High Gas-oil Ratio Research Articles

Main Challenges and Strategies to Develop Santos Basin Sub-Salt Fields, Deep water Brazil

Abstract Santos basin of Brazil is a hot area of oil and gas exploration and development in the world. Many sub-salt oil fields have been discovered in recent years. The reservoirs are mainly composed of microbial carbonate rocks with strong heterogeneity, which has developed a variety of storage space types. The fluid is complex with high gas oil ratio and CO2 content. The re-injection of produced gas brings uncertainty to the production performance and the stability of facilities. The project investment is huge due to many factors such as deep-water, deep buried and far away from the coastline. The complexity of reservoir and high investment of project make the economic and effective development of reservoir full of great challenges. This paper describes the development strategies of Brazil’s sub-salt deep-water oilfield and the main successful methods to maximize recovery and profits under uncertain conditions. It includes the following three aspects: (1) abundant information acquisition to reduce the main uncertainties; (2) development plan with robustness and flexibility to deal with potential risks; (3) multidisciplinary comprehensive research to evaluate reservoir mode and development mode.

Production optimization in a fractured carbonate reservoir with high producing GOR

The Gas-Oil Ratio (GOR) is a crucial production parameter in oil reservoirs. An increase in GOR results in higher gas production and lower oil production, potentially leading to well shut-ins due to economic infeasibility. This study focuses on a real fractured oil field that requires urgent production operations to reduce the producing GOR. In this study, the static model for the field was developed using commercial software, involving steps such as data collection, fault modeling, meshing, and statistical analysis to prepare for dynamic simulation. The dynamic model incorporates geometry, gridding, and rock properties from the static model, utilizing a dual-porosity approach for the naturally fractured reservoir and the Peng-Robinson equation for fluid phase behavior. Initial reservoir conditions, production history, and rock-fluid interactions were defined, with relative permeability curves indicating a water-wet reservoir and low critical gas saturation affecting the GOR. To better understand the relationship between reservoir and production parameters, a detailed sensitivity analysis was performed using the Response Surface Methodology (RSM). Following the sensitivity analysis, a history matching process was conducted using the Designed Exploration and Controlled Evolution (DECE) optimizer to validate the model for future forecasts. Six operational scenarios were defined to decrease the production GOR and enhance final recovery from the field. The results indicate that the water injection scenario is effective in preventing the GOR increase by maintaining reservoir pressure, thereby sustaining production over a longer period. This scenario also improves oil recovery by approximately 6% compared to the base case. Finally, optimization was carried out using the DECE optimizer for each scenario to fine-tune the operational parameters. The goal was to maximize oil revenue for each scenario during the optimization process. This study stands out as one of the few that provides a comprehensive analysis of production behavior and development planning for a real fractured reservoir with high producing GOR.

Simulation of lower Cambrian oil and gas generation and phase evolution process in ZH1 of Tazhong area

The Lower Cambrian petroleum system in the Tarim Basin has undergone multiple periods of tectonic movements, leading to successive hydrocarbon expulsion events and adjustments. The complex process of hydrocarbon accumulation occurred under deep burial conditions, persisting at depths of nearly 6,000 m over an extended period. This has resulted in the current occurrence of various phases including light oil, condensate, and gas in the deep-ultradeep strata of the Tarim Basin. The intricacies of formation of hydrocarbon accumulations and phase evolution have posed challenges to understanding the accumulation mechanisms and enrichment patterns of the Cambrian in the Tarim Basin, consequently lowering the success rate of oil and gas exploration. Such characteristics of multi-stage accumulation and adjustment are prevalent in deep hydrocarbon systems. Therefore, based on data from Well ZH1 in the Tazhong Uplift, combined with basin simulation, Compositional kinetics model, and PVT performance simulation, this study investigates the hydrocarbon generation and phase evolution processes in the deep hydrocarbon systems of the Tazhong Uplift. The results indicate that Well ZH1 entered the hydrocarbon generation peak during the Late Ordovician, followed by secondary cracking as the predominant hydrocarbon evolution process. Hydrocarbon fluids within the Lower Cambrian reservoir transitioned into the condensate phase towards the end of the Cambrian, with increasing depth resulting in higher gas-oil ratios and a decreasing trend in viscosity and density.

