Geographical Origin Assessment of Extra Virgin Olive Oil via NMR and MS Combined with Chemometrics as Analytical Approaches

Geographical origin assessment of extra virgin olive oil (EVOO) is recognised worldwide as raising consumers’ awareness of product authenticity and the need to protect top-quality products. The need for geographical origin assessment is also related to mandatory legislation and/or the obligations of true labelling in some countries. Nevertheless, official methods for such specific authentication of EVOOs are still missing. Among the analytical techniques useful for certification of geographical origin, nuclear magnetic resonance (NMR) and mass spectroscopy (MS), combined with chemometrics, have been widely used. This review considers published works describing the use of these analytical methods, supported by statistical protocols such as multivariate analysis (MVA), for EVOO origin assessment. The research has shown that some specific countries, generally corresponding to the main worldwide producers, are more interested than others in origin assessment and certification. Some specific producers such as Italian EVOO producers may have been focused on this area because of consumers’ interest and/or intrinsic economical value, as testified also by the national concern on the topic. Both NMR- and MS-based approaches represent a mature field where a general validation method for EVOOs geographic origin assessment could be established as a reference recognised procedure.

The Benefits of Real Time Monitoring Application Artificial Lifting Parameter for Surveillance, Optimization, and Cost Reduction in Mature Field, Case Study Prabumulih Field

Prabumulih Field was located in South Sumatra, Indonesia. It has been developed as an oil field since 1920n (It was categorized as a mature field). At the end of 2019, the amount of oil well production was 149 wells (93% of the producing wells installed artificial lifting). As a consequence, to maintain production, artificial lifting surveillance activities must be a major concern and be managed properly. However, there are some challenges for surveillance, for instance, the location of well spread over a large area, the condition of the access road, and limited human resources. Surveillance activity itself carried out manually required both much time and many human resources, however, acquired data was only once in a week for one well. That condition always emerged undesired occurrence because engineers who were in the headquarter did not obtain notification when producing wells were in trouble or suddenly off producing. In addition, there was a delay in time for evaluation and intervention, which resulted in decreased oil production. Nowadays, application, in order to accelerate the data retrieval process, was much needed, especially real-time acquisition and it could be monitored in several kinds of devices. This paper will be presented about the benefit of real-time monitoring application in mature field, especially for artificial lifting well (ESP and Rod Pump). It has been installed since December 2019. There were several benefits obtained after installing this technology, those were related to surveillance and optimization. For instance, reducing time and human resources needed to obtained pump parameter data, engineers who are in the headquarter could observe everyday using both laptop/personal computer and smartphone, engineers obtained notification immediately when there were wells in a trouble, decision making for optimization and or intervention was faster, increase pump run life, and reducing well service program. Besides, there was another benefit that related to cost reduction, for instance saving rig costs for well service of 350,578 USD in a year because the amount of well service decreased from 49 times to 36 times, and obtained additional gross revenue of 547,945 USD for one year (cost for real-time monitoring for a year is 116,438 USD) because production deferment reduced from 19,577 STB to 5,105 STB. Based on those data, real-time monitoring could increase the economic condition of the mature field, so it was worth applying in a mature field.

Special Issue: Application of SERS for Nanomaterials

Surface-enhanced Raman scattering (SERS) is now a relatively mature field of spectroscopy, with it having been almost 50 years since its first experimental demonstration [...]

A SUCCESS CASE OF WIDURI AREA REJUVENATION, ASRI BASIN, OFFSHORE SE SUMATRA BLOCK, INDONESIA

INTA/B Field is one of the most producing mature fields in Widuri Area, Asri Basin, Offshore SE Sumatera, Indonesia, therefore it is subjected to rejuvenation to enhance hydrocarbon production. INTA/B Field is distinguished from other fields from its featured anticlinal structures that have the northeast-southwest trending. This structure is heavily faulted mainly in the up-thrown south side of a major normal fault. Two structural configurations with various oil-water contact have successfully been identified within the field. The most of oil reserves are preserved in the western lobe in which Intan-1 sands. One of the most important reservoirs in this field is Talangakar (TAF) sand deposited as a meandering river system that streamed from the northwest to the southeast within the basin. Two main reservoirs, Gita-34A and Gita-34B are correlated throughout the field and interpreted as Miocene fluvio-channel sands. These two channels are thickened moderately from southwest to northeast which has descriptions as follows: fine- to-coarse grains, unconsolidated to friable, and low cementing materials.INTA/B Field has been produced for 25 years and currently undergoing a watered-out phase. Therefore, an integrated study is subjected to overcome this issue for mature field rejuvenation. The integrated study ranged from geology (e.g., depositional environment and facies analysis), geophysics (e.g., revisiting and reprocessing of seismic attributes), petrophysical calculation, and reservoir engineering (e.g., water conformance plot and volumetric calculation).This integrated study has successfully rejuvenated a mature field resulting and added a significant number in oil production with an average of 300 BPOD/well. The extended project is estimated to have a similar result to the forward pilot.

