high volume of invaded fluid and a solution for efficient clean-up honoring all flowing and flaring limitation constraints in an environmentally sensitive area. Wellbore model was built in a software allowing a transient wellbore and near wellbore simulation during drilling and clean-up operations. It allowed to understand such a highly dynamic process by analyzing the evolution of rate, pressure and composition versus time. This technique was applied for a field where one may face challenges during the well clean-up such as well loading up with heavy fluid and high back pressure from production line. Moreover, according to government regulations flaring during production phase should be minimized as much as possible which creates another constraints with clean-up operations associated with flaring. A detailed model of clean-up dynamics allowed a radical change of well clean-up planning. A number of scenarios are evaluated in terms of uncertainty and risk and a detailed operating procedure is developed for the optimized well start-ups. Unlplanned emergency shut-down at surface is also simulated to ensure safety and restart possibilities, within the regulatory constraints imposed locally. With the confidence that the models are representative after sensitivity studies, it provides the operator with a tool to test sensitivity cases and develop operational solutions. It is then possible to suggest the most efficient process and estimate the volume of gas to be flared in a worst case scenario, an essential information to apply for flaring permission to the government. This approach is novel, and is possible through the utilization of a dynamic transient wellbore model with a near wellbore reservoir model that takes in consideration the invasion/losses and subsequent recovery of permeability during the clean-up process (Theuveny et al., 2013). With high confidence in transient models, it is possible to plan the clean-up process in an environment with large volume of invaded filtrate and high back pressure from production line which doesn't allow to flow the well at sufficient rate to properly clean the near wellbore zone. Integrated approach of simulating near wellbore and wellbore allows to accurately capture dynamics at any time of clean-up. Mitigation plans can be developed and proven through simulation before being implemented in the field.
A new approach in advanced multiphase metering methodology designed for use in sour fields, quantifying H2S content in flow and properly accounting for it in the different phase rate measurements is presented. Flow metering in sour fields is challenging due to the need for containment of produced fluids and the effect of fluid properties in the interpretation of the measurements. The addition of H2S measurement provides additional information for production and reservoir monitoring and also yields improvements in flow metering, accounting for variations in fluid properties used for multi-phase calculation. Multiphase Flow Meters (MPFM) utilizing multi-energy gamma-ray fraction measurements are based on the ability of oil, gas, and water to absorb gamma rays of two different wavelengths. Adding an extra measurement at a third level of energy and leveraging the large contrast between the attenuation of sulfur and that of hydrocarbon and water components makes it possible to determine the mass fraction of H2S as an additional output. This technique was applied in Tengiz field, Kazakhstan, characterized by a high H2S content. In order to maintain reservoir pressure, improve recovery and utilize produced associated gas, a sour gas miscible flood pilot was started in 2007. The monitoring of compositional variation in producers is critical in the understanding of solvent (sour gas) distribution and thus in managing production-injection patterns to optimize plant throughput. Early field trials of the method were made comparing metered H2S content with surface PVT samples, confirming the accuracy of the methodology. The technology was then implemented systematically but strategically across the field. The in-line H2S measurement with automatic updates for variation in fluid properties was applied in two distinct areas: within the sour gas injection pilot area, where solvent levels vary, and outside the area where hydrocarbon composition is known to be homogeneous and constant. Long and short term tests with multi-rate well tests were conducted. Full datasets were collected from the MPFM to evaluate measurement stability and representativity under different flowing conditions and compared to results obtained without accounting for compositional changes. The results show a stable, accurate and continuous measurement of H2S content in produced fluid and an enhanced measurements of water, oil and gas rates comparable with PVT results. The in-line H2S measurement based on multi-energy gamma ray measurements is the only continuous H2S measurement technology available in multiphase flow conditions. It can be retrofitted to existing MPFMs, allowing to get additional parameter and enhanced stability of flow rate measurements where properties of produced fluid vary continuously. This paper will begin with a presentation of the theory, formulation and validation of the in-line H2S measurement and then go on to present a case history of the application in the Tengiz field, Kazakhstan for Tengizchevroil (TCO).
