Gas Cap Research Articles

Investigation of drive mechanisms in fractured oil reservoirs with tight matrix: a case study of an Iranian reservoir

ABSTRACT Tight matrix oil reservoirs pose significant challenges for oil recovery due to their low permeability and intricate fracture networks. Effective reservoir development strategies require a thorough understanding of the recovery mechanisms; otherwise, it is difficult to maximize production rates and optimize the oil recovery factor. The reservoir examined in this study contains black oil within a tight matrix, complicating the planning and selection of appropriate recovery methods. Despite strong bottom water influence and high water-cut issues, the fractures in the reservoir facilitate economical extraction. However, the reservoir’s complexity, coupled with limited knowledge and experience in this area, further complicates recovery efforts. In this study, we investigated the multi-mechanistic flow dynamics within the porous media. Simulation results indicate that during the first month of production, the dominant recovery mechanism is rock expansion drive. Beyond this period, the water drive mechanism prevails. Over a ten-year period, oil recovery is distributed as follows: 13.1% from bottom water drive, 1.0% from gas cap drive, 0.2% from rock expansion, and 0.6% from oil expansion drive.

აზოტის გამოყენება ნავთობისა და გაზის ოპერაციებში

The article discusses several options for nitrogen application in the oil and gas industry. Nitrogen gas is useful in maintaining formation pressure in oil fields, expelling gas from the gas cap, stimulating steeply inclined formations, cyclic exploitation of gas condensate deposits, Completion of wells, Cleaning of wells with Coiled Tubing, Circulatimg low pressure reservoir wells with foam.Described experience of local oil and gas companies in Georgia utilizing nitrogen pumping in welltesting and stimulation.

Geological and biostratigraphical factors in hydrocarbon recovery optimization using integrated seismic, petrophysical, and core data, Niger Delta

The study of geologic heterogeneities (the quality of reservoir rock according to its spatial variation in properties such as grain size, mineralogy, organic content, fossil content, and natural fracture) and their impact on recovery factors, optimization, and performance of injection fluids in concurrent development (production of both oil and gas at the same time) of oil rim reservoirs (reservoirs with a thin oil column that is overlain with a large gas cap) has become necessary to explore the role of geological and biostratigraphical heterogeneity in optimizing hydrocarbon recovery from oil rim reservoirs in the Niger Delta using integrated seismic, petrophysical, and core data. This is to achieve optimum hydrocarbon recovery instead of relying only on development strategies, which is usually the practice and thus fails. Petrel and Eclipse software were used to simulate the static and dynamic models, respectively, for three oil rim reservoirs, using data (seismic, petrophysical, core, and reservoir data) from a green field in the Niger Delta, Nigeria, for concurrent development under the natural depletion (base case), surfactant enhanced-water-alternating-gas (SeWAG), and water-alternating-gas (WAG) injection options. In each option, two scenarios of injection well positions were simulated: gas-oil contact (GOC) and oil-water contact (OWC). Geological studies showed that Reservoir 1 is a heterolith facies of lower-shoreface deposits with traces of Ophiomorpha burrows, Reservoir 2 is a channel facies of lower shoreface deposits with Ophiomorpha burrows, and Reservoir 3 is a heterolith facies of upper shoreface without vertical burrows. When SeWAG of ratio 1:4:2 was injected at OWC, the highest oil recovery factor was observed compared to other options, and injection at GOC gave the highest gas recovery factor. Permeability anisotropy (Kv/Kh) for reservoirs 1 and 2, with Ophiomorpha burrows being considered, was 0.32 and 0.34, respectively. High recovery factors for both oil and gas were recorded. However, the model of the same reservoir without Ophiomorpha burrows gave reduced values of Kv/Kh of 0.12 and 0.15, respectively, with reduced recovery factors. Reservoir 3, which doesn't have burrows in the initial model, has a Kv/Kh value of 0.11 with low recovery factors in various development cases. However, when Ophiomorpha burrows were integrated into the model, Kv/Kh was 0.31, and the recovery factors increased significantly. The study has shown that geological and biostratigraphical interactions induce Kv/Kh. It has a significant optimization impact on recovery factors in concurrent development and enhances vertical sweep efficiency in EOR (Enhanced Oil Recovery). The study further shows that Ophiomorpha burrows improve the geologic heterogeneity quality of a reservoir (permeability anisotropy) by enhancing the injection fluid to get into micro- and macropore spaces for efficient sweeping of oil and gas into the development well.

