Offshore Wells Research Articles

Application of leak-off test data in formation fracture gradient correlation for Niger Delta Basin natural gas wells development

Offshore drilling of gas wells in the Niger Delta is becoming very expensive and requires highly skilled manpower. Therefore, it is essential to accurately update the fracture pressure data, maintain adequate measurement while drilling, and ensure acceptable prediction with conventional empirical correlations while drilling operations are ongoing to avoid non-productive time (NPT). To effectively drill an offshore well and deliver it safely while protecting personnel, the environment, and equipment, drillers must ensure that the wellbore pressure is sufficient to balance the pore pressure without exceeding the fracture pressure anywhere along the open section of the well. Calculating and predicting the fracture pressure is critical for reducing NPT in offshore drilling and ensuring the safety of workers and goods on-site. There are numerous relationships for predicting the fracture pressures. However, they are primarily limited to onshore and shallow water fields, and as wells are drilled deeper in the Offshore Niger Delta field, a correlation (equation) based on offshore leak-off test (LOT) data is required to correctly estimate the crack pressure. Thus, this study employs a mathematical modelling technique to create an improved offshore fracture gradient equation from leak-off test data tailored to the needs of the offshore Niger Delta. The generated correlation (equation) was statistically examined, yielding a reliable coefficient of determination. It was tested again with the field cases, and the results were similar to the LOT results.

A conceptual model for sustainable cementing operations in offshore wells

This review paper introduces a conceptual model to enhance the sustainability of cementing operations in offshore wells. Traditional cementing practices, characterized by significant greenhouse gas emissions and compliance challenges, necessitate the development of more environmentally friendly approaches. The proposed model integrates low-carbon cement alternatives, such as geopolymer cements and supplementary cementitious materials (SCMs), with advanced slurry designs that incorporate nanomaterials, biodegradable additives, and recycled materials. This integrated approach reduces the environmental impact and enhances the mechanical properties and durability of cementing operations. The paper provides operational guidelines for implementing this model and discusses future prospects, emphasizing the importance of continued research and collaboration among industry stakeholders. By adopting these innovative practices, the oil and gas industry can achieve significant environmental benefits and ensure compliance with stringent regulatory standards, paving the way for a more sustainable future in offshore drilling.

A New Prediction Model of Annular Pressure Buildup for Offshore Wells

Subsea wellheads and Christmas trees are commonly utilized in deepwater oil and gas development. However, the special structure of subsea wellheads makes it difficult to monitor casing–casing annular pressure buildup, which in turn poses a greater risk to the integrity of the wellbore. In order to analyze the effect of changes in the casing-free section and the sealed section on the variation in annulus volume, a new annular pressure buildup model of casing-cement sheath-formation deformation was established and verified according to the elastic deformation theory. Furthermore, the influence of casing deformation on annulus pressure buildup was analyzed. Results indicate that the error of annulus pressure buildup predicted by the multi-string mechanical model proposed in this paper that considers the deformation of the casing sealing section is approximately 13% lower than the one that does not consider this factor. This paper provides guidance for the design of casing strings in deepwater oil and gas wells, ensuring safe production.

Evaluation of Biosurfactants to Preflush for Offshore Wells.

