Flaring has received significant attention over the past few decades and has become a major concern for many operators today. One of the contributors to hydrocarbon flaring is well clean-up operations, where traditionally oil and gas are disposed by flaring at the wellsite. This paper will share in details how integrating various technologies allowed to come up with a cost effective, zero flaring solution for well clean-up operations, that substantially reduced overall field carbon footprint. A common alternative to flaring is to store the crude in tanks and/or pump crude into production line, if available. However, the associated gas is typically flared off, as using gas compressors to inject gas into production line is extremely cost intensive and operationally complex. As an alternative, fit for purpose multiphase pumps, specifically designed to handle clean-up operations and combined with a high pressure surface well testing package proved to be a successful, innovative and cost effective solution to bring new wells to production without gas flaring. The pumps, installed at the inlet of a high-pressure separator, boost the pressure such that both oil and gas can flow directly into the production line, while water and spent acid from well stimulation treatment are separated out onsite into water tanks. The method does not require any hydrocarbon flaring, thereby drastically reducing emissions for well clean up and start up operations. The solution enabled a reduction of an average of 24 Kilo-Tonnes of CO2 equivalent of emmissions per well clean up, when compared to 100% flaring, resulting in a very significant and measurable positive environmental impact. The pumps proved to be reliable and fit for purpose, by toleranting high gas-volume-fraction (GVF) conditions and unstable flow, which is vital for clean-up operations. In addition, the setup proved to be an efficient pressure-boosting package, to gain additional production, by overcoming the high backpressure from the production lines network. The package was introduced in the giant Karachaganak oil and gas condensate field in Western Kazakhstan in high H2S environment, and was used in 13 wells over a two-years period, resulting in significant net production gains for the operator.

This paper presents the recent developments that have been achieved to improve the Karachaganak Integrated Asset Model (IAM). In 2014, SPE-172330 showed a step change in the application of integrated modelling techniques to this complex field and demonstrated the significant value of integration compared to standalone techniques. The complexity of modelling and integration is driven by more than 120 operating wells (production and injection), a complex gathering system, multiple processing facilities and multiple export lines, combined with gas reinjection for reservoir pressure support. To correctly capture real operations, the model requires layers of constraints at well, facility and export levels and an appropriate line-up of wells to maximise field oil and gas production. The model has been used to evaluate multiple field development projects with intensive capital investment worth several billions of US dollars. Hence, it is critical to ensure that the model is robust and replicates the reality. The latest improvements presented in this paper include a description of a more enhanced field optimisation approach that fulfills oil and gas export as well as gas reinjection targets whilst respecting all of the field constraints. Optimising such a complex problem is a challenging task considering the number of variables and constraints in the system. Production well ranking for line-up selection has also been improved. Rather than following a single approach of well prioritisation, for example by well Gas/Oil ratio to maximise liquid production, in the new methodology wells are smartly picked to fulfill all export and gas injection targets. Another improvement in the model was converting the optimisation logic, which was previously based on scripts, into open and transparent workflows using Visual Workflows in Resolve (application for connecting and running integrated models). This approach made it possible for Engineers to read, modify and extend the logic without having programming skills, bringing flexibility and sustainability into the model. Several case studies of actual project evaluations using the improved Integrated Asset Model will also be discussed. These studies highlight the key results, the importance of the implemented improvements for decision-making and how these affect the bottom line of projects.

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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.