High-Pressure Separation: New Technology in the Subsea Toolbox

_ Subsea production systems have come far in the more than 60 years since the first deployment in the US Gulf of Mexico, helping many countries unlock their offshore hydrocarbon riches in the years that followed. For Brazil, it was a combination of advances in subsea technologies and floating production, storage, and offloading vessel (FPSO) designs that supported the growth of its offshore oil and gas prowess. From those first forays into the Sergipe-Alagoas basin in the northeast during the 1970s, the country’s offshore oil and gas footprint has grown significantly, with today’s production from the pre-salt Campos and Santos basins—located farther from shore and in much deeper water—launching state-run oil company Petrobras to a top spot among the ranks of global producers. The ongoing development of its offshore fields will continue to boost the country’s oil and natural gas production in 2024. Since December 2022, five FPSOs have been brought online, with four installed in 2023 delivering record output. The fifth one—the FPSO Sepetiba—delivered a New Year’s Day surprise when it came online at Mero 2 oil field on 31 December 2023. HISEP, a new subsea technology currently being readied for pilot testing, could potentially ensure continued future production of the Mero field and others by capturing CO2-rich dense gases directly from the wellstream and reinjecting it into the reservoir. The technology also frees up much-needed space and reduces weight on the FPSO’s topside by moving the separation process to the seafloor. Challenges and Solutions Brazil’s challenging offshore pre-salt region—first explored by Petrobras in 2005—contains estimated reserves of 30 to 40 billion BOE and comes with an extensive list of development challenges. Its Santos Basin, for example, lies in ultradeep water with hydrocarbon reservoirs located at extreme depths ranging from 5500 to 7600 m below sea level and under salt layers more than 2000 m thick. But the challenges do not end there. Managing the basin’s high gas/oil ratio (GOR) and CO2 content leaves a significant operational footprint. In OTC 29762, authors from Petrobras noted that developing the pre-salt reservoirs requires “large production facilities with complex gas processing plants that limit the oil processing and storage capacities.” In the paper presented at the 2019 Offshore Technology Conference (OTC) Brasil, the authors said that the gas processing plants for some pre-salt fields with high production indexes, GOR, and CO2 content account for nearly 60% of the total FPSO topsides area. The Santos Basin is home to the Mero oil field, the country’s third-largest pre-salt field and the first under a production-sharing contract awarded to the Petrobras-led Libra Consortium. The field is considered one of the largest hydrocarbon discoveries in the past decade, covering about 320 km2 of the Libra block and with a net pay zone reaching 420 m filled with 29 °API oil and high productivity, according to Ana Luiza Neder, et al. (OTC 32784).

The Impact of Autonomous Inflow Control Valve on Improved Oil Recovery in a Thin-Oil-Rim Reservoir

Summary Oil production from thin-oil-rim fields can be challenging as such fields are prone to gas coning. Excessive gas production from these fields results in poor production and recovery. Hence, these resources require advanced recovery methods to improve the oil recovery. One of the recovery methods that is widely used today is advanced inflow control technology such as autonomous inflow control valve (AICV). AICV restricts the inflow of gas in the zones where breakthrough occurs and may consequently improve the recovery from thin-oil-rim fields. This paper presents a performance analysis of AICVs, passive inflow control devices (ICDs), and sand screens based on the results from experiments and simulations. Single- and multiphase-flow experiments are performed with light oil, gas, and water at typical Troll field reservoir conditions (RCs). The obtained data from the experiments are the differential pressure across the device vs. the volume flow rate for the different phases. The results from the experiments confirm the significantly better ability of the AICV to restrict the production of gas, especially at higher gas volume fractions (GVFs). Near-well oil production from a thin-oil-rim field considering sand screens, AICV, and ICD completion is modeled. In this study, the simulation model is developed using the CMG simulator/STARS module. Completion of the well with AICVs reduces the cumulative gas production by 22.5% and 26.7% compared with ICDs and sand screens, respectively. The results also show that AICVs increase the cumulative oil production by 48.7% compared with using ICDs and sand screens. The simulation results confirm that the well completed with AICVs produces at a beneficial gas/oil ratio (GOR) for a longer time compared with the cases with ICDs and sand screens. The novelty of this work is the multiphase experiments of a new AICV and the implementation of the data in the simulator. A workflow for the simulation of AICV/ICD is proposed. The simulated results, which are based on the proposed workflow, agree with the experimental AICV performance results. As it is demonstrated in this work, deploying AICV in the most challenging light oil reservoirs with high GOR can be beneficial with respect to increased production and recovery.

