Offshore Field Research Articles

Extraction, characterization, and evaluation of galactomannan from Barbatimão Verdadeiro as a potential additive for enhanced oil recovery fluids

Polymers play a crucial role in enhanced oil recovery (EOR) by increasing the viscosity of injection fluids and enhancing oil displacement. The widely used polymer, partially hydrolyzed polyacrylamide (HPAM), faces performance degradation in high-salinity and high-temperature environments. This study explores galactomannan from Stryphnodendron polyphyllum seeds as an alternative viscosifying agent for EOR fluids. An extraction process for galactomannan from Barbatimão Verdadeiro seeds was developed, yielding 23.3% m/m. The biopolymer was characterized using Fourier transform infrared spectroscopy (FTIR), nuclear magnetic resonance (NMR), thermogravimetric analysis (TGA), and size exclusion chromatography (SEC). Rheological behavior was tested in brines of different salinities, and injectivity/filterability tests were performed following API RP 63:1990 standards. The galactomannan obtained from Stryphnodendron polyphyllum exhibited a mannose-to-galactose ratio of 1.32. Rheological analysis showed pseudoplastic behavior, with viscosities of 38 cP in brine solutions at 7.37 s−1 and 60 °C. Filterability tests demonstrated satisfactory injectivity with factors of 1.09 (8 µm) and 0.67 (1.2 µm). Compared to HPAM, galactomannan exhibited superior viscosity retention in high-salinity conditions, where HPAM dropped to 6 cP. The galactomannan extracted from Stryphnodendron polyphyllum seeds is a promising biopolymer for EOR applications, offering superior performance under harsh conditions compared to traditional HPAM. Its resilience to high salinity and temperature makes it a viable alternative for pre-salt and offshore fields, contributing to more sustainable and efficient oil recovery.

Data Science Enables Management of Stealth Asphaltene Flow-Assurance Risk

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216216, “Managing Stealth Asphaltene Flow-Assurance Potential Risk in Gas-Injection Field Based on Data Science Using Over 20-Year Accumulated Data Set,” by Hideharu Yonebayashi, SPE, and Takeshi Hiraiwa, SPE, Japan Oil Development, and Khuloud T. Al Khlaifi, SPE, ADNOC, et al. The paper has not been peer reviewed. _ Gas injection is recognized generally not only to improve oil recovery but also to increase the risk of asphaltene destabilization. The recent discovery of asphaltene deposits in a subject field motivated the operator to launch an immediate investigation to evaluate what critical risks might exist and consider appropriate mitigation. It was found that precipitated but invisible asphaltenes still can be flowable. This stealth asphaltene behavior could explain a possible mechanism of the first asphaltene observation in the upper reservoir. Introduction The subject giant offshore field in the Arabian Gulf has not experienced asphaltene-induced production deterioration during long-term lean hydrocarbon gas injection. The gas has been injected into the crestal area of two reservoirs (upper and lower) with peripheral powered seawater injection. Both reservoir fluids contain a small amount of asphaltenes (0.1–1.5 wt%) distributed at higher concentration at deeper locations. In May 2022, the first discovery of asphaltene deposits from the historical no-issued area in the upper reservoir motivated an immediate investigation for risk assessment and mitigation. A resulting study captured stealth asphaltenes, which were detected by a laser-light-scattering technique while high-pressure microscopy detected no visible asphaltene solid particles. Historical Asphaltene Data Accumulation The permeability range and pore-throat size of the subject field are relatively low in the lower reservoir compared with the upper. Both reservoirs are under highly unstable asphaltene-stability conditions. The reservoir pressure-maintenance scheme, consisting of dump-floodwater injection followed by peripheral powered seawater injection and crestal gas injection, however, has maintained asphaltene-free production except for the gas-injection pilot (GIP) during 2005–2009. No asphaltenes have been observed in the crestal gas-injection area; however, asphaltene deposits were observed in the GIP area in 2007. The injected gas was enriched gradually by a vaporizing gas-drive process. The previous studies involving numerical modeling analysis and laboratory experiments reported that enriched hydrocarbon gas can more easily allow asphaltene precipitation compared with lean hydrocarbon gas. GIP Asphaltene Risk Analysis (Upper Reservoir). In 2009, an asphaltene flow-assurance risk evaluation was conducted using the single-phase bottomhole sample collected from Well 6, which is 90 ft shallower that the GIP area and far from the crestal gas-injection area. Therefore, the Well 6 reservoir fluid was not affected by injection gas. The bottomhole condition of the GIP production well was entered into the asphaltene precipitation envelope (APE) that was expanded by injection-gas enrichment but never covered by the APE without an enrichment process. Latest Laboratory Analysis (Lower Reservoir). In 2022, an asphaltene flow-assurance risk evaluation was conducted. After the location was narrowed to a depth range, Well 1 was selected by taking an asphaltene gradient into account.

