bluuebunny/crossref_metadata_2025_split huggingface dataset:
Investigation of Reduced Interfacial Tension by Surfactant Flooding in Mixed-Wet Reservoirs
Authors: Aslam Usman 
Published: June 2021

Abstract
Surfactant flooding has long been considered a reliable solution for enhanced oil recovery, either by reducing oil-water interfacial tension (IFT) or through wettability alteration. This paper reveals the effect that reduced IFT has on capillary trapping in heterogeneous reservoirs. This effect is investigated through various numerical experiments on different simulation models where rock capillary pressure is assumed to scale with IFT. Capillary contrast on the scale of a few centimeters to a few tens of meters is reduced in the presence of surfactants. This reduction in IFT, under very specific circumstances, creates favorable conditions for increased or accelerated hydrocarbon production from mixed-wet reservoirs. The focus of this study is to ascertain the effectiveness of surfactant flooding in mixed-wet reservoirs.
Simulation studies of different mechanisms which are believed to occur in mixed-wet reservoirs are presented. Simulation results indicate the promising effect of surfactant flooding on oil recovery, depending on the type of reservoir. Detailed fine-scale simulation studies are carried out with representative relative permeability and imbibition capillary pressure curves from mixed-wet cores. By designing and selecting a series of surfactants to lower the IFT to the range of 10-3dynes/cm, a recovery of 10 to 20% of the original oil-in-place is technically and economically feasible.
The efficiency of surfactant flooding is investigated through sensitivity scenarios on formation rock/fluid parameters, including permeability, interfacial tension, rate flow, etc. Geological heterogeneity (layering and heterogeneous inclusions), imbibition capillary pressure curves, viscous/capillary balance (Nc), and gravitational forces were all found to have an impact on recovery by surfactant flooding. Numerical model dimensions, permeability, IFT, density contrast between oil and water, and injection flow rates were found to be the critical parameters influencing simulation results.
Gravity segregation, typically ignored in earlier studies, was found to have a significant effect on reservoir performance. Two different numerical models, with and without impermeable shale streaks, were used to capture the gravity segregation effect. The results revealed that the reduction in interfacial tension helps gravity to segregate oil and water, ultimately resulting in improved oil recovery. Moreover, results from the numerical simulation studies revealed that either an inexpensive or a good quality surfactant at low concentration can be used to obtain the same enhanced oil recovery. The effect of change in oil relative permeability curvature, due to reduced interfacial tension, also revealed a reduction in the remaining oil saturation with an increase in the capillary number.
Application of an Integrated Ensemble-Based History Matching Approach - An Offshore Field Case Study
Authors: Aslam Usman , Perez Cardenas Luis Hernando , Klimushin Andrey 
Published: June 2021

Abstract
The Internet of Things has popularized the notion of a digital twin - a virtual representation of a physical system. There are substantial risks associated with designing a development plan for an oilfield and the industry has been making use of reservoir models - digital twins - to improve the decision-making process for many years. With an increase in the availability of computational resources, the industry is moving towards ensemble-based workflows to estimate risk in field development plans. In this paper, we demonstrate the use of an integrated ensemble-based approach to assess uncertainties in the reservoir models and quantify their impact on the decision-making process.
An important feature of a digital twin is its ability to use sensor data to update the virtual model, more commonly known as history matching or data assimilation. We demonstrate how production data can be used to identify and constrain the uncertainties in the reservoir model. Production data is incorporated using Bayesian statistics and state-of-the-art supervised machine learning techniques to create an ensemble of models that capture the range of uncertainties in the reservoir model. This ensemble of calibrated models with an improved predictive ability provides a realistic assessment of the uncertainty associated with production forecasts.
The ensemble-based approach is demonstrated through its application on an offshore oilfield located in the North Sea. The field is highly compartmentalized and has high structural uncertainty following the interpretation and depth conversion. An integrated cross-domain model is set up to incorporate typically ignored structural uncertainty in addition to the uncertainties and their dependencies in the dynamic parameters, including fault transmissibility, pore-volume, fluid contacts, saturation, and relative permeability endpoints, etc. Results from the history matched ensemble of models show a significa nt reduction in uncertainty in these parameters and the predicted production.
An advantage of the proposed technique is that the automated, repeatable, and auditable ensemble-based workflow can assimilate the newly acquired measured data into the reservoir model at any time, keeping the model up-to-date and evergreen.
Carbon Dioxide Sequestration and Drainage in Saline Aquifer
Authors: Ennin Edward 
Published: June 2021

