bluuebunny/crossref_metadata_2025 huggingface dataset:
Production Improvement Assessment Using Gas Lift and Electrical Submersible Pump for Waxy Crude Oil
Authors: Bataee M. , Hebah M. A. , Rostamian A. , Hamdi Z.
Published: October 2023

Production from heavy oil reservoirs is a challenging task and needs special design. In this study, oil well production was maximized using nodal analysis for a field of study. The optimum tubing and flow line sizes are selected by means of pressure traverse. The wellhead pressures and choke sizes were computed by finding the inflow and outflow of the flow line. Several reservoir parameters for the purpose of observing the effects of pressure depletion were investigated. Initially, fluid description, flow type, type of artificial lift, well type whether offshore or onshore, and well completion is selected. PVT data are entered, and the matching process requires some parameters such as reservoir temperature, with the corresponding pressure to be produced. Then, IPR is selected and found depending on the reservoir data. The calculated data should be matched with measured data using VLP/IPR quality check to make sure that the models emulate the actual well data. If there is no matching, entered PVT data should be checked until matching is found. If performance is accepted, the operating point is found at the intersection of IPR and VLP and that is before optimization. The optimal values are entered into the design and computing the operating point after modification if results are not as expected, the modification process is checked again until reaching satisfactory outcomes and this project's goals are met. The results of the study revealed that there was no fluid flow before the gas lift or ESP operation. All the methods studied revived well-X. The significant result was the ability of GL which was 1509 2708 STB/ day, and ESP has achieved the highest oil production of 2708 STB/ day. The economic range was found to be [(2-4.2), (2- 3.6), and (1-2.7)] MMSCF/D for CH4, N2, and CO2 respectively. That led to an economic injection rate of 3, 3.4, and 2.4 MMSCF/D for CH4, N2, and CO2 correspondingly, and for ESP is 180,229.4$ which is the highest revenue compared with the GL method. Finally, the findings contribute to oil and gas by considering greenhouse gasses. Also, it recommends the possibility of using another gas injection type and another artificial method, then compared with these results to find the best method for heavy oil.
A New Delta-Transient Method for Real-Time Permeability and Skin Prediction in Multi-Layered Oil Reservoirs Near Sealed Zones
Authors: Coelho Guilherme Neves , Fernandes Fernando Bastos , Braga Arthur M. B. , Soares Antônio C. , Rezende Fernando H. G.
Published: October 2023

Permeability and skin prediction in multilayered reservoirs near sealed boundaries during production are essential for the appropriate oilfield development. This work proposes a new method for obtaining the transient individual layers’ permeability, k(t) and skin, S(t) data in a well near a no-flow boundary (sealing fault case) by combining a production logging tool (PLT) and a mathematical formulation that deals with equivalent rock and fluid properties, e.g., transmissibility, pressure drop, and oil flow rates. New fault parameters βf and δf arise in the logarithmic approximation of the line-source solution Ei(r, t) to represent the role of the fault on the real-time permeability and skin responses.

The mathematical model presented in this paper is based on the equivalent representation of a system composed of a multilayered reservoir near a no-flow boundary that considers each unsteady-state individual layer property for the formulation. A new reservoir layer parameter named Delta-Transient for sealed zones is derived, and it deals with the unsteady-state permeability and skin effect as a function of the equivalent oil flow rate and pressure gauge real-time data. This paper shows that this parameter comprises the sum of the infinite-acting-radial-flow and the well-sealing fault terms. The calibration of the model developed in this study was performed using a numerical simulator named Saphyr, and the results presented convergence. An error analysis was also presented and demonstrated that the method is sensitive to flow rate and pressure variations.

The proposed model is applicable to formation evaluation and reservoir engineering to predict unsteady-state permeability and skin behavior on carbonates reservoirs due to the lack of adequate methods to provide reliable information. This practical field application, combined with the model's simplicity, constitutes the advantages of the model addressed in this paper.
Quality Assurance on Annulus Isolation Under Well Cementing Uncommon Events – Practical Approaches in Deepwater Wells
Authors: Moreira R. P. , Ribeiro D. B. , Lima L. B. , Piedade T. S.
Published: October 2023

