Experiment Protocol Petroleum Engineer in Russia Saint Petersburg –Free Word Template Download with AI

This Experiment Protocol outlines the methodology for testing novel polymer solutions designed for Enhanced Oil Recovery (EOR) in high-salinity, low-temperature reservoirs. The primary objective is to evaluate the rheological stability and displacement efficiency of a new hydrolyzed polyacrylamide (HPAM) derivative under conditions mimicking the offshore fields of the Barents Sea.

As a Petroleum Engineer operating within the scientific hub of Russia Saint Petersburg, it is imperative to address the specific challenges posed by the Arctic environment. The cold climate and high salinity of the formation water in these regions often degrade standard polymers, leading to reduced viscosity and poor sweep efficiency. This experiment aims to validate a chemical formulation capable of withstanding these harsh conditions, thereby optimizing extraction rates and ensuring economic viability for future projects in the Russian Arctic.

This protocol applies strictly to laboratory-scale core flooding experiments conducted at the Saint Petersburg State University facilities. The results will inform pilot injection strategies for reservoirs characterized by temperatures between 4°C and 12°C and salinity levels exceeding 150,000 ppm. The scope includes the preparation of brine, polymer synthesis verification, core sample saturation, and the execution of the displacement phase.

All procedures must adhere to the Federal Law of the Russian Federation on Industrial Safety and the specific environmental regulations of Saint Petersburg.

• Personal Protective Equipment (PPE): All personnel must wear chemical-resistant gloves, safety goggles, and lab coats. Respiratory protection is required when handling polymer powders.
• Chemical Handling: Acrylamide monomers are toxic. Strict containment protocols must be followed to prevent environmental contamination of the Neva River watershed.
• Pressure Safety: Core flooding apparatus operates at pressures up to 20 MPa. Regular inspection of seals and pressure gauges is mandatory.

4.1 Materials

• Synthetic brine matching the ionic composition of the Barents Sea formation water.
• Novel HPAM derivative (Batch #SPB-99).
• Core samples: Sandstone plugs (10 cm length, 3.8 cm diameter) sourced from the Timan-Pechora Basin.
• Crude oil: Heavy crude sample with viscosity of 150 cP at reservoir temperature.

4.2 Equipment

• High-pressure core flooding system with back-pressure regulators.
• Rheometer capable of measuring viscosity at temperatures as low as 0°C.
• High-precision syringe pumps for controlled injection rates.
• Conductivity and salinity meters.

5.1 Preparation Phase

The Petroleum Engineer must first prepare the synthetic brine to ensure it accurately reflects the high-salinity conditions of the target reservoir. The polymer solution will be prepared by dissolving the HPAM derivative in the brine at a concentration of 2000 ppm. The solution must be aged for 24 hours at 10°C to simulate reservoir conditions before testing.

5.2 Core Saturation

Core samples will be cleaned, dried, and weighed. They will then be saturated with the synthetic brine under vacuum to ensure 100% water saturation. Subsequently, the brine will be displaced with crude oil to establish initial oil saturation (Soi). The permeability of the core to oil will be measured at this stage.

5.3 Water Flooding

A primary water flood will be conducted using synthetic brine at a constant injection rate of 1 mL/min. This phase continues until the water cut reaches 98%, simulating the end of primary and secondary recovery methods.

5.4 Polymer Injection

The novel polymer solution will be injected into the core at the same flow rate. The Petroleum Engineer must monitor the pressure drop across the core and the effluent viscosity continuously. This phase is critical for determining the polymer's ability to improve the mobility ratio and sweep efficiency in low-temperature environments.

5.5 Data Collection

Data points to be recorded include:

• Inlet and outlet pressure.
• Volume of oil and water produced.
• Viscosity of the effluent polymer solution.
• Conductivity of the effluent to track breakthrough.

Upon completion of the experiment, the Petroleum Engineer will calculate the incremental oil recovery factor achieved by the polymer flood compared to the water flood. Rheological data will be analyzed to assess polymer degradation. The final report must include a recommendation on the feasibility of scaling this technology for field application in the Russian Arctic.

This Experiment Protocol is designed to provide a rigorous framework for advancing EOR technologies in Russia Saint Petersburg, contributing to the nation's energy security and technological leadership in the petroleum sector.