Abstract
Geological storage of CO2 in saline aquifers is recognized as a favorable technique that could deliver a significant decrease in CO2 emissions over the short to medium-term. However, the major risk is the possibility of leakage and injection limitation due to pore pressure. This research investigates the three major mechanisms of CO2 trapping to determine which method safely captures the most CO2, interrogates the pore pressure effect on storage, and compares traditional core flooding methods for CO2 storage with CO2 drainage which is more practical in the aquifer.
A core flooding set up was built to replicate reservoir conditions of the Anadarko Basin in Texas, USA. The research involved three reservoir pay zone rocks obtained from depths of about 7687ft that were pieced together to undergo core flooding at 4400psi-5200psi and a temperature of 168°F. In the first study conducted the core was flooded with supercritical CO2 and brine of salinity 4000ppm to generate relative permeability curves to represent drainage and imbibition. For the duration of the 3rd, 4th, and 5th studies the core saturated with brine is flooded with CO2 at pressures of 4400psi, 4800psi, and 5200psi. Parameters like the volume of CO2 captured, connate water volumes, differential pressure, Ph of produced water, trapping efficiency, relative permeability, and fractional flow curves are noted.
After scrutinizing the result it is observed that the highest volume of CO2 is captured by solubility trapping followed by structural trapping and residual trapping in that order. From this research, it can be concluded that CO2 trapping, at least for these reservoir rocks, is not affected by pore pressure. Also contrary to most practices CO2 storage is best replaced in the laboratory using drainage experiments instead of the widely used relative permeability approach.
Experimental Separation Performance of In-Line Piggable Liquid Removal Unit – Pseudo Dry Gas Systems
Authors: Liebana Laura , Thomas Lee , Wood Terry , Lao Liyun , Rogerson Graeme 
Published: June 2021

Abstract
Pseudo Dry Gas (PDG) technology is proposed as an alternative concept for transporting multiphase fluids (gas, condensate and water) for long deep-water subsea tieback developments (Ref 1 - OTC-28949-MS) (Ref 2 - IPTC-19440-MS). Using PDG technology, subsea pipeline networks can be extended to excess of 200 km total length and considerably reduce the backpressure on the wells. This allows improved recovery of the reserves and the ability to reach currently stranded fields, especially deep-water lower-pressure gas fields.
The basis of the PDG system is to remove the liquid of the main pipeline system using Piggable Liquid Removal Units. With the removal of the liquid, the gravitational pressure losses in the system are eliminated allowing the pipeline to operate like a "Pseudo" Dry Gas system. The liquid phase is transported back to shore using a second smaller pipeline running in parallel to the main pipeline by means of subsea liquid pumps (Ref 3 - OTC-29332-MS).
After techno-economic reports were completed for a known basin of stranded gas in the West of Shetland, an Oil and Gas Technology Centre (OGTC) experimental project was established to determine the operation performance of the element within the PDG technology with lowest Technology Readiness Level (TRL). Currently the liquid removal unit has a TRL2 and a TRL4 will be achieved after the experimental testing programme has been fully completed. This paper assesses the separation performance (Efficiency) of the Piggable Liquid Units or PDG unit. Previous Flow Assurance and Computational Fluid Dynamics (CFD) established expected efficiencies between 84-99% depending on the gas and liquid flow rates and other factors such as unit orientation, liquid type, operating pressure and temperature.
Each PDG unit has two modules which allow for gas-liquid separation of the multiphase fluid in the pipeline. A PDG unit prototype has been built and a testing programme has been developed and undertaken in collaboration with Cranfield University (CU) using the large scale Inclinable Multip hase Flow Loop facilities. The testing programme has two test matrices: Matrix 1 which studies the performance of a single module of the PDG unit and Matrix 2 which investigates the efficienc y of the entire PDG unit (two separation modules). Matrix 1 of the testing programme allows to characterise the system varying the flow conditions (flow regime, liquid and gas flow rates), drop out liquid level and size, effect of sand and the inclination and orientation of the unit as would be expected once installed. This paper focuses on the results obtained from Matrix 1 testing programme and compares them with the initia l PDG unit estimated efficiency values used in previous studies to demonstrate the prove of concept of the PDG technology. The overall conclusion is that the performance of the PDG liquid removal unit is greater than the ones originally used in technology assessment reports.
Real-Time Monitoring of the Effect of CO2 on the Cement Sheath
Authors: Wagner Paul , Ravi Kris , Prohaska Michael 
Published: June 2021