Well Integrity Study for CO_2 WAG Application in Mature Field X, South Sumatra Area for the Fulfillment as CO2 Sequestration Sink

The most of today's global oil production comes from mature fields. Oil companies and governments are both concerned about increasing oil recovery from aging resources. To maintain oil production, the mature field must apply the Enhanced Oil Recovery method. water-alternating-gas (WAG) injection is an enhanced oil recovery method designed to improve sweep efficiency during injection with the injected water to control the mobility of . This study will discuss possible corrosion during and water injection and the casing load calculation along with the production tubing during the injection phase. The following study also performed a suitable material selection for the best performance injection. This research was conducted by evaluating casing integrity for simulate water-alternating-gas (WAG) to be applied in the X-well in the Y-field, South Sumatra, Indonesia. Corrosion prediction were performed using Electronic Corrosion Engineer (ECE®) corrosion model and for the strength of tubing which included burst, collapse, and tension of production casing was assessed using Microsoft Excel. This study concluded that for the casing load calculation results in 600 psi of burst pressure, collapse pressure of 2,555.64 psi, and tension of 190,528 lbf. All of these results are still following the K-55 production casing rating. While injecting , the maximum corrosion rate occurs. It has a maximum corrosion rate of 2.02 mm/year and a minimum corrosion rate of 0.36 mm/year. With this value, it is above NORSOK Standard M-001 which is 2 mm/year and needs to be evaluated to prevent the rate to remain stable and not decrease in the following years. To prevent the effect of maximum corrosion rate, the casing material must use a SM13CR (Martensitic Stainless Steel) which is not sour service material.

Integrated Assisted History Matching and Forecast Optimisation Under Uncertainty for More Robust Mature Field Redevelopment Project

Redevelopment of a mature field enables reassessment of the current field understanding to maximise its economic return. However, the redevelopment process is associated with several challenges: 1) analysis of large data sets is a time-consuming process, 2) extrapolation of the existing data on new areas is associated with significant uncertainties, 3) screening multiple potential scenarios can be tedious. Traditional workflows have not combatted these challenges in an efficient manner. In this work, we suggest an integrated approach to combine static and dynamic uncertainties to streamline evaluating of multiple possible scenarios is adopted, while quantifying the associated uncertainties to improve reservoir history matching and forecasting. The creation of a fully integrated automated workflow which includes geological and fluid models is used to perform Assisted History Matching (AHM) that allows the screening of different parameter combinations whilst also calibrating to the historical data. An ensemble of history matched models is then selected using dimensionality reduction and clustering techniques. The selected ensemble is used for reservoir predictions and represents a spread of possible solutions accounting for uncertainty. Finally, well location optimisation under uncertainty is performed to find the optimal well location for multiple equiprobable scenarios simultaneously. The suggested workflow was applied to the Northern Area Claymore (NAC) field. NAC is a structurally complex, Lower Cretaceous stacked turbidite, composed of three reservoirs, which have produced ~170 MMbbls of oil since 1978 from an estimated STOIIP of ~500 MMstb. The integrated workflow helps to streamline the redevelopment project by allowing geoscientists and engineers to work together, account for multiple scenarios and quantify the associated uncertainties. Working with static and dynamic variables simultaneously helps to get a better insight into how different properties and property combinations can help to achieve a history match. Using powerful hardware, cloud-computing and fully parallel software allow to evaluate a range of possible solutions and work with an ensemble of equally probable matched models. As an ultimate outcome of the redevelopment project, several prediction profiles have been produced in a time-efficient manner, aiming to improve field recovery and accounting for the associated uncertainty. The current project shows the value of the integrated approach applied to a real case to overcome the shortcomings of the traditional approach. The collaboration of experts with different backgrounds in a common project permits the assessment of multiple hypotheses in an efficient manner and helps to get a deeper understanding of the reservoir. Finally, the project provides evidence that working with an ensemble of models allows to evaluate a range of possible solutions and account for potential risks, providing more robust predictions for future field redevelopment.

A New Structural and Tectonic Model for a Mature Field in the Greater Caucasus

Executive Summary This article deals with the necessity the re-interpret seismic data at mature fields and is based on the field data located in the territory of the Greater Caucasus. The field was discovered back in the Soviet Union (1935).

