Simonov, Maksim (Gazpromneft Science & Technology Center, Peter the Great St. Petersburg Polytechnic University) | Shubin, Andrei (Saint Petersburg State University) | Penigin, Artem (Gazpromneft Science & Technology Center) | Perets, Dmitrii (Gazpromneft Science & Technology Center) | Belonogov, Evgenii (Gazpromneft Science & Technology Center) | Margarit, Andrei (Gazpromneft Science & Technology Center)
The topic of the paper is an approach to find optimal regimes of miscible gas injection into the reservoir to maximize cumulative oil production using a surrogate model. The sector simulation model of the real reservoir with a gas cap, which is in the first stage of development, was used as a basic model for surrogate model training. As the variable (control) parameters of the surrogate model parameters of gas injection into injection wells and the limitation of the gas factor of production wells were chosen. The target variable is the dynamics of oil production from the reservoir. A set of data has been created to train the surrogate model with various input parameters generated by the Latin hypercube.
Several machine learning models were tested on the data set: ARMA, SARIMAX and Random Forest. The Random Forest model showed the best match with simulation results. Based on this model, the task of gas injection optimization was solved in order to achieve maximum oil production for a given period. The optimization issue was solved by Monte Carlo method. The time to find the optimum based on the Random Forest model was 100 times shorter than it took to solve this problem using a simulator. The optimal solution was tested on a commercial simulator and it was found that the results between the surrogate model and the simulator differed by less than 9%.
Usop, Mohammad Zulfiqar (PETRONAS Carigali Sdn. Bhd.) | Suggust, Alister Albert (PETRONAS Carigali Sdn. Bhd.) | Mohammad Razali, Abdullah (PETRONAS Carigali Sdn. Bhd.) | Zamzuri, Dzulfahmi (PETRONAS Carigali Sdn. Bhd.) | M. Khalil, M. Idraki (PETRONAS Carigali Sdn. Bhd.) | Hatta, M. Zulqarnain (PETRONAS Carigali Sdn. Bhd.) | Khalid, Aizuddin (PETRONAS Carigali Sdn. Bhd.) | Hasan Azhari, Muhammad (PETRONAS Carigali Sdn. Bhd.) | Jamel, Delwistiel (PETRONAS Carigali Sdn. Bhd.) | Ting Yeong Ye, Diana (PETRONAS Carigali Sdn. Bhd.) | Abdulhadi, Muhammad (Dialog Berhad) | Awang Pon, M Zaim (Dialog Berhad)
Reservoir G-4, a depleted reservoir in field B had been producing from 1992 to 2015 with a recovery factor of 30% before the production was stopped due to low reservoir pressure. Due to the huge inplace volume. A secondary recovery screening was conducted and gas injection was identified as the most suitable solution to revive G-4 reservoir due to its low cost impact of 0.4 Mil. USD whilst managing to deliver the same results as other solutions (i.e. Water injection & Water Dumpflood).
The project had utilized existing facilities in field B including a gas compressor. The project required only minor surface modification to re-route gas into the tubing of injection well BG-03. From simulation results, a continuous injection of 5 MMscf/d will increase the reservoir pressure by 150 psia in 9 months, with incremental potential reserves of atleast 5.0 MMstb from the benefitter wells, BG-02 & as well as incoming infill wells BG-14 & BG-15. It is also envisaged that with future development of additional infill wells, the recovery factor will be increased up to 60%.
In term of gas management, field B is able to deliver additional 15 MMscf/d post petroleum operation reduction (i.e. Fuel Gas, Instrument Gas & Gas lift). With the initiation of gas injection, the project had managed to utilize and optimize 33% of additional gas production for reservoir rejuvenation purposes.
The paper provides valuable insight into the case study and lesson learned of maximizing oil recovery through gas injection with minimal cost incurred. The approach is highly recommended to maximize oil recovery especially in mature fields with similar reservoir conditions and production facilities.
Gas injection is a proven EOR method in the oil industry with many well-documented successful field applications spanning a period of more than five decades. The injected gas composition varies between projects, but is typically hydrocarbon gas, sometimes enriched with intermediate components to ensure miscibility, or carbon dioxide in regions such as the Permian Basin, where supply is available at an attractive price.