Identification of Shale Layer in Offshore Field of North East Java Basin for Non-Conventional Oil and Gas Exploration

<p>Non-conventional hydrocarbon exploration is one way to develop shale potential to increase oil and gas reserves in Indonesia. Shale is a rock that is rich in organic material and is a target for non-conventional exploration, because it functions as a source and reservoir rock with a large shale volume and low permeability. Isopach maps can represent the thickness of shale layers and have the potential to become non-conventional exploration targets located in thick shale layers. Based on this background, this research will identify shale layers in the offshore fields of the North East Java Basin for non-conventional oil and gas exploration. The methods used are well logging and seismic methods. This research focuses on determining the location of shale layer depocenters based on isopach maps as a first step in localizing areas that will be targeted for the development of non-conventional hydrocarbon exploration. This research uses 29 2D seismic lines and 2 well data, namely NP-1 and NP-2 wells and the research target is the Kujung Formation and Ngimbang Formation in the offshore area of the North East Java Basin. The results obtained from the isopach map show that the depocenter location of the Kujung Formation is in the northwest direction with a shale thickness of 600-800 meters, while the Ngimbang Formation is in the east direction with a shale thickness of 1000-1300 meters. From the depocenter location, it can be seen that this location has a wealth of organic material so it has the potential to become a source rock and reservoir.</p>

Development of Machine Learning-Based Production Forecasting for Offshore Gas Fields Using a Dynamic Material Balance Equation

Offshore oil and gas fields pose significant challenges due to their lower accessibility compared to onshore fields. To enhance operational efficiency in these deep-sea environments, it is essential to design optimal fluid production conditions that ensure equipment durability and flow safety. This study aims to develop a smart operational solution that integrates data from three offshore gas fields with a dynamic material balance equation (DMBE) method. By combining the material balance equation and inflow performance relation (IPR), we establish a reservoir flow analysis model linked to an AI-trained production pipe and subsea pipeline flow analysis model. We simulate time-dependent changes in reservoir production capacity using DMBE and IPR. Additionally, we utilize SLB’s PIPESIM software to create a vertical flow performance (VFP) table under various conditions. Machine learning techniques train this VFP table to analyze pipeline flow characteristics and parameter correlations, ultimately developing a model to predict bottomhole pressure (BHP) for specific production conditions. Our research employs three methods to select the deep learning model, ultimately opting for a multilayer perceptron (MLP) combined with regression. The trained model’s predictions show an average error rate of within 1.5% when compared with existing commercial simulators, demonstrating high accuracy. This research is expected to enable efficient production management and risk forecasting for each well, thus increasing revenue, minimizing operational costs, and contributing to stable plant operations and predictive maintenance of equipment.

