The objective of this article is to demonstrate recent results of a water cut measurement campaign in the Karachaganak oil and gas condensate field. Historical, inaccurate well water cut assessment was due to the limitations of well test facilities which led to uncertainty in short- and long-term production forecasts. Several approaches were conducted to eliminate uncertainties in water cut measurements and to evaluate and define adequate tools to use for future water cut analysis. The use of a mobile sampling flow loop installed at the well head, where turbulent multiphase flow is guaranteed, was a safe and reliable approach to measure the water cut of the producing low and high productivity wells. Sampling and analyzing the fluid at the well site at various operating well head pressures, frequently and for long periods of time, resulted in better understanding of water cut dependence with changes in drawdown. In addition to the use of sampling on site, the optical sensor (OS) technology was a trial tested on two wells along with the sampling flow loop to confirm the accuracy of the technology. The existing test separators were not designed to handle high water rates; moreover, due to the complexity of the produced hydrocarbon, multiphase flowmeters are not able to accurately measure the correct fluid phase contribution and, as a result, inaccurately estimate phase rates. The OS tool demonstrated accurate real-time water cut readings in the liquid phase, when compared with the flow loop samples, as long as a turbulent flow is guaranteed during measurement. Thus, this technology can be considered as an accurate tool for water cut measurements. The possibility of temporary and permanent installation of the optical sensor tool at the well site or test lines is under evaluation. The current field development focuses on improved recovery from the oil rim which is above a weak aquifer. In the historically developed areas of the field this aquifer is separated from the hydrocarbons by impermeable shale and therefore water production has been minimal. Current and future development requires the drilling of new wells in areas not protected by barriers; this has led to a number of recent wells having a relatively early water breakthrough. As a result of accurate water cut measurements, unallocated water in the field was well defined and led to better control of water producing wells to maintain stability of process facilities. This application confirmed the limitations and low level of accuracy of the existing well test separators. The successful campaign to improve water cut assessment was critical to update and re-evaluate production wells’ operating philosophy, reservoir management, and the future development strategy of the carbonate reservoir.
Karachaganak is one of the world's largest oil and gas condensate fields in a deep heterogeneous carbonate reservoir with complex sour fluid system located in Western Kazakhstan. Karachaganak's estimated reserves are over 2.4 Bln bbls of condensate and 16 tcf of gas. The asset is co-operated by Shell and Eni through Karachaganak Petroleum Operating (KPO) b.v. Joint Venture. KPO successfully deployed a new KUAT operating center with aim to maximize production and improve collaboration among key functional groups managing day-to-day field activities. Maximizing oil production means getting the most condensate liquids to surface at a given gas (or other) constraints by routing producer wells through the network to arrive at the lowest field GOR. Experience showed that the key success factor was to establish a collaboration between Subsurface and Production departments built upon common understanding of field data. Physical embodiment of this collaboration is the Karachaganak Unified Action Team – KUAT, which means "power" in Kazakh. This center was established in 2020 with physical placement of Petroleum Engineers together with Production, Process and Planning Engineers in one Operating Center at the field site. The objectives of KUAT team include the following short-term integrated activities: Daily well line-up optimization as per integrated limit diagram views Integrated activity planning – e.g. optimized start-up of the new wells and projects Well surveillance planning and execution – from reference plans, EBS and opportunity-based GOR management Flow assurance KUAT team utilizes the industry standard digital solutions like PI and PI vision and Petex type of solvers as well as custom-made integrators like Data Integrator and Network Optimizer (DINO). In order to ensure that production is always maximized and potential downtime is minimized a robust understanding of the limit diagrams and well potentials is required. This information is provided by live integrated dashboards which include the real-time data from subsurface to export routes. The overall contribution from KUAT is estimated at ~7,000 BOPD or 3% of incremental field production. This paper will cover the overview of KUAT journey from early concept development to current state explaining how this center operates today. Workflows and improvements are included in the discussion as well as challenges faced throughout the implementation of newly developed team within the organization