Abstract
Global warming is one of the most significant issues the world is facing. Capturing carbon dioxide from the atmosphere or industrial processes and storing it in geological formations (carbon capture and storage, CCS) can help counteract climate change. Nevertheless, the interaction between well barrier elements such as cement, casing, tubulars, packers, and valves can lead to possible leakages. To accomplish successful carbon dioxide sequestration, injecting the carbon dioxide in its supercritical state is necessary. The supercritical carbon dioxide can corrode steel and elastomers and react with the calcium compounds in the cement, dissolving them and forming calcium carbonate and bicarbonate in the process. This carbonation can lead to channels forming on the cement-to-rock interface or cracking due to the carbonate precipitation, resulting in a loss of well integrity.
This study focusses on finding ways that enable the continuous monitoring of cement integrity, under in-situ conditions, in a lab setup. The construction of an autoclave, capable of withstanding supercritical conditions of carbon dioxide, facilitates the in-situ monitoring. This autoclave also makes CT-scans of the pressurized sample possible, as well as acoustic measurements, using state-of-the-art piezo elements. The first tests will establish a baseline using neat Class G Portland cement to verify the design and sensors. The set up consists of a rock core in the middle of the autoclave surrounded by a cement sheath. A prepared channel in the center of the core expedites the distribution of the carbon dioxide. Once the ability of the sensors to monitor the integrity is verified, different cement compositions and their interaction with supercritical carbon dioxide can be studied.
The experimental setup and the procedure discussed here closely simulate the downhole condition. Hence, the results obtained using this setup and procedure is representative of what could be observed downhole. The direction is not to remove the sample from the autoclave for analysis, as is the current industry practice, but to measure cement integrity under in-situ conditions over an extended period of time. Digitalization is powering the in-situ analysis in these tests.
The first two tests of this study, using the afore mentioned autoclave, investigated the carbonation behaviour of two Class G Portland cement slurrys, one with a low and one with a high slurry-density. The low-density slurry showed extensive degradation and even the high-density slurry showed carbonation, but only close to the sandstone core.
The results from this study can lead to the prevention of leakage of carbon dioxide to the environment and other formations, which defeats the purpose of carbon dioxide sequestration. These results should improve the economics of these wells as well as the health, safety, and environmental aspects.
Seed Extracts as Natural, Green, Non-Toxic Corrosion Inhibitors
Authors: Ng Jun Hong Clarence , Almubarak Tariq , Nasr-El-Din Hisham A. 
Published: June 2021