Characterizing hydrocarbon discoveries and prospects in the Tay Sandstone using relative elastic inversion: Greater Pilot area, Central North Sea

The Pilot oil accumulation and associated discoveries of Blocks 21/27 and 21/28 have been stranded assets for three decades. The principal cause of delay in developing the oil fields is because these are heavy oils with low gas–oil ratio and, in some cases, significant gas caps. The oil in the Tay Sandstone is trapped in structural and stratigraphic closures at a depth of 800–1300 m. Determining pay thickness and delimiting oil-in-place in some existing discoveries and especially in undrilled prospects has been problematic. This difficulty has been addressed by conducting an innovative amplitude versus offset (AVO) inversion of the seismic data which has been successfully blind tested against the wells and prognosed closures. The method, which is a band-limited form of extended elastic impedance (EEI), has proved robust for discriminating gas-, oil- and brine-filled sands from one another. Oil and gas trapped further down-dip in the discoveries Fyne, Crinan and Dandy are developed in Tay reservoirs showing generally lower net-to-gross. The sensitivity of the rEEI attribute to the presence of thicker intervals of oil pay, in this case, is used to indicate where higher net-to-gross is present above the oil–water contact, a characteristic of direct relevance to the planning of optimally located development wells.

SELECTION OF A MRP SYSTEM FOR OIL AND GAS DEPOSITS

A number of serious problems arise in the development of sub-gas zones of oil and gas deposits due to the joint occurrence of oil and gas. The key problem is gas breakthrough from the gas cap to oil wells. This entails an increase in the gas factor (GOR), a rapid and intense decrease in pressure in the gas cap. If there is a reservoir pressure maintenance system or an active aquifer as a result of a decrease in reservoir pressure in the gas cap, oil may be pushed back into it, which leads to a rise in gas-oil contact, jamming of mobile oil in the «dry sandstones» of the gas cap, which in turn leads to a decrease in reserves of mobile oil and a decrease in the oil recovery factor (ORF). All this together allows us to consider oil in the sub-gas zones as hard-to-recover reserves.Preventing and combating the negative consequences of gas breakthrough from the gas cap to oil wells is a complex task and consists of several areas, such as selection of rational drilling of production and injection wells, selection of optimal operating modes for them, use of inflow control devices or performance of repair and isolation work to limit inflow from intervals with gas breakthrough, periodic shutdown of wells to disband gas cones. The ultimate goal of solving these problems is to increase the oil recovery factor and economic efficiency indicators for the development of sub-gas zones.Due to the variety of ways to optimize the development of oil and gas reservoirs, it is not possible to cover them all in one work, therefore, the tasks associated with optimizing the reservoir pressure maintenance system are considered. It is worth noting that in comparison with the development of oil reservoirs, the presence of a gas cap significantly complicates this task due to the lack of analytical solutions for three-phase filtration. For this reason, the selection of the optimal parameters of the reservoir pressure maintenance system is usually carried out either by multivariate calculations in the hydrodynamic model (HDM), or by the method of analogies or the implementation of pilot tests of various approaches.In this study, an approach based on multivariate numerical calculations using the sector model of the development element of the gas zone was used. As a result of calculations, it was shown that when choosing the optimal parameters of the reservoir pressure maintenance system, it is advisable to use a differentiated approach, which consists in the fact that these parameters must be set individually for zones with different ratios of oil-saturated and gas-saturated thicknesses.

Risk Mitigation in Development Drilling Through Improved History Matching by Incorporating Uncertainty Analysis with a Hidden Gas Cap

Risk Mitigation in Development Drilling Through Improved History Matching by Incorporating Uncertainty Analysis with a Hidden Gas Cap

The Early Determination Method of Reservoir Drive of Oil Deposits Based on Jamalbayli Indexes

