Gas Reinjection Research Articles

The role of the production geologist in carbonate reservoir development

Carbonate production geologists are deployed to tackle field management and (re)development issues on increasingly brownfields. This paper shares examples of how geologists raise awareness of current and potential production opportunities with insights into permeability architecture and its uncertainty. The examples represent diverse fluid types and a range of depositional, diagenetic and structural settings. “Plumbing diagram” examples communicate what matters to flow from the reservoir to the well perforations. In the Luconia gas fields, thin low porosity horizons either accentuate or baffle vertical permeability to rising aquifers. In a Middle Eastern GOGD development constrained by gas re-injection, well placement into unfractured intervals led to an oil redevelopment at a lower gas cut. In a Middle Eastern waterflood, dynamic characterisation of permeability contrasts facilitates improved oil recovery through sweep management. The examples stress the importance of continued geological data analyses in brownfield settings, as well as active engagement during engineering-dominated discussions on fluid flow that inevitably follow field development plan execution and monitoring. A discussion examines why brownfield development opportunities delay to later field life, and into the energy transition, how production geologists might improve geothermal and sequestration reservoir developments.

Assessing Gas Flaring Mitigation Technologies in Nigeria: A Review of Existing Solutions and Future Trends

Gas flaring remains a critical global issue with significant economic and environmental impacts. Despite ongoing efforts, Nigeria remains one of the top ten countries for gas flaring. This research assesses both advanced and existing technologies aimed at mitigating gas flaring in Nigeria, focusing on their viability, effectiveness, and environmental implications. The evaluation begins with gas re-injection techniques, which involve redirecting flared gas back into reservoirs to enhance oil recovery and reduce emissions. It also covers flare gas recovery systems that capture and re-purpose flared gas for energy production or other beneficial uses. Additionally, the potential of liquefied natural gas (LNG) projects to minimise flaring and monetise associated gas is explored. Furthermore, the study examines innovative approaches such as gas-to-methanol (GTM) conversion, which transforms flared gas into methanol, a valuable chemical feed-stock. The review also considers advanced methods like carbon capture and storage (CCS), which can absorb carbon emissions from flaring and mitigate its environmental impact. The assessment includes the integration of renewable energy sources as a sustainable alternative to fossil fuel-based energy generation to reduce reliance on flaring. Findings reveal that while progress has been made in reducing flaring volumes, challenges persist, particularly in regulatory enforcement, economic feasibility, and technological adoption. The review highlights the need for improved policy frameworks, increased investment in sustainable technologies, and international cooperation to achieve Zero Routine Flaring by 2030. This study provides valuable insights and recommendations for policymakers and industry stakeholders to enhance Nigeria’s environmental sustainability and economic resilience.

An improved prediction model for miscibility characterization and optimization of CO2 and associated gas co-injection

Insufficient reservoir pressure and gas source problems seriously limit effective applications of CO2 flooding in hydrocarbon reservoirs. An attractive strategy is to co-inject the produced associated hydrocarbon gas with CO2 to achieve miscible/near-miscible flooding to enhance oil recovery. However, the composition of the injected mixture and the in-situ spatio-temporal composition evolution of the displacing/displaced fluids significantly affect the CO2-oil miscibility and the overall hydrocarbon recovery performance. In this work, based on slim tube simulation results, a prediction model of minimum miscible pressure (MMP)/minimum near-miscible pressure (MNMP) is established. This model takes into account the effects of CO2 concentration distribution, oil composition and temperature changes to achieve accurate spatiotemporal characterization of miscibility in the reservoir. In addition, the distribution law of the phase and components front for the impure CO2 injection process was also investigated. The miscible volume factor and recovery efficiency were used as the basis for judging the minimum injection concentration limit of CO2. The simulation results of slim tube experiment indicate that the MMP and MNMP obtained are 16.74 MPa and 12.35 MPa, respectively. Furthermore, the error caused by the traditional slim tube experiment can be reduced by using the CO2 produced fraction. It is found that CO2 injection concentration and reservoir temperature are the main factors affecting miscibility, but injection rate has less effect. Moreover, the fast migration of CH4 front leads to the shrinkage of miscible/near-miscible zone, which is not conducive to CO2 flooding. Finally, the CO2 injection concentration of non-breakthrough stage, breakthrough stage and large-scale breakthrough stage was determined to be 78.3%, 61.5% and 29.2%, respectively. This work provides strong evidence for the treatment of associated gas reinjection, which is beneficial for optimization of carbon capture, EOR-utilization and storage (CCUS-EOR) projects.