With the improvement of environmental protection requirements in offshore oil and gas exploration, there is a great demand to find environmentally friendly surfactants for cementing preflush fluids. In the present paper, the application potential of three biosurfactants of rhamnolipid, lipopeptide, and sophorolipid in the preflush fluid was evaluated through a series of experiments. The experiments studied the interfacial tension (IFT) of the biosurfactants, resistance to temperature, salt resistance (sodium chloride and sea salt), and the influences of the studied biosurfactants on the rheological compatibility and capabilities to convert the wettability of the formation from oil-wet to water-wet, mud cake removal efficiency, and to improve the interfacial bonding properties of the preflush fluid. The results showed that rhamnolipid, lipopeptide, and sophorolipid exhibited excellent surface activities in high-temperature and sodium chloride (NaCl) environments. When exposed to sea salt, lipopeptides lost their function due to agglomeration, while rhamnolipids and sophorolipids maintained structural stabilities and high surface activities. When rhamnolipid was mixed with sophorolipid in a ratio of 2:1 at the same concentration, the combined biosurfactant had the best surface activity among the studied surfactants. The combined biosurfactant not only had good rheological compatibility with the drilling fluid and cement slurry but also showed excellent properties in the removal of mud cake. In addition, the effect of the removal of the mud cake was verified by the gas channeling experiment. The experimental results show that the presence of mud cake can reduce the bonding strength. When rhamnolipid was mixed with sophorolipid in a ratio of 2:1 at the same concentration, the removal efficiency of mud cake was the highest, and the interfacial bonding property of the cement sheath can be improved.

Data-driven prediction of drilling strength ahead of the bit

This paper compares the performance of two data-driven methods, Signal-Matching Predictor (SMP) and Long Short-Term Memory (LSTM), for predicting drilling strength (Es) ahead of the bit based on drilling data from nearby offset wells. The comparison is based on the accuracy, applicability, complexity, and computational cost of the methods with the objective of suggesting the most appropriate tool for look-ahead drilling strength prediction. The methods were tested using data from offshore wells in Newfoundland. The SMP used a fixed-size sliding-window of real-time Es data from the target well to find a match in the offset well within similar geological formations and chose the scaled value from the offset well as the prediction. In the second approach, twelve LSTM models were trained using the drilling data of twelve offset wells, and the drilling data of the thirteenth well was used for blind testing. Results showed that the SMP achieved a coefficient of determination (R2) of 0.92, 0.92, and 0.79 for predicting 1.5, 3, and 5 feet ahead of the bit, respectively, while the LSTM reached an R2 of 0.95, 0.92, and 0.80 for the respective prediction intervals. The R2 of the LSTM models was further increased to 0.96, 0.94, and 0.83 after retraining it with weighted samples in formation transition zones. Also, a post-processing technique was proposed that further enhanced the R2 of the LSTM-based approach to 0.98, 0.97, and 0.93, respectively. The strength of the LSTM-based approach was to use measurable drilling parameters as the only inputs and not the Es itself. According to the results, the LSTM-based method can be reliably used to predict the Es ahead of the bit allowing drillers to identify upcoming drilling dysfunctions.

Oil and gas flow anomaly detection on offshore naturally flowing wells using deep neural networks

The oil and gas industry is changing. The drive towards cleaner and safer operations is becoming increasingly important. Researchers are looking for more efficient and accurate ways to detect faults that could lead to environmental and sustainability issues. This study aims to enhance the safety and sustainability of the oil and gas industry by improving existing artificial intelligence approaches to automate monitoring and detection of malfunctions. This article explores the application of deep neural networks for anomaly detection in monitoring oil and gas flow in natural flow offshore wells, proposing an innovative approach that takes advantage of the power of Genetic Algorithms and Gated Recurrent Units (GRU). The study aims to enhance the safety and sustainability of the oil and gas industry by leveraging artificial intelligence to automate the monitoring and detection malfunctions. Utilizing a comprehensive dataset from the 3W Petrobras project, which includes real-time data from 21 wells collected between 2012 and 2018, the research focuses on detecting various anomalies such as abrupt increases in basic sediment and water, spurious closures of downhole safety valves, severe slugging, flow instability, rapid productivity loss, quick restrictions in the production choke, scaling, and hydrate formation in production lines. The methodology integrates Long Short-Term Memory (LSTM) networks and GRU backbones with genetic algorithms to optimise model performance. Several hyperparameter optimisation tools were explored innovatively, focusing mainly on Genetic Algorithms, and it was possible to obtain an algorithm with 2 stacked GRU with better comparative performance compared to what is reported in the literature and producing an F1 equal to 0.97. The findings demonstrate the potential of AI to improve real-time anomaly detection, thereby reducing operational risks and contributing to the industry's transition towards greener practices. It also underscores the importance of open data and collaborative efforts in advancing AI applications in the oil and gas sector, aligning with the United Nations' Sustainable Development Goals to mitigate climate impact and promote responsible consumption and production.