Case Study: Gas Lift-Plunger Lift Combination Creates Full Life Cycle Production Solution

From the Wolfcamp and Bone Spring in the Permian Basin to the Niobrara and Codell in the Denver-Julesburg Basin, lateral lengths of 10,000 ft or greater are becoming the norm in tight-oil resource plays (Rassenfoss 2022; Addison, 2021; S&P 2021). From a production standpoint, longer laterals equate to greater stimulated rock volume per wellbore. That means higher flow rates, but it can also introduce more dynamic behavior and steeper production declines. The extended-well trajectories are often accompanied by high dogleg severities, high gas/oil ratios (GORs), and sand and solids production (Whitfield 2023; S&P 2021). Efficiently accommodating all of these factors while cost-effectively managing natural declines over time can be a challenge for any single artificial lift method. However, the combination of gas lift and plunger lift technology gives operators a flexible option to optimize production beginning with initial peak flow rates at the start of production and extending all the way through to depletion. This “full life cycle” approach encompasses three distinct phases that collectively span the entire slope of the tight-oil well decline curve: - Gas lift in early to mid-life (from first production to ±300 B/D) - Plunger-assisted gas lift (PAGL) in the mid- to late-life plateau (from ±300 to ±100 B/D) - Plunger lift in late life (from ±100 B/D to last oil) An artificial lift approach leveraging gas lift, PAGL, and plunger lift at different points along the production timeline aggregately brings the key advantages of all three to bear in horizontal tight-oil wells, including - Gas lift’s ability to mimic natural reservoir flow, lifting fluids to surface by reducing the flowing tubing pressure and creating differential pressure between the reservoir and wellbore. Gas lift handles an array of production rates (up to 2,000-plus B/D) and well characteristics—including high GORs and solid content—and can adapt to rapidly changing conditions during early well life. - PAGL’s ability to increase reservoir drawdown, stabilize production, and reduce system surging as production diminishes to the point where gas lift starts to become inefficient in the mid-life phase. - Plunger lift’s ability to use pressure buildup below the plunger to carry accumulated fluids to surface at rates as low as a few B/D, requiring no external power source to surface the plunger. The plunger creates a “swabbing effect” as it passes through the tubing that helps draw fluids from perforated intervals while keeping tubing swept of paraffin, scale, asphaltene, sand, etc.

Simulation studies on optimizing oil productivity in oil rim reservoirs under gas cap blow down production strategy

Gas cap blow down strategy is normally deployed for Ultra-thin oil rim reservoirs with huge gas caps due to extremely high gas oil ratios from wells in such reservoirs. The current state leads to loss of production from the oil reserves due to high initial reservoir pressure thus, reducing its net present value. Data on important factors essential to the productivity of oil rim reservoirs are used to build a heterogeneous ultra-thin reservoir with a time step of 10,000 days using the Eclipse software and its embedded correlations. The reservoir is subjected to a gas cap blowdown via a gas well, then an oil well is initiated into the model at onset and after time periods of 2000, 4000, 6000 and 8000 days to estimate the oil recovery. It is expected that due to the large nature of the gas cap, pressure decline will be drastic and leading to a low oil recovery, hence the injection of water and gas at different rates at the periods indicated. The results indicate an oil recovery of 4.3% during gas cap blow down and 10.34% at 6000 days. Peak oil recoveries of 12.64% and 10.80% are estimated under 30,000 Mscf/day at 4000 days and 1000 stb/day at 6000 days respectively. This shows an incremental oil recovery of 8.34% and 6.5% over that recorded during gas cap blow down. The results also indicate that the gas production at those periods was not greatly affected with an estimated increment of 257 Bscf recorded during 30,000 Mscf/day at 4000 days. All secondary injection schemes at the respective time steps had positive impact on the overall oil recoveries. It is recommended that extra production and injection wells be drilled, enhanced oil recovery options and injection patterns be considered to further increase oil recovery.