Remedial Conformable Sand-Control Technology Deployed Offshore Colombia

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23690, “First Horizontal Deployment of Remedial Conformable Sand-Control Technology in Colombia: Qualification and Case Study,” by Suzanne Stewart, SPE, TAQA, and Jose M. Bermudez, SPE, and Camilo Mazo, Hocol, et al. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference. _ The challenge of remedial sand control lies in the fact that the system must pass through restrictions in the upper completion before ideally conforming to the inner diameter (ID) of the zone requiring sand control. The complete paper describes the qualification of a multilayer, open-cell matrix polymer (OCMP) system for the first horizontal deployment in an offshore gas well. The system is capable of being deployed remedially through tight tubing restrictions while providing conformant sand control in a horizontal wellbore without the need for gravel packing, making the approach particularly valuable for scenarios where surface space is limited. Background During 2006, gas Wells CH-20, CH-19, and CH-18 were originally drilled and completed in the B2 zone in the Chuchupa field offshore Colombia. Wells CH-20, CH-19, and CH-18 experienced water breakthrough from the aquifer in late 2016, 2018, and 2020, respectively. The first workover operation in these wells was performed in 2021. The aim was to isolate the B2 zone with a packer and to perforate the slightly shallower B1 zone to access attic gas. In Well CH-18, an inflatable packer between Zones B2 and B1 was installed successfully, resulting in the ability to produce at full potential, while Wells CH-19 and CH-20 recovered their potential partially but below the calculated target rate. A new operation for the three wells was planned in 2022 to set a mechanical packer to isolate Zone B2 and reperforate Zone B1 to increase flow area, reduce drawdown at the sandface, and diminish the risk of sand production. However, because produced sand had accumulated in front of the perforations in all wells, removing the sand and setting the mechanical packer was impossible. At present, Wells CH-19 and CH-20 are not producing and Well CH-18 is on lower-than-calculated target production. Given the production difficulties, the plan is to isolate Zone B2 successfully in all wells, clean the wells, and install effective remedial sand control with significant surface-space constraints. OCMP: Conformant Remedial Through-Tubing Sand Control The OCMP system evaluated and subsequently selected for this application consists of multiple layers of highly porous (up to 85%) and permeable (40 darcies or greater) OCMP bonded to a specially designed base pipe. The compressibility of the system enables it to be run in hole compressed within a sleeve to allow passage through tight restrictions in the upper completion; then, once in place, the sleeve can be removed, allowing a return to the original shape and conformance to the ID of the sand-producing section. The system can be run on slickline, braided line, coiled tubing, or pipe. If deployed with a hydraulic conduit, it has the capability to perform sand cleanout during deployment and can incorporate an integral hydraulic-set, high-expansion anchor. If run with slickline or braided line, it is necessary to run an anchoring device on a separate trip; then, the first OCMP system can be anchored in place.

Integrated Seismic Attributes as a Tool to Delineate the Oligocene Channels Architecture, Baltim Field, Offshore Central Nile Delta, Egypt

The hydrocarbons in the Nile Delta area are produced from both clastic and non-clastic reservoirs, with ages ranging from the Early Cretaceous to the Plio-Pleistocene. The study area is situated in Baltim field offshore, Central Nile Delta, approximately 10 kilometers off the Egyptian coast (Fig. 1). The main producing reservoir in Baltim field is Abu Madi Formation (Miocene age) as there were many discoveries in the last decades resulting in most of the area had been considered as a brown field. Nowadays, the Oligocene section is considered as the hope for new hydrocarbon potentiality in the deep section (below Miocene). Among the drilled sedimentary sequence in the Nile Delta, Tineh Formation (Oligocene age) contains multiple levels of reservoir rocks with high-quality reservoirs including: Satis-1, Satis-3, Notus-1, Tineh-1, Atoll-1 & Salamat-1 (Fig. 2). This work's objective is to delineate the different channels of the Oligocene section in trial to add more reserves to the field. One of the main challenges for the exploration of these deep reservoirs is to delineate the reservoir geometry itself. A strong tool for improving bed thickness imaging and mapping, geologic discontinuities and channel delineation is the spectral decomposition technique providing more details than the conventional amplitude extractions. So, in this work, we applied the spectral decomposition tool to track the geometric dimensions of the Oligocene channels. RGB color blending performed from 10, 16, and 20 Hz represents the most significant geological features to get a better picture of the channel’s geometry. After determining the channel’s boundary by using the RGB blending, the channel geo-body was extracted. This technique helps in reducing the uncertainties of hydrocarbon exploration. Consequently to the integration between RMS amplitude maps and the channel geo-body that was extracted from the spectral decomposition, Oligocene channels became clearer and the boundaries well defined.