Abstract
Acid treatments are commonly used in the oilfield to remove inorganic scale or to stimulate formatio ns. These treatments typically consist of using hydrochloric acid (HCl), acetic acid, formic acid, or chelating agents. At elevated temperatures, these acids are highly corrosive and can cause severe damage to tubulars as well as downhole equipment. To reduce damage from these acids, corrosion inhibitors are added to the treatment solution.
Corrosion inhibitors used in the oil and gas industry are typically quaternary amines or sulfur-containing compounds. These compounds adsorb to the surface of the metal, thereby reducing contact between the metal surface and the corrosive substance. However, these corrosion inhibitors are damaging to the environment and harmful to human health. Alternative new environmentally-friendly corrosion inhibitors are also either toxic to the human body or face performance limitations at higher temperature field applications. To develop new environmentally friendly and non-toxic corrosion inhibitors for high-temperature applications, 15 edible seeds were tested as alternative sources of corrosion inhibitors.
In order to determine the inhibition effect of 15 different seeds, N-80 and S13Cr coupons were exposed to 15 wt.% HCl solutions at temperatures between 77-250°F with 2 wt.% of grounded seed added for 6 hours. In addition, a control solution containing no corrosion inhibitor was used to establish a corrosion rate for a base case.
This paper will show the results of such seeds and attempt to provide an awareness of natural seeds extract for use as corrosion inhibitors in conjunction with well acid treatments. It was noted that out of the 15 seeds, seeds 1 and 2 were found to perform the best at these conditions, exhibiting more than 90% corrosion inhibition efficiency. Seed 4 was observed to perform the worst, exhibiting only 16.8% inhibition efficiency. At 150°F, 2 wt.% of seeds 1 and 2 were tested with seed 1 achieving a corrosion rate of 0.00253 lb/ft2 while seed 2 was unable to provide sufficient inhibition with a corrosion rate of 0.153 lb/ft2. The control solution was found to have a corrosion rate of 0.371 lb/ft2 over the 6 hours at 150°F. Seed 1 was further tested at 200°F with the addition of corrosion inhibitor intensifiers and resulted in a corrosion rate of 0.00087 lb/ft2, while at 250°F, a corrosion rate of 0.00811 lb/ft2 was observed. The tests using S13Cr also showed that seed 1 worked well as a corrosion inhibitor for CRAs. The thermal degradation of seed 1 was also examined using NMR.
These results show a new naturally occurring, green, non-toxic, high-temperature applicable corrosion inhibitor that can be developed from edible seeds.
Field Application of Software Model and Wellbore Strengthening Materials for Drilling Depleted Reservoirs and Mechanically Weak Formations in Gulf of Suez
Authors: Mohamed Youssry Abd El-Aziz , Ahmed Ragab Saber , Al-Zahry Ayman Abd El-ghany , Moustafa Amr Ismail , Elnashar Radi Ahmed , Salama Ayman Salama , Ouda Abdalla Ahmed , Mohamed Ahmed Hamdy 
Published: June 2021

Abstract
Drilling operations might require increasing mud weight beyond formation's fracture gradient margin which may lead to downhole losses into formation and other potential problems resulting in Non-Productive Time (NPT). This paper describes successful application of wellbore strengthening software (WSS) to simulate formations’ strengthening process by increasing Hoop Stress while drilling depleted reservoir sand or mechanically weak formations. The software model takes into consideration well design, basic rock properties and in-situ earth stresses. The paper also defines design of mud formula and lab procedures verifying the designed wellbore strengthening materials (WSM) blend and successful application in field. Design and selection of mud formula are main pillars of successful formation strengthening procedure to match with induced fractures width. Unlike other software models that use generic particle size distribution (PSD) data, software in this study takes into consideration PSD of specific batches of WSM to simulate wellbore strengthening process and recommend the optimum WSM blend, concentrations. Based on mud formula design from WSS, lab tests were conducted to verify concentrations and selection of WSM and accordingly formulas were applied successfully for complicated drilling operations. Static and dynamic formation strengthening techniques were applied successfully in multiple wells. Based on software results and recommendations, Techniques’ application managed to strengthen weak formations up to 121% of original fracture gradient, decreased section drilling time by 20% which resulted in drilling costs reduction by up to 24.2 %. As a result of this successful application in many critical wells, WSS results are now integral to operator's well plan to enhance wellbore pressure integrity of weak intervals, in following drilling operations. The presented study is based on an innovative approach to strengthen weak and depleted formations in critical drilling operations using exact PSD data of WSM batches, formation properties and customized software model, an optimum concentrations blend can be selected to strengthen wellbore and hence it can be customized for every application where optimum formation strengthening is required.
Geosteering Optimization Using the Multi-Boundary Detection Technology in Rubiales' Field, Colombia
Authors: Manchola Jhon , Ballestero Dianys , Villasmil Jose , Nava Gerson 
Published: June 2021