Development and Application of New Multifunctional Foaming Agents to Enhance Production in Oil Wells

Summary Maintaining or increasing production from wells in mature oil reservoirs with high pressure, temperature, brine hardness, and salinity is a significant technological and economic challenge. These wells usually produce with a high gas-oil ratio and large water cuts and often operate with gas lift systems. This work focuses on the development and application of new multifunctional foaming agents (MFAs) to enhance production from oil wells under these conditions. The MFAs were developed based on molecular design and laboratory studies, which demonstrated that they can be used with water cuts exceeding 30% and in the presence of salinity and hardness levels up to 400,000 ppm and 180,000 ppm, respectively. Furthermore, these agents remain stable at temperatures up to 180°C. The production/lift efficiency of the MFAs was evaluated using two novel dynamic laboratory methods that are conducted close to the wellhead and at downhole conditions of temperature and pressure, respectively. The experimental results demonstrate a significant enhancement in the liquid production efficiency, with some cases showing an increase from no production to as much as 44% when the MFAs were used. The laboratory tests were also used to optimize the MFA type and concentration in the design of a field application. The field test was conducted in three oil wells with water cuts ranging from 40% to 90%, depths exceeding 5000 m, bottomhole temperature around 150°C, and brine hardness and salinity up to 180,000 ppm and 310,000 ppm, respectively. This is the first reported field test of MFAs for production enhancement under such challenging conditions. The MFA was coinjected with gas lift via the annulus. The MFA mixed with reservoir fluids in the tubing and generated foam downhole with concentrations ranging from 160 ppm to 750 ppm. The rheological properties of the foam were designed to prevent pressure losses and the formation of stable foam or emulsions at surface facilities. The field tests demonstrated that the MFA was able to increase oil production at a fixed gas lift injection flow rate. Alternatively, it was able to reduce lift gas consumption while maintaining or even increasing the original oil production.

Modeling of the movement of rich gas in a porous medium in immiscible, near miscible and miscible conditions

Gas injection is one of the most common enhanced oil recovery techniques in oil reservoirs. In this regard, pure gas, such as carbon dioxide (CO2), nitrogen (N2), and methane (CH4) was employed in EOR process. The performance of pure gases in EOR have been investigated numerically, but till now, numerical simulation of injection of rich gases has been scared. As rich gases are more economical and can result in acceptable oil recovery, numerical study of the performance of rich gases in EOR can be an interesting subject. Accordingly, in the present work the performance of rich gases in the gas injection process was investigated. Methane has been riched in liquefied petroleum gas (LPG), natural gas liquid (NGL), and Naphtha. Afterwards, the process of gas injection was simulated and the effect of injection fluids on the relative permeability, saturation profile of gas, and fractional flow of gas was studied. Our results showed that as naphtha is a heavier gas than the two other ones, IFT of oil-rich gas with naphtha is lower than other two systems. Based our results, gas oil ratio (GOR) and injection pressure did not affect the final performance of injection gas that has been riched in NGL and LPG. However, when GOR was 1.25 MSCF/STB, rich gas with naphtha moved with a higher speed in the domain and the relative permeability of each fluid and fractional flow of gas were affected. The same result was achieved at higher injection pressure. When injection pressure was 2000 psi, movement of gas with higher speed in the domain, alteration of relative permeability and changes in the fractional flow of gas were obvious. Therefore, based on our result, injection of naphtha with low pressure and high GOR was suggested for considered oil.

Carbon dioxide capture, enhanced-oil recovery and storage technology and engineering practice in Jilin Oilfield, NE China

This paper systematically presents the established technologies and field applications with respect to research and engineering practice of CO2 capture, enhanced oil recovery (EOR), and storage technology in Jilin Oilfield, NE China, and depicts the available series of supporting technologies across the industry chain. Through simulation calculation + pilot test + field application, the adaptability of the technology for capturing CO2 with different concentrations in oilfields was confirmed. The low energy-consumption, activated N-methyl diethanolamine (MDEA) decarburization technology based on a new activator was developed, and the operation mode of CO2 gas-phase transportation through trunk pipeline network, supercritical injection at wellhead, and produced gas-liquid separated transportation was established. According to different gas source conditions, liquid, supercritical phase, high-pressure dense phase pressurization technologies and facilities were applied to form the downhole injection processes (e.g. gas-tight tubing and coiled tubing) and supporting anti-corrosion and anti-blocking techniques. In the practice of oil displacement, the oil recovery technologies (e.g. conical water-alternating-gas injection, CO2 foam flooding, and high gas-oil ratio CO2 flooding) and produced fluid processing technologies were developed. Through numerical simulation and field tests, three kinds of CO2 cyclic injection technologies (i.e. direct injection, injection after separation and purification, and hybrid injection) were formed, and a 10×104 m3/d cyclic injection station was constructed to achieve “zero emission” of associated gas. The CO2 storage safety monitoring technology of carbon flux, fluid composition and carbon isotopic composition was formed. The whole-process anti-corrosion technology with anticorrosive agents supplemented by anticorrosive materials was established. An integrated demonstration area of CO2 capture, flooding and storage with high efficiency and low energy-consumption has been built, with a cumulative oil increment of 32×104 t and a CO2 storage volume of 250×104 t.