Production Optimization in Mature Field Through Scenario Prediction Using a Representative Network Model: A Rapid Solution Without Well Intervention

As part of the production optimization exercise in J field, an initiative has been taken to enhance the field production target without well intervention. J field is a mature field; the wells are mostly gas lifted, and currently it is in production decline mode. As part of this optimization exercise, a network model with multiple platforms was updated with the surface systems (separator, compressors, pumps, FPSO) and pipelines in place to understand the actual pressure drop across the system. Modelling and calibration of the well and network model was done for the entire field, and the calibrated model was used for the production optimization exercise. A representative model updated with the current operating conditions is the key for the field production and asset management. In this exercise, a multiphase flow simulator for wells and pipelines has been utilized. A total of ∼50 wells (inclusive of idle wells) has been included in the network model. Basically, the exercise started by updating the single-well model using latest well test data. During the calibration at well level, several steps were taken, such as evaluation of historical production, reservoir pressure, and well intervention. This will provide a better idea on the fine-tuning parameters. Upon completion of calibrating well models, the next level was calibration of network model at the platform level by matching against the platform operating conditions (platform production rates, separator/pipeline pressure). The last stage was performing field network model calibration to match the overall field performance. During the platform stage calibration, some parameters such as pipeline ID, horizontal flow correlation, friction factor, and holdup factor were fine-tuned to match the platform level operating conditions. Most of the wells in J field have been calibrated by meeting the success criterion, which is within +/-5% for the production rates. However, there were some challenges in matching several wells due to well test data validity especially wells located on remote platform where there is no dedicated test separator as well as the impact of gas breakthrough, which may interfere to performance of wells. These wells were decided to be retested in the following month. As for the platform level matching, five platforms were matched within +/-10% against the reported production rates. During the evaluation, it was observed there were some uncertainties in the reported water and gas rates (platform level vs. well test data). This is something that can be looked into for a better measurement in the future. By this observation, it was suggested to select Platform 1 with the most reliable test data as well as the platform rate for the optimization process and qualifying for the field trial. Nevertheless, with the representative network model, two scenarios, reducing separator pressure at platform level and gas lift optimization by an optimal gas lift rate allocation, were performed. The model predicts that a separator pressure reduction of 30 psi in Platform 1 has a potential gain of ∼300 BOPD, which is aligned with the field results. Apart from that, there was also a potential savings in gas by utilizing the predicted allocated gas lift injection rate.

One Phase Well OPW : Unlock Shallow Reservoir Efficient and Economically by Eliminating Surface Casing

Tunu is a mature giant gas and condensate field locate in Mahakam Delta, East Kalimantan, Indonesia. The field has been in development for almost 30 years and currently has been considered as a mature field where to put a state of an economic well has become more challenging nowadays. The deeper zone of Tunu has no longer been considered as profitable to be produced and the current focus is more on the widespread shallow gas pocket located in the much shallower zone of Tunu. One phase well is architecture without 9-5/8" surface casing. OPW is one-section drilling using a diverter mode from surface to TD without using BOP. Historical for OPW is began from 2018, where drilling reservoir section using diverter mode in two-phase. In 2018 also succeeded in performing perforated surface casing. Due successfully in drilling operation using diverter and perforated surface casing, in 2019 drilling trials for OPW were carried out. Until now, the OPW architecture has become one of the common architecture used in drilling operations as an optimization effort. Until December 2020 PHM has completed 15+ OPW wells. A general comparison of OPW and SLA well is at the cost of constructing a well of approximately 200,000 - 300,000 US$. The disadvantages of OPW wells are more expensive in the mud and cement section when using a 9-1/2" hole, but in terms of the duration, OPW drilling time is more efficient up to 2-3 days. If viewed from the integrity of the OPW wells, from 15 OPW wells that have been completed, only 2 of them have SCP.

Maximizing Co-Activity Operation and Mastering Drilling Practice as Effective Strategies for Marginal Field Development

A limited remaining reserve is one of the challenges commonly found in mature field development. Swamp fields in the Mahakam block is an example of mature field development which leads to a marginal operation. Delivering wells more economically is one of the key points to survive during those conditions. Rig operation with a significant daily expenditure could be a way for improvement to yield economic wells. In general, an efficient rig operation would deliver wells in a shorter duration and at a lower cost. In order to lessen the well duration, two aspects could be improved: performing co-activity operation to shorten the horizontal time (preparation) and mastering drilling practices to shorten the vertical time (drilling). In the co-activity operations aspect, various initiatives have been implemented, such as rigless operations, batch drilling, and offline or simultaneous activities. While in the drilling practices aspect, drilling parameters, bit design, connection practice, and team motivation were the areas that have been improved. This paper will elaborate further on those initiatives. Implementing massive co-activity operations and the best drilling practices have demonstrated a significant time saving of 24% for the shallow well (final depth around 1800 m) and 27% for the deep well (final depth around 4300 m) in the block. These practices have also made a new record of the fastest well completion in 2.17 days and the highest drilling ROP for 141 m/hour with drilling 2303 m in the first 24 hours. The record of most drilled length in 24 hours is the world best performance of RSS BHA as per Directional Driller Company worldwide record. As a result, the 2020 average cost of the shallow well was 2.6 MUSD while the deep well was 4.1 MUSD. Those massive co-activity operations and drilling practices have been properly executed since 2019 without any safety incident and related NPT. The positive results have helped the development project to survive in marginal conditions.