Summary Historically, the concept of “reservoir drive” aimed to simplify the mathematical modeling in reservoir engineering. Within this framework, the energy of the reservoir, particularly its aquifer, was idealized, leading to classifications such as “partial waterdrive,” “full waterdrive,” “gas cap drive,” and so forth. However, in reality, all existing energy sources interact simultaneously within reservoirs. Accordingly, this study aims to develop a new concept for a more realistic description of reservoir drive mechanisms and evaluation of reservoir energy performance. Numerous computer simulations have revealed a strong correlation between the ratio of relative changes in pore volume to relative changes in reservoir pressure and the reservoir’s energy nature and activity level. Moreover, the noted ratio did not depend on production technology, pressure/volume/temperature properties of hydrocarbon systems, rheological properties of reservoir rocks, or other factors. Based on this correlation, specific parameters termed as Jamalbayli Indexes (JI) have been identified to quantitatively describe reservoir energetic performance. JI consist of two parameters. One of them describes the relative change in pore volume per unit of relative change in reservoir pressure, and the second is the relative change in pore volume per unit of relative change in formation porosity. Here, “relative change” means a change in a parameter relative to its original value. These parameters are dimensionless and can have values around or equal to unity. A new conceptual framework for describing reservoir drive mechanisms based on JI has been formulated. According to this framework, reservoir drive mechanism is determined by comparing the computed JI values with unity rather than relying on subjective assessments of the trend of some functional dependencies. For the first time, it has become possible to express the reservoir drive performance quantitatively and determine the level of energy activity of the reservoirs with the help of JI. Additionally, a technique has been developed to evaluate the numerical values of JI for specific oil (including volatile oil) deposits based on the production data at any stage of production. The proposed methodology was tested using data from the eighth horizon of the Russkiy Khutor field in Russia. The test results not only confirmed the reliability of the obtained model but also demonstrated the adequacy of the proposed concept as a whole. Summarizing the results of other works by the authors, the adequacy of the proposed concept for both oil, gas, and gas condensate deposits has been confirmed. The research findings are expected to contribute to updating the traditional principles used for the mathematical problem statements in fluid flow in porous formations. Additional Key Terms and Phrases Reservoir Drive Mechanism; Early Determination Methods; Reservoir Performance Analysis; Production Data Interpretation; Enhanced Oil Recovery; Reservoir Management; Drive Mechanism Identification; Reservoir Fluid Dynamics; Production Rate Analysis; Reservoir Engineering Techniques; Field Development Planning; Reservoir Simulation; Pressure/Volume/Temperature (PVT) Analysis; Production Monitoring and Evaluation drive mechanisms; production data analysis; volatile oil; Jamalbayli indexes; drive performance indexes

DEVELOPMENT OF AN ALGORITHM FOR CALCULATING COMPONENT COMPOSITION TO IMPROVE THE DEVELOPMENT OF OFFSHORE OIL FIELDS IN THE NORTH CASPIAN BASIN

The paper presents an algorithm to reconstruct the component composition of the mixture based on the results of production modeling in the black oil format and a fixed set of tables with the results of phase equilibrium calculations in a given pressure range. The approach is based on analyzing the ratio of flow rates for each phase and the ratio between average reservoir pressure and saturation pressure. The algorithm takes into account the possibility of oil degassing when saturation pressure decreases, as well as gas breakthrough of gas caps to the bottoms of producing wells.Implementation of the method is based on a unified thermodynamic model of multilayer reservoir, built on the principles of a single set of HC mixture components and uniform parameters of the equation of state on a set of fluid samples for all modeling stages: reservoir model, model of the gathering system and site facilities. In addition to steady-state flow calculations performed together with reservoir modeling, the unified model is planned to be used for dynamic flow calculations in the corresponding simulator (well start/stop), which will allow solving production problems in the process of operation of wells with complex completions.The conversion algorithm is automated using modern high-level tools: Python and data automation components from MS Excel, which eliminates the need for manual data input at all stages and makes it possible to obtain the estimated component composition of produced fluid for any set of wells and for any time step within the forecasting horizon.The obtained compositions are used to verify the reproduction of the main controlled parameters (oil density and gas oil ratio) and can be used for subsequent calculations of fluid transportation and treatment systems.The implemented algorithm has been tested for stability at different ratios of gas and oil flow rates by wells and meets the practical requirements of engineering calculations — the error of oil density is not higher than 2 % and gas factor is not higher than 10 %.