Defining acceptable criteria for primary cementing operations has always been challenging. When unconventional events or conditions occur during the cement job, the potential impact on future well integrity shall be evaluated before proceeding further operations during well construction. This study aims to describe practical approaches on evaluating zonal isolation based on cementing design robustness and post job signature when such unconventional conditions are present in Brazilian deepwater wells. A large database for well casing cementing scenarios in Brazilian deepwater fields provides information to correlate and identify the most present cementing abnormalities and undesired well conditions prior to cementing and the quality of annular isolation through cement evaluation logs ran. The analysis, additionally to the operational normality evaluation, considers different scenarios such as the presence of extensive salt zones, low-fracture gradient formations, ballooning plastic formations and the different cementing strategies performed in each well. The data provides evidence that fluid losses and cementing hardware malfunction are the most common failure modes for annulus isolation in the deepwater wells analyzed. However, there are situations where these abnormalities do not interfere in cementing quality, and a more detailed analysis should be performed to identify if an impaired condition will occur. Two case studies detail the process, the first for salt zone cementing in pre-salt wells show that it is possible to identify the loss zone depth through job parameters, and the second case study for two-stage cementing in post-salt wells show that it is possible to identify impact on casing hardware malfunction. Although the common practice of cement evaluation under cementing abnormalities takes the running of logs to identify impact on zonal isolation, the approach here described consider an engineered analysis on the job parameters that may simplify the process safely and lead to cost reduction for casing cement quality assurance.
Dynamic Wettability Alteration at Pore-Scale Using Viscoelastic Surfactant/Chelating Agents Systems
Authors: Ahmed M. Elmuzafar , Sultan Abdullah S.
Published: October 2023

The role of wettability is crucial in the extraction of hydrocarbons as it determines how well the oil adheres to the rock surface, directly impacting the efficiency of the extraction process. Numerous studies have been conducted to modify the wettability of rocks to a favorable state. In this study, we delve into the microscopic level to observe the actual process of altering the contact angle during flooding using microfluidic technology within a glass micromodel. Initially, the micromodel is saturated with formation water and subsequently displaced by oil to establish the initial oil saturation. The microfluidic setup consists of a precise pump for flood control and a high-speed microscope to capture images for later analysis using image processing software to obtain the actual contact angle. The contact angle is measured at five arbitrary locations, and the average is calculated at specific time intervals based on image analysis. Three different fluid systems were utilized: pure Viscoelastic Surfactant (VES), VES with DTPA, and VES with GLDA. The concentration of these systems was selected based on optimal rheology and interfacial tension performance. The contact angle was measured at various injection stages to observe its dynamic change from the initial state to the final state and assess the resulting recovery from each fluid system. The pure VES system modified the wettability from slightly oil-wet to slightly water-wet and achieved a 48% recovery of the original oil in place (OOIP). On the other hand, the addition of DTPA altered the wettability from slightly oil-wet to extremely water-wet; however, this did not lead to higher recovery, and water breakthrough occurred, reducing the sweep efficiency with a 45% recovery. The GLDA VES system altered the wettability to moderately water-wet, which proved to be the most favorable wettability condition, resulting in a 56% ultimate recovery. This investigation successfully demonstrated the effectiveness of using VES-assisted chelating agents in altering rock wettability and increasing oil recovery at the pore scale.
Non-Intrusive Level Measurement Using Guided Elastic Waves
Authors: Gorski Dmitri , Lieske Uwe , Neubeck Robert , Witsø Peder Solum
Published: October 2023

Accurate level measurement in process vessels is important for safety, production optimization and control as well as for optimization of chemical additives. Most of the level measurement sensors used in oil and gas production today are Differential Pressure (DP) transmitters, displacers and, sometimes, Guided Wave Radar (GWR). More advanced profiler-type sensors are used more rarely and most often only for process analytics. Almost all of the commercially available level measurement instruments are intrusive, meaning that they require a flange or penetration for installation and maintenance. In practice, this implies that installation and maintenance on an existing installation have to be conducted during a turnaround. This makes such a project prohibitively expensive considering the cost of turnaround time and the fact that a turnaround on an offshore platform is only performed once every 1-4 years.

This work describes pilot trials with a novel non-intrusive level measurement system that utilizes Guided Elastic Waves (GEW) for attenuation tomography. Pilot experiments were carried out in a model separator with an internal diameter of 1.00 m and length 3.75 m. The pilot separator which was filled to pre-determined levels with tap water, mineral oil and construction sand. Flow of water was induced in some of the experiments. Phase levels were recorded manually through a sight glass and compared to readings generated by the novel measurement system.

Experiments showed that the novel level measurement system is able to detect levels of sand and liquid as well as clean water/oil interface levels with very high accuracy. Flow had no significant influence on the measurement results and the sensor output remained stable over the cause of one month. After the successful testing, the system has been qualified for its first trial on an offshore installation. In addition to an offshore pilot, more R&D needs to be conducted in order to develop capabilities to measure emulsion and foam interface layers as well as to determine how fouling by scale, waxes and other impurities present in a full-scale separator influence the measurement.
Integrated Approach Combining Plant Data and Thermodynamic Simulation for Management of Inorganic Scale in Topsides Processing Facilities
Authors: Neto S. Simoes , Smiderle A. L. , Neto J. M. Dias , Alves A. F.
Published: October 2023

A major concern with pre-salt processing is the water salinity and its high scaling potential. High standing output levels necessitate an effective scaling management strategy. One element of a successful program is scale prediction, which is frequently done utilizing the produced water's thermodynamic equilibrium.