An integrated 3D geomechanical study for accessing the wellbore complications of offshore wells in Mumbai offshore, India

An integrated 3D geomechanical study for accessing the wellbore complications of offshore wells in Mumbai offshore, India

Investigating creep performance of Wel-lok BiSN plug for sealing of offshore wells

In this study, we explore the long-term creep performance of the Wel-lok BiSN plug, a novel bismuth alloy-based sealing technology developed for the efficient abandonment of offshore oil wells. Unlike conventional cement-based solutions, the Wel-lok system leverages a thermite reaction to melt a bismuth alloy in situ, which flows into the wellbore to create a robust, leak-proof seal upon solidification. This process, completed within minutes, offers a rapid and environmentally friendly alternative to traditional methods. We conducted a comprehensive experimental and numerical analysis to assess the plug's durability under simulated downhole conditions, including a 50-year pressure buildup scenario.The primary merit of this method is its ability to provide a quick and reliable seal, significantly reducing the time and environmental impact associated with well abandonment. The thermite reaction and subsequent bismuth alloy flow ensure a high-density seal less prone to leakage than conventional cement-based plugs. Additionally, the Wel-lok system's resilience under long-term pressure buildup, as confirmed by our finite element simulations using ABAQUS, indicates its potential for extended durability.However, the method also has its disadvantages. Relying on a thermite reaction necessitates precise control over the reaction conditions to ensure consistent alloy melting and flow. Any deviation could result in incomplete sealing. Furthermore, while the bismuth alloy offers superior sealing performance, its behaviour under extreme downhole conditions, particularly over extended periods, still requires further empirical validation.Our findings, derived from laboratory thermite reaction modelling and finite element simulations, confirm that the material properties of the Wel-lok system, particularly its creep behaviour, significantly enhance sealing performance. This research validates the Wel-lok system's potential for widespread application in offshore well abandonment and contributes to developing sustainable and reliable well-sealing technologies.

Open-hole extension limit of offshore extended-reach well considering formation collapse

The current extension limit prediction model for offshore extended-reach well (ERW) in mudstone does not consider the formation collapse, which poses a huge risk to offshore drilling construction. To address this problem, this paper presents new open-hole extension limit prediction model for ERW. By considering formation collapse, rate of penetration (ROP), and annular pressure loss, the extension limit models during normal drilling and tripping were derived. The sensitivity of geological and engineering factors was evaluated by analyzing limits for wells 1H and 2H. The research results showed that: (1) The extension limit increases with the ROP and formation collapse duration, but decreases with the increase in mud weight, plastic viscosity, and flow rate. (2) In ERWs, the mud flow rate has a significant impact on the extension limit than the plastic viscosity of mud fluid. However, mud weight has the least impact compared to the two. (3) Considering various parameters, the predicted extension limit of well 1H, when the mud weight is 1.16 g/cm3 [9.67 ppg], is 1593.28 m [5225.96 ft] less than the limit when the collapse period is not considered.

Chemostratigraphy of the Sherbrook Supersequence – 13 wells from the offshore Otway Basin