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.

A REVIEW ON CARBON DIOXIDE (CO2) – ASPHALTENES INTERACTIONS

WAG - CO2 is an oil enhanced recovery method that has been applied successfully to some of the largest pre-salt fields in Brazilian offshore oil provinces. This recovery method provides the advantage of reducing the emission of green-house gas (CO2) to the atmosphere. However, the re-injection of CO2 gas into reservoirs may also provoke deleterious effects on asphaltenes equilibria under reservoir conditions, promote pore plugging, and inflow formation damage. Thus, it is crucial that researchers investigate with caution the use of WAG- CO2 method to avoid unwanted situations. This technical contribution reviews the state of the art of WAG- CO2 recovery method, provides useful pieces of information of laboratory studies on the behavior of asphaltenes in presence of CO2, and, finally, it presents prescriptive guidelines for addressing pivotal CO2 - asphaltenes issues.

Reliable sustainable management strategies for flare gas recovery: technical, environmental, modeling, and economic assessment: a comprehensive review.

The gas flaring network is an inseparable constituent commonly present in most of the oil and gas refineries and petrochemical facilities conferring reliable operational parameters. The improper disposal of burn-off gases improperly results in environmental problems and loss of economic resources. In this regard, waste to energy transforming nexus, in accord with the "carbon neutrality" term, has potentially emerged as a reasonable pathway to preserve our planet. In a transdisciplinary manner, the present review article deeply outlines the different up-to-date strategies developed to recover the emitted gases (flaring minimization) into different value-added products. To analyze the recovery potential of flare gases, different technologies, and decision-making factors have been critically reviewed to find the best recovery methods. We recommend more straightforward recovery methods despite lower profits. In this regard, electricity generation seems to be an appropriate option for application in small amounts of flaring. However, several flare gas utilization processes such as syngas manufacturing, reinjection of gas into petroleum reservoirs, and production of natural gas liquid (NGL) are also recommended as options because of their economic significance, technological viability (both onshore and offshore), and environmental benefits. Moreover, the adopted computational multi-scale data assimilation for predictive modeling of flare gas recovery scenarios has been systematically reviewed, summarized, and inspected.

Assessment of the industrial emissions impact on the quality of atmospheric air in the Burlin district of West Kazakhstan region DEVELOPMENT

The article is devoted to the study of air pollution in the Burlin district of the West Kazakhstan region, where one of the main sources of air pollution is the Karachagan oil and gas condensate field, the main feature of which is the high content of hydrogen sulfide in natural gas from 4 to 4.3%. The analysis showed that the atmospheric air state in the specified area is determined by the characteristics of harmful emissions sources, composition, volumes of pollutant emissions and climatic characteristics of the territory, which determine the conditions for the polluting components dispersion. The qualitative and quantitative characteristics of the chemical composition of the atmospheric air in the study area, as well as the features of their changes over the years end climatic seasons, are largely determined by emissions of nitrogen oxides, carbon, sulfur dioxide, hydrogen sulfide, volatile organic compounds and inorganic dust into the atmosphere by oil and gas facilities. The anthropogenic influence of industry in this area is also evidenced by the calculated value of the integral coefficient of air pollution. At the same time, industrial enterprises, having increased the anthropogenic impact on the environment, have the ability to prevent negative environmental consequences. The system of industrial environmental control of the chemical composition of industrial emissions at the Karachagnak field facilities is carried out on an ongoing basis. The analysis showed that a reduction in emissions and, accordingly, a reduction in ground-level concentrations of air pollutants at the Karachagnak field facilities is ensured by a whole range of technological and organizational measures, among which the technology of high-pressure gas reinjection deserves special attention. It necessitates the need to carry out systematic work to study the ecological state of the territory of the Karachagnak field, using not only ground-based research methods, but also modern geoinformation and aerospace technologies that make it possible to dynamically assess the changes taking place, conduct a geo-ecological assessment and make a forecast for the development of the environmental situation in this area. territories. The work carried out contributes to further analysis of the regional assessment of the environmental state of the atmosphere of large industrial centers.