FACIES PARTITIONING AT REGIONAL AND FIELD SCALES IN THE BARREMIAN KHARAIB‐2 CARBONATES, UAE

Carbonates in the Lower Cretaceous (Barremian to early Aptian) Kharaib Formation are reservoir rocks at giant oil fields in the UAE and Qatar. The Barremian Kharaib‐2 member (K60), the focus of this study, is in general composed of a regionally continuous succession of high‐energy, shallow‐water limestones bounded above and below by “dense” low‐energy mud‐rich strata. Despite several decades of research, conventional carbonate facies classification schemes and resulting facies groupings for the Kharaib‐2 member have failed to show a statistically acceptable correlation with core‐ and log‐derived petrophysical data. Moreover, sedimentary bodies potentially responsible for dynamic reservoir heterogeneities have not clearly been identified. This paper proposes a standardized facies classification scheme for the Kharaib‐2 carbonates based on vertical facies proportion curves (VPCs) and variogram analyses of core data to construct stratigraphic correlations at both field and regional scales. Data came from 295 cored wells penetrating the Kharaib‐2 member at ten fields in the on‐ and offshore UAE. Thin, dense intervals separating reservoir units were adopted as fourth‐order transgressive units and were used for stratigraphic correlation. Field‐scale probability maps were used to identify sedimentary bodies such as shallow‐water rudistid shoals.Regional stratigraphic correlations of the Kharaib‐2 member carbonates based on the VPCs identified variations in depositional environments, especially for the lower part of the reservoir unit; depositional facies at fields in the SE of the UAE were interpreted to be more distal compared to those at offshore fields to the NW. At a field scale, the VPCs failed to identify significant lateral variations in the carbonates. However, variogram analyses of cored wells showed spatial concentrations of specific facies in the inner ramp domain which could be correlated with high‐energy depositional bodies such as shoals dominated by rudist debris. The bodies were sinusoidal in plan view with lengths of up to 8 km and widths of ca. 1 km. Although similar‐shaped bodies with these dimensions have been reported from other carbonate depositional systems, they have not previously been reported in the Kharaib Formation. At a regional (inter‐field) scale, the stratigraphic correlation of standardized sedimentary facies remains problematic; however, mapping of facies associations and their relative proportions relative to their environments of deposition demonstrated new patterns for the stratigraphic architecture of the Kharaib‐2 member in the UAE.

Polyester mooring system design and evaluation of a semi-platform in south China sea

Polyester rope offers numerous advantages over traditional steel catenary mooring systems and is considered an appealing option for deep-water mooring systems. In this paper, the design and evaluation procedure of the polyester mooring system for a semi-submersible platform located in the South China Sea is presented. A fully coupled numerical model of the semi-submersible platform, including all risers and mooring lines, has been established and calibrated through wave basin testing. To simulate the elongation behavior of polyester, a static-dynamic stiffness model is employed, and the corresponding procedure for mooring evaluation is established to simulate the mooring response under extreme environmental conditions. A comprehensive fatigue analysis is also conducted for the polyester mooring system using time domain dynamic theory. The effects of Vortex-Induced Motion (VIM) on mooring fatigue damage are also considered. The results indicate that the polyester mooring system could be safely operated at the target offshore field throughout its service life. Additionally, model test calibration is a crucial procedure during the entire mooring evaluation process, and the numerical model should be adjusted appropriately to accurately reflect the dynamic behavior of the coupled system. This study also illustrates that the stiffness of the rope plays a crucial role in polyester mooring design and global performance calculations. The proposed evaluation methodology can provide a foundation for the design of polyester mooring systems and for evaluating their safety and reliability in engineering practice.