This paper presents a methodology and algorithm to systematically calculate scaling index of produced water blend to be compared to representative brines which were defined for scaling inhibitor design tests. Thermodynamic calculations of calcite saturation indexes at relevant process conditions are evaluated for the mixture of produced wells streams and for the platform critical brine.

It was implemented an algorithm that integrates plant historian database to thermodynamic calculation routines and presents the results in a user-friendly web portal for proper visualization. Calcite saturation index is calculated using Pitzer activity model which is often used for calculations of inorganic scaling potential in high ionic waters. Produced wells flowrates are used for defining mixture fractions of the produced blend. For each platform there is one representative brine composition that was used for scale inhibitor design, herein called the platform critical brine. However, the compositions of wells produced water are updated as soon as new water analysis is available. The algorithm creates a scaling index (ISS) based on calcite saturation indexes that measures how far from the critical brine the produced mixture is in relation to calcite saturation index.

The ISS is evaluated systematically in daily basis for several platforms offshore Brazil. The results show how the different wells configurations (flowrates) impact the produced water blend criticality with respect to inorganic scaling. The implemented routine gives insight to production engineering personnel regarding potential problems with scaling and chemicals design. It can be used to assess if the platform critical brine should be updated, and possibly new chemicals designed. Additionally, the ISS can be used to optimize the topsides process conditions in specific scenarios.

The processing conditions and produced water compositions of pre-salt oilfields offshore Brazil results in scaling potential at topsides. This paper describes the methodology applied for monitoring the scaling potential systematically on a daily basis for several pre-salt platforms.
Marine Vibrator Milestone: A Pilot Seismic Survey
Authors: Alfaro R. , Secker S. , Zamboni E. , Guitton A. , Cozzens A. J. , Henderson N. , Nechayuk V. , Jenkerson M. , Johnson G. , Karran J.
Published: October 2023

The Marine Vibrator Joint Industry Project (MVJIP), sponsored by TotalEnergies, Shell and ExxonMobil, completed a successful pilot survey in Q3 2022 using two Integrated Project Node (IPN) Marine Vibrators in an offshore European open water setting.

The IPNs were deployed in two configurations: one under tow, and the other stationary at each shot point. Various sweep types and duty cycles were also tested. An airgun source of equivalent energy size was also used for comparison. Throughout the pilot the IPNs demonstrated exemplary performance. There were no HSE incidents during the project, nor was there any technical downtime related to the IPNs. Moreover, real time quality control results were able to show the IPNs high fidelity with respect to the pilot sweep and excellent sweep-to-sweep repeatability.

A fast-track processing sequence was completed, which showed that the IPNs have been able to image the subsurface very well including steeply dipping reflectors. This demonstrates the progress that has been achieved by the MVJIP over the last 10 years and gives a real impetus to continue the development of the marine vibrators into a commercial source. The next steps will be to complete a more comprehensive full processing sequence on all the lines to extract the best possible images.
Development and Evaluation of Asphaltene Inhibitors for Offshore Brazilian Crudes
Authors: Ewbank Conrado Gerard , Clements John , Deluge Max , Rabelo Rodrigo Balloni , Dezotti Rafael Sobral , Dallaqua Roger Pezzuol
Published: October 2023

Asphaltene deposition has been an extremely critical flow assurance challenge in the Oilfield industry and the chemical treatment with continuous asphaltene inhibitors injection has been one of the best solutions for operators to face this challenge preventively, especially in the offshore market where it has the presence of extreme application conditions. This study focuses on optimizing the selection of the best chemicals and dosages of asphaltene inhibitors in Brazilian offshore crudes quickly and effectively.

Combinations of different techniques and surfactants (non-ionic and polymeric surfactants) were evaluated in this study. To determine the best solution to be used for these systems, studies were carried out through the colloidal characterization both of asphaltenes in petroleum and of the effect of additives on the asphaltene deposition mechanism using LUMiSizer (Dispersion Analyzer), an equipment that enables extremely effective techniques, with high sensitivity and fast response time, applied for different Brazillian Offshore crude oils To determine the kinetics of destabilization and a tendency of asphaltene aggregate formation, data were acquired from LUMISizer, confirming the minimization of aggregate growth in more stable systems. Results also indicate the existence of a minimum effective concentration, suggesting a minimum dosage that promotes coating in the flakes formed, so that the steric barrier is effective in the curvature of the growth and deposition of asphaltenes. The LUMiSizer was used to rank the efficiency of different inhibitors and dispersants for a specific oil. Such results are even more informative than just saying whether an inhibitor is suitable or not.
Study on Emulsification Characteristics and Anti-Emulsification of Emulsions for Offshore Thermal Well Production Fluids in Bohai Bay, China
Authors: Hao Liu
Published: October 2023