Molecular dynamics simulation on the displacement behaviour of crude oil by CO2/CH4 mixtures on a silica surface.

Produced gas re-injection is an effective and eco-friendly approach for enhancing oil recovery from shale oil reservoirs. However, the interactions between different gas phase components, and the oil phase and rocks are still unclear during the re-injection process. This study aims to investigate the potential of produced gas re-injection, particularly focusing on the effects of methane (CH4) content in the produced gas on shale oil displacement. Molecular dynamics simulations were employed to analyze the interactions between gas, oil, and matrix phases with different CH4 proportions (0%, 25%, 50%, and 100%), alkanes and under various burial depth. Results show that a 25% CH4 content in the produced gas achieves almost the same displacement effect as pure carbon dioxide (CO2) injection. However, when the CH4 content increases to 50% and 100%, the interaction between gas and quartz becomes insufficient to effectively isolate oil from quartz, causing only expansion and slight dispersion. Interestingly, the presence of CH4 has a synergistic effect on CO2, facilitating the diffusion of CO2 into the oil film. During the gas stripping process, CO2 is the main factor separating oil from quartz, while CH4 mainly contributes to oil expansion. In addition, for crude oil containing a large amount of light alkanes, extracting light components through mixed gas may be more effective than pure CO2. This study offers valuable insights for applications of produced gas re-injection to promote shale oil recovery.

Enhanced oil recovery through alternating gas Re-injection to reduce gas flaring in the Bakken

Environmental performance is a significant driver of energy production today, and providing attractive methods to reduce flaring remains a high priority for oil producers. The Energy & Environmental Research Center (EERC), with support from the Bakken Production Optimization Program (BPOP), is investigating the reinjection of the associated gas into producing wells to reduce flaring.The project's main objectives are to evaluate technically and economically the feasibility of deploying alternating gas re-injection in the Bakken formation as a means to increase oil recovery, reduce flaring and maintain compliance. The approach addresses the compression capacity constraints, mineral ownership types, and gas availability. Gas reinjection has the added benefit of producing incremental oil that can offset installation and operational costs associated with gas compression and nonproducing time for a well during injection. A flow simulation model is created to investigate alternating gas injection of a four-well pad and to assess the possibility of incremental oil production. Extensive numerical simulation is conducted. Capital expenditure, operating costs and the revenue from oil recovery were considered. Results indicate that gas injection within rates of 100–200 Mcfd can produce incremental oil. The gas volume needed is greater than what is typically flared from a facility, however, less than the total produced gas volume, and, therefore, possible. Communication of gas is likely to occur between wells within 1500 feet and wells positioned heel to heel that are common to the well-pad facility. The most promising injection period appeared to be within a 2-week to 1-month cycle. Thus, the proposed approach can be employed as an efficient Enhanced Oil Recovery (EOR) technique, alternating gas injection of 3 MMcfd may potentially increase the produced oil rate by 70 %. The findings support continued work to further investigate well configurations that can best benefit from the technique and to mature economic case studies.