Graphene Nanoplatelets Extend Life of Scale-Inhibitor Squeeze Treatment

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 215228, “Graphene Nanoplatelets for Extended Lifetime of Scale-Inhibitor Squeeze Treatment in a High-Temperature Reservoir,” by Suzalina Zainal, SPE, Norzafirah Razali, and Mohamad A. Rodzali, Petronas, et al. The paper has not been peer reviewed. _ Scale-inhibitor squeeze (SISQ) treatment is an established method for offshore fields that allows an extended effectiveness of scale inhibitors in preventing deposition over time. One of the primary issues in SISQ campaigns is the short squeeze lifetime of less than 1 year. The study detailed in the complete paper proposed graphene nanoplatelets (GNP) as a preflush system to extend the lifetime of a conventional SISQ treatment. This carbon-based nanomaterial allowed enhanced adsorption of the phosphonate-based scale inhibitor. GNP as a Preflush System A high-surface-area GNP preflush system was chosen to condition the rock surface to overcome the apparent lack of suitable surfaces available for scale-inhibitor adsorption during SISQ treatment. The GNP was injected to coat the rock surface. GNPs consist of a few graphite layers with thicknesses varying from 0.7 to 100 nm. The carbon-based nanomaterial forms a honeycomb structure, regarded as a good alternative to its predecessor, graphene, because of its lower cost and potential for large-scale production. GNP particle size ranges between 100 and 200 nm. This 2D carbon nanomaterial offers several advantages, such as high surface area, a high aspect ratio with a planar shape, and good mechanical properties with excellent thermal and electrical conductivities. It is also inert toward common reservoir fluid. Experimental Procedure Materials. Injection and formation water (brine samples) were prepared based on compositions listed in Table 1 of the complete paper. Berea core plugs were used for static-adsorption and injectivity experiments. In these two experiments, the core samples were used to provide similar rock properties when comparing performances of the baseline preflush (seawater) vs. nano-preflush systems. The average rock permeability for the candidate oil field is between 200 and 400 md. Dispersion Evaluation in High Divalent Brine. Gum arabic (GA) stabilized the GNP in high divalent brine. The polymer-grafted GNP (P-GNP) samples were evaluated in terms of exfoliated sites as compared with GNP alone. Zeta-potential and particle-size analysis also were performed at different P-GNP concentrations. Static-Adsorption Evaluation. A static-adsorption method was designed to replicate preflush injection of P-GNP before introduction of scale inhibitor. Experiments compared the adsorption of the scale inhibitor onto crushed Berea rock, precoated with P-GNP, with another without pre-coating that used seawater preflush only. Coreflood Evaluation. Because of the scarcity of the native core samples, only Berea core samples were used for the injectivity study, while native core samples were used for the SISQ adsorption/desorption coreflood evaluation. In both types of experiments, a P-GNP preflush system was compared with the baseline (seawater preflush).

Solution Enables Well Surveillance in Stacked Reservoirs With Near-Critical Fluids

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23912, “Digital Solution for Well Surveillance in Stacked Reservoirs With Near-Critical Fluid Systems,” by Kristian Mogensen, SPE, Carlos Mata, SPE, and Swarjit Samajpati, ADNOC, et al. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference. _ Fully compositional integrated asset models (FC-IAMs) are being deployed for an increasing number of fields in the operator’s portfolio. The complete paper describes the development of comprehensive digital well surveillance and field-production optimization for an offshore field consisting of four stacked reservoirs, each containing near-critical fluids. Augmenting the FC-IAM with high-frequency sensor data in addition to proprietary tools to actively monitor well performance helps identify and pursue opportunities to maximize oil production from the field, subject to several system constraints. Introduction The field is approximately 120 km offshore Abu Dhabi. During the appraisal phase, eight wells penetrated the structure and confirmed that the predominant lithologies are composed of dolomite and anhydrite, with subordinate limestone. Production of oil and gas comes from four main reservoirs—A, B, C, and D. The ongoing development centers around miscible gas injection along the crestal part of each reservoir and peripheral water injection. Integrated asset models are one of many key initiatives supporting the operator’s Smart Production Growth initiative. Although the calculations identifying scope for improved production rates are firmly founded in science, substantial digitization efforts are required to automate, streamline, and sustain any such digital solution. Fig. 1 illustrates the fact that company database management plays a fundamental role in providing reliable input to keep models updated and fit for purpose. Fluid-Property Modeling Each of the four producing reservoirs contains near-critical fluids exhibiting a steep compositional depth gradient, which means that the solution gas/oil ratio (GOR) is well-specific and may change over time. The GOR trend is governed by several factors. The lightest part of the fluid column may be produced first because of the improved mobility; this would lead to a decreasing solution GOR over time. However, because of the crestal miscible gas injection, significant swelling will result in a gradual GOR increase followed by gas breakthrough. Solution GOR increases because of gas swelling. It is important to make the distinction between solution gas and free gas because the operational guidelines dictate that the reservoir pressure should be maintained above the saturation pressure and above the minimum miscibility pressure. Well-Test Validation Workflow The compositional framework adds an extra layer of complexity because fluid composition needs to be specified at the well level. A robust procedure is needed to first assign an initial reservoir fluid composition to each well. The second key task is to capture changes over time. The method of solution is referred to as a target GOR calculation. For any given fluid system, an equation of state (EOS) model must be tuned to experimental data to convert compositional information to black-oil properties at specific pressures and temperatures. A so-called anchoring fluid composition initially is assigned to the well, and the EOS can then calculate the resulting GOR and other variables from a simulated separator test. The evolved gas and liquid phases are then recombined mathematically to match a measured GOR from a production test. Matching is an iterative process but normally converges very quickly.