An elemental chemostratigraphic study of the offshore Otway Basin has been undertaken as part of a collaboration between Chemostrat and Geoscience Australia, the main aim of which is to better constrain the sequence boundaries of, and within, the Sherbrook Supersequence. This study includes the elemental analysis of 1185 cuttings samples from the Sherbrook Supersequence (and overlying stratigraphy) in 13 offshore wells. Sampling of cuttings was particularly challenging as many of the targeted wells have a paucity of material available for destructive analysis. Inductively Coupled Plasma-Optical Emission Spectrometry and Mass Spectrometry (ICP-OES and MS) analysis was undertaken to establish a regional elemental chemostratigraphic framework of the Sherbrook Supersequence. The resultant framework comprises two chemostratigraphic sequences, seven chemostratigraphic packages and eighteen chemostratigraphic units. While the analysis could not clearly distinguish the base of the Sherbrook Supersequence it has provided valuable insight into correlations between wells, within the Sherbrook and overlying Wangerrip supersequences. Importantly it has confirmed that in the offshore part of the basin sedimentary processes and inputs remain unchanged from the Shipwreck to the Sherbrook (Turonian–Maastrichtian).

Optimization and Application of Wax Removal Technology for Fixed Tubing String in Offshore Wells

This study focuses on the selection and application of wax removal techniques tailored for fixed tubing columns in offshore wells that have been obstructed by wax deposits. Initially, the paper delves into the importance of well decommissioning and examines prevalent decommissioning techniques, outlining their respective advantages and limitations. Subsequently, three distinct unblocking technologies are proposed, tailored to address different causes and scenarios of well clogging: physical plugging removal technology, chemical treatment technology, and mechanical unblocking technology. Each technology is thoroughly analyzed, discussing their applicable scopes, operational procedures, equipment and anticipated effectiveness in removing blockages. To validate the feasibility and practicality of these proposed unblocking methods, an actual offshore well case study is conducted. The results demonstrate that thermal nitrogen wax removal technology emerges as the most effective approach, necessitating further optimization of its application. The paper then details the oil-filed implementation of this technology, including methods for generating hot nitrogen and its subsequent application. Following the implementation, significant improvements in wax removal and unblocking are observed, attesting to the technology's effectiveness. The findings of this study offer valuable insights and practical guidance for addressing wax blockage issues in fixed tubing columns of offshore oil wells. By providing a comprehensive analysis of different unblocking techniques and their application in oil-filed, this paper contributes to enhancing the efficiency and reliability of offshore oil production operations.

Equinor Leads Project To Turn Ubiquitous Drill Cuttings Into Precious PVT Samples

They were told it wouldn’t work. But in a new study, experts at Equinor and Applied Petroleum Technology (APT) suggest they are on the brink of using contaminated drill cuttings to predict critical reservoir fluid properties. The two Norwegian firms believe their project will soon make it possible to treat cuttings, collected from each well, as if they were pressure/volume/temperature (PVT) samples, which are collected from a significantly smaller share of wells due to the risks and high cost of doing so. Since its inception in 1972, Equinor has drilled over 5,000 offshore wells, from which just over 2,000 PVT samples have been gathered. Given that only two or three good samples are taken from most wells—almost always exploration wells—a significant data gap exists for the remainder, most of which are the subsequent development wells. And each year, Equinor drills around 20 to 25 new wells, mostly near existing platforms. If oil and gas firms could obtain PVT-like results from cuttings alone, they would presumably gain more precise guidance on where to place new wells along with insights on facility/topside design, reservoir management, and eventually on the plugging and abandonment phase. The big obstacle Equinor and APT are trying to surmount centers on how rock cuttings are soaked in oil-based muds (OBMs) as they circulate up the wellbore before being collected from a shale shaker. The oil ends up masking the reservoir’s hydrocarbons, rendering traditional geochemistry methods ineffective. What Equinor has shown in its study is that problem can be circumvented to obtain reliable estimates of API gravity and viscosity, two defining aspects of reservoir fluid quality and flow potential. Several more outputs are in the works. Tao Yang, an industry-recognized reservoir expert and chief professional at Equinor, said when he spoke with geochemists in the company about the project nearly 2 years ago, they were decidedly dubious. “They gave us a warning at the beginning and said that this was a very difficult area, that the cuttings were too dirty, and that we probably wouldn’t get anything out of them,” he said. But what few in the upstream industry knew at the time is that there existed a technology that can overcome the contamination issue—and it has been around for decades. Invented in the 1960s, gel permeation chromatography (GPC) coupled with ultraviolet (UV) absorbance detection, or simply GPC-UV, is used primarily by the chemicals sector for polymer analysis. The GPC aspect separates molecules based on their size as they flow through a gel-filled column. The smaller molecules take the longest to pass through while the larger molecules move more rapidly—the opposite of how most geochemistry assays work. As the molecules move down the column, they are exposed to UV light. Depending on their chemical structure, each molecule will absorb light at varying intensities which in turn can be measured and used to detect the presence of various compounds, including those indicative of oil.