Prospects of an Acid Gas Re-Injection Process into a Mature Reservoir

This study provides insights into the experience gained from the investigation of the dynamic behavior of a mature sour hydrocarbon reservoir modeling under an acid gas re-injection process production strategy. The primary objective was to analyze and evaluate the production behavior of proposed injection zones by assessing various injection scenarios and obtaining oil production over time. To achieve that, a workflow was developed to prioritize potential injection areas, select the optimal wells, determine the optimal operational parameters and optimize a pilot application design based on expected performance. Within this framework, the study encompasses diverse acid gas injection schemes on a pilot scale approach, including acid gas combined with waterflooding. The outcome of this analysis will eventually lead to the identification of the most promising and highest-performing injection scheme, elucidating the optimal range of operating parameters. This optimal combination forms the basis for the economic analysis of the venture and the subsequent detailed design of a full-scale application, where real-world implementation will validate the projected results.

A rapid optimization methodology of produced gas reinjection EOR in carbonate reservoirs

The Carboniferous carbonate reservoir of the Pre-Caspian basin has abundant oil and gas resources. The typical features of low porosity and low permeability and reservoir oil with high concentrations of H2S and CO2 and heavily dissolved gas-oil ratio allow produced gas reinjection as an effective and economic way to enhance oil recovery (EOR). However, the optimal design of injection/production parameters for gas injection processes is the premise for development scheme and technical decision. Compared to the conventional method of one-parameter-at-a-time approach with lack of interactions between various factors and tremendous challenge of main controlling factors identified, in this work we present a rapid optimization methodology to identify the main factors from numerous candidate parameters and obtain optimum levels of key factors. Our chosen methodology is a combination of experimental design with response surface method (RSM). Firstly, the two-level Plackett-Burman experimental design was used to screen and rank ten operational variables for the gas reinjection process. The top five significant parameters with the sum of their influencing weight greater than 94.3 % are bottomhole pressure for producers, reinjection ratio, injection period, injection gas timing and completion interval. Then the three-level Box-Behnken experimental design was employed to perform optimization exploration with the RSM. Regression models of the oil recovery factor (RF) were constructed by using these five key factors, which fits excellently with numerical simulation results. Finally, the optimal levels of controlling factors were determined to maximize oil recovery. This optimization procedure is very practical for reservoir engineers to guide a rapid evaluation of gas injection processes.

Effects of CH4/CO2 multi-component gas on components and properties of tight oil during CO2 utilization and storage: Physical experiment and composition numerical simulation

An essential technology of carbon capture, utilization and storage-enhanced oil recovery (CCUS-EOR) for tight oil reservoirs is CO2 huff-puff followed by associated produced gas reinjection. In this paper, the effects of multi-component gas on the properties and components of tight oil are studied. First, the core displacement experiments using the CH4/CO2 multi-component gas are conducted to determine the oil displacement efficiency under different CO2 and CH4 ratios. Then, a viscometer and a liquid density balance are used to investigate the change characteristics of oil viscosity and density after multi-component gas displacement with different CO2 and CH4 ratios. In addition, a laboratory scale numerical model is established to validate the experimental results. Finally, a composition model of multi-stage fractured horizontal well in tight oil reservoir considering nano-confinement effects is established to investigate the effects of multi-component gas on the components of produced dead oil and formation crude oil. The experimental results show that the oil displacement efficiency of multi-component gas displacement is greater than that of single-component gas displacement. The CH4 decreases the viscosity and density of light oil, while CO2 decreases the viscosity but increases the density. And the numerical simulation results show that CO2 extracts more heavy components from the liquid phase into the vapor phase, while CH4 extracts more light components from the liquid phase into the vapor phase during cyclic gas injection. The multi-component gas can extract both the light components and the heavy components from oil, and the balanced production of each component can be achieved by using multi-component gas huff-puff.