Miscible nitrogen injection into oil reservoirs, on the other hand, is a relatively uncommon EOR technique because nitrogen often requires a prohibitively high pressure to reach miscibility. Unlike other injection gases, the minimum miscibility pressure for nitrogen decreases with increasing temperature. In fact, in deep, hot reservoirs containing volatile oil, nitrogen may develop miscibility at a pressure similar to the MMP for hydrocarbon gas or carbon dioxide. The phase behavior is more complicated than what can be captured by correlations and hence requires equation-of-state calculations.
Results from a recent EOR screening study in ADNOC indicate that a couple of high-temperature oil reservoirs in Abu Dhabi may be potential targets for miscible nitrogen injection. This paper discusses key aspects of the EOS modeling. Advanced gas injection PVT data are available to enable a fair comparison between nitrogen, carbon dioxide and lean hydrocarbon gas. In this work, we have modelled and analyzed the phase behavior of two volatile oil systems with respect to nitrogen, hydrocarbon gas, and carbon dioxide injection, as part of a reservoir simulation study, which will be covered in a subsequent publication; see
This paper studies the technical and economic viability of this EOR technique in Eagle Ford shale reservoirs using natural gas injection, generally after some period of primary depletion, typically through long, hydraulically fractured horizontal-reach wells. The Eagle Ford formation has produced approximately 2 billion bbl of oil during the last 7 years, yet its potential may be even greater. Using improved oil-recovery (IOR) methods could result in billions of additional barrels of production. Shale EOR Works, But Will It Make a Difference? The promise of getting 30% more oil production from shale wells has set off a race by companies trying to see if they can replicate what EOG has done.
However, despite the fact that large resources of natural gas are present, several countries have to rely on imports for the domestic gas consumption. These countries have recently put forward ambitions to change this and become self-sufficient or even larger exporters of (Liquefied) Natural Gas. Regional countries have articulated to become self-sufficient in the future. This can be realised by at first lowering growth of domestic natural gas consumption by replacing electricity production by renewable and nuclear power. Other means to free up gas for consumption are increased energy efficiency (typically 2 to 5% of production) and finding alternatives for natural gas Injection for pressure maintenance (up to 30% of production).
This session addresses the challenges of staying above saturation pressure and/or maximizing recovery of the most valuable components for as long as possible, for the entire unit. Additionally, the strategy must include data acquisition and be executed within the confines of reasonable capital requirements, and without significant well intervention. Reservoir & well pressure management issues d. Mature unconventional production wells experience substantial production declines and were likely stimulated less optimally than newer wells. Rather than simply drilling more wells, this has led operators to look to restimulation of wells with reduced production rates and lesser stimulated reservoir volume.
Gas-based EOR in tight unconventionals is a growing application to tap the vast unproduced oil and condensate resources in liquid-rich shale basins. The Huff-n-Puff process now involves several hundred wells in the Eagle Ford, and pilots are planned or ongoing in all other liquid-rich basins (Bakken, Permian, and Montney). The course will discuss the Huff-n-Puff gas EOR process specifically, but will also address relevant fundamentals of displacement-based gas EOR methods (miscibility, vaporization, and displacement) in tight unconventionals. Introduction to Unconventional gas EOR Summary of gas EOR methods and recovery mechanisms What makes unconventional gas EOR different than conventional? To learn about and share experiences in gas EOR in tight unconventionals.
Flow assurance in the oil and gas industry refers to the systems put in place to guarantee uninterrupted profitable and sustainable flow of hydrocarbons from the reservoir to surface facilities and ultimately to refineries. Flow assurance challenges include: inorganic scale, asphaltene, wax, corrosion, hydrates, etc. Managing these challenges is becoming more complex because of development of fields under harsher conditions e.g. HPHT reservoirs, sour reservoirs, heavy oil; in addition to further implementation of EOR (gas injection, chemical, surfactant and polymer floods). Different engineering and chemical solutions can be put in place to manage these challenges. All cancellations must be received no later than 14 days prior to the course start date.
Southwest Research Institute is adding a new facility to its capabilities in testing and evaluating subsea equipment and systems. This review of papers illustrates some of the innovative solutions used in the region. This paper focuses on a numerical-modeling analysis of the acid-gas-injection (AGI) scenario in carbonate HP/HT reservoirs, and presents the way in which AGI impacts asphaltene-precipitation behavior. This paper demonstrates a design methodology that combines the API and American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessels Code (BPVC) for designing an example subsea pressure containing component for HP/HT conditions greater than 15,000 psi and 250°F.