Analytical Development of an Improved Inflow Performance Relationship (IPR) Model for Solution Gas Drive Reservoirs

Attempts had been made by many authors to develop an inflow performance relationship model suitable for solution gas drive reservoirs. However, they have not been as successful as most of the developed models suffer from certain degrees of inaccuracies and this necessitates the need for an improved model as the economic analysis of an oilfield greatly depends on the ability to accurately forecast future productions. Therefore, the objective of this research is to develop an improved inflow Performance Relationship model for solution gas reservoirs by employing a purely analytical approach and also compare the performance of the developed model with that of the existing IPR models (Vogel, Wiggins, Fetkovich, and Klins and Majher). A series expansion of the pseudo-steady state solution of the equation that governs fluid flow in reservoirs of radial geometry is obtained using Taylor's method and the infinite series obtained is truncated after a reasonable number of terms to ensure high degree of accuracy while also avoiding computational complexity. Moreover, the unknown coefficients in the truncated series were determined using the available reservoir fluid data. Finally, statistical analysis was carried out to determine the degree of deviation of the new and existing IPR models from the actual IPR. This analysis shows that the improved model (with an average coefficient of determination of 0.97) outperforms the existing IPR models to which it was compared. Therefore, the improved model is recommended for situations where extreme accuracy is of utmost importance. Doi: 10.28991/HEF-2021-02-02-04 Full Text: PDF

Physical Simulation and Mathematical Model of the Porous Flow Characteristics of Gas-Bearing Tight Oil Reservoirs

The separation of solution gas has great influence on the development of gas-bearing tight oil reservoirs. In this study, physical simulation and high-pressure mercury intrusion were used to establish a method for determining the porous flow resistance gradient of gas-bearing tight oil reservoirs. A mathematical model suitable for injection–production well networks is established based on the streamline integral method. The concept of pseudo-bubble point pressure is proposed. The experimental results show that as the back pressure decreases from above the bubble point pressure to below the bubble point pressure, the solution gas separates out. During this process, the porous flow resistance gradient is initially equal to the threshold pressure gradient of the oil single-phase fluid, then it becomes relatively small and stable, and finally it increases rapidly and exponentially. The lower the permeability, the higher the pseudo-bubble point pressure, and the higher the resistance gradient under the same back pressure. For tight reservoirs, the production pressure should be maintained above the pseudo-bubble point pressure when the permeability is lower than a certain value. When the permeability is higher than a certain value, the pressure can be reduced below the pseudo-bubble point pressure, and there is a reasonable range. The mathematical results show that after degassing, the oil production rate and the effective utilization coefficient of oil wells decline rapidly. These declines occur later and have a flat trend for high permeability formations, and the production well pressure can be reduced to a lower level. Fracturing can effectively increase the oil production rate after degassing. A formation that cannot be utilized before fracturing because of the blocked throats due to the separation of the solution gas can also be utilized after fracturing. When the production well pressure is lower than the bubble point pressure, which is not too large, the fracturing effect is better.

Adsorption Studies of Waterborne Trihalomethanes Using Modified Polysaccharide Adsorbents

The adsorptive removal of trihalomethanes (THMs) from spiked water samples was evaluated with a series of modified polysaccharide adsorbents that contain β-cylodextrin or chitosan. The uptake properties of these biodegradable polymer adsorbents were evaluated with a mixture of THMs in aqueous solution. Gas chromatography employing a direct aqueous injection (DAI) method with electrolytic conductivity detection enabled quantification of THMs in water at 295 K and at pH 6.5. The adsorption isotherms for the polymer-THMs was evaluated using the Sips model, where the monolayer adsorption capacities ranged between 0.04 and 1.07 mmol THMs/g for respective component THMs. Unique adsorption characteristics were observed that vary according to the polymer structure, composition, and surface chemical properties. The modified polysaccharide adsorbents display variable molecular recognition and selectivity toward component THMs in the mixed systems according to the molecular size and polarizability of the adsorbates.

Analysis of Lateral Fluid Gradients From DFA Measurements and Simulation of Reservoir Fluid Mixing Processes Over Geologic Time