Brine Salinity: A Deciding Factor for Carbondioxide Dissolution and Trapping during Geological Sequestration

Adequate geological storage of carbondioxide in saline aquifers is a function of several factors that requires understanding and examination. Previous works have argue that solubility of carbondioxide in brine decreases as the salinity of the brine increases, but it is unclear in the literature the impact of salinity on carbondioxide (CO2) trapping during sequestration. This work adopt a simulation based approach to determine CO2 dissolution and trapping at different salinities. A dataset was written and validated with CMG’s greenhouse gases simulator and the thermodynamics properties calculation carried out with Peng-Robinson equation of state. Four sensitivity analyses was conducted with brines of no salinity (pure water), salinity of 100000ppm, 200000ppm and 300000ppm and model outputs compared for CO2 sequestration. The result shows that CO2 solubilised in water with zero level salinity, and a lower gas cap size was formed at the top of the structure. Later, gas cap size increases as the salinity level increases at the top of the structure. Also, the moles soluble in water decreases as the salinity level increases with the least moles for zero water salinity. Alternatively to the moles solubilised, the number of moles of CO2 trapped increases with the salinity level. CO2 storage in deep saline aquifers is the best storage techniques but its injection into aquifer of high salinity reduced its solubility.

Prospectivity analysis for underground hydrogen storage, Taranaki basin, Aotearoa New Zealand: A multi-criteria decision-making approach

Seasonal underground hydrogen storage (UHS) in porous media provides an as yet untested method for storing surplus renewable energy and balancing our energy demands. This study investigates the technical suitability for UHS in depleted hydrocarbon fields and one deep aquifer site in Taranaki Basin, Aotearoa New Zealand. Prospective sites are assessed using a decision tree approach, providing a “fast-track” method for identifying potential sites, and a decision matrix approach for ranking optimal sites. Based on expert elicitation, the most important factors to consider are storage capacity, reservoir depth, and parameters that affect hydrogen injectivity/withdrawal and containment. Results from both approaches suggest that Paleogene reservoirs from gas (or gas cap) fields provide the best option for demonstrating UHS in Aotearoa New Zealand, and that the country’s projected 2050 hydrogen storage demand could be exceeded by developing one or two high ranking sites. Lower priority is assigned to heterolithic and typically finer grained, labile and, clay-rich Miocene oil reservoirs, and to deep aquifers that have no proven hydrocarbon containment.

Modelling CO2 storage in oil and gas reservoirs in the Gippsland Basin

The Gippsland Basin has world class geology for carbon capture and storage (CCS) and a long history of oil and gas production. Depleted oil and gas fields within the Gippsland Basin that are candidates for carbon dioxide (CO2) storage are in close proximity to existing infrastructure that could be repurposed as part of a CCS project. Modelling of CO2 storage in the depleted Bream oil and gas reservoir is being progressed. Bream reservoir properties are very well understood due to extensive geological and geophysical data sets available from wells and seismic data. Additionally, the field has been through three key phases of development during its production history; oil production and gas re-injection in 1988, gas cap blowdown started in 2002, and seasonal gas storage and withdrawal started in 2012 through to field shut-in in 2020. This provides a wealth of dynamic data that is used to calibrate the reservoir models to improve our confidence in the CO2 plume prediction. However, there are also challenges in modelling CO2 storage in depleted fields. Unlike saline aquifers, CO2 can be injected into a three-phase depleted reservoir that contains residual oil and gas saturation. The key aspects of our workflow to evaluate the plume behaviour are presented in this paper.

COMPRENSIÓN DEL MERCADO ENERGÉTICO ESPAÑOL 2022 CON UN ANÁLISIS DE LOS DATOS OFICIALES

The energy situation that occurred in the Spanish electricity and natural gas markets in 2022 implies the concept of a global crisis. This entails a significant increase in the prices of electricity and natural gas. Historically, the relationship between these two concepts has always been substantial, as demonstrated in the conducted study. This article aims to analyze whether this relationship between both markets has continued to be strong in the past year, 2022, and to assess the factors that may have distorted the results. To achieve this, publicly available data recorded by various operators in the electricity and natural gas markets have been meticulously analyzed and reviewed from a statistical-mathematical perspective. The study investigates the implications of the rising prices of electricity and natural gas, as well as the measures taken by the Spanish Government in June 2022. Furthermore, it is essential to consider that in 2022, several anomalous factors occurred, such as the Russia-Ukraine war and the Spanish market intervention resulting from the price increases, suggesting a different market behavior. The primary conclusion drawn from the analysis of the published data is that the high prices in 2022 can be attributed not solely to the high prices of natural gas, as indicated in the media. This will be elaborated upon throughout this study. Key Words: Gas Cap Adjustment Mechanism, Massive Consumption of natural gas and exports of electricity in 2022. Correlation between OMIE and MIBGAS.