Flood Management: Solving Conformance or Sweep Efficiency Problems: Part 1

_ Since the advent of secondary recovery mechanisms, waterflooding or gas displacement, the oil industry has suffered from a variety of problems that yield inefficient displacement of hydrocarbon fluids during flooding. The industry has also suffered from a very low success rate at correcting these poor sweep efficiency problems. The first three articles in this series are designed to enhance our ability to identify, characterize, solve, and evaluate performance of solutions applied to conformance or sweep efficiency problems. This process structure will allow us to discuss key elements that should generate a higher success rate in solving conformance problems. Part 1 of this series focuses on candidate selection and problem clarification or problem understanding which are the first two elements of Fig 1. Overview The process wheel shown in Fig. 1 is used to identify the steps most production engineering companies take as they work through their conformance or sweep efficiency problems. This provides a basis by which we can discuss the various elements of solving these problems. The companies I have worked for chose to call this “conformance engineering.” Let’s define conformance engineering as: The process of utilizing reservoir and wellbore information to understand the flood performance and then use that understanding to adjust aspects of the flood which results in improved oil recovery. That is the working definition this series of articles will use for conformance engineering. I think we can all agree that this includes a large variety of sweep efficiency problems. These range from deep reservoir displacement fluid control issues to near-wellbore control issues and every combination of these elements. This includes issues for controlling displacing fluids at the injector or the producer. We can also use this to understand and characterize human-induced floods vs. natural processes. Strong water aquifer drives have the same displacement mechanisms as waterflooding. They have significant differences to elements like the pressure source, which is broad for aquifer drive and a very specific point source of pressure for pattern floods. In addition, a strong aquifer drive utilizes gravity segregation to enhance the efficiency of the drive where a pattern waterflood can suffer from gravity underrun. This is one of the reasons a peripheral waterflood can be a very effective secondary recovery process. We also consider fields where natural gas cap expansion drives oil displacement. In some fields, the gas cap is supported by gas reinjection. Prudhoe Bay is a prime example where there is no market for natural gas, so gas reinjection into the gas cap and gas cap expansion becomes a strong recovery mechanism for this field. For the sake of this JPT article series we will consider any flood process whether natural or induced to be part of flood management basics.

Natural gas flaring status in the Bakken shale play and potential remedial solutions

The flaring of associated gas from oil wells and the excess gas from gas-processing units and oil refineries is one of the most prominent producers of greenhouse gas emissions and is an extraordinary waste of economic value given the huge volumes of flared gas. In light of the increasing awareness of its negative impact, the industry is investigating economical means to reduce the anthropogenic release of greenhouse gases into the atmosphere. Oil production from the Bakken and Three Forks formations has significantly increased over the last ten years without commensurate augmentation of gas capture infrastructure, which consequently resulted in increased flaring of the associated gas. The North Dakota Industrial Commission (NDIC) has set rigorous regulations to reduce flaring. However, operating companies are experiencing challenges to meet NDIC gas capturing limit of 95%, which leads to oil production being curtailed.The project’s main objectives are to evaluate technically and economically the feasibility of deploying gas re-injection in the Bakken Formation as a means to increase oil recovery, reduce flaring and meet North Dakota Industrial Commission requirements. The techno-economic assessment utilizes reservoir simulation inputs and outputs such as production rate, fluid composition, injection fluid rate and composition, and bottom hole flowing pressure to provide a detailed costs and revenue estimation of injection and production. Different gas injection schemes are investigated, surface equipment and gas injection network are modeled and optimized. It is substantiated that gas re-injection can increase oil recovery by 34%. The results of this effort suggest that gas re-injection to mitigate flaring in the Bakken can be economically achievable.

An optimized economic-environmental model for a proposed flare gas recovery system