Downhole fluid analysis (DFA) is one pillar of reservoir fluid geodynamics (RFG). DFA measurements provide both vertical and lateral fluid gradient data. These gradients, especially the asphaltene gradient derived from accurate optical density (OD) measurements, are critical in thermodynamic analysis to assess equilibration level and identify RFG processes. Recently, an RFG study was conducted using DFA and laboratory data from an oil field in the Norwegian North Sea. Fluid OD gradients show equilibrated asphaltenes in most of the reservoir, with a lateral variation of 20%. This indicates connectivity, which is confirmed by three years of production data. Two outliers are off the asphaltene equilibrium curve implying isolated sections, one each on the extreme east and west flank. Their asphaltene fraction varies by a factor of six. Such a difference reveals that different charge fluids entered the reservoir, and the equilibrated asphaltenes are the result of an after-charge mixing process. Meanwhile, different gas-oil contacts (GOCs) exist in the reservoir, indicating a lateral solution-gas gradient. Geochemistry analysis shows the same level of mild biodegradation in all the fluid samples, including those from two isolated sections. This means that biodegraded oil spills into the whole reservoir with little or no in-reservoir biodegradation. Furthermore, lateral asphaltene gradients at different times after charge have been preserved; it was a factor of six in asphaltenes content initially and is now 20% in the present day. This unique data set provides a valuable constraint to simulate reservoir fluid after-charge mixing processes to present day, aiming to investigate the factors impacting the evolution of lateral composition gradients in geologic time in a connected reservoir. Numerical simulations were performed over geologic time in reservoirs filled by oil with a lateral density gradient, which imitates the lateral compositional gradients in the gas-oil ratio (GOR) and asphaltenes measured in the above oil field. Simulations show that this lateral gradient creates lateral differential pressures and causes a countercurrent fluid flow forming a convection cell. In reservoirs with realistic vertical-to-horizontal aspect ratios, such fluid flows are not rapid, and lateral gradients can be partially retained in moderate geologic times. Additionally, diffusion was included in the simulation. The reservoir model was initialized with two GOCs producing subtle lateral GOR and density gradients. The simulated mixing process transports gas from higher GOR regions to lower GOR regions and reduces the GOC difference. However, the flux of solution gas transport is small. Consequently, we conclude that lateral GOR and asphaltene gradients can persist for moderate geologic time, which is consistent with observation from the field.

Natural Dumpflood in Malaysia Succeeds as Low-Cost Offshore Oil-Recovery Method

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 196498, “First Natural Dumpflood in Malaysia: A Successful Breakthrough for Maximizing Oil Recovery in an Offshore Environment With Low-Cost Secondary Recovery,” by Muhammad Abdulhadi, SPE, Toan Van Tran, SPE, and Najmi Mansor, Dialog Group, et al., prepared for the 2019 SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 29–31 October. The paper has not been peer reviewed. The complete paper describes the first successful implementation of natural dumpflooding offshore Malaysia as a case study to provide insight into the value of using the approach to maximize oil recovery in a mature field, particularly in a low-margin business climate. Background Field B, located offshore Balingian province approximately 80 km northwest of Bintulu, has a water depth of 90 ft and is highly compartmentalized and faulted, with almost 100 faults present. The field features three subfields further divided into nine major fault compartments. Eight primary reservoirs exist, with more than 20 subreservoirs stacked atop one another with multiple drive mechanisms, including water drive, gas-cap drive, and solution gas drive. Several of these subreservoirs are thick sands between which communication exists through juxtapositions, shared gas caps, or aquifer. Other subreservoirs are isolated by thin layers of shale apparent in certain wells but absent in others. The high complexity of Field B requires any opportunity identified to be thoroughly evaluated and examined before execution. Field B is a moderately sized field discovered in 1976, with production commencing in 1984. During the 30 years of oil production, the field peaked at 30,000 B/D in 1990 and dipped to 3,000 B/D in late 1999. The facilities consist of four drilling platforms, a processing platform, and a compressor platform. A total of 48 wells were drilled in the field, with most wells completed as dual-string producers. The recovery factor (RF) of the reservoirs ranges from 10% for solution gas drive to 50% for strong water drive. The behaviors of these reservoirs are starkly different. The solution gas-drive reservoirs have poor-quality sand (less than 200 md), a low productivity index, limited sand thickness (less than 30 ft), limited sand connectivity, and sharp pressure decline after 2 to 3 years of production. The water-drive reservoirs, however, have good-quality sand (up to 5,000 md), a high productivity index, thick sand (greater than 40 ft), extensive sand connectivity, and limited pressure decline. The stark differences in the reservoirs’ behavior further complicate field management. The field currently is in late life, with recovery to date of 19% with an RF of 23%. Most of the water-drive reservoirs are already swept up to the crest, while the solution gas-drive reservoirs are depleted nearly to abandonment pressure. After 30 years of production, the total field water cut was at 80%, while oil production was approximately 5,000 B/D, signifying the diminishing economic life of the field.

Reaction Mechanism for Methane-to-Methanol in Cu-SSZ-13: First-Principles Study of the Z2[Cu2O] and Z2[Cu2OH] Motifs

As transportation continues to increase world-wide, there is a need for more efficient utilization of fossil fuel. One possibility is direct conversion of the solution gas bi-product CH4 into an energy-rich, easily usable liquid fuel such as CH3OH. However, new catalytic materials to facilitate the methane-to-methanol reaction are needed. Using density functional calculations, the partial oxidation of methane is investigated over the small-pore copper-exchanged zeolite SSZ-13. The reaction pathway is identified and the energy landscape elucidated over the proposed motifs Z2[Cu2O] and Z2[Cu2OH]. It is shown that the Z2[Cu2O] motif has an exergonic reaction path, provided water is added as a solvent for the desorption step. However, a micro-kinetic model shows that neither Z2[Cu2O] nor Z2[Cu2OH] has any notable activity under the reaction conditions. These findings highlight the importance of the detailed structure of the active site and that the most stable motif is not necessarily the most active.