Geochemistry and Petrology of Reservoir and Cap Rocks in Zar-3 Pilot CO2 Storage Complex, SE Czechia

The planned pilot CO2 storage Zar-3 is an oil field with a gas cap in the final production stage in the SE Czech Republic. It is composed of a dolomite Jurassic reservoir sealed by three different formations that differ significantly in lithology. Previous studies left open questions on the nature of pore space and connectivity and the quality of the seal in the future CO2 storage complex. Microscopic petrography of the reservoir suggests dolomitisation in shallow water followed by karstification and brecciation with fracture-correct-dominated porosity. The seal horizons have porosity limited to the micro- and nanoscales. The oil consists of significantly biodegraded black oil of Jurassic origin mixed with less biodegraded gasoline-range hydrocarbons. Biomarkers in the caprock bitumens trapped in nanopores show a genetic relationship to the reservoir oil. Gas in the not yet fully depleted gas cap of the field is of thermogenic origin with no contribution of microbial methane. The formation water has total dissolved solids typical of isolated brines not diluted by infiltrated fresh water. The geochemical characteristics of the storage system together with the fact that the initial oil column is about 105 m tall with another 150 m of gas cap suggest that the seals are efficient and the Zar-3 future storage complex is tight and safe.

The Iberian exception: Estimating the impact of a cap on gas prices for electricity generation on consumer prices and market dynamics

As the volatility of short-term energy market prices increases due to exogenous shocks and the changing nature of the energy mix, market interventions are gaining importance in the policy debate. Accurate and robust quantification of their impact is becoming therefore essential. This paper conducts a causality analysis to evaluate the Spanish “gas cap” for electricity generation during the 2022 energy crisis. We use Bayesian structural time series models to isolate its impact on affected consumers, primarily those under the regulated tariff, from June to December 2022. Our results show that the mechanism successfully lowered prices compared to a counterfactual scenario without the intervention. However, the policy also led to an increase in electricity generation from gas-fired combined cycle plants. In addition, exports to France increased by over 80% after implementation, as Spanish wholesale prices became cheaper than French prices. Our analysis (1) provides an accurate quantification to date of one of the most consequential energy market interventions in recent years; (2) demonstrates the fruitful use of a novel evaluation method for energy policy; (3) highlights the trade-off between the short-term goal of consumer price relief and the long-term goals of fossil fuel reduction and decarbonisation.

Calculation Method of the Phase Recovery of Gas Cap Reservoir with Bottom Water

In gas cap reservoirs underlain by bottom water, the connection between the reservoir and the aquifer leads to an increasing invasion of bottom water as reservoir development progresses. The average formation pressure of the reservoir will change, and the separated phase recovery of the gas cap reservoir with bottom water will be affected by the change in the average formation pressure. The traditional average formation pressure calculation formulas do not consider the water influx, so the accurate calculation of separated recovery cannot be obtained by those calculation methods. The development of gas cap reservoirs with bottom water presents several challenges, including the simultaneous production of oil and gas, undetermined rates of bottom water influx, and uncertain formation pressure and gas-to-oil ratios. These factors contribute to substantial discrepancies between theoretical calculations and actual observations. A more accurate and comprehensive approach is required to address these issues and enable a precise determination of the phase separated recovery in gas cap reservoirs with bottom water. The volume-deficit method is integrated with the Fetkovich quasi-steady state method for water influx. The water-influx prediction is incorporated into the material balance equation, which is further refined by introducing the Fetkovich model to enhance the estimation of the average formation pressure. The average formation pressure, once determined, is utilized in conjunction with the established relationships among this pressure, surface oil production, gas production, and the dissolved gas–oil ratio. Through the application of mass conservation principles, the varying degree of phase recovery, as influenced by fluctuations in the average formation pressure, is calculated. The precision of this refined method has been validated by a comparison with outcomes generated by simulation software. The results reveal a commendable accuracy: an error in the average formation pressure calculation is found to be merely 2.61%, while the errors in recovery degrees for gas cap gas, dissolved gas, and oil-rim oil are recorded at 2.73%, 2.94%, and 1.28%, respectively. These minor discrepancies indicate a good level of consistency and affirm the reliability of this advanced methodology, as demonstrated by passive assessments. This paper provides a method to accurately calculate the phase recovery without some oil- and gas-production data, which provides accurate data support for the actual production evaluation and subsequent development measures.