Cyclic steam injection is one of the most effective EOR technologies for Bohai off-shore heavy oil field. Production capacity of thermal recovery has reached 1.9 times of cold production in the same period. However, with the increase of huff and puff cycles, large amount of water-in-oil emulsion is produced with water cut increasing gradually, especially in the range of 30-50%, which leads to poor oil-water separation effect on the platform's heating dehydration equipment, and even causes the working current of the electric dehydration equipment to be too high, resulting in the increase of water cut of the exported crude oil. At the same time, oil-water emulsification may block the formation pore roar, affecting the oil flow channel, resulting in the reduction of thermal production.

Our work is mainly focused on the emulsification characteristics and Anti-emulsification of the emulsions from thermal well production fluids. Based on the characteristics of the produced liquid during thermal recovery and injection, a high-speed disperser is used for preparing water-in-oil emulsion. Effects of water cut on emulsion viscosity, crude oil and emulsion are carried out by using remoter, one-dimensional core displacement device as well as microscope. Meanwhile, microscopic characteristics of emulsions, and phase state of cores and dynamic anti-emulsification of cores are also studied.

The results show that with the increase of water cut, viscosity of the emulsion increases greatly, which is risen to 5.9 times more than that of crude oil when the oil-water ratio is 5: 5. At the same flow velocity, the pressure gradient of the emulsion in the low-permeability core tube of 1000 μm3 is significantly higher than that of crude oil. In the hypertonic tube of 3000 μm3, the difference between the pressure gradient of the emulsion and the crude oil is not obvious at the same percolation velocity. Testing results show that the emulsion increased the maximum steam injection pressure to 3.15 MPa. After adding the anti-emulsion demulsified solution to the emulsion, the number of water drops was extremely reduced. The demulsifier has dual functions of anti-emulsification and reducing steam injection pressure in rock core.

Anti-emulsification can effectively reduce the emulsification degree of the produced liquid in thermal recovery of offshore steam huff and puff, so as to improve the thermal recovery effect.
Offshore Mature Fields in Deepwaters: The Final Challenge
Authors: Pedroso Carlos A.
Published: October 2023

Increasing the recovery factor of a mature field should be a top goal for every petroleum engineer. Producing oil from mature fields is both strategic and necessary: ​​Necessary because we need to increase our efficiency and reduce our carbon footprint. And it is unreasonable to leave in the rock a resource that nature took millions of years to generate. And strategic because oil from a mature field is (or should be) cheaper and has very low risk: I know where it is, I know how to produce it and I know what not to repeat.

However, producing onshore mature fields is much simpler than offshore. It is common to have onshore mature fields, which produce at marginal rates, for 80 years or more, which is rare offshore. Production costs require marginal wells to be closed. And the costs and difficulties are geometrically proportional to the water depth. Shallow water fields in Norway can reach an RF of 65%. In Brazil, recovery factors of up to 85% are expected in onshore fields, while modern and highly prolific pre-salt fields are expected to produce 16% of their oil il place. 84% of the oil will remain in the rock.

The alternative is to apply technologies massively, and the sooner they are planned and implemented, the better. Among the possible strategies and lines of action applicable are:

Water and gas management. Optimization of water injection using techniques such as: PWRI (produced water re-injection), IAFP (injection of water above fracture pressure), etc Reduction in well construction cost for infill drilling. Application of well slender architecture with one trip completion. Use of liner conveyed gravel pack for unconsolidadted sandstones. U-well planning and construction. Reduction of area and weight of production units: Use of technologies such as RWI (raw water injection), SSWO (Subsea Separation of Water and Oil), etc This paper aims to make an overview of the applied and applicable technologies for extending the useful life of offshore fields, trying to make viable also for high water depths a philosophy of a recognized mature field operator: "The last field to be explored must be the increase of the recovery factor "
Mero Field: Topsides for Fluids with High GOR and High CO2 Content – How Innovative Solutions Unlock the Addition of Processing Capacity and Subsea Processing to Add Value Generation
Authors: Shiguematsu F. M. , Passarelli F. M. , de Araújo F. B. , de Castro V. F , Favre J. Y.
Published: October 2023

Libra field has reservoir fluids with high GOR and CO2 content which add significant challenges to the development projects. Innovative solutions on topsides were assessed to optimize the process plant, aiming to reduce complexity, footprint, and weight, to allow processing capacity increase, adding value to development projects. This article details the technology selection process, the challenges of implementation with the first successes as well as the obtained gains in comparison with base case solution.