The objective of this paper is to demonstrate multiple application of multi-energy gamma ray venture type multiphase flowmeter (MPFM) trial campaign in Karachaganak gas condensate giant carbonate field, operated by KPO B.V. The results of MPFM that was included into surface well test spread, to verify its performance, was compared against portable test separator and plant production testing facilities (control separator, flowmeters) and manual sampling results. MPFM from other vendors historically failed to deliver accurate production measurement mainly due to complexity of reservoir fluid in Karachaganak field. To ensure the MPFM considers this complexity, PVT samples were taken to provide laboratory data for PVT model of the MPFM to ensure sufficient quality of PVT data and compare against PVT model inside MPFM. First application of MPFM was during clean-up of the well prior handover well to production. Using MPFM helped to improve the quality during data acquisition. This information was critical for the well to be accepted by processing facility it is hooked-up to and to define optimal operating regime. Validation of BS&W, GOR and rates in unstable (foaming, carry over) and transient phase of production using MPFM has shown practical advantages. Another application was for water sampling loops to measure water cut and production rates. KPO has had challenges with inaccurate water cut measurement due to the limitations of existing test separators. A recent approach of performing fluid sampling (sampling loop) at the well head proved to be reliable source of measurements. In addition, the MPFM in combination with the test separator has been used to further improve the quality of the measurements of each phase. The third MPFM application had been with high gas-volume-fraction (HGVF) pumps, that helped to produce from low reservoir pressure, low GOR and high water cut wells. The operational range of HGVF pump was limited to maximum 75-80% of gas-volume-fraction (GVF). MPFM measures GVF in real-time to ensure HGVF pump operates in optimum operational range by managing the surface flow conditions. With current limitations of test separators in Karachaganak field and due to complexity of the gas-condensate fluid, the use of MPFM brings additional quality in the measurements (rates, water cut and GOR) which is crucial for field production optimization, reservoir management and short and long term forecasting.
The objective of the paper is to present the application of a transient multiphase flow simulator for the purpose of modelling and improving understanding of complex well behaviour which is not possible with a steady-state solution. The outcome was optimizing well production performance of problematic wells in terms of slugging flow and water loading at high network pressure in a gas condensate and oil field. Continuous reservoir pressure decline, increasing gas-oil-ratio (GOR) and water cut have led several wells in the field to exhibit slugging flow. Different intervention trials in the subject wells failed to bring the well online in continuous flow. The methodology employed was to construct the well model in a transient multiphase flow simulator using the available data; well completion schematic, compositional PVT fluid properties, and well test data. The fluid was characterised using the PVT package. The well model was built, and its performance was matched to dynamic natural slugging flow, shut-in conditions, clean-up operations, and artificial lifting case where nitrogen was injected via coiled tubing to lighten the wellbore fluid density. The modelling results of the well performance analysis have explored crossflow between reservoir zones and water loading phenomena on long sub-horizontal oil producers, at high operating well head pressures, as the cause of flow instability. The multi-stage completion and multiple reservoir intervals, with differing reservoir properties, were captured during construction of the well model. The static fluid gradient survey analysis verified the simulator outcomes, and this in turn proved its applicability for the complex fluids. The well model provided deep understanding of fluid flow in the wellbore for flowing and static conditions. The model was used to evaluate well intervention scenarios to establish a stable flow regime. These studies highlighted the possibility to achieve optimal operating well head pressures to avoid aggravating water loading and stable production process. Various multiphase stable flow optimization methods were examined along with an economic assessment. The dynamic multiphase flow simulator has been found useful in reproducing complex flow behaviour observed in problematic wells and improve stable production. The approach of using a transient multiphase flow simulator on wells with water loading issues and also with crossflowing intervals is vital, and this first time application has proved beneficial for the Karachaganak gas condensate and oil field.
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