Co-Injection of Foam and Particles: An Approach for Bottom Water Control in Fractured-Vuggy Reservoirs

Fractured-vuggy carbonate reservoirs are tectonically complex; their reservoirs are dominated by holes and fractures, which are extremely nonhomogeneous and are difficultly exploited. Conventional water injection can lead to water flooding, and the recovery effect is poor. This paper takes the injection of foam and solid particles to control bottom water as the research direction. Firstly, the rheological properties of foam were studied under different foam qualities and the presence of particles. The ability of foam to carry particles was tested. By designing a microcosmic model of a fractured-vuggy reservoir, we investigated the remaining oil types and the distribution caused by bottom water. Additionally, we analyzed the mechanisms of remaining oil mobilization and bottom water plugging during foam flooding and foam–particle co-injection. The experimental results showed that foam was a typical power-law fluid. Foam with a quality of 80% had good stability and apparent viscosity. During foam flooding, foam floated at the top of the dissolution cavities, effectively driving attic oil. Additionally, the gas cap is released when the foam collapses, which can provide pressure energy to supplement the energy of the reservoir. Collaborative injection of foam and solid particles into the reservoir possessed several advantages. On one hand, it inherited the benefits of foam flooding. On the other hand, the foam transported particles deep into the reservoir. Under the influence of gravity, particles settled and accumulated in the fractures or cavities, forming bridge plugs at the connection points, effectively controlling bottom water channeling. The co-injection of foam and solid particles holds significant potential for applications.

Effect of Aquifer Strength and Gas-cap Size on Oil Recovery Efficiency in Thin-Oil Rim

Recovering oil from thin oil rim reservoirs depends on some factors such as the gas-cap size, thickness of initial oil column, aquifer strength, permeability anisotropy (kV/kH), and rock and fluid properties. The arbitrary selection of these factors by researchers during investigation limits the systematic assessment of the influence of these factors on hydrocarbon recovery from thin oil rim reservoirs. This work investigated the effect of aquifer strength, gas cap size, and permeability anisotropy on hydrocarbon recovery, using design of experiment (DOE) as a tool in the systematic selection of some of the factors that influence hydrocarbon recovery. A static model of the base case oil rim was built in Petrel. Using Eclipse simulator, two other reservoir models having different gas cap sizes from the base case were built. Forty-eight simulation cases were generated using the result from the design of experiment (DOE). The aquifer model used is a Fetkovich analytical aquifer model, and the aquifer volume factors used for this investigation are 0.7, 1.0, 1.5 and 2.5, while the gas cap sizes (m-factor) used are 0.5, 1.0 and 2.0. The permeability anisotropy used are 0.01, 0.05, 0.10 and 0.40. Each simulation case was made to run for a period of twenty years (20years) and the results for the Field Oil Efficiency (FOE), Field Water Production Total (FWPT) and Field Gas Production Total (FGPT) were obtained and analyzed. It was found from this study that, the oil percentage recovery will increase as the gas cap size is decreased, while the percentage gas and water recoveries will increase as the size of the gas cap is increased for a thin oil rim reservoir. Again, for a thin oil rim reservoir with gas cap size of 0.50 ≤ m ≤ 2.00, percentage recovery of gas, oil and water will increase with aquifer volume. Also, based on the result obtained, a thin oil rim reservoir with small to moderate gas cap size (0.5≤ m≤1.0) will yield higher oil recoveries irrespective of the kV /kH ratio.

Gas-Liquid Hydrodynamics during Liquid Displacement by Gas in Up-Hill Pipeline

Mobile pipelines are the most efficient and reliable way to transport large quantities of oil over long distances in warfare, rescue and disaster relief. The oil in the pipe must be discharged and recovered when the oil transfer task is completed, usually via gas cap evacuation. Gas cap evacuation is the main method to evacuate mobile pipelines. During evacuation, due to the influence of topography, working conditions and gravitational forces, the oil in an up-hill pipeline is gradually deposited in the low-lying part of the pipeline to form a liquid, resulting in the incomplete emptying of the pipeline which directly affects the recovery efficiency of the pipeline. Focusing on the analysis of the gas carrying oil flow process in an up-hill pipeline during the evacuation of gas displacing oil in the mobile pipeline, the tail and head of the liquid accumulation were analyzed, and the liquid accumulation flow model was established based on the gas–liquid two-phase stratified flow theory. This model was used to analyze the flow law of the accumulated liquid under different pipe inclination angles, initial accumulation thicknesses and pipe diameters. It was found that the stagnant oil in the pipeline is carried by the gas flow into the upward tilting pipeline due to the influence of the axial gravity force of the pipeline. The gas flow can be divided into three phases: the initial discharge stage, the oscillation stage and the final discharge (reflux) stage.