Technology Focus: Field Development (September 2024)

As the industry progresses, the need for further collaboration is imperative on all fronts. Academic expertise, operational experience, and knowledge gathered through trial-and-error analysis must be meshed in order to achieve the optimizations that are increasingly needed with the depletions we experience in various fields globally. The challenges that we face as an industry will require development of new technologies, whether workflows or other innovative solutions, that we never thought possible because of the need for supporting infrastructure to address them. The challenges also require more closely coupled connections between stakeholders—the innovators in academia and industry and the doers who close the gap of technology deployment. Deployment requires taking the ideas and tried and tested opportunities to fruition, where the knowledge is shared and highlighted for our community at large. The three papers synopsized in this feature include a discussion of augmented depletion development, a technique in which openhole wells are drilled within the fractured network of a pad; an approach to well-path generation that relies on the collection of experienced-based constraints from each discipline to generate possible alternatives to the well path; and a multidisciplinary approach used to develop a presalt field offshore Brazil. The hope is that the technical articles in this feature can demonstrate to the reader the scope of collaboration and the effect of technical knowledge sharing that our industry currently enjoys—and requires. I hope they drive more questions and provoke further and deeper understanding of the content to the benefit of all. More importantly, I hope they highlight the complexity that is involved in addressing the industry challenges in field development and project management.

Impact of 4D Seismic Data Assimilation in the Production Forecasting of a Heavy Oil Turbidite Sandstone Field Offshore Brazil

The incorporation of 4D seismic data can be done at model characterization and data assimilation steps, the latter applying the observed data to update the model properties. In this work, we evaluate the impact of 4DS data in the production forecasting results investigating the influence on these distinct steps. We employ a prior model set generated without 4DS data and another prior set with 4DS in the characterisation. We perform, then, the DA in three different ways: (1) using only well history data with a prior set without 4DS; (2) using well history and 4DS data with this same prior set; and (3) using well history and 4DS data with the prior set generated with 4DS data. We employ the Ensemble Smoother with Multiple Data Assimilation method for data assimilation and implement a procedure to adjust the well productivities and injectivities after DA. This work assesses the differences among the three DA cases in terms of field oil production forecasting, model attributes and model misfits, the latter evaluated in terms of the assimilated data set and of a different data set for validation purposes only. We apply the work to a real heavy oil turbiditic field located offshore Brazil. The case application demonstrates a successful data assimilation study on a real field integrating well history and 4DS data. The results show that the utilisation of 4DS in both model characterisation and DA steps brought value to the final uncertainty reduction results. The posterior model ensemble with 4DS data in model characterization and DA provided the lowest model misfits overall to the full data set, being the best choice for application in field production forecasting studies. The case without 4DS data provided significantly more pessimistic field oil production than the cases with 4DS, making very evident the importance of employing 4DS at uncertainty reduction workflows.