The deployment of Multi-Phase Flow Meter (MPFM) from commissioning to execution campaign in harsh offshore/H2S uncertainty conditions is presented. The case study was performed in Lam and Zhdanov fields operated by Dragon Oil, Offshore Caspian-Turkmenistan. The objective was to enhance the quality of well testing and allocation factor by comparing test separators (TS) measurements against multiphase flow meter (MPFM) readings and, in a bigger scope to converge the difference versus onshore plant measurements of oil and water. Commissioning stage of MPFM was started off by comparing its results with TS. Comparison program was made and followed by considering the operating envelope of both technologies: MFPM and TS, input PVT parameters, measurement conditions and success criteria. Water-liquid ratio (WLR) and water rate from MPFM was compared against wellhead samples utilizing automatic centrifuge and total water at plant. MPFM was subjected to measure flow during both: well clean-up stage and production logging of a slugging well. High gas volume fraction and scale/wax precipitation have required methodology development to maintain the accuracy of MPFM. 14 wells were subjected to comparison test showing differences in gas and liquid rates between MPFM and TS are within acceptable criteria while difference in water rate was high due to slugging nature of flow. High-frequency measurements of WLR from MPFM showed water rates accompanying slugging were consistent with wellhead sampling and total onshore water production. Two-phase test separator was underestimating the water due to few sampling and improper separation at manual centrifuge. In high gas volume fraction equal to 98.5% and above MPFM accuracy in liquid rate becomes very sensitive to reference point of gas. To maintain the liquid accuracy, the in-line measurement of gas point was done so that accuracy of liquid measurements improved. MPFM has identified wells with scale and wax precipitation, which can be observed from photon counts deviation at two energy levels of gamma-ray spectrum. By adding 3rd energy level, it was possible to estimate the thickness of scale and wax on the wall of meter venturi throat and hence maintaining the MPFM flowing rate accuracy. MPFM campaign showed accurate measurement of water for Cheleken in addition to adding efficient well testing frequency while providing reliable high data frequency. This case study shows the first mobile MPFM application in Caspian offshore for producing wells’ testing. Results in comparison with TS signifies better and faster ways to calibrate the surface TS. MPFM testing campaign has led to the early identification of possible flow assurance issues and consequently, development of methodologies and recommendations to ensure reliability of MPFM and permanent test separators.
The Caspian offshore is a promising area for hydrocarbon accumulation. Since it is an offshore, it is a challenging area in terms of strict environmental regulations and safety. At the early stage of the project it was clear, that reservoir properties of the exploration well require artificial lift assistance to produce during well testing. Therefore, designing proper DST string with artificial lift was crucial to the success of well testing. This paper describes the methodology to select the artificial lift solution for well test. It shows the unique combination of technologies and techniques that enabled a DST with ESP in combination with the Y tool, that provides capabilities to run thePLT below the pump. Also, one of the main challenges of well testing operation was to handle heavy oil fluid at surface. Being in environmentally sensitive area, designing a surface well testing equipment in a limited footprint, that enables efficient separation and disposal of heavy oil was very critical. Another challenge was unconsolidated formation with the high risk of sand production under drawdown, therefore downhole testing string and ESP pump supposed to withstand large quantity of solids during the production. The key technology that enabled testing was a new generation of abrasion resistant ESP pumps, that are designed to handle extensive solids production. The heavy oil also posed a number of risks. The surface equipment was specifically designed to heat oil in the tanks and if required to mix with diesel before flaring operations. Local regulation does not permit production during the night time and allows limited number of days for well testing. Therefore, well testing design must enable to acquire all necessary information within short period of test duration. The real-time data transmission and interpretation was a key to achieve main goal of the testing in exploration well - to accurately characterize the reservoir. This was the first successful ESP-DST in Caspian Sea. Despite of many challenges, the technologies that were selected for well testing operation was proven to be reliable. This allowed Operator to untap previously not accessible hydrocarbon reserves.
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