Comparative Study of CO2 Storage Capacity Estimation in Depleted Oil & Gas Reservoir: A Case Study in Vermillion Basin Gulf of Mexico

CO2 emissions rates have seen an exponential growth from the 19th century up till date, if no drastic measures and plans are implemented to prevent this exponential growth the consequence will be devastating. The notion of achieving net-zero greenhouse gas emissions gained prominence through the Paris Agreement, a groundbreaking accord reached at the United Nations Climate Change Conference. This agreement was devised to mitigate the impact of greenhouse gas emissions. To execute the net-zero CO2 emission plan, the USDOE has set a new goal to remove gigatons of carbon dioxide (CO2 ) from the atmosphere and durably store it for less than $100/ton of net CO2 -equivalent. Making such a goal a reality requires an accurate estimation of CO2 storage capacity for the successful implementation of Carbon Capture and Storage (CCS) technologies, and the assessment of the impact of CCS to the reduction of CO2 emissions. Hence this paper serves as a template for accurately estimating CO2 storage capacity in depleted saturated oil reservoirs with initial gas cap using three approaches: Volumetric, Production and Correlation-based methods and compares the accuracy of the estimates. A case study was conducted on a depleted VR273_Q combination sand in the Vermillion Basin, Gulf of Mexico (GOM). The deterministic and stochastic (P50) CO2 storage capacity estimates from the Volume-based method are 1.21 million tonnes (Mt) and 1.23 Mt respectively, while the deterministic CO2 storage capacity estimates from the Production and Correlationbased method are 1.32 Mt and 1.41 Mt respectively. All three approaches showed similar results, with little deviations attributed to petrophysical uncertainties arising from data gaps i.e., absence of well logs to key wells. However, these uncertainties are captured by Stochastic (P90) CO2 storage capacity estimates of 1.47 Mt from the Volume-based method. Although the Correlation-based approach slightly overestimates the CO2 storage capacity, it can be used as a starting point for quick estimation as it only requires production data which are readily available on various databases for GOM. Finally, through this paper, opportunities for concerned agencies to make well-informed energy-related policies and business decisions are made possible.

Reduction in the transport of sour gases and hydrocarbons to underlying PE-RT through thin films of PVDF

Raised temperature polyethylene (PE-RT) is being studied for use in the conveyancing of sour hydrocarbon fluids in spoolable composite pipe at temperatures above 90 °C. This grade of polyethylene swells on exposure to all hydrocarbons but specifically aromatic hydrocarbons and so there is a requirement to reduce the flux of hydrocarbons and gases into the base PE-RT. A multi-material pipe wall is one solution to reduce these fluxes but new experimental methods are required for design and validation while saturated in sour hydrocarbon fluids.In this study the simultaneous transport of species such as CO2, H2S, CH4, water vapour and aromatic hydrocarbon vapours such as toluene, xylene, IRM902 and cyclohexane were measured in real time through single films of PVDF and PE-RT and multilayer walls of PVDF/tie layer(s)/PE-RT extracted from a built (co-extruded) pipe section. The permeation test facility contained specialized gas chromatographs modified for continuous quantification of all species. The experimental methods were designed to run at 93 °C with gas pressures of 104 barg or 250 barg. Experiments were run with gas only mixtures (dry tests) and also with gas cap above a mixture of liquid hydrocarbons and water (wet tests). When possible, transport properties such as diffusion and solubility coefficients were derived from the permeation traces. The volume flow rate of all species was higher through PE-RT compared to PVDF and the volume flow rate for CO2, H2S, and CH4, increased when the gas pressure was increased from 104 to 250 barg. The gas permeability was calculated for the base polymers and also the combined multilayer structure. The flow rates estimated for a multilayer specimen using the values measured on individual films were confirmed experimentally. A simple mathematical model was proposed to derive the apparent permeability of the multilayer system and the steady-state concentration profiles across the specimen wall. Specimens were inspected for damage after a final depressurization at 70 bargmin−1. Post exposure assessment of the laminates showed that the adhesion levels were improved and the failure mode was altered from adhesive to cohesive on ageing.