The Geoscience Frontier of Gulong Shale Oil: Revealing the Role of Continental Shale from Oil Generation to Production

The clay mineral content of Daqing Gulong shale is in the range of about 35%–45%, with particle sizes less than 0.0039 mm. The horizontal fluidity of oil in Gulong shale is poor, with near-zero vertical flowability. As a result, Gulong shale has been considered to lack commercial value. In recent years, however, interdisciplinary research in geoscience, percolation mechanics, thermodynamics, and surface mechanics has demonstrated that Gulong shale oil has a high degree of maturity and a high residual hydrocarbon content. The expulsion efficiency of Gulong shale in the high mature stage is 32%–48%. Favorable storage spaces in Gulong shale include connecting pores and lamellar fractures developed between and within organic matter and clay mineral complexes. The shale oil mainly occurs in micro- and nano-pores, bedding fractures, and lamellar fractures, with a high gas–oil ratio and medium–high movable oil saturation. Gulong shale has the characteristics of high hardness, a high elastic modulus, and high fracture toughness. This study achieves breakthroughs in the exploration and development of Gulong shale, including the theories of hydrocarbon generation and accumulation, the technologies of mobility and fracturing, and recoverability. It confirms the major transition of Gulong shale from oil generation to oil production, which has extremely significant scientific value and application potential for China’s petroleum industry.

A novel model for the solution gas-oil ratio suitable for CO2-rich reservoir fluids

Reservoir fluids with high carbon dioxide (CO2) fraction in their compositions have been the focus of growing attention due to the increasing importance of CO2 injection in subsurface reservoirs for enhanced oil recovery and carbon capture and sequestration. Their thermophysical behavior has unique characteristics when compared to the behavior of reservoir fluids with low CO2 content. However, empirical models that are extensively used to model the reservoir fluid behavior originally did not cover this particular composition, and their extrapolation to this subset of fluids has been little explored in the literature. This study first evaluates the performance of nine such traditional empirical models for the solution gas-oil ratio (Rs) property of CO2-rich reservoir fluids. Predictions are compared against an experimental database containing 1457 points. The database covers reservoir fluids with CO2 molar content ranging from 0% to 38% and gas-oil ratio (GOR) from 75 scf/STB to 2487 scf/STB. Previous models’ results show rather poor predictions for reservoir fluids with high CO2 content, with high deviations from experimental data and inconsistencies. Therefore, this paper proposes a general Rs model that is able to model reservoir fluids with high CO2 content and high GOR with significant superior performance. The new Rs model predictions present a mean absolute percentage error (MAPE) of 6% and a root mean square error (RMSE) of 27 scf/STB for the aforementioned experimental values. For a test (holdout) dataset containing 173 data points from novel reservoir fluid compositions, the MAPE was 8% and the RMSE was 71 scf/STB. The proposed model outperforms the existing models on both training and test sets, even for reservoir fluids with low or no CO2 content.

Experimental Study on the Sweep Law of CO2 Miscible Flooding in Heterogeneous Reservoir in Jilin

