An Experimental Investigation of the Effect of Changing the Rock's Wettability on the Performance of Carbonated Water Injection CWI

CWI is affected by multiple factors, including the wettability of the rock. These experiments seek to determine the results that are obtained when CW is injected in a tertiary mode for systems: (1) wetted by water and (2) mixed wettability; to date, no study has used this approach. The same sandstone core was used in all trials, and each test consisted of saturating the core with live crude, followed by the injection of water as a secondary recovery and then the injection of CW as a tertiary recovery. An additional sensitivity test was conducted that consisted of varying the composition of the dissolved gas in the crude. In general, in a water wet system, the recovery associated with the injection of CW is higher (normalized) compared to a mixed wettability system. This does not mean that the results were negative in the mixed system. On the contrary, the results are positive since on the order of an additional 20% was recovered. However, the pressure differential in a mixed system is higher (14%) compared to water wet system. Although it is common knowledge that wettability of the rock affects the production and pressure results in an experiment, these are the first experiments that have been performed exclusively to determine quantitatively the response to CWI while maintaining the other parameters constant.

Comprehensive investigation of low salinity waterflooding in carbonate reservoirs

Waterflooding has been practiced as a secondary recovery mechanism for many years with no regard to the composition of the injected brine. However, in the last decade, there has been an interest to understand the impact of the injected water composition and the low salinity waterflooding (LSWF) in oil recovery. LSWF has been investigated through various laboratory tests as a promising method for improving oil recovery in carbonate reservoirs. These experiments showed diverse mechanisms and results. In this study, a comprehensive review and analysis for results of more than 300 carbonate core flood experiments from published work were performed to investigate the effects of several parameters (injected water, oil, and rock properties along with the temperature) on oil recovery from carbonate rock. The analysis of the results showed that the water composition is the key parameter for successful waterflooding (WF) projects in the carbonate rocks. However, the salinity value of the injected water seems to have a negligible effect on oil recovery in both secondary and tertiary recovery stages. The study indicated that waterflooding with optimum water composition can improve oil recovery up to 30% of the original oil in place. In addition, the investigation showed that changing water salinity from LSWF to high salinity waterflooding can lead to an incremental oil recovery of up to 18% in the tertiary recovery stage. It was evident that applying the optimum composition in the secondary recovery stage is more effective than applying it in the tertiary recovery stage. Furthermore, the key parameters of the injected water and rock properties in secondary and tertiary recovery stages were studied using Fractional Factorial Design. The results revealed that the concentrations of Mg2+, Na+, K+, and Cl− in the injected water are the greatest influence parameters in the secondary recovery stage. However, the most dominant parameters in the tertiary recovery stage are the rock minerals and the concentration of K+, HCO3−, and SO42− in the injected water. In addition, it appears that the anhydrite percentage in the carbonate reservoirs may be an effective parameter in the tertiary WF. Also, there are no clear relations between the incremental oil recovery and the oil properties (total acid number or total base number) in both secondary and tertiary recovery stages. In addition, the results of the analysis showed an incremental oil recovery in all ranges of the studied flooding temperatures. The findings of this study can help to establish guidelines for screening and designing optimum salinity and composition for WF projects in carbonate reservoirs.

Pioneering Secondary Recovery Strategies in a Complex Geological Environment and Challenging Reservoirs Located in Offshore Sarawak

The Balingian province is located offshore Sarawak, comprising of at least 7 oil fields with its regional geology consisting of a combination of deltaic & shoreface system. Though consisting of clastic reservoirs, the fields are highly sophisticated in terms of reservoir compartmentalization, hence uncertainties in fluid contacts, differing depletion strategies and varying production performance per well. As the regional production has gone into brownfield stage, the challenge is to determine the most suitable secondary recovery method to prolong field life. The subsurface & feasibility studies conducted produced mixed results between application of water & gas injection, giving recovery factors between 30 to 40%, and implementation so much depending on source of water & gas and cost benefit analyses. The application of IOR across Balingian province are executed in pilot mode across all fields. While the pilots are still continuing, this paper is to share the methodology, recovery factors and process of the regional study and some results from the ongoing surveillance post-execution, and the wayforward.