ANALYSIS OF TECHNOLOGIES FOR COLLARING LARGE-DIAMETER SECTIONS OF OIL AND GAS WELLS

The article considers issues on construction of deep oil and gas multi-column wells with an extended trunk. Drilling of such wells is relevant, for example, on offshore fields, where drilling from the shore with a vertical deviation of over 1000 m is much more economically feasible than from floating vehicles.For drilling wells with an extended trunk and passing through zones incompatible with drilling for geological reasons, it is necessary to begin construction of a well with landing a large diameter direction – often up to 720 mm. The article analyzes the emerging problems and ways to solve them by drilling large-diameter wells and landing casing string. The results of practical experience in conducting work in the Pechora Sea and at the Astrakhan gas condensate field are summarized, on the basis of which recommendations for carrying out similar works are given.When constructing wells, especially starting with a large diameter, it is not always possible to drill a well efficiently, even with drilling equipment ideally suited to specific geological and technological conditions. And this, in turn, can lead to losses of production time and materials, and in the extreme case – to emergency works. Based on the analysis carried out, the article proposes an algorithm of technological operations for drilling wells and landing large diameter directions, which increases the probability of successful drilling to the design depth.

Hydrocarbon prospective study using seismic inversion and rock physics in an offshore field, Niger Delta

This study integrates seismic inversion and rock physics techniques to evaluate the hydrocarbon potential of an offshore field in the Niger Delta. Five wells revealed three reservoir sands with favourable reservoir properties, including gross thickness (49.2–81.4 m), porosity (0.18–0.2), permeability (565–1481 mD), and water saturation (0.16–0.54). A robust wavelet extraction process was implemented to guide seismic inversion, and a well log-centric approach was employed to validate the resulting acoustic impedance data. Rock physics analysis established correlations between acoustic impedance (Zp), porosity, fluid content, and lithology, enabling the identification of hydrocarbon-filled sands, brine-saturated sands, and shales. These relationships enabled the discrimination of hydrocarbon-filled sands [5000–8000 (m/s)(g/cc)], from brine-saturated sands [5600–8400 (m/s)(g/cc)], and shales [5000–9000 (m/s)(g/cc)] within the inverted seismic data. The inverted acoustic impedance section showed a general increase with depth, reflecting the typical compaction effects in the Niger Delta. Analysis of the impedance distribution across horizon time slices revealed prospective zones with low impedance values [below 6300 (m/s)(g/cc)], particularly in horizons 1 and 2. These newly identified zones exhibit the strongest potential for hydrocarbon accumulation and warrant further investigation. This study demonstrates the effectiveness of using well log and rock physics constrained seismic inversion for hydrocarbon exploration in an offshore field in the Niger Delta.

Oil, well, development, shelf, bulk island, efficiency, gravitation

Traditional technologies of oil production on the land and the sea shelf have low coefficient of oil recovery, thus cause a huge loss to environment to what become frequent oil spills testify worldwide. In article the innovative way of development of oil fields allowing to increase significantly oil recovery by means of artificially created gravitational mode is described and also completely to exclude environmental pollution when developing offshore fields thanks to oil production by a dense grid of wells which are drilled from horizontal wells. In comparison with usual ways of oil production on the shelf, such as development, from bulk islands, oil platforms and platforms, this way has a number of technological and economic advantages. Experience of application of similar technologies around the world is considered. For comparison outputs of wells and capital expenditure on the example of oil fields Kyrykmyltyk and Kashagan in Kazakhstan are counted.

Large-deformation study of T-bar penetration in spatially variable sediments

The T-bar penetrometer is extensively used in offshore field investigation and laboratory testing to evaluate the undrained shear strength of soft clay because of its reliability and repeatability in measurements. However, most previous studies on T-bar penetration have adopted a deterministic approach and focused solely on homogeneous soils, neglecting the geological uncertainty caused by the spatial variability of soil. To remedy this situation, this study aimed to investigate the effect of soil spatial variation on the T-bar penetration process in soft clay by employing large deformation random finite element modeling. The findings indicate that the variability in soil strength substantially modifies the flow pattern and failure mechanism of the soil, consequently influencing the penetration resistance factor of the T-bar. It was observed that the resistance factors follow the log-normal distribution. A relationship between the probability of failure as well as the factor of safety was determined, allowing for a clear assessment of the reliability level associated with varying factors of safety. To allow for this effect, a practical framework is developed to correct T-bar penetration data to estimate soil strength.