It is very important to effectively describe the sweep characteristics of CO2 miscible flooding based on physical models for actual reservoir development. In this study, based on the geological characteristics of the Jilin ultra-low permeability reservoir, which has significant vertical heterogeneity, a two-dimensional double-layer heterogeneous visualization model with a permeability contrast of 10 and thickness contrast of 2 was designed to perform experimental research on the sweep law of CO2 miscible flooding with an injection-production mode of “united injection and single production”. With the goal of determining the obvious differences in the gas absorption capacity and displacement power of the two layers, the CO2 dynamic miscible flooding characteristics were comprehensively analyzed, and the sweep law of CO2 miscible flooding, including the oil and gas flow trend, migration direction of the oil–gas interface, and distribution characteristics of the miscible zone, was further studied in combination with the oil displacement effect. In this experiment, the gas absorption capacity was the key factor affecting the sweep efficiency of the CO2 miscible flooding. Under the combined influence of the internal and external control factors of the reservoir thickness, permeability, and injection-production mode, the gas absorption capacity of the high-permeability layer was much greater than that of the low-permeability layer, resulting in the retention of a large amount of remaining oil in the low-permeability layer, which effectively displaced and swept the oil in the high-permeability layer. The gas absorption capacity of the reservoir, gravitational differentiation, and miscible mass transfer were key factors affecting the migration of the oil–gas interface and distribution of the miscible zone. The entire displacement process could be divided into three stages: ① The gas-free rapid oil production stage, which was dominated by the displacement; ② the low gas–oil ratio stable oil production stage, which was jointly affected by the displacement and miscible mass transfer; and ③ the high gas–oil ratio slow oil production stage, which was dominated by the effect of CO2 carrying.

Oxidization characteristics and thermal miscible flooding of high pressure air injection in light oil reservoirs

Physical modeling, numerical simulation and field case analysis were carried out to find out the subsurface thermal oxidation state, thermal oxidation front characteristics and production dynamic characteristics of high pressure air injection thermal oxidation miscible flooding technology. The lighter the composition and the lower the viscosity of the crude oil, the lower the fuel consumption and the combustion temperature are. The thermal oxidation front of light oil and volatile oil can advance stably, and a medium-temperature thermal oxidation stable displacement state can be formed in the light oil reservoir under high pressure conditions. With strong thermal gasification and distillation, light oil and volatile oil are likely to form a single phase zone of gasification and distillation with thermal flue gas at the high-temperature and high-pressure heat front, finally, an air-injection thermal miscible front. In light oil reservoirs, the development process of high-pressure air-injection thermal miscible flooding can be divided into three stages: boosting pressure stage, low gas-oil ratio and high-efficiency stable production stage and high gas-oil ratio production stage. Approximately 70% of crude oil is produced during the boosting pressure stage and low gas-oil ratio high-efficiency and stable production stage.

A comprehensive performance evaluation methodology for miscible gas flooding: A case study in a giant carbonate reservoir in Middle East

This work focuses on a typical low-permeability carbonate reservoir in Middle East that has been developed by miscible hydrocarbon (HC) gas flooding for more than 10 years. The oilfield is now suffering from gas channeling, high gas/oil ratio (GOR), and invalid gas circulation. To figure out the reasons and propose an optimized development plan, it is necessary to accurately determine the characteristics and behavior of miscible gas flooding. To achieve this, a comprehensive performance evaluation method for miscible gas flooding is established in this work by integrating production data, inter-well gas tracer test, saturation surveillance, pressure surveillance, minimum miscibility pressure (MMP) variation, and streamline simulation. The following miscible HC gas flooding characteristics are interpreted, including typical gas flow path, miscibility behavior, major controlling factors impacting performance, and the main challenges of the current development scheme, which provides a fundament for proposing mitigation plan. By using this evaluation method, the behavior of gas flow in the ongoing miscible flooding process is precisely characterized, which is a “gravity override-gas coning” mode in which gas override is formed by an upward injected gas flow and then gas flows through gas cap to producers that leads to gas coning, resulting in high GOR and invalid gas circulation. This flow mode mainly resulted from the unsatisfied miscibility that led to gas escaping from miscible phase and gas channeling. Furthermore, it was found out that pressure difference is the dominating factor for gas channeling. In addition, we also found that MMP varies during HC gas injection process due to the change in the oil composition, which emphasizes the importance of recovering and maintaining pressure. Based on these findings obtained from extensive dynamic performance analysis and numerical simulations, an optimization strategy is finally proposed for improving the performance of miscible HC gas flooding.