Application of Enhanced RPB Tool in Malaysian Oilfields for Gas Injection RF Benchmarking and Analogue Identification

Identification of an optimal field development plan is one of the most critical decisions for oil asset management. In the new norm of low oil prices, this assumes even more relevance for mature oilfields to maximize overall recovery. In greenfield developments and oilfields in early production life, the absence of a clear roadmap detailing their future development strategy can often lead to missed opportunities and sub-optimal recovery. To bridge this gap, Petroliam Nasional Berhad (PETRONAS) began identifying new improved oil recovery (IOR) opportunities in mature fields and started formulating an optimal development plan in greenfields. In 2019, PETRONAS embarked on implementing the Reservoir Performance Benchmarking (RPB) tool to evaluate reservoir recovery potential with waterflood. This paper will detail the Phase-II development of this data-analytics based tool which focuses on delivering a comprehensive roadmap, which includes other recovery mechanisms such as gas injection and reservoir under primary recovery. Phase-I of RPB tool (SPE-196443) had considered water injection as a key secondary recovery process to evaluate the benchmark recovery factor for an oil reservoir. As part of Phase-II development, this has been further enhanced to evaluate field recovery potential and provide the benchmark recovery factor for primary recovery and gas injection processes. For fields under primary recovery, a comparative assessment between volumetric depletion and varying aquifer/gas-cap drive is conducted to ascertain the recovery potential. Assessment for incremental secondary recovery gains considers both gas injection and water injection scenarios in the enhanced benchmarking methodology. In addition, the benchmarking calibration methodology has also focused on incorporating additional reservoir parameters specific to each of the recovery processes for overall estimation of the benchmark value. The benchmarking tool also identifies analogue reservoirs to enable replication of best development practices and optimization of the development strategy. With the deployment of this enhanced RPB tool, a comprehensive 5-year roadmap has been developed to improve Malaysian oilfields recovery. This has enabled PETRONAS to augment its resource funnel inventory, streamline its opportunity ranking and integrate project maturation tracking with existing digital platforms of its entire portfolio. This is a novel benchmarking tool to assess reservoir potential recovery factor for primary and secondary recovery processes (both water and gas injection) along with analogue identification for replication of best development practices

Properties and Kinetics of Selective Zinc Leaching with Choline Chloride and Urea

A choline chloride-urea (ChCl-urea) deep eutectic solvent (DES) was used to experimentally investigate the secondary recovery of zinc from zinc-bearing dust sludge via a leaching process. The effects of varying the liquid–solid ratio, leaching temperature, stirring speed, and leaching time on the zinc leaching efficiency were determined, and the optimum values of these parameters were found to be 15:1, 90 °C, 400 rpm, and 600 min, respectively, at which a leaching efficiency of 86.87% was achieved. XRF and EDS analyses confirmed that the zinc content in the sludge decreased noticeably after leaching, while those of other elements did not, indicating the selective and efficient leaching of zinc. A study of the leaching kinetics showed that the reaction conforms to the nuclear shrinkage model without solid product layer formation, and the calculated apparent activation energy is 22.16 kJ/mol.

Computer Implementation of the Dykstra-Parsons Method of Waterflood Calculation

One of the challenges of the petroleum industry is achieving maximum recovery from oil reservoirs. The natural energy of the reservoir, primary recoveries in most cases do not exceed 20%. To improve recovery, secondary recovery techniques are employed. With secondary recovery techniques such as waterflooding, an incremental recovery ranging from 15 to 25% can be achieved. Several theories and methods have been developed for predicting waterflood performance. The Dykstra-Parson technique stands as the most widely used of these methods. The authors developed a discrete, analytical solution from which the vertical coverage, water-oil ratio, cumulative oil produced, cumulative water produced and injected, and the time required for injection was determined. Reznik et al extended the work of Dykstra and Parson to include exact, analytical, continuous solutions, with explicit solutions for time, constant injection pressure, and constant overall injection rate conditions, property time, real or process time, with the assumption of piston-like displacement. This work presents a computer implementation to compare the results of the Dykstra and Parson method, and the Reznik et al extension. A user-friendly graphical user interface executable application has been developed for both methods using Python 3. The application provides an interactive GUI output for graphs and tables with the python matplotlib module, and Pandastable. The GUI was built with Tkinter and converted to an executable desktop application using Pyinstaller and the Nullsoft Scriptable Install System, to serve as a hands-on tool for petroleum engineers and the industry. The results of the program for both methods gave a close match with that obtained from the simulation performed with Flow (Open Porous Media). The results provided more insight into the underlying principles and applications of the methods.