A complex case of thermal maturity assessment in a terrigenous sedimentary system: The Northwestern Black Sea basin

An integrated approach combining fluorescence spectrometry, pyrolysis geochemistry, and dispersed organic matter (DOM) maceral analysis has been used to determine the thermal maturity of Oligocene source rocks in two neighboring offshore wells within the complex deep-sea system of the Northwestern Black Sea. The samples contain predominantly immature Type II kerogen, including a mixture of marine liptinite (alginite, liptodetrinite), degraded liptinite, primary vitrinite, and reworked vitrinitic macerals. The occurrence of several vitrinite reflectance (VRo) populations in the samples is attributed to a high influx of reworked vitrinite transported to the marine basin from multiple terrestrial sources with diverse degrees of degradation. The presence of multiple VRo populations complicates the application of VRo for determining the thermal maturity of the organic matter. Further, the VRo measurements on the primary vitrinite population show only a subtle increasing trend with depth. A significantly improved thermal maturity resolution was obtained using the red to green quotient (R/G). R/G was measured on the autochthonous unicellular Tasmanites-type alginite under UV-excitation. In contrast to VRo the results show a significant correlation between increasing R/G values with increasing depth. This indicates that the R/G quotient is a better maturity proxy for the studied low maturity marine system with a large influx of sediments. The beginning of the downward declining trend in the temporal variation of liptinite is regarded as the onset of catagenesis. This occurs at a burial depth of 2.5 km and a R/G value of 0.50, corresponding to a VRo equivalent (VRo Eq) of 0.44%. At a burial depth of 3.2 km and a R/G value of 0.57 (VRo Eq = 0.57%), the onset of the oil window is marked by an increase in the amount of solid bitumen (initial oil solid bitumen). The observed alterations in maceral composition with burial depth align with the thermal maturity of the wells. However, the data suggest that the thermal evolution of the organic matter is out of sync with the surrounding formation temperature, possibly due to rapid burial induced by a high sedimentation rate.

Sequence stratigraphy and palaeogeography of the Upper Jurassic and Lower Cretaceous in the Eastern Barents Sea

AbstractThe Upper Jurassic–Lower Cretaceous sedimentary rocks in the Eastern Barents Sea Basin are up to 2 km thick and represent one of the least studied Arctic intervals. Here, for the first time, we present a detailed analysis of 43,000 km of 2D seismic profiles, as well as well‐log and core data from 24 offshore wells with the aim to create a comprehensive sequence stratigraphic framework that can be integrated with the rest of the basin. Results show that (1) seven third‐order sequences and five types of clinoforms can be identified based on integrated seismic and well data. The age of each sequence was established based on published biostratigraphic investigations along with new dinocyst interpretations included in this study; (2) the deep marine basin was gradually filled with sediments coming from north, east and south as a response to HALIP, Canada Basin opening and Cimmerian uplift of Novaya Zemlya, and was preserved only in the south‐western part of the Barents Sea Basin at the end of Early Cretaceous and (3) both Eastern Barents Sea and West Siberia Basin share similarities in sedimentary environments and tectonic setting, though the spatial distribution of clastic reservoirs in Upper Jurassic and Lower Cretaceous mega‐sequence heavily depends on the source areas that require more provenance focused research. The results presented here can be used in further regional exploration in the area and to better understand the geodynamic evolution of the Greater Barents Sea Basin.