Iran is the second largest oil and gas producer among the Persian Gulf states, with 13.26 billion m3 gas flaring in 2020, approximately 9.34% of the global gas flaring. To reduce pollutants emissions and energy loss, an accurate feasibility study of flare gas recovery technologies is needed as the first step. Multi-objective optimization of process structure for the development of a comprehensive flare gas recovery system based on process simulation has not attracted much attention in the literature. In this study, a process structure for a flare gas recovery system was proposed using a multi-objective optimization approach to decrease associated gas flaring in southern Iran with a current flaring capacity of 279.7 MMSCFD. In the proposed structure, associated gas goes through sweetening and Natural Gas Liquids (NGL) units. After separating the liquid and vapor products, the NGL outlet gas is allocated to different units, including reinjection of gas to oil wells, gas pipelines, Liquefied Natural Gas, Compressed Natural Gas, Gas to Liquid, Gas to Power, and Desalination units. These units were simulated in Aspen HYSYS, providing an accurate economic and environmental analysis. Afterward, the shares of NGL outlet gas allocated to downstream units were considered optimization variables. The process structure was optimized by maximizing the economic (net present value) and environmental (greenhouse gas emission) objective functions. Results show that in the optimized process structure, 93.4% of the NGL outlet gas is allocated to gas injection and 6.6% to the power generation unit, resulting in a reduction of 6.22 million tons of CO2 emissions per year in this oilfield. The net present value of the flare gas recovery system is approximately 1.504 billion dollars, with a payback period of 1.60 years, suggesting the feasibility of the process.

How to Choose the Suitable Steel of Wellhead, Wellbore, and Downhole Tools for Acid Gas Reinjection Flooding

The material selection of injection gas wells in acid gas flooding is the bottleneck of the successful implementation of the technical scheme. Through standard and literature research, the materials of the wellhead, wellbore, and packer for reinjection well in acid gas flooding are preliminarily established, and then the suitable materials are further screened by using the weight-loss and surface characterization method. Finally, a new type of packer is designed to optimize the wellbore material. The results show that 35CrMo (CR = 0.0589 mm/y) steel is used for wellhead materials, 625 alloy steel is selected as the sealing surface, and 625 or 825 alloys (with CR ≤ 0.0055 mm/y) steel is used for wellhead sealing material. The main material of the packer is 718 Alloy (with CR ≤ 0.0021 mm/y). The cost of T95 steel within 20 years (1263 ten thousand yuan) of service is much smaller than that of G3 alloy (1771 ten thousand yuan), but after 30 years of service, its cost is close to that of G3 alloy. A kind of downhole packer for acid gas reinjection is designed. Among them, G3 alloy steel tubing is used between the packer and the relief valve, T95 steel tubing is selected above the packer and below the safety valve, and the packer is set in the G3 steel tubing. The serious pitting corrosion of T95 steel in the liquid phase environment is due to the uneven deposition of FeS and FeCO3 on the steel surface.

An Examination of the Legislative Framework on Gas Flaring in Nigeria

The rapid development of the global oil and gas industry has led to an increase in atmospheric emissions which is detrimental to the wider atmosphere. The flaring of gas during oil exploration and production activities alarmingly contributes to the emission of green-house gases which contribute to climate change. The enactment of legislation with adequate provisions for reducing and eliminating gas flaring from oil and gas activities cannot be over emphasized. Few countries of the world have successfully eliminated the problem of gas flaring through conservation and the enactment of adequate legislation which prescribes stringent sanctions for defaulters. However, Nigeria is an example of a country with inadequate gas flaring laws. The doctrinal methodology was adopted here in this research. Hence, Both primary and secondary sources of materials were used. This paper examined the effectiveness of the legal frame work and regulatory regimes on gas flaring in Nigeria with a view to determining if the phase-out of the problem can be achieved. This paper found out that the provisions of the Associated Gas RE-Injection Act (AGRA) 1979 and its Regulations of 1984, among other laws, are inadequate for regulating and/or eliminating gas flaring. This paper finally recommended developing more effective laws on gas flaring and methods by which the gas being flared can be conserved to ensure a clean and healthy environment in Nigeria, particularly the Niger-Delta.