The first large Mero's floating production unit was conceived with processing capacities of 180,000 bpd and 12,000,000 Sm³/d of gas due to reservoir characteristics. It was a challenge to fit it in a VLCC hull size within reasonable CAPEX and lead time. Therefore, technical studies were carried out to optimize Libra topsides, driven by footprint/ weight and power reduction, better operational efficiency, extension of oil production plateau and water injection capacity increase that were successful via implementation of the innovative solutions: increase 1st separation pressure; sea water pre-treatment and gas dehydration optimizations; and addition of an innovative subsea processing system.

The present article compares the first gains obtained by the addition of innovative solutions that modified the original concept of the first large Mero's floating production unit as follow: (1) increase of the first liquid-gas separation stage pressure in the oil treatment plant, that allowed gas compression plant and power demand reduction; (2) significant reduction in gas dehydration plant weight/ footprint and complexity by enabling triethylene glycol as alternative. This technical solution was not applied in Pre-Salt units until that time; (3) designing the interfaces between the floating production unit and the innovative subsea gas processing system will allow future interconnection to extend the oil production plateau, adding value in case technology development success; (4) increase of sea water injection capacity. The implementation of the innovative solutions above summarized is improving the design and operational efficiency of the FPU adding value to the project.

The results obtained by the implementation of innovative solutions in Mero's FPU until this moment are showing the success of conceptual studies evaluation and enabling improvements in processing plant and allowing the inclusion of subsea processing system.
Wireline In-Situ Fluid Property Measurement: A High CO2 Case Study from a Brazilian Pre-Salt Carbonate
Authors: Bittencourt B. T. , Vasconcellos P. B. M. P. , Monteiro V. F. , Bertolini A. , Dantas M.
Published: October 2023

Knowing the characteristics of oil and the presence of contaminants (such as CO2) is essential for the proper evaluation of a petroleum accumulation. This work aimed to verify the accuracy of the oil composition estimates obtained by the In-Situ Fluid Analyzer (IFA) module, from SLB, for different pre-salt oil accumulations in the Santos Basin. A methodology, based on the results of this study, was applied to anticipate the information about the formation fluid characteristics for a wildcat well using the compositional estimates of the IFA module during the logging operation.
RIMS: A Fully Integrated Technology for Long-Term Riser Monitoring
Authors: Albani Yvan , Cavallini Francesco , Girello Enrico , Lazzarin Diego , Massari Giovanni , Novello Marco
Published: October 2023

Nowadays, offshore operators have an increased requirement to reduce the operational risks while performing offshore natural resources exploitation. This, in particular, applies to critical steel catenary risers whose long-term integrity with respect to fatigue and extreme events is key for safe operations: due to their dynamic behavior, risers are one of the most critical assets being subject to severe environmental and operation loads, which shall be studied in detail at the design stage. Given the large number of external actions and the riser complex response, riser engineering is typically affected by several uncertain parameters, therefore an accurate monitoring of its integrity is key to ensure safe operations in the short-term and gain the necessary knowledge in the medium to long-term thus enabling design optimization, asset maintenance and life extension. These considerations place risers monitoring as a central technological theme for the offshore energy industry.

The design and realization of an adequate riser monitoring is a complex activity requiring: i) the deep knowledge of riser physics to support a holistic assessment of the parameters to be monitored, ii) the direct access to modern technologies, as digital twin, to enable the realization of even more efficient and innovative monitoring solutions tailored for the specific projects’ needs. In this context, Saipem has a privileged viewpoint given its long-term experience in rigid riser engineering, construction, and installation (as EPCI contractor responsible for the SURF scope) combined with strong capability in providing integrate, novel and fully customized solutions for underwater assets monitoring through its Sonsub business.

This paper investigates the benefits coming from this integrated approach where the monitoring system is conceived, realized, and installed as an integral part of the related riser and explores the potential advantages linked to the implementation of data interpretation features capable to support riser system integrity analysis along the asset operational life. This paper provides also an overview of the challenges behind riser monitoring systems realization passing through the main development phases: from the initial qualification and engineering phase to the installation and integration testing.