Abstract
Horizontal drilling is part of the development plan for Rubiales field in Colombia, operated by the National Oil Company. By this, different geosteering technologies have been applied during the infill drilling campaign and, it has varied over time. The multi-boundary detection tool has successful results in terms of net sand percent increase, precise location, and cost decrease, related to drilling operations.
Some of the challenges for well placement are thin thickness channels with no lateral continuity (deposition environment), oil-water contact closeness, poor correlation with cutting samples, between others. The technology minimizes risks with the real-time resistivity inversion. This process generates a visual representation of the resistivity profile around the wellbore, including geometric definition, dip, and thickness estimation.
These inversion results are used to recommend trajectory adjustments while drilling. The complete geosteering experience in Rubiales with the new technology (more than one hundred sixty producing wells so far) has been classified into three main types of wells: lateral sections drilled in continuous sand intervals; lateral variation of resistivity; and wells with a change of prospective zone by channel discontinuity.
The implementation success is described by the net sand percentage increasing, around 16% compared with other technologies. The average drilling length was improved by 20% and the number of geological sidetracks concerning previous stages of exploitation reduced by more than 90%, without affecting the drilling rate. These factors, including the update of the sedimentological models, inclusion of new reserves, and the production increase, are part of the optimization plan.
Development and Execution of Heritage Petroleum Company Limited’s First Offshore Workover Campaign - A Case History of Successful Implementation of Performance Management
Authors: Mohammed Shazim , Persad Dale , Baksh Kirk 
Published: June 2021

Abstract
Heritage Petroleum Company Limited (HPCL) is the newest operating oil and gas company in Trinidad and Tobago and was vested and entrusted with the operation and management of all the exploration and production assets of Petroleum Company of Trinidad and Tobago Limited ("Petrotrin"). Being driven by oil-based revenue meant that rig intervention projects had to be innovative, economically viable and practical to meet the company’s financial commitments. This paper presents the concepts and processes behind the development and implementation of HPCL’s Workover Scoping and Procurement Framework.
The offshore team recognized the need to frame the well review and workover candidate selection process as well as a procurement process that was both operationally accommodating and in accordance with public procurement regulations. This process would also have to be tested, since it was a new concept that was not practiced by Petrotrin.
The well review process involved defining reservoir deliverability and in-place volumes through static and dynamic modelling, establishing current well potential and deliverability via nodal analysis with installed completion designs, topside infrastructure conditions and flow restrictions.
The procurement process was achieved by identifying local resources and generating framework agreements for services and equipment. Job specific resources were tendered to ensure a transparent selection and award. The process also involved ranking the risks of all candidates. Economic analyses were performed to determine whether the financial indicators were positive to ensure viability of the campaign. A scorpion plot was also used to manage the performance of this framework during the campaign.
The result was a campaign consisting of 15 wells that was delivered on time and within the workover budget. Actual production gain was over 1700 BOPD as opposed to the expected gain of 1450 BOPD. Budgeted Net Present Value (NPV) and actual NPV was calculated to be US$ 9.42 million dollars and US$ 11.7 million dollars respectively. All resources were demobilized and removed from the offshore acreage to reduce risks and floating expense to the company at the end of the campaign.