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.
The well discussed in this paper has a history of sand production and has exhibit long cyclic slugging behavior with a frequency of several days and reduced average production. The lower completion has a 2000-ft gap between the mule shoe and the packer that is exposed to the larger diameter of 7-in. liner. It is not fully understood whether the slugging is caused by the gap at the lower completion or by sand transportation or both.
Dynamic wellbore modelling with sand particle transport is essential to model the abovementioned complex slugging behavior. A stepwise approach was adopted to allow systematic evaluation of this complex slugging phenomenon. Initially, a lumped inflow with no sand transportation was assumed. In the next stage, sand transportation was included with zonal inflow details added. Several sensitivities on sand particle sizes, particle density, zonal productivity index, etc. were carried out, all of which were aimed at reproducing the long cyclic slugging behavior observed in the field.
Transient simulations successfully produced the slugging behavior observed in the field. Cyclic slugging was seen to be caused by the flow dynamics generated by particles of small to medium size. Some of the key findings were complete blockage by porous sand stationary bed at the lower completion gap (with subsequent pressure buildup), transition from stationary bed to moving bed, rate-dependent velocity of a slow-moving particle bed (eventually producing to surface), and fresh sand particle production from the reservoir at increased drawdown. Measured data from the sand detector confirmed the production of sand, particularly around the same period as predicted by simulation.
Potential slug mitigation solutions were established that should help to achieve higher and stable production. One solution was to achieve higher flow velocity and therefore enable sand transportation as a continuous moving bed (i.e., no blockage), such as reducing the gap size at the lower completion section together with either tubing size reduction or electric submersible pump (ESP) installation. The other solution was to implement an appropriate sand control/sand consolidation method.
Sand production is a common flow assurance issue and sometimes can result in unstable flow behavior causing reduced production. This work is the first attempt to implement particle transport modelling in transient multiphase flow simulation to successfully address a slugging issue in a real well. The analysis helped in understanding the mechanism causing the slugging and arriving at a potential mitigation solution. Further, it provides a step-by-step workflow and a template to address such problems.
In the oil sector, TOTAL should become the "low cost champion". This is presently our main challenge as mentioned by our CEO in the strategical document "One Total, our ambition". A key to succeed in a mature field such as PNGF North (CONGO) is to convert gas lifted wells into ESP activated wells. The ATEX VSD innovation consists of having the electrical module of an ESP activated well located in hazardous area, avoiding high costs that would result from a platform extension (for an electrical room). This innovation was designed by TOTAL E&P CONGO (TEPC) and installed on the YAF2 platform (YANGA field) in June 2018 has enabled to increase the production of the YAM254 well by 250% and its operational efficiency by 25 points. This innovation, which would not be possible without the close cooperation between headquarters and TEPC, could be extended to the entire TEPC subsidiary and thus open doors for new development opportunities for TOTAL brown fields.
In a deepwater environment, production fluid conditions have to satisfy complex requirements to flow smoothly to the production facilities on the FPSO. Flow assurance specialists work at turning these constraints into operating guidelines. This allows to close the gap between reservoir conditions, optimized design of the subsea network, topsides processing capabilities and operability requirements.
In the context of Kaombo, offshore Angola (Block 32), the wide range of reservoir conditions and fluids plus the extreme specificities of the subsea network called for an innovative approach with the following objectives: Empower the operator with a visual decision tool for normal and unplanned operations of the subsea system Promote collaboration between production, flow assurance & geoscience teams to reach an efficient decision, and minimize production shortfalls Allow a design robust enough to tackle geosciences uncertainties Optimize subsea design margins
Empower the operator with a visual decision tool for normal and unplanned operations of the subsea system
Promote collaboration between production, flow assurance & geoscience teams to reach an efficient decision, and minimize production shortfalls
Allow a design robust enough to tackle geosciences uncertainties
Optimize subsea design margins
This new approach, the "Visual Operating Envelopes", aims at explicitly and visually defining the operating limitations of the subsea production loops in a multi-parameters environment: A multi-dimensions map, function of the six main parameters (basically liquid and gas-lift flowrates, water and gas contents, reservoirs pressure and temperature) influencing multiphase flow into pipeline is hence created to evaluate the six main operating constraints (thermal and hydraulic turndown rates, wells eruptivity, maximum flowrates) for the full range of Kaombo fields.