Foamed Cement Applications in Oil Industry Based on Field Experience: A Comprehensive Review.

Foam cement is a versatile cementing material that has found numerous applications in the oil and gas industry. As research continues to advance and improve the properties of foam cement, it is likely that we will see an increased use of this material in the years to come. This review aims to summarize the current state of the art and the latest developments in the utilization of foam cement in oil fields. The study focuses on the key benefits of foam cement, including its light weight, excellent flow properties, ability to maintain its structural integrity over time, and high compressive strength. It also examines its various applications in oil field operations, such as cementing against fragile formations, well abandonment, zonal isolation, cementing offshore wells, and well remedial cementing. Furthermore, the paper evaluates the various factors that influence the performance of foam cement, such as the mixing design, foam structure, and stability. In addition, the methods for evaluating the foamed cementing job and the integrity of the formed cement sheath are also presented. The review also highlights the current challenges and limitations of foam cement technology that should be considered when using foamed cement in oil field applications and discusses the future directions for its development and optimization. This review provides a comprehensive overview of the applications of foam cement in oil fields and will be of great interest to engineers, researchers, and practitioners in the oil and gas industry.

Types of offshore drilling platforms

The Russian Energy Strategy for the period up to 2035 estimates the development of the hydrocarbon resource potential of the continental shelf of the Arctic seas as the most important geopolitical and technical challenge for the Russian oil and gas sector. An adequate response to it means sufficient production of hydrocarbons in the country beyond the time horizon of 2035. Russia’s continental shelf includes the following oil and gas bearing provinces: West Barents, East Barents, Timan-Pechora, West Siberian, Khatango-Vilyui, Laptev, East Arctic, Novosibirsk-Chukotka, Okhotsk, Baltic and Caspian regions. The first eight provinces are located in the Arctic shelf zone, which is a strategic region in the context of resource potential and opportunities for the development of available mineral resources. The estimate for the initial recoverable hydrocarbon resources is 100 billion tons of standard fuel. The methods and equipment used for drilling offshore wells (offshore drilling) are very similar to those used for onshore drilling. In contrast to onshore drilling, the functional scheme for offshore drilling is complicated by the presence of a water column between the wellhead and the drilling rig. This paper gives an overview of existing offshore drilling rigs: fixed, semi-fixed and mobile platforms. It also includes description of pros and cons of such offshore platforms.

Integrated technology for layered sand control and layered water injection

In order to solve the problem of water injection string failure caused by pipe creep and sand production in layered water injection wells, an integrated technology of layered sand control and layered water injection has been developed. A suspended large-radiuslayered mechanical sand control pipe column has been designed, providing sufficient design and usage space for the layered water injection pipe column. Developing a new type of anti-creep sealed packer can effectively improve the anti-creep performance of the water injection string and extend the validity period of the string. This technology integrates and optimizes layered water injection and sand control technology, large channel backwashing technology, integrated testing and allocation technology, and anti-creep technology of the pipe string. While effectively solving sand production in offshore water injection wells, it extends the service life of the water injection pipe string and reduces operating costs. Since 2018, this technology has been implemented in over 200 wells in Chengdao Oilfield, with a maximum of 6 layers for prevention and injection, a maximum well inclination of 48.8°, and a construction success rate of over 90%. It has achieved very good development results and economic benefits.

Influence of fluid viscosity hierarchy on the reverse-circulation displacement efficiency