To offer a very pragmatic view on the topic, the paper presents a brief summary of Saipem recent experience in developing and qualifying riser monitoring systems for some Brazilian projects specifically designed for steel catenary riser configurations.
Validation of a Completion Digital Twin Applied to Packer Setting
Authors: Oliveira L. A. , da Silva F. R. G. , Bellumat E. , Gama W. C. , Costa M. V. F. , Donatti C. N. , Rosenbach L. I. N. C. , Fasolin K. , Martins A. L.
Published: October 2023

Open hole packers setting usually is performed running in hole the completion equipment and afterwards running a wireline operation to precisely check the packer position and make the needed adjustments to set it in accordance with the geological targets. The current digital twin software incorporates comprehensive models and it receives surface data in real time to analyze the current operation status, by comparing real and calculated (expected) data, with quantitative criteria. It allows the user to follow up the completion column running in hole, to make real time editions if any item needs to be replaced during operation (impact damage, measurement update, etc.). Torque and drag models allow to infer the completion column elongation and verify the real elements position within the well and based on integrity assessment the work window is calculated real time. The target depths are defined during drilling operations using logging data, then drill string elongation calculated with the drilling digital twin software was used to align the real reference depth in both scenarios, drilling and completion. With the real position of the packer in hole it was possible to define the stick up needed to adjust its position to the target depth before setting it. A validation was performed using three offshore real cases, where the packer position considering completion column elongation and the wireline results for packer position considering the pipe tag position detection were compared. In both approaches, a measurement for stick up was obtained to define the correct depth for packer setting and considered to be in good agreement. The novelty is the usage of numerical simulation to optimize the time spent to conclude the packer setting by avoiding an extra operation at the rig site, saving time, costs and operational risks.
Offshore Wind Power Plants in Brazil: Challenges and Opportunities for Port Infrastructure and Maritime Transport Logistics Sectors
Authors: Costa B. R. M. , Jaeger L. N. G.
Published: October 2023

Brazil has the potential to emerge in a leading position worldwide in the energy transition movement, especially employing renewable resources. In this scenario, wind power is one of the big bets to boost the generation of clean energy in the country. Currently, Brazil is the biggest producer of onshore wind energy in Latin America and the world's 6th country in wind capacity. This is due to the large wind flows, especially in the Northeast, South and Southeast regions of the country. In the offshore environment, it also has conditions to be a promising agent in wind power generation, with 7,367 km of coastline and 3.5 million km2 of maritime space under its jurisdiction, giving it favorable characteristics for the installation and operation of these projects. Moreover, it has an excellent position in relation to other emerging markets, due to its experience in the offshore oil and gas industry, onshore wind and civil construction sectors, in addition to the availability of raw materials (especially steel). The Brazilian potential has already been awakening the interest of investors on a large scale at the international level. Hence, this article shall bring a study mapping the challenges and opportunities in relation to the development of the offshore wind power generation market in Brazil, focusing on the port and maritime sectors.
Selection of High Temperature Scale Inhibitor for Squeeze Application in Indian Offshore Carbonate Reservoir
Authors: Uniyal Rishabh , Jaruhar Suman Kumar , Sarkar Manoj Kumar , Devshali Sagun , Parida Dibyajyoti , Bhoye Sushil , Biswas Sudipta
Published: October 2023

The paper aims to elucidate the process undertaken to identify suitable inhibiting chemical to prevent down hole deposition of scale in ONGC western offshore wells by means of a squeeze job. Detailed description of methodology adopted for chemical selection has been elaborated in the paper.

Most fields in ONGC's Western Offshore region are brown/matured fields with depleted reservoirs pressures. Seawater injection is one of the primary techniques used to combat depleting reservoir pressure. This has led to rampant escalation in scaling issues in offshore limestone reservoirs and subsequently, the frequency of scale removal jobs has also increased exponentially over the past two decades. Scale prevention is a superior and economical alternative to scale removal due to lesser consumption of chemicals and prolonged life. As part of this study, the feasibility of carrying out Scale Inhibitor Squeeze Jobs in ONGC offshore wells was examined and subsequently, extensive laboratory experiments were performed to identify suitable chemicals. The experiments included inhibition efficiency tests, thermal stability tests and extended core flow studies (adsorption and desorption methods) to verify chemical compatibility with core sample of a number of generic and vendor based chemicals under simulated reservoir conditions.

After a comprehensive literature review and market scouting, six Scale Inhibitors were shortlisted and evaluated for their inhibition efficiency, thermal stability and compatibility with the rock formation through laboratory experiments. After extensive testing, Chemical X was identified as being most suitable for scale squeeze job in carbonate formations having temperatures up to 110° Celsius (230° F) and was also compatible with the formation. The adsorption and desorption isotherms respectively demonstrated sufficient chemical retention in the core and slow elution in the discharge. The measured Scale Inhibitor concentration was found to be greater than the Minimum Inhibitor Concentration (MIC) required for scale prevention. This indicated that any potential squeeze job would likely have a reasonable expected life.