A Semi-Analytical Approach for Calculating Productivity Index in Vertical Flowing Well: High Gas-Oil Ratio Field Data as a Case Study

Abstract The concurrent transport of hydrocarbon, water, and most times solids ensues all through the production system concerned in transporting multiphase fluid from the producing reservoir zone to the wellbore and then to surface. The flow capacity of a well can be estimated through the inflow performance relationship (IPR) that essentially depends on productivity index (PI). Productivity index is a vital and indispensable oil and gas industry tool for forecasting the deliverability and helps in economic feasibility studies of the well. The lack of a correct model for bottom-hole flowing pressure calculation has always been a challenge and results in erroneous estimate of productivity index of a production well. Numerous models on bottom-hole flowing pressure in wells have been recounted in different literatures over the years. Many of the earlier works were based on steady-state flow assumption, likewise not all the constituent terms that practically influence flow behavior of fluid in pipe were considered in derivation of the past models. In the present work, an enhanced semi-analytical model for determining well bottom-hole flowing pressure is offered where all the constituent terms practically influence flow behavior of fluid in pipe and employed in building the new model for estimating productivity index in a vertical well. This article builds a semi-analytical model for predicting flowing pressure at every flow transition period evidencing the water hammer pressure fluctuations often experienced at the start-up operation. Subsequently, the time-dependent flowing pressure obtained from the newly derived model was used to estimate the productivity index using high gas-oil ratio surface data from Niger Delta field. The result of productivity index obtained at steady-state period shows that the average prediction percentage error of the current approach is reduced to 3.78% compared to previously derived steady-state-based model by Guo et al. (2007, “A Rigorous Composite-IPR Model for Multilateral Wells,” Society of Petroleum Engineers, SPE 100923, San Antonio, TX, p. 11), Guo (2001, “Use of Wellhead-Pressure Data to Establish Well-Inflow Performance Relationship,” SPE Eastern Regional Meeting, Canton, OH, Oct., SPE 72372, p. 7), and Adesina et al. (2018, “A Realistic Model for Estimating Productivity Index of Vertical Well Using Wellhead Data,” Society of Petroleum Engineers, SPE-193506-MS) that, respectively, report as 18.59%, 5.23%, and 3.96%. The factors that influence the magnitude of water hammer pressure fluctuation at the start-up period have been identified through the derivation. The semi-analytical model improves the prediction accuracy and aids the reliability of design to avoid incidence of pipe burst due to pressure peak and serves as a tool to analyze the well performance.

The Impact of Carbon Capture Storage and Utilization on Energy Efficiency, Sustainability, and Production of an Offshore Platform: Thermodynamic and Sensitivity Analyses

Abstract Oil and gas production in FPSOs (floating, production, storage, and offloading) faces a dual challenge: meeting variation in energy demand while decreasing its negative environmental impact. The present article integrates thermodynamic analysis of oil and gas processing plants and screening analysis to determine the most important operational parameters to lower energy demand and increase efficiency and production. Therefore, the main goals of this study are to identify the contribution of the total effect of the operating parameters in an FPSO with CCUS (CO2 capture, utilization, and storage). Twenty-seven thermodynamic and structural design variables are selected as input parameters for the sensitivity analyses. Four machine learning-based screening analysis algorithms such as smooth spline-analysis of variance (SS-ANOVA), PAWN, gradient boosting machine (GBM), and Morris are adapted to achieve the following objectives: (1) overall power consumption of FPSO, (2) CO2 removal efficiency of carbon capture and storage (CCS), (3) power consumption of CCS, and (4) total oil production. The influence of three real crude oil compositions with variations in gas–oil ratio (GOR) and CO2 content is assessed. The combination of thermodynamic and screening analyses showed that the optimal operating pressure parameters of CCS significantly reduce the energy consumption and exergy destruction of the key main and utility plants. Furthermore, the results indicated that total power consumption, CCS efficiency, and CCS power consumption are much more sensitive to the CO2 content of the fluid reservoir than GOR, while the total oil production is influenced only by the GOR content. Finally, for scenarios with high CO2 or GOR content, the effect of design variable interactions is decisive in changing the separation efficiency and/or the compression unit performance.