Nonlinear behavior analysis of smooth bore unbonded flexible pipes under radial compression

Smooth bore unbonded flexible pipes are widely used to transport oil and gas in offshore fields. Due to its main application in shallow water, the radial bearing capacity is usually designed to be low for economic reasons. If the compressive load applied by tensioner equipment is too high during installation, the flexible pipe will fail due to excessive deformation. In this paper, the nonlinear behavior of smooth bore flexible pipes passing through tensioner equipment was investigated numerically and experimentally. A three-dimensional numerical model considering the nonlinear behavior of the materials, layer-to-layer contacts, and friction for flexible pipe radial compression analysis was established. A radial compression test was conducted to verify the accuracy of the numerical model; Then the numerical model was used to analyze the radial compressive behavior of each layer, and its load-bearing capacities and failure mechanisms were investigated. Finally, a parametric study was performed on the opening angle and number of tensioner tracks. The results of this study can provide a useful reference for the installation of smooth bore flexible pipes.

Optimizing a transformer-based network for a deep-learning seismic processing workflow

StorSeismic is a recently introduced model based on the transformer network to adapt to various seismic processing tasks through its pretraining and fine-tuning strategy. In the original implementation, StorSeismic uses a sinusoidal positional encoding (PE) and a conventional self-attention mechanism, borrowed from natural language processing applications. For seismic processing, they provide good results but also indicate limitations in efficiency and expressiveness. We develop modifications to these two key components, by using relative PE and low-rank attention matrices as replacements for the standard ones. Our changes are tested on processing tasks applied to realistic Marmousi and offshore field data as a sequential strategy, starting from denoising, direct-arrival removal, multiple attenuation, and finally root-mean-squared velocity ([Formula: see text]) prediction for normal moveout correction. We observe faster pretraining and competitive results on the fine-tuning tasks and, in addition, fewer parameters to train compared with the standard model.

Session 18. Oral Presentation for: Transforming offshore field developments with Pivotree™: an innovative technology solution for fast, cost effective, and low footprint projects

Session 18. Oral Presentation for: Transforming offshore field developments with Pivotree™: an innovative technology solution for fast, cost effective, and low footprint projects

Novel approaches to uncertainty estimation in seismic subsurface characterization

Uncertainty estimation in subsurface characterization workflows is an important input to decision-making in earth science-related problems. We present three methods to characterize seismic-related uncertainty, each of which includes a real data case study. Two of these methods are designed to characterize depth uncertainty in positioning of migrated reflectors. Such estimates may be used in derisking well depth prognoses, analysis of well misties, and for estimating ranges on resource volume. The first method derives rapid and robust estimates of depth uncertainty around an existing velocity model using traditional velocity analysis to constrain the solution space while limiting a-priori constraints, consistent with a frequentist approach to uncertainty characterization. The second method characterizes depth uncertainty more rigorously in respect to the physics and prior information available by performing full-waveform inversion in a Bayesian framework. This method produces similar uncertainty estimates to the first in the case of simple velocity models but is more accurate where the overburden is complex; however, it requires significantly greater computational expense, thus limiting current practical applications. The third method is an amplitude variation with angle (AVA) inversion for reservoir properties designed to output uncertainty products for interpreters, utilizing the Bayesian framework and Zoeppritz equations to define the forward physics. Application to an offshore Egypt field demonstrates that it can generate reliable estimates of reservoir properties (e.g., lithofluid type or shale volume) including uncertainty, useful in various parts of subsurface characterization. These results also show that the method could provide improved point estimates of reservoir properties compared to conventional deterministic AVA inversion approaches. There is usually a trade-off between increasing the accuracy of subsurface characterization versus creating faster, less expensive, and more readily understood workflows for practitioners. We discuss how the relative importance of these competing factors should be considered within the context of how the outputs will be used.