The study explores the possibility of carrying out a first ever scale squeeze job in ONGC Western Offshore reservoirs particularly with high temperature application. Core flow experiments were performed using scale inhibitor chemical to derive adsorption and desorption isotherms used to prepare customized job plans.
Optimization of Coring Retrieval Process Using a Thermo-Poro-Elastic Approach
Authors: Silva T. V. , Riente A. F. , Binas F. A. V. , Barboza A. , Lima Santos J. P.
Published: October 2023

Cores can be considered the ground truth only if we eliminate or minimize their damage during the core cutting, tripping, and surface handling. During coring operation, while tripping out of hole, core is submitted to a relatively sudden decrease in pressure, leading to fluid expansion and movement out of the pore space. The rapidly expanding fluids can generate fractures and damage the core. Such damage would adversely affect their properties. In this paper an analytical approach model is introduced and applied to provide the maximal coring retrieval tripping rates. Ideally, core tripping rates should be established for each core, but common practice is based on generic rules of the industry. Traditional operating schemes do not justify the long tripping times.

With these high daily rig costs in mind, a more scientific and quantitative approach, tailored to each case is required. The Thermo-Poro- Elastic (T-P-E) geomechanical approach used in this study includes the diffusion time required for imposed pore pressure difference to dissipate while also considering the effects due to the temperature changes, the mud cake and swabbing during retrieval.

The hydraulic diffusivity and the fluid are the main factors that contribute to the maximum allowable safe tripping rates. A relationship between the hydraulic diffusivity and the decompression rate will be presented for each specified fluid type. For water-bearing cores there is almost no change in hydraulic diffusivity, on the other hand, gas-bearing cores and oil-bearing cores vary with depth.

This paper is a review of T-P-E analytical development and mathematical models to approximate the case of core tripping considering the effects of the pore pressure, temperature change, the mud cake, and swabbing. The model indicates that the fluid type and hydraulic diffusivity have been considered as the controlling factors. The analytical approach has been applied for modeling the tripping of water, gas, and oil-bearing cores to provide maximum allowable tripping rates.
WAG Optimization of Egg Model with Brazilian Pre-Salt Fluid Using PSO Algorithm
Authors: Freitas V. R. , Sánchez William Humberto Cuéllar , Lima G. S. , Pastrana M. A. , Barroso E. P. , Muñoz Daniel M. , de Almeida R. V. , Fortaleza E. L. F.
Published: October 2023

Water Alternating Gas (WAG) is a consolidated enhanced oil recovery method that outperforms secondary recovery methods such as waterflooding or gas injection. Optimization of the WAG parameters can increase the cost function and improve revenues, but the algorithms usually implemented require high computational resources and time. In this context, a bio-inspired algorithm, Particle Swarm Optimization (PSO) is used to determine the best candidate for only two parameters, water and gas injection time, resulting in the determination of the WAG cycle and WAG ratio, thus drastically reducing the complexity of the problem. The proposed long-term optimization algorithm was applied in a modified version of a well-known reservoir benchmark Egg model, in which the fluid composition was adapted to resemble Brazilian pre-salt reservoir fluids and WAG injection. Moreover, it is shown that the best results obtained consider longer periods of water injection and improve the NPV by 5.5%.
Flow Assurance Analysis for Long-Distance Tieback
Authors: Sartor R. B. , Junqueira I. M. F. , Oliveira N. C.
Published: October 2023

This paper aims to present the results of long-distance tieback sizing connecting a manifold located 45km away from an FPSO through a multiphase flow steady-state simulation to present recommendations for sizing flow lines in terms of diameter, thermal insulation, flow, pressure, and service temperature, as well as the requirements for multiphase pumping (power, operating points, rotation, flow regime, fraction of gas in the suction, pressure differential, etc.).

With the results of the simulations, it was possible to observe the behavior of the fluid flow along the flowline and riser. In addition, we found an arrangement of multiphase pumps, based on an available catalog, that would allow the transport of the fluid to the FPSO. We faced the challenge of finding the adequate flow velocity, ensuring that the residence time as well as the adequate head loss of the fluid along the entire pipeline was sufficient to avoid temperatures lower than the paraffin formation temperature.

Based on stationary simulations, it was found that the flow temperature remains above 40 °C for higher production capacities. However, it is important to highlight that by reducing the production of the wells, the flow temperature may reach the paraffin point.