Identification of Complex Fluid Properties in Condensate Gas Reservoirs Based on Gas–Oil Ratio Parameters Calculated by Optimization Mathematical Model

In the production development stages of volatile oil reservoirs and condensate gas reservoirs, especially in the early stages of production, the phenomenon of high gas–oil ratio often occurs. As a result, the prediction results of oil and gas are greatly deviated from the actual situation, which seriously affects the implementation of potential excavation and increases production operation for condensate gas reservoirs. Therefore, the accurate identification of condensate gas and volatile oil is the key to improve the development efficiency in condensate reservoirs. However, due to the similar geophysical logging response characteristics for condensate gas, volatile oil, and light oil reservoirs, the qualitative identification effect only based on conventional logging is not ideal. Therefore, we propose a method to calculate the gas–oil ratio by introducing gas logging information and use the gas–oil ratio quantitative calculation results to identify condensate gas and volatile oil layers. First, we establish a physical model of the formation components of the condensate gas reservoir. Based on this physical model, we establish the response equations of various logging tools and evaluate the correlation between the gas logging information and the production gas–oil ratio to establish the response equation of gas logging. Then, we comprehensively use the well logging and gas logging response equations to establish an optimization mathematical model, solve the optimization objective function, obtain the relative content of natural gas and movable oil in the formation to calculate the gas–oil ratio parameters, and finally use this calculation result of the gas–oil ratio to quantitatively identify the fluid type. The application results show that the gas–oil ratio quantitative calculation method that we proposed can calculate the gas–oil ratio parameter accurately, and the calculation results are consistent with the formation testing data, which provides technical support for the identification of complex fluid properties in condensate gas reservoirs.

Characterization of saturation and pressure distribution based on deep learning for a typical carbonate reservoir in the Middle East

The typical carbonate reservoir in the Middle East has huge potential, but due to low permeability and high gas-oil ratio, the characteristics of reservoir saturation and pressure distribution are not clear, which makes reservoir development very difficult. As an intelligent prediction and analysis technique, deep learning provides a novel solution to solve this problem. In this study, firstly, the actual static geological data and dynamic production data from the target reservoir were gathered to provide a data foundation for model training and analysis. And then, Random Forest algorithms, Reservoir Engineering methods, and Kriging interpolation algorithms were selected to predict and supplement the missing data of pressure and saturation field. After that, the Convolutional Long Short-term Memory (ConvLSTM) neural network algorithm was employed to build an optimal model to forecast the oil/water/gas saturation distribution and pressure distribution fields. The results showed that the optimal ConvLSTM model achieved good prediction performance. Not only the calculation efficiency, but also the prediction accuracy was higher, in which the average R2 was 0.8825 and the average accuracy was 0.865. Furthermore, we proposed five development optimizations for the remaining oil potential tapping strategies according to the prediction results. The workflow proposed in this study provides a new direction for the characterization of saturation and pressure distribution in a typical carbonate reservoir.

Modeling subsea gas-liquid separation using proxy for phase separation for pre-salt reservoirs with high GOR

Brazilian pre-salt oil fields include ultra-deep water reservoirs with high CO2 content and high gas/oil ratio (GOR). For these cases, large volumes of CO2-rich gas reach the topside facilities that present limited gas processing capacity. In this context, the production of the oil field is restricted to the maximum gas production capacity of these facilities. The use of a subsea gas-liquid separation (SGLS) and reinjection system may be a solution to boost oil production, as this strategy allows reinjecting part of produced gas directly from the seabed. In this study, we developed a methodology for modeling the subsea separation and reinjection process, which is integrated with a compositional reservoir simulator. A proxy based on an equation of state (EOS) was used for volumetric phase separation in the subsea separator. This approach eliminates the necessity of flash calculation at the SGLS conditions. The methodology makes it possible to assess the potential impact of implementing this technology from a reservoir management perspective. The modeling methodology is applied to a benchmark case (synthetic simulation model representative of a pre-salt reservoir) and evaluated the impact of the SGLS over total production. The results show that the SGLS technology can successfully boost oil production in the context of platform gas production restriction. As soon as the SGLS was implemented, an extended oil production plateau was achieved due to increased gas production capacity. We observed a significant GOR increment in produced fluids during the simulation as a result of gas recycling strategy. This increasing GOR caused the field production to be restricted by maximum gas production constraint most of the time, despite the SGLS implementation. A higher GOR also affects the SGLS performance, increasing the proportion of gas that becomes available for separation at subsea separator conditions. An economic analysis is presented, showing that the SGLS has the potential to increase the financial return of the project. The introduced methodology will enable the inclusion of the subsea separation process in future analyses, paving the way for feasibility assessments and optimization processes for cases in which the SGLS may be an alternative.