A Novel Approach to Determine the Enriched Gas Recycling during the Enriched Gas Flooding Process

A novel approach was proposed for calculating the enriched gas recovery factor based on the theory of two-phase isothermal flash calculations. First, define a new parameter, pseudo formation volume factor of enriched gas, to represent the ratio of the surface volume of produced mixture gas to underground volume of enriched gas. Two logarithmic functions were obtained by matching the flash calculation data, to characterize the relationships between pseudo formation volume factor and the produced gas-oil ratio. These two functions belong to the proportion of liquefied petroleum gas in enriched gas; the proportion is greater than 50% and less than 50%, respectively. Given measured gas-oil ratio and produced gas volume, underground volume of produced enriched gas can be calculated. Injection volume of enriched gas is known; therefore, recovery factor of enriched gas is the ratio of produced to injected volume of enriched gas. This approach is simply to calculate enriched gas recovery factor, because of only needs three parameters, which can be measured directly. New approach was compared to numerical simulation results; mean error is 12%. In addition, new approach can effectively avoid the influence of lean gas on the calculation of enriched gas recycling. Three stages of enriched gas recovery factors in field Z were calculated, and the mean error is 5.62% compared to the field analysis, which proves that the new approach’s correctness and practicability.

Improvement of the Liquefied Natural Gas Vapor Utilization System Using a Gas Ejector

The production, transportation, and storage of liquefied natural gas (LNG) is a promising area in the gas industry due to a number of the fuel’s advantages, such as its high energy intensity indicators, its reduced storage volume compared to natural gas in the gas-air state, and it ecological efficiency. However, LNG storage systems feature a number of disadvantages, among which is the boil-off gas (BOG) recovery from an LNG tank by flaring it or discharging it to the atmosphere. Previous attempts to boil-off gas recovery using compressors, in turn, feature such disadvantages as large capital investments and operating costs, as well as low reliability rates. The authors of this article suggest a technical solution to this problem that consists in using a gas ejector for boil-off gas recovery. Natural gas from a high-pressure gas pipeline is proposed as a working fluid entraining the boil-off gas. The implementation of this method was carried out according to the developed algorithm. The proposed technical solution reduced capital costs (by approximately 170 times), metal consumption (by approximately 100 times), and power consumption (by approximately 55 kW), and improved the reliability of the system compared to a compressor unit. The sample calculation of a gas ejector for the boil-off gas recovery from an LNG tank with a capacity of 300 m3 shows that the ejector makes it possible to increase the boil-off gas pressure in the system by up to 1.13 MPa, which makes it possible to not use the first-stage compressor unit for the compression of excess vapours.

Flare Gas Recovery from an Existing Oil Plant using Gas Compressors

Global warming is nowadays one of the main and important issues. As the increase in the concentration of carbon dioxide and other greenhouse gases in the atmosphere as a result of the combustion of these gases causes such phenomena. Therefore, oil and gas plants need to be constantly reviewed over time to maintain high performance and operability, especially while changing feed composition and rate to meet standard product specifications. The aim of this study is to study the effect of flare gases recovery using gas compressors on the economic and environmental performance of an existing oilfield plant. A commercial simulation program aspen HYSYS Version 11 was used. The Kalabsha Central Processing Facility (KCPF) in the Western Desert of Egypt is the studied plant. This plant handles 30 million standard cubic feet per day (MMSCFD) from free water knock out drum and 1.6 MMSCFD of gases from heaters. 20 MMSCFD from gas is charged to the gas pipeline and 10 MMSCFD is sent to the flare with the 1.6 MMSCFD. It is proposed to install gas compressors to capture the gases from the free water knock out drum and heaters before sending them to the flare. Such technology can be used as a guide in upgrading existing and new oil and gas plants to reduce gas flaring. In addition, environmental protection also adds more economic profits from burning the recovered gas besides increasing the life of the flare equipment.

An investigation of methods for calculating the volume of methane dissolved in reservoir water

Existing gas production technologies limit gas recovery at the level of 85 %. Therefore, it is important to introduce technologies that make it possible to maximize the volume of production and intensify the inflow; for their selection it is important to have a reliable estimate of the residual gas reserves, since with a significant volume of the aquifer of gas fields, the volume of dissolved gas can be up to 10 % of the total reserves of the reservoir, which should be taken into account when designing the application of technologies to increase gas recovery.The main hydrocarbon dissolving in reservoir water is methane. In this regard, it is of interest to study methods that make it possible to determine the volume of hydrocarbon gases dissolved in saline water, which will make it possible to determine the total reserves of such gas. We investigated the existing methods for calculating the amount of methane dissolved in reservoir water, and gave a quantitative assessment of the volume of gas dissolved in water.

Techno Commercial Analysis of Liquefied Petroleum Gas Recovery From Natural Gas Using Aspen HYSYS

Liquefied petroleum gas is an alternative, relatively clean and a supreme source of energy, which is being used as a key component in the global energy supply. The international trade agreements and the chemical and non-chemical demand of liquefied petroleum gas with the increase in the world’s population have brought its production from the processing of natural gas to the limelight. During its processing, a variety of different components are extracted from it, including methane and ethane which remains in the bulk as natural gas. The objective of this research work is to find the capability of investigating the liquefied petroleum gas recovery performance to make the process economical by saving the processing cost and energy. The novelty of this work is to deal with the design and simulation of a liquefied petroleum gas plant using Aspen HYSYS. To make this process energy efficient and economical, different schemes of process alternatives were applied by reducing the sizes of the exchanger and other pieces of equipment. Three cases are studied in which feed is precooled by rerouting the stream and/or by repositioning of the chiller for the recovery of liquefied petroleum gas from natural gas by analyzing their cost and process parameters. The modelling and simulation base case and three different case studies are realized in Aspen HYSYS. It has been observed that case study 2 results in about 10% increase in LPG production where the chiller is repositioned in the separation section of the LPG production flowsheet. Case study 3 shows a maximum decrease in hot side utilities in the flowsheet of about 20% while 10 and 14% decreases are observed for case studies 1 and 2, respectively. Furthermore, economic analysis indicates about 18 and 22% in the capital cost for case studies 2 and 3, respectively, due to the lower size of process units. The outcome of this investigation is to present plenty of suggestions to improve the process efficiency and minimize the requirement to over design the plant components.