Another aspect observed in the stationary simulations was that the flow of the fluid tends to present a "slug" type behavior in the ascending section of the riser, especially close to the point of arrival at the FPSO.
Design and Experimental Identification of the Main Hydrodynamic Parameters for an Open-Frame ROV to the Peruvian Scallops Stock Assessment
Authors: Florez Paola Fonseca , Huamani R R. , Huanca Eber , Nina Wilder , Avila Juan Pablo Julca
Published: October 2023

This work presents the design and the experimental methods to identify the main hydrodynamic parameters for an open-frame underwater vehicle for the stock assessment of the Peruvian scallops. The added mass was determined from free oscillation tests in the surge, sway and heave directions with the reduced prototype model submerged in water and supported by springs. The acceleration data collected during the oscillations demonstrated that the equation of damped natural frequency gave a better approximation of added mass because of the fluid damping. The drag parameters in the directions of surge, sway, and heave were determined by two experimental methods in which the prototype was moved with constant velocities. In the first method, the prototype moved attached to a towing carriage through a water channel, and the second method consisted of applying different forces using the vehicle's thrusters that let it move. In both methods, the vehicle's velocity and force were known. The data collected led to determine the linear and quadratic drag parameters using the least square method. The results of the self-propelled tests were slightly different from those obtained in the towing tank because the thrust was not measured with the thruster installed in the prototype, being this in motion, confirming the importance of quantifying the interactions thruster- thruster and thruster-frame and the loss of force due to the vehicle's motion.
Integrity Management of Offshore Process Piping and Equipment with Sand Production – Part II: Remediations
Authors: Shirazi S. A. , Darihaki F. , Yamazaki Y. , Nakano Y. , Ushiguchi K. , Quang V. Lam , Ngoc L. Le
Published: October 2023

Sand production is challenging integrity issue that should be monitored to prevent interruption in the oil and gas production facilities. On the other hand, the limitations in the offshore platforms can contribute to the failure in the production system due to sand erosion. The objective of this study is to establish a practical framework of monitoring and a tool for generating Integrity Operating Window (IOW) thresholds, which are used for handling sand production in most safe and effective manner. The ultimate goal is to obtain the highest possible production output from producing wells while minimizing sand erosion related risks to as low as a reasonably practical level. The recommended monitoring measures of sand production, production rate and wall thickness are discussed as a part of sand management system. CFD-based models and mechanistic models are additional tools that can enhance this procedure. Erosion simulations of pipe walls indicated that the cushion tees that have replaced the piping with bends to prevent/reduce erosion rates are also susceptible to significant erosion. Therefore, wall thickness measurements are being conducted at critical locations. A simplified mechanistic model was employed to support developing sand erosion IOW prediction tool and determining monitoring locations, provided that a process for wall thickness measurements at critical locations is in place for verifying and fine tuning the models on regular basis.
Identifying Litho-Fluid Facies Using Machine Learning: A Case Study of Niger Delta Sandstone Reservoirs
Authors: Adeeyo Y. A. , Osinaike A. A. , Adun G. O. , Menkiti H.
Published: October 2023

To minimize uncertainties in reservoir characterization and modeling workflows, an accurate definition of reservoir heterogeneity, including lithologic and pore fluid variations, is required. Particularly because reservoir heterogeneity limits the spatial distribution of petrophysical and elastic properties used to understand the reservoir system or quantify its resource or storage potential. Traditionally, variations in reservoir rock and fluid properties are identified by interpreting depositional patterns and fluid content from core or cutting samples, or by applying statistical rock physics techniques to elastic well log data. However, collecting core data is costly, and both methods can be subjective, necessitating expert knowledge of sedimentological and rock physical principles to produce meaningful classification results.

To overcome these limitations, we present a cost-effective and comparatively objective framework for identifying litho-fluid facies (LFF) using machine learning (ML) algorithms. Various statistical ML techniques were used for data-driven delineation of the LFF in the Niger Delta siliciclastic formation from a suite of commonly available geophysical well logs. The study followed a two-part process to arrive at the desired outcome. First, the target classes—clean hydrocarbon sand, shaly hydrocarbon sand, brine sand, and shale—were generated using a Dirichlet Process Gaussian Mixture Model (DPGMM) with Variational Inference (VI), an unsupervised clustering technique. These classes were subjected to probabilistic thresholding based on their log-likelihood and silhouette coefficient scores to obtain high-quality training samples. Following that, the training samples were used to construct supervised multiclass predictive models capable of generalizing the target LFF. Several classification metrics and charts were used to assess the accuracy and speed of the models to determine the model with the best predictive and computational performance.

This ultimately revealed that the best-performing model was a single decision tree classifier with perfect metric scores, significantly high prediction probabilities, and minimal computational time. The random forest and gradient boosting classifiers performed similarly well on the task. Moreover, the use of analytical and statistical techniques throughout the process facilitated an objective and accurate differentiation of the rock and fluid types.

The ability of the models to generalize to unseen data in a new well location with high predictive confidence makes it possible to characterize the spatially distributed facies in the study area with minimized uncertainty. Hence, we recommend the adoption of this framework for rapid and accurate LFF identification.