Acid Gas Re-Injection System Design Using Machine Learning

An “energy evolution” is necessary to manifest an environmentally sustainable world while meeting global energy requirements, with natural gas being the most suitable transition fuel. Covering the ever-increasing demand requires exploiting lower value sour gas accumulations, which involves an acid gas treatment issue due to the greenhouse gas nature and toxicity of its constituents. Successful design of the process requires avoiding the formation of acid gas vapor which, in turn, requires time-consuming and complex phase behavior calculations to be repeated over the whole operating range. In this work, we propose classification models from the Machine Learning field, able to rapidly identify the problematic vapor/liquid encounters, as a tool to accelerate phase behavior calculations. To set up this model, a big number of acid gas instances are generated by perturbing pressure, temperature, and acid gas composition and offline solving the stability problem. The generated data are introduced to various classification models, selected based on their ability to provide rapid answers when trained. Results show that by integrating the resulting trained model into the gas reinjection process simulator, the simulation process is substantially accelerated, indicating that the proposed methodology can be readily utilized in all kinds of acid gas flow simulations.

Phase behavior of condensate gas and CO2 / CH4 re-injection performance on its retrograde condensation

Wenchang A Depression in Pearl River Mouth Basin is the largest hydrocarbon generating depression in the west of the area. After more than 30 years of exploitation, a large amount of gas condensate has been produced near the wellbore, which will cause gas condensate damage to the reservoir. It is planned to reinject the self-produced gas from Well WC9-2-X and the gas transported from the WC14-3 gas field to relieve the condensate damage in the near-wellbore area by means of retrograde condensation. In this article, the phase state change process of condensate gas in Well WC9-2-X with temperature and pressure was firstly investigated, and then the retrograde condensation effect of two types of gas on condensate was investigated. The research shows that when the reservoir temperature is 158.80 °C, the dew point pressure of condensate gas is 20.71 MPa, and the maximum amount of condensate is 1.28% (P = 9.01 MPa). Although Wenchang 9–2 is a low condensate reservoir, in the process of depressurization and production over the years, gas condensate has gradually accumulated, resulting in a large amount of gas condensate near the wellbore. With the increase of the gas re-injection amount, the two types of gas have a significant effect on the retrograde condensation of the gas condensate. From the variation trend of the gas and oil density released by the retrograde condensation, it can be seen that the re-injection gas preferentially dissolves the light components in the condensate, and then gradually dissolves the heavy components. The self-produced gas (gas No. 1) of Well WC9-2-X is dominated by CH4 (78.33 mol%), and the CO2 / CH4 contents in the input waste gas (gas No. 2) of the WC14-3 gas field are 42.50 mol% / 41.60 mol%, respectively. The retrograde condensation effect of gas No. 2 is better than gas No. 1, mainly because the content of CO2 in gas No. 2 is high, and it is easier to achieve the effect of miscible dissolution of condensate when mixed with condensate. It is recommended that gas No.2 should be preferentially used in WC9-2-X well for reinjection of retrograde condensation to relieve condensate damage. This article provides theoretical support for gas re-injection to relieve condensate damage in Wenchang 9–2 gas field, and has important significance for long-term exploitation of condensate gas reservoir.

Failure Analysis of the Metal Hose Puncture and Leakage in a Natural Gas Reinjection Station

The metal hose in the pump room of an oilfield natural gas reinjection station has multiple punctures and leaks. In order to analyze the reasons for the failures, a macro inspection, hydrostatic pressure and blasting test were carried out on a new hose of the same specification. Phase organization analysis, macro inspection, physical and chemical inspection, scanning electron microscopy (SEM), energy spectrum analysis, metallographic analysis and composition analysis of the conveying medium were carried out on the two failed hoses. The results show that the hydrostatic pressure test of the same batch of the new hoses of this specification meets the requirements of the standard, however the burst pressure does not meet the requirements of the standard. The failure is caused by the welding quality problems at the joint connection, welding defects such as weld bead, incomplete penetration and welding slag. The existence of deformation-induced martensite is found in the metallographic structure of the failed hose corrugated tube. There is tensile stress in the service environment, and a high content of corrosive medium Cl- in the conveying medium. Under the action of internal stress, the internal corrosive medium causes corrugation, the tube undergoes stress corrosion, thus initiating corrosion cracks and propagating along the grain boundaries, leading to the cracks and failure accidents.