Reverse-circulation cementing is an alternative strategy for well cementing where the cementing fluids are injected directly into the annulus from the surface. This cementing strategy can reduce downhole circulation pressures compared to conventional circulation cementing and potentially eliminate the need for retarders in the cement slurry. In reverse-circulation operations, the fluid hierarchy will normally involve density-unstable combinations along the annulus. Since the annular geometry prevents the mechanical separation of fluids, reverse-circulation cementing is associated with a risk of slurry contamination and mixing during placement. Although reverse-circulation cementing has been known for several decades and is used for cementing of both onshore and offshore wells, it remains unclear whether conventional circulation job design guidelines apply to reverse-cementing or indeed how fluid properties should be optimized for such operations. The purpose of the current study is to contribute to the understanding of buoyant annular displacements, with a particular focus on the role of viscosity hierarchy on the annular displacement in vertical and near-vertical annuli.We present a combined experimental and numerical study of density-unstable downward displacements in a downscaled, narrow concentric annulus. A transparent annulus flow loop was used to conduct downward displacements. A high-speed camera and a mirror arrangement were used to track the displacement. Numerical simulations of the experiments and selected other cases were performed using the open-source OpenFOAM computation framework. We study Newtonian and mildly shear-thinning fluids, and our study aims to determine whether it is more efficient to use a displacing fluid with higher viscosity or lower viscosity than the displaced fluid while maintaining a constant average viscosity for the fluid pair. The experimental and numerical results, which are in good qualitative agreement, demonstrate that the viscosity hierarchy of the fluids significantly affects the displacement flow features. Our results show that a more viscous displaced fluid leads to faster growth of the instabilities and, as a result, less efficient displacement. Oppositely, we observe less tendency for finger growth and a more diffusive mixing region for more viscous displacing fluids. The effect of the viscosity hierarchy can get stronger by increasing the inclination of the annulus and the viscosity difference between the fluids from 0.006 to about 0.02 Pa⋅s. The findings can assist in the selection of fluid properties for future reverse-circulation displacement operations.

Methanol infrared spectral characteristics in offshore gas logging

Methanol infrared spectral characteristics in offshore gas logging. Methanol was found in the logging gases during offshore gas logging by infrared spectra. Logging gas spectra from over 300 offshore wells and 1,000 onshore wells were processed and analyzed, and methanol characteristics were prevalent in the offshore logging gases but not onshore logging gases. The spectra of instruments Alpha111829 and Alpha111834 are studied as examples. The methanol concentrations in some areas exceeded 1 vol%, seriously interfering with the other measurements of alkane gases. Moreover, there are rapid changes in the trends of methanol concentrations. It indicates that methanol does not originate from drilling fluid additives. The results of the correlation analysis show that there are no strong correlations between methanol and the other logging gas component concentrations. Therefore, methanol may be neither a judgmental indicator component gas for natural gas nor oil but a separate energy source. We believe methanol in the offshore logging gases originates from strata. The discovery and analysis of methanol in offshore logging gases are significant in atmospheric and marine environments, oil and gas exploration, geochemistry, and energy.

Sand control screen selection for cased dual‐annulus gas offshore wells based on scaled laboratory tests

AbstractThis paper assessed and ranked several alternatives to control sand production in a well recompletion effort of offshore gas wells that have experienced massive sanding. The aim was to select an appropriate thru‐liner sand control system to increase well productivity. Four different screen types were evaluated, including a wire‐wrapped screen (WWS), slotted liner (SL), punched screen (PS), and a new multi‐layer open cell matrix polymer (OCMP) filter resembling gravel‐pack. The performance of screens regarding sand production and plugging was evaluated using a sand retention testing facility featuring a custom‐made device that mimics the unique well completion configuration. Further, a novel testing setup was constructed to assess the erosion potential of screens subject to high‐velocity gas and sand flow. All assessments were conducted under the representative actual well conditions. Laboratory tests indicate the superior performance of the OCMP filter compared to the other three options. Even though SL, WWS, and PS performed similarly in sanding, the WWS posed a higher erosion risk, with PS following in second place. The plugging tendency of the WWS was the least among all the options, whereas the PS had the highest tendency. Despite this, the WWS's sanding performance is expected to decline due to its vulnerability to erosion. Overall, the testing results indicated that the OCMP filter provides a promising solution to the issue of sand production in the gas wells being evaluated. However, the interaction of the OCMP filter with potential treatment chemicals in the wells should be tested before it can be used.