Effecting a Pneumatic Operated Assembly, for an Improved Oil Recovery IOR, in Onshore Wells

As hydrocarbon formation continues, owing to its natural sourcing, technologies have continually emerged on how these hydrocarbons can be effectively produced at a commercial benchmark. Asides its natural drive system, the enhanced oil recovery methods have been one key approach that has been effected towards increasing hydrocarbon's production rate, from its reservoirs. The natural reservoir energy has allowed for about 10% production of original oil in place. And, extending a field's productive life by employing the secondary recovery has further improved production to 20 to 40%, with EOR amounting to about 30 to 60% production. This however, would tell of the impending need towards further developments on increasing upon this production rate. Hence, the approach on using a pneumatic operated assembly with considerations made on onshore wells. This paper seeks to depict a focal on "Pneumatic IOR (Improved Oil Recovery)" as a method to be effected for onshore wells towards improving its productivity. The pneumatic system uses compressed air, contained in a cylinder - through specialized tubing, alongside pressure control systems, that helps regulate the flow and amount of the compressed air; to propel a metallic bar that will act on the reservoir surface. A force of impact, which will induce vibrations inwards, is generated. The mechanical motion of the metal bars for which this compressed air acts upon will provide the travel force, which when it acts on the reservoir surface of interest, will induce geologic stresses. This stresses and vibrations are important constituents in increasing pressure, downhole. Thereby, enabling fluid flow upwards through the wellbore to the surface. And, this will proffer the necessary physics, needed for pressure development downhole, which will be of importance in improving Oil Recovery.

Assessment and Optimization of Waterflooding Performance in a Hydrocarbon Reservoir

In order to properly meet up with the ever-increasing demand for petroleum products worldwide, it has become increasingly necessary to produce oil and gas fields more economically and efficiently. Waterflooding is currently the most widely used secondary recovery method to improve oil recovery after primary depletion. A crucial component required to conduct an efficient waterflooding operation is an optimal production setting, most especially with respect to the amount of water involved. This research work has been carried out to develop a model that can be used to maximize oil recovery and minimize water production with the least amount and number of waterflood variables in order to minimize the secondary recovery investment cost. The gradient-based approach to optimize the production and net present value (NPV) from a waterflood reservoir using the flow rates or bottom hole pressures of the production wells as the controlling factors with the use of smart well technology was applied. In this approach, a variant of the optimal switching time technique was used in the optimization process to equalize the arrival times of the waterfront at multiple producers, thereby increasing the cumulative oil production. The optimization procedure involved maximizing the objective function (NPV) by adjusting a set of manipulated variables (flow rates). The optimal pressure profile of the waterflood scenario that gave the maximum NPV was obtained as the solution to the waterflood problem. The proposed optimization methodology was applied to a waterflood process carried out on a reservoir field developed by a five-spot recovery design in the Niger Delta area of Nigeria, which was used as a case study. The forward run was carried out with a commercial reservoir oil simulator. The results of the waterflood optimization revealed that an increase in the net present value of up to 9.7% and an increase in cumulative production of up to 30% from the base case could be achieved.

Distributed Event-Triggered Secondary Recovery Control for Islanded Microgrids

Distributed cooperative control methods are widely used in the islanded microgrid control system. To solve the deviation of frequency and voltage caused by the droop control, it is necessary to recovery the frequency and voltage to the rated value using a secondary control strategy. However, the traditional communication method relies on the continuous periodic one, which makes the communication burden of the islanded microgrid system heavy and conflicts with the actual operation of the power grid. Using the secondary recovery control method based on the distributed event-triggered method, we conserve communication resources by reducing the number of transmissions of sampled data and achieving the recovery control of the frequency and voltage and the original proportional sharing of active power. In addition, we analyze the stability of the distributed event-triggered strategy and build a microgrid system with MATLAB/Simulink to verify the effectiveness of the control method. Furthermore, we compare with a traditional periodic communication system and demonstrate the superiority of our distributed event-triggered approach.

Research on the method of repairing gas lift pipeline from FPSO Ruby - II to Pearl wellhead platform

Some offshore oilfields of Vietnam such as Bach Ho, Rong, Dai Hung, Ruby,… are at this moment in the secondary recovery stage. Gas lift production is one of the suitable methods in this period. Gas lift has proved itself as a more advantageous method in comparisons with other mechanical methods applied at Ruby oilfield. On the Pearl wellhead platform located in Ruby field, a gas lift system is installed to serve for the extraction of petroleum. The system is provided with compressed gas supplied from the FPSO Ruby II through a subsea 6 inches pipeline gas lift. For the sake of effective producing activity, it is a vital task to ensure the safety of this pipeline system during operations. In the case of failures, reparation should be applied immediately to minimize shutdown time and reduce the cost of troubleshooting. This article presents the “smart flange” technique to repair the gas lift pipeline system from the FPSO Ruby - II to the Pearl wellhead platform. Results of the work provide realistic knowledge to propose practical solutions to the maintenance and reparation of this system and thus, improve its operation.