This "operating envelope" tool can then define the minimum and maximum recommended flowrates for different operating conditions based on the following safe criteria: Arrival temperature above the Wax Appearance Temperature No hydrates risk during preservation No severe slugging effect Production below the flowline design flowrate Velocity below the erosional velocity
Arrival temperature above the Wax Appearance Temperature
No hydrates risk during preservation
No severe slugging effect
Production below the flowline design flowrate
Velocity below the erosional velocity
In addition, the optimized gas lift flowrate is directly accessible, and the pressure available at every wellhead is compared to the backpressure associated to the operating point to assess the eruptivity of the wells.
By having previously defined an overall operating envelope, it is extremely easy to evaluate quickly the impact of new operating conditions (due to degraded operating conditions, changes in reservoir parameters, modifications in the drilling and wells startup sequence), which makes this new approach very powerful and versatile. It also contributes to the definition of the production forecast during operation phase integrating reservoir depletion and available gas lift rate.
Instead of relying on specific simulations for a limited number of cases, this innovative method defines a new approach where operating parameters are evaluated from the start, and boundaries are clearly identified, thus allowing to build a sound production profile for an extensive range of operating conditions. By doing so, system knowledge is improved, bottleneck conditions are anticipated, operators, flow assurance and geoscience teams are able to tightly collaborate and take smarter decisions together, resulting in more production. Eventually the method applied to a multiphase pipeline is actually transposable to every problem involving multi-dimensional inputs with combined constraints.
A study by a real-time monitoring company showed that many coiled-tubing strings are retired with a lot of life left in them. It suggested companies could lower costs by using pipe for a longer time and could benefit from multicompany studies showing how their decisions compare to the competition. This paper describes a methodology for classification of artificial-lift-system (ALS) failures and addition of a commonly used root-cause failure classification. The great majority of wells do not pollute.
This study presents a methodology to define the most-adequate artificial-lift technique on the basis of technical limitations, a suitability coefficient (based on an attributes table), and economic analysis toward horizontal well configuration. This paper presents an artificial-lift selection process to maximize the value of unconventional oil and gas assets. This paper focuses on a fit-for-purpose methodology to evaluate well-production performance for a wide range of artificial-lift techniques.
A common theme worldwide in the production of gas fields is the eventual requirement to deliquify the wells. Depending on depth and location, many successes and challenges are encountered. This session looks at field cases to document industry best practices, funda.m.entals and applications for gas well deliquification leading to optimal field development. We invite stories covering the widest variety of measures ranging from the most common (automated intermittent production, surface compression and velocity string) and the well specific (foa.m.-assisted lift, plunger lift) to the most advanced (gas lift, downhole pumping). Production wells in gas reservoirs with an active aquifer are vulnerable to liquid loading issues as the gas-water contact rises with depleting reservoir pressure and ultimately reaches the well.
The Production Optimisation in Gas and Oil Assets workshop is a high-quality event where experts, operators, and service companies share their latest development, successes, and failures on late-life production topics. This workshop aims to improve and accelerate the development of activities to optimise late-life production in gas and oil wells and assets. The event will include dedicated sessions on field cases of gas well deliquification, on well flow dynamics (liquid loading and slugging), on solids deposition (sand, salt, scale) and corrosion, on surfactants (both for wells and pipelines), on topside Optimisation, and on data analytics and digitalisation. Both hardware, field experience, as well as new prediction methods will be included. Technical presentations will be alternated to breakout sessions, giving plenty of opportunities for lively interaction and networking among participants.
The Production Optimisation in Gas and Oil Assets workshop is a high-quality event where experts, operators, and service companies share their latest developments, successes, and failures on late-life production topics. This workshop aims to improve and accelerate the development of activities to optimise late-life production in gas and oil wells and assets. The event will include dedicated sessions on field cases of gas well deliquification, on well flow dynamics (liquid loading and slugging), on solids deposition (sand, salt, scale) and corrosion, on surfactants (both for wells and pipelines), on topside Optimisation, and on data analytics and digitalisation. Both hardware, field experience, as well as new prediction methods will be included.